PLA-6391, Response to Request for Additional Information for the Review of License Renewal Application (Lra), Sections B.2.23, B.2.24, B.2.26, B.2.27, B.2.28, B.2.31

Response to Request for Additional Information for the Review of License Renewal Application (Lra), Sections B.2.23, B.2.24, B.2.26, B.2.27, B.2.28, B.2.31

ML082200292
Person / Time
Site:	Susquehanna
Issue date:	07/25/2008
From:	Mckinney B Susquehanna
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
PLA-6391
Download: ML082200292 (55)

Text

Brltt T. McKinney PPL Susquehanna, LLC Sr. Vice President & Chief Nuclear Officer 769 Salem Boulevard *. a Berwick, PA 18603 Tel. 570.542.3149 Fax 570.542.1504 btmckinney@pplweb.com JUL 5 280 pp1 .

U. S. Nuclear Regulatory Commission Document Control Desk Mail Stop OP 1-17 Washington, DC 20555 SUSQUEHANNA STEAM ELECTRIC STATION REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (LRA)

SECTIONS B.2.23, B.2.24, B.2.26, B.2.27, B.2.28, B.2.31 Docket Nos. 50-387 PLA-6391 and 50-388

References:

1) PLA-6110, Mr. B. T McKinney (PPL)to Document ControlDesk (USNRC),

"Applicationfor Renewed OperatingLicense Numbers NPF-14 and NPF-22,"

dated September 13, 2006.

2) Letterfrom Ms. E. H. Gettys (USNRC) to Mr. B. T. McKinney (PPL),

"Requestfor AdditionalInformationfor the Review of the Susquehanna Steam Electric Station, Units 1 and 2 License Renewal Application, "dated June 23, 2008.

In accordance with the requirements of 10 CFR 50, 51, and 54, PPL requested the renewal of the operating licenses for the Susquehanna Steam Electric Station (SSES)

Units 1 and 2 in Reference 1.

Reference 2 is a request for additional information (RAI) related to License Renewal Application (LRA) Sections B.2.23 B.2.24, B.2.26, B.2.27, B.2.28, and B.2.31. The enclosure and attachments to this letter provide the additional requested information.

There are no new regulatory commitments contained herein as a result of the attached RAI responses. However, based on these responses, two license renewal commitments have been revised and one license renewal commitment has been deleted. LRA Commitment #25 is revised in response to RAI B.2.23-1 as shown in Attachment 1. documents the response to RAI's B.2.26-1, B.2.26-2 and B.2.26-3 which concludes that the "Steam Flow Restrictor Inspection" is not required. Therefore, LRA Commitment #22 is deleted. LRA Commitment #27 is revised in response to RAI B.2.31-1 as shown in Attachment 3.

If you have any questions, please contact Mr. Duane L Filchner at (610) 774-7819.

I Document Control Desk PLA-6391 I declare, under penalty of perjury, that the foregoing is true and correct.

Executed on: ýZ--dzog B. T. McKinney

Enclosure:

PPL Responses to NRC's Request for Additional Information (RAI)

Attachments: Attachment 1 - LRA Revisions in Response to RAI B.2.23-1 Attachment 2 - LRA Revisions in Response to RAIs B.2.26-1, B.2.26-2, and B.2.26-3 Attachment 3 - LRA Revisions in Response to RAIs B.2.31-1 and B.2.31-3 Copy: NRC Region I Ms. E. H. Gettys, NRC Project Manager, License Renewal, Safety Mr. R. Janati, DEP/BRP Mr. F. W. Jaxheimer, NRC Sr. Resident Inspector Mr. A. L. Stuyvenberg, NRC Project Manager, License Renewal, Environmental

Enclosure to PLA-6391 PPL Responses to NRC's Request for Additional Information (RAI)

Enclosure to PLA-6391 Page 1 of 14 RAI B.2.23-1:

In the "scope of program" program element, the LRA states that this program detects loss of material due to crevice and pitting corrosion and selective leaching of the copper alloy cooler channel in the Control Structure HVAC System. Selective leaching generally does not cause changes in dimensions and is difficult to detect. The examination techniques used by this program to detect degradation is visual and/or volumetric. Neither one of these techniques by itself will detect selective leaching.

Please justify how this program will manage selective leaching and explain why these components are not included in LRA AMP B.2.29, Selective Leaching Program.

PPL Response:

The LRA is amended as shown in Attachment 1 to credit the Selective Leaching Inspection, in place of the Cooling Units Inspection, to manage loss of material due to selective leaching of the copper Control Structure HVAC cooler channels.

RAI B.2.23-2:

The GALL AMP XI.M32, "One-time Inspection" program, "detection of aging effects" program element, has different inspection methods identified for monitoring specific aging mechanisms such as crevice corrosion, galvanic corrosion, etc. However, the LRA states generally that the program uses a combination of established volumetric or visual examination techniques. Please clarify which techniques will be used to detect the various aging mechanisms.

PPL Response:

Visual inspection (VT-I or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine whether crevice or pitting corrosion is occurring.

Visual inspection (VT-3 or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine whether galvanic or general corrosion is occurring.

Visual inspection (VT-3 or equivalent) techniques will be used to determine whether reduction in heat transfer is occurring. The specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32.

Enclosure to PLA-6391 Page 2 of 14 RAI B.2.23-3:

In the "monitoring and trending" program element, the LRA states that no actions are taken as part of this program, since it is a one-time inspection activity. Please confirm if the corrective action program will increase the sample size in the event aging effects are detected.

PPL Response:

Unacceptable inspection findings will be evaluated under the SSES corrective action program. The evaluation done under the SSES corrective action program will identify appropriate corrective actions including the need to perform additional inspections.

RAI B.2.23-4:

In the "acceptance criteria" program element, the GALL AMP XI.M32, "One-time Inspection" program states that any indication or relevant conditions of degradation detected are evaluated. LRA Section B.2.23 states that no unacceptable loss of material (or wall thinning) or fouling of heat exchanger tubes and fins that could result in a loss of component intended function during the period of extended operation, as determined by engineering evaluation. Explain why the acceptance criteria for B.2.23 differ from the recommendations of the GALL Report and clarify what "no unacceptable loss of material (or wall thinning) or fouling..." means.

PPL Response:

Any indications or relevant conditions of degradation detected during the inspections will be evaluated. Similar to the example provided in the GALL text, the inspection observations will be compared to predetermined acceptance criteria. Inspection results that do not meet the acceptance criteria will be entered into the corrective action program for evaluation.

The license renewal application is amended as follows to provide consistency with the GALL Acceptance Criteria.

B.2.23 Cooling Units Inspection

> The text under Acceptance Criteria in Section B.2.23 (on LRA page B-74) is revised by addition (bold italics) and deletion (eriketh:r-.h) as follows:

Any indicationsor relevant conditions of degradationdetected during the inspections will be compared to pre-determinedThe acceptance criteria.-fer-the Cooling UInit, I*-Setion a-e: No unacceptable- loss of material (or wall thinning), r fouling of heat oxchange. tubes and fins, that If the acceptance criteriaare not met,

Enclosure to PLA-6391 Page 3 of 14 then the indications/conditionswill be evaluated under the SSES Corrective Action Programto determine whether they could result in a loss of component intended function during the period of extended operation, as determined b, engineering evaluation.

RAI B.2.23-5:

The "operating experience" program element states that the Cooling Unit Inspection is a new program and there is no plant-specific program operating experience. Several condition reports have been generated during walkdowns, surveillance and maintenance activities on the cooling units that are included in the scope of this program. Please identify if there was any age related degradation documented for these cooling units.

PPL Response:

Condition reports associated with the cooling units within the scope of the Cooling Units Inspection have been generated during various routine plant activities. A review of the condition reports associated with the cooling units did not identify any age-related degradation for the specific subcomponents addressed by the Cooling Units Inspection.

RAI B.2.24-1:

The "operating experience" program element states that the "Heat Exchanger Inspection" is a new program and there is no plant-specific program operating experience. However, during performance of surveillance tests or maintenance activities on these heat exchangers any degradation of tubes that was observed would have been documented.

Please identify examples of issues that may have been documented to address age-related degradation of the heat exchanger tubes within the scope of this program and include them in your operating experience element.

PPL Response:

A review of documentation generated during various routine plant activities associated with the heat exchangers within the scope of the Heat Exchanger Inspection was performed. The review did not identify any age-related degradation of the heat exchanger tubes within the scope of this inspection.

Enclosure to PLA-6391 Page 4 of 14 RAI B.2.26-1:

The GALL AMP XI.M32, "One-time Inspection" program, "detection of aging effects" program element, has different inspection methods identified for monitoring specific aging mechanisms such as crevice corrosion, galvanic corrosion, etc. However, the LRA states generally that the program uses established visual examination techniques.

Please clarify which visual technique will be used to detect reduction of fracture toughness as evidenced by cracking.

PPL Response:

Clarification of which visual technique that will be used for detection of fracture toughness is not required because aging management program (AMP) B.2.26, Main Steam Flow Restrictor, is eliminated in the response to RAI B.2.26-2 below. As stated in the PPL Response to RAI B.2.26-2, the Main Steam Flow Restrictor Inspection is not an aging management program required for license renewal. The LRA is amended to delete the Main Steam Flow Restrictor Inspection. As such, a response is not required for RAI B.2.26-1. contains the LRA amendment related to deleting the Main Steam Flow Restrictor Inspection.

RAI B.2.26-2:

The "acceptance criteria" program element states that no cracking that could result in a loss of component intended function(s) during the period of extended operation, as determined by engineering evaluation.

