ML071500565

Response to NRC Requests for Additional Information Related to Wolf Creek Generating Station License Renewal Application

ML071500565
Person / Time
Site:	Wolf Creek
Issue date:	05/25/2007
From:	Garrett T Wolf Creek
To:	Document Control Desk, NRC/NRR/ADRO
References
ET 07-0020
Download: ML071500565 (129)

Text

WO"LF CREEK"NUCLEAR OPERATING CORPORATION Terry J. Garrett Vice President, Engineering May 25, 2007 ET 07-0020 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

Reference:

1) Letter ET 06-0038, dated September 27, 2006, from T. J. Garrett, WCNOC, to USNRC 2) Letter ET 07-0011, dated May 2, 2007, from T. J. Garrett, WCNOC, to USNRC 3) Letter ET 07-0016, dated May 10, 2007, from T. J. Garrett, WCNOC, to USNRC

Subject:

Docket No. 50-482: Response to NRC Requests for Additional Information Related to Wolf Creek Generating Station License Renewal Application Gentlemen:

Reference 1 provided Wolf Creek Nuclear Operating Corporation's (WCNOC) License Renewal Application (LRA) for the Wolf Creek Generating Station (WCGS). As part of the review for license renewal, the Nuclear Regulatory Commission (NRC) staff conducted two audits at WCGS. The LRA Aging Management Programs audit was performed during the week of March 26, 2007 and the Aging Management Reviews during the week of May 7, 2007.Enclosure 1 provides the question and answer database that was compiled during the audits. Each entry consists of a numbered question, reference to the applicable section of the LRA and the WCNOC response.Attachment I provides a comprehensive commitment list including all commitments made in response to References 1, 2, and 3. Six commitments made in Reference 1, numbers 3, 6, 15, 17 and 26, have been revised. Commitment number 22 has been deleted. Two additional commitments have been added.P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET ET 07-0020 Page 2 of 3 If you have any questions concerning this matter, please contact me at (620) 364-4084, or Mr. Kevin Moles at (620) 364-4126.Sincerely, ,-Terry J. Garrett TJG/rlt Attachment Enclosure cc: J. N. Donohew (NRC), w/a, w/e V. G. Gaddy (NRC), wla, w/e B. S. Mallett (NRC), w/a, w/e V. Rodriguez (NRC), w/a, w/e Senior Resident Inspector (NRC), w/a, w/e ET 07-0020 Page 3 of 3 STATE OF KANSAS COUNTY OF COFFEY))Terry J. Garrett, of lawful age, being first duly sworn upon oath says that he is Vice President Engineering of Wolf Creek Nuclear Operating Corporation; that he has read the foregoing document and knows the contents thereof; that he has executed the same for and on behalf of said Corporation with full power and authority to do so; and that the facts therein stated are true and correct to the best of his knowledge, information and belief.Vice ident Engineering SUBSCRIBED and sworn to before me CINDY NOVINGER STATE OFANSAS iMy Appt P. Exp.Expiration Date I /

Enclosure 1 to ET 07-0020 Wolf Creek AMP Audit Questions and Responses Wolf Creek AMR Audit Questions and Responses (114 Pages)

Wolf Creek AMP Audit Questions and Responses Quiostion No ILRA S,4@c JAudit Que tion .'1>i Final Respoflse

-AMPA001 B.2.1.22 What inspection techniques are to :The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting be utilized to detect degradations Components program uses visual inspection for detection of aging effects.such as cracking, hardening, and ,Visual inspections of internal surfaces of plant components will be loss of strength as stated in the performed during the conduct of periodic maintenance, predictive description of this AMP in the maintenance, surveillance testing and corrective maintenance.

License Renewal Application (LRA)? I Inspections will determine if cracking, loss of strength -hardening, or loss of material aging effects are occurring.

Stainless steel exposed to diesel exhaust will be inspected for cracking.

Other stainless steel components lin the scope of the Internal Inspection program do not meet the 1400 F threshold temperature for cracking.

HVAC flexible connectors will be inspected to ensure they are free from hardening

-loss of strength.Piping and piping components will be inspected for loss of material.

Loss iof strength -Hardening is only applicable to Elastomers in the HVAC!systems.

Physical manipulation during visual inspection of elastomers ,could be used to verify the absence of hardening or loss of strength.

The'AMP will provide procedural guidance and training required for personnel Iperforming visual inspections.

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ce---i i-Iteitobserved thTt of hashe program plan procedure will specify what, if any exclusions will exist credited the Inspection of Internal for small bore piping and ducting covered by the AMP. The program plan 1AMPAOO2 .B..2.1.22 AMPA3 B.2.1.6 Surfaces in Miscellaneous Piping procedure has not been completed, however, currently there is no preset and Ducting Components Program minimum piping or ducting size excluded from the program. Specific for inspection of internal surfaces of exclusions will depend upon many factors including constraints associated steel, brass and aluminum piping, with inspection equipment (e.g. borescope size). All piping and ductwork ducting and components.

What is currently in the scope of the program is identified, (see AMP applicability the minimum size of the piping and list). Piping currently in scope for the program is as small as W" though ducting covered under this AMP? most of the piping is 1," or greater. Ducting currently in scope for the Are there any special techniques program ranges in size from 10" to 45" and only includes carbon steel planned to. be used tO detect (non-galvanized) ductwork.