Please confirm if the cast austenitic stainless steel (CASS) main steam flow restrictors were screened for thermal aging? Are they susceptible? Will flaw tolerance evaluation be performed if cracking is detected?

Please explain what type of corrective actions and monitoring will be implemented if cracking is detected.

PPL Response:

Consistent with NUREG-1 801 (GALL)Section XI.M 12, "Thermal Embrittlement of Cast Austenitic Stainless Steel (CASS)," PPL has performed a screening of the CASS portions of the main steam flow restrictors to determine the susceptibility for thermal aging. PPL has determined that the CASS portions of the flow restrictors are not susceptible to reduction of fracture toughness due to thermal embrittlement.

4 Enclosure to PLA-6391 Page 5 of 14 The CASS portions of the flow restrictors were cast by a centrifugal casting method. A telephone conversation between PPL and an engineer with the company that produced the castings, Wisconsin Centrifugal Incorporated, who was employed at their facility at the time of fabrication, confirmed the castings were formed centrifugally. PPL reviewed the QA documentation packages for the flow restrictors and determined that the castings were constructed from cast austenitic stainless steel, in conformance with material specification SA-351 CF8. This material is a low-molybdenum grade of CASS, as opposed to a high-molybdenum grade (i.e., "M" grade) of CASS material, such as SA-351 CF8M, which requires 2-3% molybdenum content. Therefore, the steam line flow restrictor castings for SSES are considered to be constructed of low molybdenum (0.5%

maximum) content material. In accordance with the guidance provided in the GALL Section XI.M12, the centrifugally-cast, low molybdenum CASS portions of the flow restrictors are not susceptible to thermal embrittlement.

As such, the Main Steam Flow Restrictor Inspection intended to manage reduction of fracture toughness due to thermal embrittlement is not an aging management program required for license renewal.

In addition to the screening for susceptibility for thermal aging, PPL re-evaluated the other conclusions from the aging management review of the Main Steam Flow Restrictors. The results of that re-evaluation are as follows:

" The flow restrictors in the Main Steam system are not pressure boundary components. Therefore, neither ASME Section III nor ANSI B3 1.1, which typically require a fatigue analysis or the use of stress range reduction factors for 7000 cycles, are applicable. As such, fatigue cracking of the main steam flow restrictors is not an applicable aging effect.

• The Inservice Inspection (ISI) Program was credited to confirm the effectiveness of the BWR Water Chemistry Program to manage a loss of material for the main steam flow restrictors. The basis for crediting the ISI program was that similar materials and environments were inspected by ISI. However, the Chemistry Program Effectiveness Inspection (CPEI) confirms the effectiveness of the BWR Water Chemistry Program. While ISI results may be considered in the development and implementation of the CPEI one-time inspection, the ISI Program is not an aging management program for the main steam flow restrictors.

• Stress Corrosion Cracking (SCC) is not an aging effect requiring management for the main steam flow restrictors because there is no tensile stress in the CASS portions of the flow restrictors to promote stress corrosion cracking. Also, the flow restrictors do not have a pressure boundary function that could be affected by cracking, and cracking will not affect the flow restriction function of the flow restrictors. Extreme cracking that could result in the loss of flow restrictor structural integrity, could affect its flow restriction function, however, such a

Enclosure to PLA-6391 Page 6 of 14 failure is not plausible, given the lack of a driving mechanism for crack initiation and/or crack growth.

LRA Section 3.1.2.1.3, Table 3.1.1, Table 3.1.2-3, Appendix A (Table of Contents, Section A. 1.2.30, and Table A-i), and Appendix B (Table of Contents, Table B-i, Table B-2, and Section B.2.26) are revised to reflect these results. Attachment 2 contains the LRA amendment related to deleting the Main Steam Flow Restrictor Inspection.

RAI B.2.26-3:

In the "detection of aging effects" program element, the LRA states that the amp "Steam Flow Restrictor Inspection" will be applied to all eight (four per unit) main steam flow restrictors at SSES. Please clarify if this means that all eight flow restrictors will be inspected. Please provide the sample size, and identify if the program will provide for increasing the sample size in the event that aging effects are detected.

PPL Response:

As stated in the PPL Response to RAI B.2.26-2, above, the Main Steam Flow Restrictor Inspection is not an aging management program required for license renewal. The LRA is amended to delete the Main Steam Flow Restrictor Inspection. As such, a response is not required for RAI B.2.26-3. contains the LRA amendment which deletes the license renewal commitment to perform the Main Steam Flow Restrictor Inspection.

RAI B.2.27-1:

In the GALL AMP XI.M32 "One-time Inspection" program the "detection of aging effects" program element, has a different inspection methods identified for monitoring specific aging mechanisms such as crevice corrosion, general corrosion, etc. However, the LRA states generally that the program uses a combination of established volumetric or visual examination techniques. Please clarify which techniques will be used to detect the various aging mechanisms.

PPL Response:

Visual inspection (VT- 1 or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine whether crevice or pitting corrosion is occurring.

Visual inspection (VT-3 or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine whether galvanic or general corrosion is occurring.

Visual inspection (VT-3 or equivalent) techniques will be used to determine whether

Enclosure to PLA-6391 Page 7 of 14 reduction in heat transfer is occurring. The specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32.

RAI B.2.27-2:

In the "monitoring and trending" program element, the LRA states that no actions are taken as part of this program, since it is a one-time inspection activity. Please confirm if the corrective action program will increase the sample size in the event aging effects are detected.

PPL Response:

Unacceptable inspection findings will be evaluated under the SSES corrective action program. The evaluation done under the SSES corrective action program will identify appropriate corrective actions including the need to perform additional inspections.

RAI B.2.27-3:

In the "acceptance criteria" program element, GALL AMP XI.M32 states that any indication or relevant conditions of degradation detected are evaluated. LRA Section B.2.27 states that no unacceptable loss of material (or wall thinning) or fouling of heat exchanger tubes and fins that could result in a loss of component intended function during the period of extended operation, as determined by engineering evaluation.

Explain why the acceptance criteria for B.2.27 differ from the recommendations of GALL and clarify what "no unacceptable loss of material (or wall thinning) or fouling..."

means.

PPL Response:

Any indications or relevant conditions of degradation detected during the inspections will be evaluated. Similar to the example provided in the GALL text, the inspection observations will be compared to predetermined acceptance criteria. Inspection results that do not meet the acceptance criteria will be entered into the corrective action program for evaluation.

The license renewal application is amended as follows to provide consistency with the GALL Acceptance Criteria.

Enclosure to PLA-6391 Page 8 of 14 B.2.27 Monitoring and Collection System Inspection The text under Acceptance Criteria in Section B.2.27 (on LRA page B-86) is revised by addition (bold italics) and deletion (s, ke1*eugh) as follows:

Any indicationsor relevant conditions of degradationdetected during the inspections will be compared to pre-determinedT-he acceptance criteria.-for-the lMonitoring and Collection System InSpection I.AVOIill- We:o unaccoptabloe loss; ofmatearial (or wall thinning) that If the acceptance criteriaare not met, then the indications/conditionswill be evaluated under the SSES CorrectiveAction Programto determine whether they could result in a loss of component intended function during the period of extended operation, as dcte.mined by engineeFin*

evaluatieR.

RAI B.2.28-1:

In Table 3.2.2-9, the diesel generator starting air system, has the AMP "Supplemental Piping/Tank Inspection" program credited for managing the aging effect of loss of material for stainless steel drain trap bodies and carbon steel moisture separators.

However, a review of the AMP Evaluation Results Document indicates that diesel generator starting air system is not included in the scope of the Supplemental Piping/Tank Inspection Program. Please justify why it is not included.

PPL Response:

The carbon steel moisture separators and stainless steel drain trap bodies in the diesel generator starting air system are within the scope of the Supplemental Piping/Tank Inspection. The Diesel Generators system should have been included in the listing of systems within the scope of this inspection, but was inadvertently omitted. Therefore, the Diesel Generators System is added to the scope of this inspection.

The license renewal application is amended as follows to reflect this change:

APPENDIX B, AGING MANAGEMENT PROGRAMS

> The text in LRA Section B.2.28 under the Scope of Program bullet (on LRA pages B-87 and B-88) is revised by addition (bold italics) as follows:

B.2.28 Supplemental Piping/Tank Inspection Aging Management Program Elements The results of an evaluation of each program element are provided below.

Enclosure to PLA-6391 Page 9 of 14 Scope of Program The Supplemental Piping/Tank Inspection is credited for managing loss of material due to crevice and pitting corrosion on carbon steel surfaces at air-water interfaces in the following systems:

- Condensate Transfer and Storage, Containment and Suppression, Control Structure Chilled Water, Diesel GeneratorsSystem, High Pressure Coolant Injection (HPCI), Main Steam, Reactor Core Isolation Cooling (RCIC), Residual Heat Removal (RHR), and Residual Heat Removal Service Water systems

- Standby Gas Treatment System (SGTS) - For SGTS, the inspection is also credited for managing loss of material due to microbiologically influenced corrosion (MIC) at the air-water interface with the mist eliminator loop seal, which is filled with raw water from the Service Water System, and galvanic corrosion at points of contact between the mist eliminator housing and the SGTS filter enclosure, where condensation and water pooling may occur.

Additionally, the Supplemental Piping/Tank Inspection detects and characterizes whether, and to what extent, a loss of material due to crevice and pitting corrosion is occurring (or is likely to occur) for stainless steel surfaces at air-water interfaces in the following systems:

- Condensate Transfer and Storage, Diesel GeneratorsSystem, Fuel Pool Cooling and Cleanup, and Standby Liquid Control systems RAI B.2.28-2:

The GALL AMP XI.M32, in the "detection of aging effects" program element, different inspection methods are identified for monitoring specific aging mechanisms such as crevice corrosion, galvanic corrosion, etc. However, the LRA states generally that the program uses a combination of established volumetric or visual examination techniques.

Please clarify which techniques will be used to detect the various aging mechanisms.

PPL Response:

Visual inspection (VT- I or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine whether crevice or pitting corrosion is occurring.

Visual inspection (VT-3 or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine whether galvanic or general corrosion is occurring.

Visual inspection (VT-3 or equivalent) techniques will be used to determine whether reduction in heat transfer is occurring. The specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32.

Enclosure to PLA-6391 Page 10 of 14 RAI B.2.28-3:

In the monitoring and trending element, the LRA states that no actions are taken as part of this program, since it is a one-time inspection activity. Please confirm if the corrective action program will increase the sample size in the event aging effects are detected.

PPL Response:

Unacceptable inspection findings will be evaluated under the SSES corrective action program. The evaluation done under the SSES corrective action program will identify appropriate corrective actions including the need to perform additional inspections.

RAI B.2.28-4:

In the "acceptance criteria" program element, the GALL AMP XI.M32 states that any indication or relevant conditions of degradation detected are evaluated. LRA Section B.2.28 states that no unacceptable loss of material (or wall thinning) that could result in a loss of component intended function during the period of extended operation, as determined by engineering evaluation. Explain why the acceptance criteria for B.2.28 differ from the recommendations of the GALL Report and clarify what "no unacceptable loss of material (or wall thinning)" means.

PPL Response:

Any indications or relevant conditions of degradation detected during the inspections will be evaluated. Similar to the example provided in the GALL text, the inspection observations will be compared to predetermined acceptance criteria. Inspection results that do not meet the acceptance criteria will be entered into the corrective action program for evaluation.

The license renewal application is amended as follows to provide consistency with the GALL Acceptance Criteria.

B.2.28 Supplemental Piping/Tank Inspection The text under Acceptance Criteria in Section B.2.28 (on LRA page B-89) is revised by addition (bold italics) and deletion (strikethfettgh) as follows:

Any indicationsor relevant conditions of degradationdetected during the inspections will be compared to pre-determinedThe acceptance criteria.-fe44he Supplemental Piping/Tank Inspecteia are: No Unacceptable less of material (or wall U4thiRO-)tha-t If the acceptance criteria are not met, then the

Enclosure to PLA-6391 Page 11 of 14 indications/conditionswill be evaluated under the SSES Corrective Action Program to determine whether they could result in a loss of component intended function during the period of extended operation, a. d'etcmined by.engineerin RAI B.2.31-1:

The license renewal application (LRA) states that the aging management program (AMP)

B.2.31 "Small Bore Class 1 Piping Inspection" is a new program that will be consistent with the generic aging lessons learned (GALL) AMP XI.M35, "One-time Inspection of ASME Code Class 1 Small Bore Piping." Provide your basis for categorizing AMP B.2.31 as being consistent with GALL AMP XI.M35 when AMP B.2.31 implies that non-volumetric examination techniques may be used as an alternate basis for performing the one-time inspections of the small bore Class 1 piping components and when AMP B.2.31 credits the program with managing an aging effect (i.e., loss of material) that is not within the scope of GALL AMP XI.M.35. Clarify whether the LRA will need to be amended to identify these aspects of the program as exceptions to GALL AMP XI.M35, and if so, justify your basis for crediting these exceptions for aging management of small bore Class 1 piping components.

In the LRA, both in the program description and in several aging management review line items, the AMP B.2.31 is credited with confirming the effectiveness of the Boiling Water Reactor (BWR) Water Chemistry Program in mitigating the aging effects of loss of material using "nondestructive examinations (including volumetric techniques)."

However, GALL AMP XI.M35 is credited only with managing the aging effect of cracking and the only examination technique used in AMP XI.M35 is volumetric examination.

PPL Response:

The SSES LRA is amended in Attachment 3 to demonstrate that AMP B.2.3 1, Small Bore Class 1 Piping Inspection, is consistent with GALL AMP XI.M35 with no exceptions.

AMP B.2.31 is credited for managing the aging effect of cracking, as a result of stress corrosion or thermal or mechanical loading, and a one-time volumetric examination is the acceptable method for confirming that cracking of ASME Code Class 1 small-bore piping is not occurring.

AMP B.2.22, Chemistry Program Effectiveness Inspection, is credited with verifying the effectiveness of AMP B.2.2, BWR Water Chemistry Program, to mitigate loss of material.

Enclosure to PLA-6391 Page 12 of 14 contains the revised LRA sections.

RAI B.2.31-2:

The LRA AMP B.2.31, "Small Bore Class 1 Piping Inspection," is being used to monitor both the aging effect of cracking and the aging effect of loss of material in Class 1 small bore piping. However, the environmental stressors that may lead to cracking are not necessarily the same as the environmental stressors that may lead to loss of material.

Clarify the selection processes and criteria that will be applied as part of this program to ensure that SSES will select and schedule inspection of the most limiting small bore Class 1 piping locations for both of these aging effects.

PPL Response:

The Small Bore Class 1 Piping Inspection, as amended in the response to RAI B.2.31-1, is credited to manage only cracking. As such, in the selection of the small bore Class 1 piping locations for the one-time inspection, there is no need to consider environmental stressors that may lead to loss of material. The selection criteria to be applied as part of this program are provided in the "Monitoring and Trending" program element discussion in LRA Section B.2.31.

RAI B.2.31-3:

For AMP B.2.3 1, under the program element "monitoring and trending," the LRA states that actual inspection locations will be based on physical accessibility, exposure levels, nondestructive examination techniques, and locations identified in NRC [Information Notice 97-46]. The NRC Information Notice was written relative to cracking that was detected in small bore unisolable high pressure injection piping at Oconee, Unit 2, which is a pressurized -water reactor (PWR). Justify your basis for using Oconee Unit 2 experience as being applicable operating experience for the SSES Small Bore Class 1 Piping Inspection Program and clarify how the information contained in NRC Information Notice 97-46 will be applied in selection process in order to ensure that the most susceptible small bore Class 1 piping locations to cracking (as a result of thermal and mechanical loading, or stress corrosion cracking) will be selected for the one-time inspection.

PPL Response:

The considerations in determining the inspection locations for AMP B.2.3 1, Small Bore Class 1 Piping Inspection, include operating experience and related industry guidance documents. Operating experience to date includes NRC Information Notice (IN) 97-46, which was issued to all holders of operating licenses or construction permits for nuclear power reactors (BWRs and PWRs). IN 97-46 states that a gap between a thermal sleeve and the associated safe-end allowed intermittent mixing of the hot reactor coolant and the

Enclosure to PLA-6391 Page 13 of 14 cooler makeup water flowing through the pipeline, resulting in alternate heating and cooling of the weld between the pipe and the safe-end. This phenomenon was a likely contributor to the fatigue cracking that occurred at the weld. PPL will consider the potential for piping locations to experience intermittent mixing between hot and cold flows in the sample selection of inspection locations for AMP B.2.31.

The SSES LRA is amended to state, more generally, that operating experience will be considered, without referencing a specific document such as IN 97-46. Attachment 3 contains the revised LRA sections.

RAI B.2.31-4:

In AMP B.2.3 1, under program element "Detection of Aging Effects," the LRA states that SSES has found cracking due to vibrational fatigue of small bore piping and is performing augmented inspections as part of the Inservice Inspection program. Identify the small bore piping components that experienced the vibrational-induced cracks and the augmented inspection techniques that resulted in the detection of the cracking in the piping components. Clarify whether or not PPL has taken appropriate corrective actions either to repair the flaw indications in the components or to replace the impacted components, and identify whether or not these components locations will be re-inspected in the future. If these components will be inspected in the future, identify the inspection technique and frequency that will be used, with justification, for the re-inspections of the components.

PPL Response:

SSES experienced nine socket weld failures (leaks) between 1992 and 2005. All of the leaks were on small bore piping attached to the Unit 2 reactor recirculation system. No socket weld failures have been experienced on Unit 1. All of the leaking welds were cut-out and replaced, or entirely eliminated by modification of the pipeline.

SSES Unit 2 Socket Weld Failure History:

3/1992 SPDBD222-1 Reactor Recirculation Pump 2A Seal Stage Flow Line 12/1993 SPHBD230-6 To Reactor Bldg Closed Cooling Water From Pump Seal & Cooler E401A 9/1995 SPDBD222-1 Reactor Recirculation Pump 2A Seal Stage Flow Line (Same weld from 3/1992) 10/1995 SPDCA250-1 Stem Leakoff for HV243F023B 3/1997 SPDCA251-2 Stem Leakoff for HV243F03 1B 9/1997 SPDCA251-2 Bonnet Vent for HV243F031B 12/1999 SPDCB220-1 From Reactor Recirculation Pump 2A Upper Seal Chamber To Penetration X52A

Enclosure to PLA-6391 Page 14 of 14 8/2000 SPDCB220-1 From Reactor Recirculation Pump 2A Upper Seal Chamber To Penetration X52A (Different weld than the failure in 12/1999) 3/2005 SPDCA251-2 Bonnet Vent for HV243F031B (Different weld than failure in 9/1997)

In response to the socket weld failures experienced at SSES and other plants, the SSES ISI group developed a shear wave ultrasonic (UT) inspection technique to volumetrically inspect socket welds. The shear wave UT is an augmented technique that has been used extensively during plant outages since 2000 to inspect welds that had been determined to be at-risk for vibrational fatigue due to their proximity to a vibration source (e.g., a recirculation pump). Crack-like indications were identified in 10%-15% of the inspected welds. The shear wave UT technique cannot definitively determine if an indication is a crack or a weld defect. For example, welding defects such as metallic and non-metallic inclusions, incomplete fusion, incomplete penetration and porosity are identified by the UT and are not discernible from actual crack indications.

While a weld defect may never result in a leaking crack, it does increase the potential for a fatigue failure if the weld is subjected to sufficient cyclic loading. As Such, PPL conservatively chose to replace all welds found to have crack-like indications as a proactive defense against future fatigue failures. Every weld with a crack-like indication was either cut-out and replaced or eliminated by a piping modification. Numerous modifications were made to replace socket-welded fittings with solid pipe (using pipe bends, instead of fittings) and to alter the natural frequency of the piping to avoid excitation by the vibration source. All new socket welds were made with the EPRI 2x 1 configuration to improve fatigue resistance. To date, none of the 2x 1 welds have resulted in a leaking crack at SSES.

The shear wave UT socket weld inspections described above were specifically requested by engineering to assist in the evaluation and resolution of the vibrational fatigue failures.

Those inspections were in addition to the periodic volumetric inspections that were already being performed under the Augmented Inservice Inspection (ISI) for Vibration Induced Failures (AUG8), which was implemented at SSES in 1992-1993. The scope of the augmented ISI program includes socket welds on small bore branch lines in the Reactor Recirculation and RHR systems inside containment with similar configurations to other lines that had experienced prior weld indications or failures. Subsets of those welds are inspected periodically during outages, dependent on radiological and access considerations. Welds that have been successfully inspected more than once are typically removed from the inspection scope.

Recent inspection results have indicated a substantial reduction in the number of indications. PPL is confident that vibrational fatigue on the subject piping welds has been successfully addressed. As such,.the necessity to continue volumetric inspections under the augmented ISI program is currently being evaluated.

to PLA-6391 LRA Revisions in Response to RAI B.2.23-1

Attachment 1 to PLA-6391 Page 1 of 10 The text in LRA Section 3.3.2.1.5 (on LRA page 3.3-10) is revised by addition (bold italics) as follows:

3.3.2.1.5 Control Structure HVAC Systems Aging Management Programs The following aging management programs manage the aging effects for the Control Structure HVAC Systems components/commodities:

" Bolting Integrity Program

• Closed Cooling Water Chemistry Program

• Cooling Units Inspection

• Fire Water System Program

" Selective Leaching Inspection

" System Walkdown Program

Attachment 1 to PLA-6391 Page 2 of 10 The text under Discussion in LRA Table 3.3.1 (on LRA page 3.3-64) is revised by addition (bold italics) as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report Item Component/Commodity Aging Aging Management Further Discussion Number Effect/Mechanis Programs Evaluation m Recommended 3.3.1-25 Copper alloy HVAC piping, Loss of material A plant-specific aging Yes, plant Except as noted, the System . -

piping components, piping due to pitting and management program specific Walkdown Program is credited to elements exposed to crevice corrosion is to be evaluated. manage loss of material for condensation (external) copper alloy components (HVAC and non-HVAC) that are exposed to condensation (external).

The Cooling Units Inspection is a one-time inspection that will detect and characterize loss of material for copper alloy HVAC heat exchanger components that are exposed to condensation (external).

The Selective Leaching Inspection is a one-time inspection that will detect and characterize loss of material due to selective leaching for HVAC and non-HVAC copper alloy components that are exposed to condensation (external). Note H is used.

Further evaluation is documented in Section 3.3.2.2.10.3.

Attachment 1 to PLA-6391 Page 3 of 10 The text under Discussion in LRA Table 3.3.1 (on LRA page 3.3-92) is revised by deletion (sti4keteuagh) as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report Item Component/Commodity Aging Aging Management Further Discussion Number Effect/Mechanis Programs Evaluation m Recommended 3.3.1-84 Copper alloy >15% Zn piping, Loss of material Selective Leaching of No Consistent with NUREG-1 801.

piping components, piping due to selective Materials elements, and heat exchanger leaching The Selective Leaching components exposed to raw Inspection is credited to manage water, treated water or closed loss of material due to selective cycle cooling water leaching for copper alloy >15%

Zn components that are exposed to raw water or treated water.

Fnr crb-in H\AC heat cXchagR cmpnnt, h Coo*irg Unit Inr',R-pectior, a GRe time insPectionR, i, crodited to detect and chracateriZc los66 Of material due to selectiVe

Attachment 1 to PLA-6391 Page 4 of 10

>, The text in LRA Table 3.3.2-5 (on LRA page 3.3-131) is revised by addition (bold italics)and deletion (stfikedhfeugh) as follows:

Table 3.3.2-5 Aging Management Review Results - Control Structure HVAC Systems Component Intended Aging Effect Aging NUREG-1801 Commodity Function Material Environment Requiring Management Volume 2 Table 1 Item Notes Management Programs Item Closed Cracking Cooling Water N/A N/A H Chemistry Program Closed Treated Water Loss of Cooling Water VII.C2-4 3.3.1-51 D, H&V Unit, (Internal) Material Chemistry Program _______ 0312 Control Structure Pressure Copper Alloy Loss of Selective (0E146A1/2 & Boundary (Red Brass) Material Leaching A OE146B1 /2) (selective Inspection VII.F1-9 3.3.1-84 E Channels leaching) ....... W ...

Loss of Cooling Units VII.Fl-16 3.3.1-25 E-Material Inspection Indoor Air Loss of (External) Material Sectv Leaching VII.F1-16 3.3.1-25 H (selective Inspection leaching) Inspection

Attachment 1 to PLA-6391 Page 5 of 10 The text in LRA Table 3.3.2-5 (on LRA page 3.3-132) is revised by addition (bold italics) and deletion (4)4kethfeugh as follows:

Table 3.3.2-5 Aging Management Review Results - Control Structure HVAC Systems Component Intended Aging Effect Aging NUREG-1801 Commodity Function Material Environment Requiring Management Volume 2 Table I Item Notes Comodty FuctonManagement Programs Item Closed Cracking Cooling Water N/A N/A H Chemistry Program Closed Treated Water Loss of Cooling Water VII.C2-4 3.3.1-51 D, Cooling Unit, Coolng Uit, (Internal) Material Chemistry 0312 Intenal)Program Control Room Selective Floor Pressure Copper Alloy Loss of Leaching (OEl51A1/2 & Boundary (Red Brass) Material Lecting A 0El51 B1/2) (selective Inspection VII.F1-9 3.3.1-84 E-Channels leaching)

Loss of Cooling Units VII.F1-16 3.3.1-25 E-Material Inspection 0337 Indoor Air Loss of (External) Material Sectv Leaching VII.F1-16 3.3.1-25 H (selective Inspection leaching) Inspectn I

Attachment 1 to PLA-6391 Page 6 of 10 The text in LRA Table 3.3.2-5 (on LRA page 3.3-134) is revised by addition (bold italics)and deletion ()tfikefettgh) as follows:

Table 3.3.2-5 Aging Management Review Results - Control Structure HVAC Systems Component Intended Aging Effect Aging NUREG-1801 Function Material Environment Requiring Management Volume 2 Table 1 Item Notes Commodity ComoitFncio ______Management Programs Item Closed Cracking Cooling Water N/A N/A H Chemistry Program Closed Treated Water Loss of Cooling Water VI1.C2-4 3.3.1-51 D, Material Chemistry 0312 Cooling Unit, (Internal) Program Computer Program Room Floor Pressure Copper Alloy Loss of Selective (OE15OA1/2 & Boundary (Red Brass) Material Leaching VII.F1-9 3.3.1-84A OE150B1/2) (selective U s Inspection E-leaching) Geel te Channels Loss of Cooling Units VIIF1-16 3.3.1-25E Material Inspection 333-7 Indoor Air Loss of (External) Material Sectv Leaching VII.F1-16 3.3.1-25 H (selective Inspection leaching) Inspection

Attachment 1 to PLA-6391 Page 7 of 10

) The text for the Plant-Specific Notes associated with the LRA Section 3.3 aging management review summary tables (on LRA page 3.3-349) is revised by addition (bold italics) and deletion (Stfiketolugh) as follows:

Plant-Specific Notes:

0337 1 Not Used. AMP also maRagec Iess of material due to ,eetVe leach*ng.

Attachment 1 to PLA-6391 Page 8 of 10 The text in LRA Table A-I (on LRA page A-43) is revised by addition (bold italics) and deletion (stfiketh,-eugh) as follows:

A.1.4 License Renewal Commitment List Table A-1 SSES License Renewal Commitments FSAR Enhancement Supplement or Commitment loca tion Item Number Location Implementation (LRA App. A) Schedule

25) Selective Program is a new one-time inspection. A. 1.2.43 Within the 10-Leaching The Selective Leaching Inspection detects and characterizes year period prior Inspection conditions to determine whether, and to what extent a loss of material to the period of due to selective leaching is occurring (or likely to occur) for extended susceptible components including piping and tubing, valve bodies, operation.

pump and turbocharger casings, heat exchanger, cooler, and chiller components, hydrants, sprinkler heads, strainers, level gauges, orifices, and heater sheaths. The components within the scope of the program are formed of cast iron, brass, bronze, and copper alloy materials. The components are subject to raw water, treated water, groundwater (buried), indoor air with condensation, outdoor air, and fuel oil environments. The components within the scope of this program are located in -wen~tyfive twenty-six different plant systems. -

Attachment 1 to PLA-6391 Page 9 of 10

) The text in LRA Section B.2.23 under the Scope of Program bullet (on LRA page B-73) is revised by deletion (stikethfettgh) as follows:

B.2.23 Cooling Units Inspection Aging Management Program Elements The results of an evaluation of each program element are provided below.

• Scope of Program The Cooling Units Inspection detects and characterizes conditions relative to the following to determine whether, and to what extent degradation is occurring:

- Loss of material due to crevice and pitting corrosion and selective leaching on the internal and external surfaces of the copper alloy (red brass) cooler channels in the Control Structure HVAC System.

Attachment 1 to PLA-6391 Page 10 of 10 The text in LRA Section B.2.29 under the Scope of Program bullet (on LRA page B-91) is revised by addition (bold italics) and deletion (otrikethfeag as follows:

B.2.29 Selective Leaching Inspection Aging Management Program Elements The results of an evaluation of each program element are provided below.

Scope of Program The Selective Leaching Inspection detects and characterizes conditions to determine whether, and to what extent, a loss of material due to selective leaching is occurring (or likely to occur) for susceptible components including piping and tubing, valve bodies, pump and turbocharger casings, heat exchanger, cooler, and chiller components, hydrants, sprinkler heads, strainers, level gauges, orifices, and heater sheaths. The components within the scope of the program are formed of cast iron or copper alloy (brass and bronze) materials. The components are subject to raw water, treated water, groundwater (buried), indoor air with condensation, outdoor air, and fuel oil environments. The components within the scope of this program are located in 25 26 plant systems within the scope of license renewal.

Attachment 2 to PLA-6391 LRA Revisions in Response to RAls B.2.26-1, B.2.26-2, and B.2.26-3

Attachment 2 to PLA-6391 Page 1 of 12 The text in LRA Section 3.1.2.1.3 (on LRA pages 3.1-6 and 3.1-7) is revised by addition (bold italics) and deletion (strikethfeugh) as follows:

3.1.2.1.3 Reactor Coolant System Pressure Boundary Aging Management Programs The following aging management programs manage the aging effects for the Reactor Coolant System Pressure Boundary components:

" Bolting Integrity Program

" BWR Stress Corrosion Cracking (SCC) Program

" BWR Water Chemistry Program

" Chemistry ProgramEffectiveness Inspection

" Closed Cooling Water (CCW) Chemistry Program

" Flow-Accelerated Corrosion (FAC) Program

" Inservice Inspection (ISI) Program

.*Main Steam RFlowA.9 RoPGtrictFr IRn*pection M Small Bore Class I Piping Inspection 0 System Walkdown Program

) The text in LRA Table 3.1.1 (on LRA pages 3.1-25, 32, and 33) and in LRA Table 3.1.2-3 (on LRA pages 3.1-75 and 76) is revised by addition (bold italics) and deletion (strikethrough) as follows:

Attachment 2 to PLA-6391 Page 2 of 12 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report Item Component/Commodity Aging Effect I Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.1.1-41 Stainless steel and nickel alloy Cracking due to BWR Stress Corrosion No Consistent with NUREG-1 801.

piping, piping components, and stress corrosion Cracking and Water piping elements greater than or cracking and Chemistry The BWR Stress Corrosion equal to 4 NPS; nozzle safe ends intergranular stress Cracking Program in conjunction and associated welds corrosion cracking with the BWR Water Chemistry Program is credited to manage cracking for stainless steel and nickel alloy safe ends and piping components (including MS flew eclements/ rostrictrcs aind valve bodies) equal to or greater than 4 inch NPS.

The combined programs are also credited to manage cracking of stainless steel pump casings and covers, and weld overlays.

Attachment 2 to PLA-6391 Page 3 of 12 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report Item Component/Commodity Aging Effect/ Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.1.1-55 Cast austenitic stainless steel Loss of fracture Inservice inspection No Consistent with NUREG-1801 Class 1 pump casings, and valve toughness due to (IWB, IWC, and IWD). with exceptions.

bodies and bonnets exposed to thermal aging Thermal aging reactor coolant >250oC (>482°F) em brittlement susceptibility screening The Inservice Inspection (ISI) is not necessary, Program is credited to manage inservice inspection loss of fracture toughness for requirements are CASS pump casings, pump sufficient for managing covers, thermal barriers, and these aging effects. valve bodies. The ISI Program ASME Code Case N-481 contains an exception.

also provides an alternative for pump Fnrr CASS val~ve hnrdir6 less-than casings. +I,- C-11 D-.- rl-RA'sin etoon, *in, irnant / -Ar

,-ernnof--n ^if 1' A QCC A +a fhi~~ t Tha aIFrIr-iu':W M.r8 tr or

& .J J. .=] ,IL .d J. J.

FJ~ULIU1 !6 Guruuite t9 uetebt 1-r ^f f-Mirt IL ..............

-r fn- -~n-e Jl ................

(n^

IIJI

/ these componcnts.

Note: Revised in response to RAI B.2.31-1, but also shown here for clarity

Attachment 2 to PLA-6391 Page 4 of 12 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report Item Component/Commodity Aging Effect Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.1.1-57 Cast austenitic stainless steel Loss of fracture Thermal Aging No Reduction of fracture toughness Class 1 piping, piping toughness due to Embrittlement of CASS for CASS main steam fl component, and piping elements thermal aging restrputOrs, pump casings, pump and control rod drive pressure embrittlement covers, thermal barriers, and housings exposed to reactor valve bodies, is addressed under coolant >250'C (>482 0 F) item 3.1.1-55.

Reduction of fracture toughness for CASS orificed fuel support pieces, control rod guide tube bases, jet pump assemblies, and core spray line sparger elbows is addressed under item 3.1.1-51.

SSES has no other Class 1 piping, piping components, piping elements, or control rod drive housings formed of CASS material.

Attachment 2 to PLA-6391 Page 5 of 12 Table 3.1.2-3 Aging Management Review Results - Reactor Coolant System Pressure Boundary ComponentI Intended [Aging Effect Aging NUREG-1801 Commodity I

_ _ _

Function

_ _ _ _

Material

_ _ I Environment

_ _ _ IManagement Requiring Management Programs Volume 2 Item Table 1 Item Notes BWR Water Chemistry Program Flow 4Rseeie Elements / Treated Water Loss of Restrictors, Throttling CASS IV.C1 -14 3.1.1-15 (External) Material Main Steam Chemistry Program Effectiveness Inspection T-IAAng- IV.C1-1i5 3~-44-§ A Fatigue RedU~tO-R E Mai-Steam Fa~tYF8 Fmlow~ Rcztricto -V-.G-1-34. 5 E-BWR-SGG GCacking 8WR Wate~ pIlcI-9 3.1.1-44 A Ghem~is#

Pfe§~a4:R

Attachment 2 to PLA-6391 Page 6 of 12 Table 3.1.2-3 Aging Management Review Results - Reactor Coolant System Pressure Boundary Intended Aging Effect Aging NUREG-1801 Component Table 1 Item Notes Function Material Environment Requiring Management Volume 2 Commodity Management Programs Item C

BWR Water Chemistry Flow Program Elements TaTreated Water Loss of Restrictors, Throttling Carbon Steel (External) Material Chemistry IV.A1-11 3.1.1-11 C Program Main Steam Effectiveness Inspection

......... L T--AO -,

!V.C!1i5 3.4-03 A

Attachment 2 to PLA-6391 Page 7 of 12

• The text in the LRA Appendix A Table of Contents (on LRA page A-3) is revised by addition (bold italics) and deletion (s4i4kedff-eigh) as follows:

TABLE OF CONTENTS A.0 Final Safety Analysis Report Supplement 4 A.1 Introduction 4 A.1.1 New FSAR Section 4 A.1.2 Aging Management Program and Activities 4 A.1.2.29 Lubricating Oil Inspection 15 A.1.2.30 Main Steam Flo,- Ro-,stric*,tr InspectionNot Used 15 A.1.2.31 Masonry Wall Program 15

• The text in LRA Section A.1.2.30 (on LRA page A-15) is revised by addition (bold italics) and deletion (strkethfeugh) as follows:

A.1.2.30 Main Steam Flow Restrictor In.*peetio.nNot Used The Main Steam Flow Restrictor Inspection detects and charactcrizs redu-ction Of fracGturo tou1ghness of the cast austonitic stainless stool (CASS) subco-GM POnRents of the m-ain steam flow restric-tor-s. The- inspection will detect cracking that is symptomaticG of reduction of fracture toughness. Reduction ot fracture toughness does not c*ue crackinRg, but the reduced toughness allows existing cracks to propagate at higher rates. This inspoction pro'.'ides direct e-Vidence as to whether, and to what extent, cracking has occurred or is likely to occur in the main steam f*o rest.*ictors.

The Main Steam Flow ReStrictor Inspection is a new one time inspection that will be implemented prior to the period of extended operation. The inspection actiViti.es will be conducted within the 10-year period prior to the period oe extended operation.

Attachment 2 to PLA-6391 Page 8 of 12 The text in LRA Table A-I (on LRA page A-40) is revised by addition (bold italics) and deletion (st-iket*eu*gh) as follows:

Table A-1 SSES License Renewal Commitments FSAR Enhancement Supplement or Item Number Commitment locat In Location Implementation (LRA App. A) Schedule 22)Mai Program Is a ne.ne.ti A.12.30 With the 10 Steam AG~e~teG yeaF pe~ied p~i RwThe

,RAstrt Main Steam Flew Restrictor

• InspectiOn is credited for, te the Pe~dE

,.,e,.,

managing, reductiof;*n Of fracture

-f Notf Used toughness, as e-idenced by cracingforthe m~ain steamA flow The text in LRA Appendix B Table of Contents (on LRA page B-3) is revised by addition (bold italics) and deletion (&H-kethleigh) as follows:

TABLE OF CONTENTS B.0 Aging Management Programs B.1 Introduction 4 B.2 Aging Management Programs 8 i de A m 13.2.26 maRn B.2.26 Steam Flow ~estFictGF I nspPectionvR !Used Usd8 81

Attachment 2 to PLA-6391 Page 9 of 12 The text in LRA Appendix B Table B-1 (on LRA page B-10) is revised by deletion (st4kethfeugh) as follows:

Table B-1 Correlation of NUREG-1801 and SSES Aging Management Programs Number NUREG-1801 Program Corresponding SSES Program XI.M32 One-Time Inspection

• Chemistry Program Effectiveness Inspection See Section B.2.22.

• Cooling Units Inspection See Section B.2.23.

e Heat Exchanger Inspection See Section B.2.24.

a Lubricating Oil Inspection See Section B.2.25.

• anSteam Flowý.A Ree;strfictoFlrInpection SoeSetion B.2.26.

The text in LRA Appendix B Table B-2 (on LRA page B-16) is revised by deletion (st*iket*fough) as follows:

Table B-2 Consistency of SSES Aging Management Programs with NUREG-1801 (continued)

Program New Consistent Exceptions Plant- Enhancement Name /Existing with NUREG- to NUREG- Specific Required 1801 1801 Steam New Y-es -

Res~tF-GtE

Attachment 2 to PLA-6391 Page 10 of 12 The text in LRA Section B.2.26 (on LRA pages B-81, 82, and 83) is revised by addition (bold italics) and deletion (st*ikethfeugh) as follows:

B.2.26 Main Steam Flow Restrctor'Inspection -t Used Proram Desri-;pte*n The purpos~e of the Main Steam Flow Restrictor InSPectionR is to detect and characterize reduction of fracture toughness of the cast au.steitiGc stainles9.,s steel (CASS) subcomRponents Of the-manteam flowM restrcos h npcinwl etcakn that is sympoaic f reductfion of fracture togns.Reductionn of frac-ture toughness6 does not cause8 cracking, but the reduc~ed toughness allows existing cracks to propagate at higher rates.

This inspection proVides direct evidence as to whether, and to what extent, cracking has occurred or is likely to occur in the main steam flow rostrictors. Implemnentation of the Main Steam Flov..' Re trictOr Inspection Will ensure that the flow~~ restriction fiunction of the subject restrictor-S ismanaie Rcnistent With the currenRt licensingO basis during the period Of extended operation.

The Main S-tea-m. Flowm~ Rqest4rictor Ins~pection is e n time inpcinthat Will bez Dimplemeted pFior to the period of extended opertion. The inspection activities will be conducted W..ithin the 10 year period prior to the period of extended operation.

T-he Main Steam FloW Restrictor Ins-pection is e n ieiseto for SSES that will be consistent With the 10 elements of an effective aging management program as descGribed in NUJREG 1801,Section XI.M32, "One Time Inspectio" Exceptions to NUREG-1801 NUREG-1801 Consistency The Main Steam Flow Restrictor Inspect*ion is6a new one time inspection for SSES that will be consistent With the 10 elements of an effective aging managemenRt programas decibdin NUREG 1801 S lAectionn XI N42 , "One-Time Inspectio.

Agn angmn PormEle~a ~ ments The results of an evaluation of each program element are provided below.

• Scope of Program The Main Steam Flow Restirctor Inspection is credited for managing reductiono fracture toughnessG, as evidenced by cracking, for the main steam flow reStricOrs 0 12Prvtzmtivr Ar-teinn

Attachment 2 to PLA-6391 Page 11 of 12 No actions are taken as padt of the Main Steam; Flow ReStrictor Inspection to prevent aging effecrts or to mitigate aging degradation.

tParameters Monitored or Inspected The parameters inspected by the Main Steam Flow Res~tFictor Inspection include visual evidence Of cracking. Visual examnination will be pe~foRmed by qualified personnel using established nondestructive examination (NDE) technique appropriate to the system/loc~ation being inspected.

.Detection of Aging E~ffects The Main Steam Flow ReStrictor Inspection will be applied to all eight (four per unit) instea floW

• rentritr**s at SSES. The Main Steam FlGw ReStFrGtOr INspectiGn use established vis ual nondestructive examnination (NDE=) techniques to detc roducton oIf fra;cIlture toughness as evidenced by cracking, and will be peGloRmld by qualified personnel. The inspection is consistent 'Mth the NURI G 1801 one;time i nspection recommnendations for detection of cracking. Due to the specific focus6 of this inspection, the other aging effects and inspectin methods in the NUREG 1801 one time inspectien are Rot applicable to this inpcto.

The Main Steamn Flow' RoStitr Inspection activities beWconducted M.9011-l after the issuance o~f the renewed licenses and prior to the end o~f the current operating licenses for SSES Unit I and Unit 2, wiMth s;ufficient time to implement programmatic oversight for the period of extended operation, if necessar,'. The activitiesq will be co~nducted no earliter th~an 10 years prior to the endo the crenoperating licenses, so that aging effects With long incubation periods have time to manifest.

MonitorFing and Trending No( actions; a:;rce takeAs'pa f the Main;O Steam Flew1. Rtestricutor Ins;pection to monitor andmir teRnd iRspection results. This is a one time inspection used to determine if, and to what e furher actions6, including monitoring and tFReding, may** ea mxent,

• Acceptance Critera The- acceptance criterionR forF the Main Stea4m FlowA'Restrictor InspectionR is: no cracking that ould ireut in a- loss-of compoM mentintended fuctioRn(s) during the peI of extended operatin, as determined by engineering evaluation.

GGCorective Actions This element is co-m..mon toA SSES proagrams and acti'.itieS that are credited with aging management during the period of extended operation and is-, disc.ussed in Sectio!BGR 3 This elnemet is cmmon to SSE=S proegrams and activities that are credited with agnmngement duqrig the period o-f extended operation a:nd- isdicuse in~~-,-qqtQ AgiA.nMistratinvge Cntrolg This element is-coA-m.mon to SSES programs; and acti'.itieS that are credited with aging mnanagement duFrig the pleriod o-f extended oper-ation and is-dfiscuse inr

Attachment 2 to PLA-6391 Page 12 of 12 Operating Experience The MaiN Steam Flew RestINctol Inspection is a nativity for

ý.A.,Iherch there is no operating exprec indicating the need for an aging mnagement programn. He wever, ehosae W consistent with accepted idsr Requir-ed Enhancements Nene.

Implementation of the Main Steam FloGw Restrictor Ins;pection will verify that there a;re no aging e~ffects requiring management for the 6ubject com;ponentsr wl detf appFrpriate Gorrective actions, possibly including proegammatic oversight, to be taken t ensure that the componenRt intended fuinction(s) Will be maitanedcosisten-Zt wiAgth t-he-current lcning bai dur...-ingte period o~f exAtendled- operation.

Attachment 3 to PLA-6391 LRA Revisions in Response to RAls B.2.31-1 and B.2.31-3

Attachment 3 to PLA-6391 Page 1 of 13 The text in LRA Section 3.1.2.2.2.1 (on LRA page 3.1-8) is revised by addition (bold italics) and deletion (stfkethfough) as follows:

3.1.2.2.2.1 BWR Top Head and Top Head Nozzles, PWR Steam Generator Shell Assembly The BWR Water Chemistry Program is supplemented by the Inservice Inspection (ISI)

Program for managing loss of material due to general, pitting, and crevice corrosion for the steel reactor vessel upper head and the top head nozzles exposed to reactor coolant. A one-time inspection is not credited.

The BWR Water Chemistry Program in association with the Chemistry Program Effectiveness lnspectionSmall Bore Class , Piping In.p8etion manages loss of material due to general, pitting, and crevice corrosion for steel piping and valves less than 4 inches exposed to reactor coolant. The Chemistry ProgramEffectiveness InspectionSmall Bore Class Piping , Inpection is a one-time inspection.

Loss of material for a steam generator shell assembly is only applicable to PWRs.

) The text in LRA Section 3.1.2.2.2.3 (on LRA page 3.1-9) is revised by addition (bold italics) and deletion (st-ikethie'&gh) as follows:

3.1.2.2.2.3 Flanges, Nozzles, Penetrations, Pressure Housings, Safe Ends, and Vessel Shells, Heads, and Welds The BWR Water Chemistry Program is supplemented by the Inservice Inspection (ISI)

Program for managing loss of material due to crevice and pitting corrosion for the steel reactor vessel upper head closure flange and shell closure flange with stainless steel cladding exposed to reactor coolant. A one-time inspection is not credited.

The BWR Water Chemistry Program alone is credited for managing loss of material due to crevice and pitting corrosion of the steel reactor vessel shell rings, ID attachments and welds, bottom head, nozzles, safe ends, and CRD stub tubes and housings with stainless steel cladding exposed to reactor coolant. A one-time inspection is not credited.

The BWR Water Chemistry Program in association with the Chemistry Program Effectiveness InspectionSmn-a Bo-re Class 1 Piping lnspeGtion or the Inservice Inspection (ISI) Program manages loss of material due to pitting and crevice corrosion for stainless steel components of the reactor coolant system (RCS) pressure boundary exposed to reactor coolant. The Chemistry ProgramEffectiveness Inspection*-aql Bo-re Class I PipiRg Is*npecti. n is a one-time inspection.

Attachment 3 to PLA-6391 Page 2 of 13 e The text in LRA Section 3.1.2.2.4.1 (on LRA page 3.1-10) is revised by addition (bold italics) and deletion (& iketlweuoh) as follows:

3.1.2.2.4.1 BWR Top Head Enclosure Vessel Flange Leak Detection Lines The reactor vessel flange leak detection line at SSES is a Class 1 line that is normally dry. The stainless steel line is evaluated for a treated water environment and is therefore susceptible to cracking due to stress corrosion cracking. This aging effect is managed with a combination of the BWR Water Chemistry Program and the Chemistry ProgramEffectiveness InspectionSmall Bore Class ! Piping Inspection.

> The text in LRA Section 3.1.2.2.8.1 (on LRA page 3.1-10) is revised by addition (bold italics) and deletion (strikethfe'gh) as follows:

3.1.2.2.8.1 Stainless Steel BWR Jet Pump Sensing Lines For SSES, the jet pump instrumentation lines inside the vessel are not subject to aging management review, as they do not perform an intended function. The lines outside of the vessel are part of the RCS pressure boundary and are subject to aging management review for a reactor coolant environment. Cracking of the stainless steel lines external to the vessel is managed with a combination of the BWR Water Chemistry Program and the Chemistry ProgramEffectiveness InspectionSmall Bore Class I PPing '....pe9.-,

> The text in LRA Table 3.1.1 (on LRA pages 3.1-16, 19, and 32) and in LRA Table 3.1.2-3 (on LRA pages 3.1-74, 76, 79, 80, 81, 88, 89, 90, and 92) is revised by addition (bold italics) and deletion (s4Fikethfeugh) as follows:

Attachment 3 to PLA-6391 Page 3 of 13 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report Item Component/Commodity Aging Effect / Aging Management Further Evaluation Discussion Number I Mechanism [Programs Recommended I 3.1.1-11 Steel top head enclosure Loss of material due Water Chemistry and Yes, detection of The BWR Water Chemistry (without cladding) top to general, pitting One-Time Inspection aging effects is to be Program in association with the head nozzles (vent, top and crevice corrosion evaluated Inservice Inspection (ISI) Program head spray or RCIC, and is credited to manage loss of spare) exposed to material for the reactor vessel reactor coolant upper head dome and closure flange, top head nozzles N6 and N7, and piping and valves >4 inches.

The BWR Water Chemistry Program alone is credited to manage loss of material for nozzles (except N6 and N7), safe ends, and flanges, and also for main steam flow elements. The BWR Water Chemistry Program in association with the Chemistry ProgramEffectiveness InspectionSmall Bore Clas* i PiPing lnspection is credited to manage loss of material for piping and valves < 4 inches.

Refer to Section 3.1.2.2.2.1 for further information.

Attachment 3 to PLA-6391 Page 4 of 13 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report Item Component/Commodity Aging Effect / Aging Management Further Evaluation Discussion Number I Mechanism I Programs Recommended I 3.1.1-15 Stainless steel; steel with Loss of material due Water Chemistry and Yes, detection of The BWR Water Chemistry nickelalloy or stainless to pitting and crevice One-Time Inspection aging effects is to be Program in association with the steel cladding; and corrosion evaluated Chemistry Program nickel-alloy reactor Effectiveness InspectionS&al1 coolant pressure Bore Class 1 P'ping InspectioR or boundary components the Inservice Inspection (ISI) exposed to reactor Program is credited to manage coolant loss of material for stainless steel components of the RCS pressure boundary.

This item is consistent with NUREG-1801 where the ChemistryProgram Effectiveness InspectionS4m4ai Bore Class 1 Piping Inspecio is credited. It is not consistent where the ISI Program is credited.

Refer to Section 3.1.2.2.2.3 for further information

Attachment 3 to PLA-6391 Page 5 of 13 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report Item Component/Commodity Aging Effect / Aging Management Further Evaluation Discussion Number [ Mechanism Programs [Recommended "

3.1.1-55 Cast austenitic stainless Loss of fracture Inservice inspection No Consistent with NUREG-1 801 steel Class 1 pump toughness due to (IWB, IWC, and with exceptions.

casings, and valve thermal aging IWD). Thermal aging bodies and bonnets em brittlement susceptibility The Inservice Inspection (ISI) exposed to reactor screening is not Program is credited to manage coolant >250'C (>482°F) necessary, inservice loss of fracture toughness for inspection CASS pump casings, pump requirements are covers, thermal barriers, and sufficient for valve bodies. The ISI Program managing these contains an exception.

aging effects. ASME Code Case N-481 For CASS va-ve bodies loss than also provides an 4 inc-h NIPS, the Small BoAre ls alternative for pump SPiping In*,pection is credited to casings. manaRge loes of fracture Main steamn flow elem~ents i floW restrictors formned of CASS arc Main Steam Fleo- Restrictor Inspectien is credited te detect loss Of fracture toughness fer these components.

Note: Revised in response to RAI B.2.26-2, but also shown here for clarity

Attachment 3 to PLA-6391 Page 6 of 13 T~ihIA ~1 2-~ Aninri M~n~n~m~nt RAviAW RA~.JIt~ - Rn~r~tnr CnnIz~nt 5~v~tnm PrA~~Iirn Rnund~rv Table 3 2-3

. .1 ................ . t- Reactor.................Pres............ . .......

- -

Component / Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Commodity Function Requiring Programs Volume 2 Management Item Condensing Pressure Stainless Treated Loss of BWR Water Chemistry IV.C1-14 3.1.1-15 A Chamber Boundary Steel Water Material Program 0W05 (Internal) Chemistry Program Effectiveness Inspection Small Bore Class 1 Piping Flow orifice Pressure Stainless Treated Loss of BWR Water Chemistry IV.C1 -14 3.1.1-15 A

< 4 in. Boundary Steel Water Material Program 0405 (Internal) Chemistry Program Effectiveness Inspection Small Bore Class 1 Piping Piping & Pressure Carbon Treated Loss of BWR Water Chemistry IV.A1-11 3.1.1-11 C Fittings Boundary Steel Water Material Program W05

< 4 in. (Internal) Chemistry Program Effectiveness Inspection SR-all Bore Clas- 1 PiPiRg 4W-PeGt-I GR Piping & Pressure Stainless Treated Loss of BWR Water Chemistry IV.C1-14 3.1.1-15 A Fittings Boundary Steel Water Material Program W05

< 4 in. (Internal) Chemistry Program Effectiveness Inspection Small BorFe Class 1 Piping Piping & Pressure Stainless Treated Loss of BWR Water Chemistry IV.C1-14 3.1.1-15 A Fittings Boundary Steel Water Material Program Flange leak (Internal) Chemistry Program detection Effectiveness Inspection lines Small B-re Class 1 PiPi*g

Attachment 3 to PLA-6391 Page 7 of 13 Table 3.1.2-3 Aging Management Review Results - Reactor Coolant System Pressure Boundary Component / Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Commodity Function Requiring Programs Volume 2 Management Item Valve bodies Pressure Carbon Treated Loss of BWR Water Chemistry IV.A1 -11 3.1.1-11 C

< 4 in. Boundary Steel Water Material Program 01105 (Internal) Chemistry Program Effectiveness Inspection Small Bore Glass 1 Piping Valve bodies Pressure Stainless Treated Loss of BWR Water Chemistry IV.C1-14 3.1.1-15 A

< 4 in. Boundary Steel Water Material Program 0405 (Internal) Chemistry Program Effectiveness Inspection Small Borc Cla66 1 Piping Valve bodies Pressure CASS Treated Loss of BWR Water Chemistry IV.C1-14 3.1.1-15 A

< 4 in. Boundary Water Material Program 0405 (Internal) Chemistry Program Effectiveness Inspection Small Borne C-lass 1 Piping Valvebe'e Presse GASS Treated Red-en of Small Bore Class 1 Piping I-1 3 1A -55 E-4 .... ,....Wat-e Fm*aetu-e

(!ReFnal) Tegns Plant-Specific Notes:

0105 Not Used. Serall ,NUREG 1801 Items call for the aging m ngement program of Water Chemisty CoGntro augmented by One Time Inspection. Here Water Chemistry Control is augmented by the Small Bor"e Cla.s 1 Piping Inspection, Which is"a One Time Inspection program for Class 1 small bore Piping. Therefore a note A (or C) wa- u.ed.

__________

Attachment 3 to PLA-6391 Page 8 of 13 The text in LRA Section A.1.2.44 (on LRA page A-19) is revised by addition (bold italics) and deletion (stikeleugh) as follows:

A.1.2.44 Small Bore Class 1 Piping Inspection The Small Bore Class!I Piping Ineto confirms tho offectiVeness of the BVA.R Watei Chemistr' Program in mitigating-loss of material and cracking for small bore Class 1 piping. it will also verify, by inspectio)ns forcracking, that reductionR of fracrtu1-re toughness due to thermal embittment requires noadditional aging managem8et fo small bore , Class piping. The Small Bore Class 1 Piping Inspection is a one-time inspection to detect cracking resulting from thermal and mechanicalloading or intergranularstress corrosion. The inspection will provide assurancethat either cracking of small bore Class I piping is not occurring or the cracking is insignificant,such that an aging management program (AMP) is not warranted.

The inspection will also confirm the effectiveness of the BWR Water Chemistry Programin mitigatingcracking due to intergranularstress corrosion. The Small Bore Class 1 Piping Inspection is applicable to small bore ASME Code Class 1 piping aRd-syrems less than 4 inches nominal pipe size (NPS 4), which includes pipes, fittings, and branch connections. The inspection provides additional ass-urance that either aging of small bore ASME Code Class I piping is n*t *occurring o that the aging is6 insignificant, such that an additional aging management proegram is; REA warranted.

The Small Bore Class 1 Piping Inspection is a new one-time inspection that will be implemented prior to the period of extended operation. The inspection activities will be conducted within the 10-year period prior to the period of extended operation.

Attachment 3 to PLA-6391 Page 9 of 13

> The text in LRA Table A-I (on LRA page A-44) is revised by addition (bold italics) and deletion (strikethfeugh) as follows:

Table A-1 SSES License Renewal Commitments Item Number Commitment FSAR Enhancement or Supplement Implementation Location Schedule (LRA App. A)

27) Small-Bore Program is a new one-time A. 1.2.44 Within the 10-year Class 1 Piping inspection. The SSES program period prior to the Inspection will include measures to verify period of extended that cracking ~aoeptabe operation.

deg~adatieF4 is not occurring in Class 1 small-bore piping, thereby validating the effectiveness of the Chemistry Program to mitigate cracking

_g-.reatedde a-ati., and confirming that no additional aging management programs are needed for the period of extended operation.

> The text in the Scope of Program discussion in LRA Section B.2.22 (on LRA page B-68) is revised by addition (bold italics) as follows:

B.2.22 Chemistry Program Effectiveness Inspection

- Scope of Program The scope of the Chemistry Program Effectiveness Inspection includes the internal surfaces of aluminum, copper alloy, carbon and low alloy steel, cast iron, and stainless steel components in the following license renewal systems that contain treated water, treated water that is closed cooling water, or fuel oil that is controlled by a SSES chemistry program:

Treated Water (BWR water) - Condensate Transfer and Storage, Containment and Suppression, Control Rod Drive Hydraulics, Core Spray, Feedwater, Fuel Pool Cooling and Cleanup, High Pressure Coolant Injection, Main Steam, Makeup Demineralizer, Makeup Transfer and Storage, Reactor Core Isolation Cooling, Reactor Nonnuclear Instrumentation, Reactor Recirculation (nonsafety-related instrument tubing/valve bodies), Reactor Vessel & Auxiliaries (nonsafety-related RPV level/backfill instrument tubing/valve bodies), Reactor CoolantSystem Pressure

Attachment 3 to PLA-6391 Page 10 of 13 Boundary, Reactor Water Cleanup, Refueling Water Transfer and Storage, Residual Heat Removal, Sampling (reactor area and post-accident sampling), and Standby Liquid Control systems.

The text in LRA Section B.2.31 (on LRA pages B-98, 99, and 100) is revised by addition (bold italics) and deletion (t,.kethf,,gh) as follows:

B.2.31 Small Bore Class I Piping Inspection Program Description The purpose of the Small Bore Class 1 Piping Inspection i, to confirm thePeetiveness of the E1WR WAateF Ghemistr,' Program in mitigating loso aeiland cracking-for small bore Class I piping. it will also verify, by inspections for cracking, that reduUotin of fracture toughness due to thermal emnbrittlement require noaddtional aging management for small bore Class 1 piping.- The Small Bore Class 1 Piping Inspection is a one-time inspection to detect cracking resulting from thermal and mechanicalloading or intergranularstress corrosion. The inspection will provide assurancethat either cracking of small bore Class I piping is not occurringor the cracking is insignificant,such that an aging management program (AMP) is not warranted. The inspection will also confirm the effectiveness of the BWR Water Chemistry Programin mitigating cracking due to intergranularstress corrosion.

This inspection is applicable to small bore ASME Code Class 1 piping and systems less than 4 inches nominal pipe size (NPS 4), which includes pipes, fittings, and branch connections. The ins.petion provides additinal assurance that either aging of small bore A.SME Code I Ii Class piping not occurring or that the agig Isuh that an additi-nal agin*

• manament pr.gram (AlMP) iso,,t warranted. This program is applicable only to plants that have not experienced cracking of ASME Code Class 1 small bore piping resulting from stress corrosion or thermal and mechanical loading.

Should evidence of significant crackingagiFg be revealed by a one-time inspection or previous operating experience, periodic inspection will be proposed, as managed by a plant specific AMP. SSES has found no cracking of small bore piping due to stress corrosion or thermal and mechanical loading.

The Small Bore Class 1 Piping Inspection is a new one-time inspection that will be implemented prior to the period of extended operation. The inspection activities will be conducted within the 10-year period prior to the period of extended operation.

NUREG-1801 Consistency The Small Bore Class 1 Piping Inspection is a new SSES one-time inspection that will be consistent with the 10 elements of an effective aging management inspection as described in NUREG-1801,Section XI.M35, "One-time Inspection of ASME Code Class 1 Small-Bore Piping."

Attachment 3 to PLA-6391 Page 1 of 13 Exceptions to NUREG-1801 None.

Aging Management Program Elements The results of an evaluation of each program element are provided below.

Scope of Program The SSES inspection will include measures to verify that cracking Uaneptabe degad is not occurring in Class 1 small bore piping, thereby validating the effectiveness of the BWR Water Chemistry Program to mitigate crackingagiRg Felat de AeiGand confirming that no additional aging management programs are needed for the period of extended operation. See Monitoring and Trending for a discussion of sample selection.

• Preventive Actions The SSES inspection will be an inspection and evaluation activity with no actions to prevent aging effects.

Parameters Monitored or Inspected The SSES inspection will include volumetric nondestructive examinations i, ,u

• olumetric tecn*iqus)- performed by qualified personnel following procedures consistent with Section XI of ASME Code and 10CFR50, Appendix B. The program may also include destructive examinations.

" Detection of Aging Effects SSES has not experienced cracking of small bore class 1 piping due to stress corrosion or thermal and mechanical loading; therefore, this inspection is appropriate.

This inspection will perform volumetric examinations on selected weld locations. SSES has found .. a.k.ig crack-like indicationsdue to vibrational fatigue of small bore piping and continues to inspect by has performed additionalinspections for vibrationalfatigue through augmentation of the SSES Inservice Inspection Program.

• Monitoring and Trending The SSES inspection will include a representative sample of the system population, and, where practical, will focus on the bounding orlead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin. Actual inspection locations will be based on physical accessibility, exposure levels, available non-destructive examination (NDE) techniques, and operating experience. lo-cGations identified in Nuclear Regulato,', Commissio;n (NRC)

Attachment 3 to PLA-6391 Page 12 of 13 Informt;io.n Noi 97_46. Nondestructive volumetric examinations (..

,(IN) .

Vol*ume...tric tehniqu1e *will be performed by qualified personnel following procedures that are consistent with Section Xl of ASME Code and 10 CFR 50, Appendix B.

Inspections already bejig performed by augmentation of the SSES Inservice Inspection Program for vibrational fatigue of small bore piping, will be factored into the sample determination for the Small Bore Class 1 Piping Inspection.

Unacceptable inspection findings will be evaluated by the SSES corrective action process. The SSES Small Bore Class 1 Piping Inspection will require an increased sample size in response to unacceptable inspection findings. Evaluation of indications may lead to the creation of a plant-specific AMP.

"Acceptance Criteria Indications detected during inspections will be evaluated in accordance with the ASME Code. The evaluation of indications will include determining the extent of condition and necessary expansion of samples.

"Corrective Actions This element is common to SSES programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B.1.3.

" Confirmation Process This element is common to SSES programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B.1.3.

" Administrative Controls This element is common to SSES programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B.1.3.

"Operating Experience The Small Bore Class 1 Piping Inspection is a new inspection for which there is no SSES specific operating experience. The evaluations and examinations to be performed by this inspection will use existing techniques with demonstrated capability and a proven industry record to detect cracking in piping weld and base metal.

Required Enhancements None.

Attachment 3 to PLA-6391 Page 13 of 13 Conclusion The Small Bore Class 1 Piping Inspection will provide assurancethat either cracking of small bore Class I piping is not occurring or the cracking is insignificant,such that an AMP is not warranted. verify that loss of material, cracking* du, to StreF coArrosion or thermia and MochanicOalloaig and cracking duo to roeductionn of fatr toughness are being efctiey mana.ged for the subjt piping. The Small Bore Class 1 Piping Inspection will require an increasedsample size in response to unacceptable inspection findings. Evaluation of indicationsmay lead to the creation of a plant-specific AMP to provide assurance that the aging effects rac-kinTg will be managed such that components subject to aging management review will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

The text in LRA Appendix C (on LRA page C-23) is revised by addition (bold italics) and deletion (stPFkethieugh) as follows:

LRA APPENDIX C RESPONSE TO BWRVIP APPLICANT ACTION ITEMS BWRVIP-74-A BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal (4) The staff is concerned that leakage The SSES reactor vessel flange leak around the reactor vessel seal rings could detection lines are in the scope of license accumulate in the VFLD lines, cause an renewal. See the scoping and screening increase in the concentration of results in the LRA for the Reactor Coolant contaminants and cause cracking in the System Pressure Boundary (piping and VFLD line. The BWRVIP-74 report does fittings, flange leak detection lines, Section not identify this component as within the 2.3.1.3 and Table 3.1.2-3). Refer to scope of the report. However, since the Section 3.1.2.2.4 of the LRA for further VFLD line is attached to the RPV and information, and also see item 3.1.1-19 in provides a pressure boundary function, LR Table 3.1.1. Cracking of these lines is applicants should identify any AMP for the mitigated by the BWR Water Chemistry VFLD line. Program, the effectiveness of which is verified by the Chemistry Program Effectiveness Inspection SmallBere Class I Piping Inspectin. These aging management programs are described in Appendix B of the LRA.