Visual Inspection is used exclusively for corrosion of the nonferrous detection of aging effects in ferrous and non-ferrous materials.

Visual materials?

inspection techniques utilized are the same regardless of whether the material is ferrous or non-ferrous, though industry experience will be utilized whenever possible to enhance detection of corrosion for._nonferrous materials.

The flow accelerated corrosion 1As indicated in NSAC 202L, Revision 3, the new revision of EPRI program described in the GALL guidelines incorporates lessons learned and improvements to detection, Report relies on EPRI guidelines modeling, and mitigation technologies that became available since provided in NSAC 202L, Revision 2. !Revision 2 was published.

The updated recommendations are intended to WCGS's Flow Accelerated Corrosion refine and enhance those of previous revisions without contradictions to Program is based on NSAC 202L, ensure continuity of existing plant FAC programs.[Revision.3.

Provide justificationsas

...........I Im;W 'QetoNo IIRA~ Sec T _ Aiiidt1etio 240Finial Resko, fns e to how the Revision 3 guidelines are either equivalent or more stringent than those in Revision 2.The WCGS FAC program takes exception to the following NUREG-1801 XI.M17 program elements based on using guidance of NSAC 202L, Revision 3 instead of Revision 2. The sections of NSAC 202L associated

!with these program elements were reviewed to show that Revision 3 iguidelines are equivalent to those in Revision 2: Element (1), Scoping of Program -The differences of section 4.2, Identifying Susceptible Systems, between Revision 2 and Revision 3 are mostly editorial.

The guidance of prioritizing the system for evaluation in section 4.2.3 of Revision 2 is addressed in section 4.9 of Revision 3 by applying safety factors in ranking the risks. Section 4.4, Selecting and Scheduling Components for Inspection, of Revision 2 was re-organized in Revision 3. Sample selection for modeled lines and non-modeled lines of Revision 2 was enhanced with more clarification and more details in Revision 3, Guidance for using plant experience and industry experience in selecting inspection locations were added in Revision 3. The basis for sample expansion was clarified in Revision 3.Instead of dividing into selection of initial inspection and follow-up inspections in Revision 2, the guidance in Revision 3 is provided for a given outage including the recommendations for locations of re-inspection.

It is more compatible to the schedule of the implementation of FAC program of the industry.Element (4), Detection of Aging Effects -Clarification of the inspection itechniques of UT and RT was added in section 4.5.1 of Revision 3. There jare no changes of the guidance for UT grid. Appendix B was added in Revision 3 to provide guidance for inspection of vessels and tanks. The guidance for inspection of small-bore piping in Appendix A of Revision 2 and 3 are essentially identical.

The guidance for inspection of valves, orifices, and equipment nozzles were enhanced in section 4.5.2 of Revision 3. Also, section 4.5.4 was added for use of RT to inspect large-bore piping, section 4.5.5 for inspection of turbine cross-around piping,..............

..-and section 4.5.6 for inspection of valves.Describe situations which Wolf Creek uses the guidance provided in EPRI NSAC 202L, demonstrate effectiveness of the "Recommendations for an Effective Flow-Accelerated Corrosion Flow Accelerated Corrosion Program Program", which is utilized throughout the industry.

This document has at WCGS. Include actual data (i.e., proven to provide input to effective programs.

In addition, the components measured wall thickness, nominal that are replaced in the Wolf Creek FAC program are normally replaced pipe thickness, minimum acceptable 1with FAC-resistant material; no failures have been identified with the FAC-thickness, etc.) and details of the !resistant material.___corrective actions taken when I In August 1999, the Callaway pipe break occurred.

Using our program, 1AMPA004 iB.2.1.6 2 IQuestion Nob I (tIRA S~q [ :Audit Questiqn I F~inal Res popse, 'degradation or wall thinning was within the same month we inspected the identical location at Wolf Creek.observed during flow accelerated Wall thinning was identified; the affected piping was replaced like-for-like corrosion inspections.

Describe how two days later. Additional inspections were added to the next refueling'effective were these corrective outage (RF 11) inspection scope as a result of finding wall thinning.

The f;*.n in lirnin.I C r + I~rlin Cnir ninhn I; ., rnlI A ;+k k , -.h .In t nin in DC1I 0 O IaL IV O 1 VI II I "ati, "V WI I V LI lIVI the wall thinning problem.VI VL F v VII I ll WO I Vila I VU IVILII l l III 1 ,JIvy J III Il I" .. V-inspection of replaced chrome-moly pipe is scheduled. (Ref PIRs 1999-2958, 2000-2032)

Review of the work orders from 1995 showed that there has been no reported FAC-related leak or rupture at WCGS. Most of the work orders identified the degradation of wall thinning during the inspection by the FAC program. There was no case where the wall thickness was found tO violate the minimum acceptable thickness.

There were cases where the initial acceptable thickness determined in accordance with the program guidelines (

Reference:

Al 23H-002) were reached and more rigorous analyses were performed to justify continued service. Problems identified during implementation of the program activities were not significant and adequate corrective actions were taken to prevent recurrence.

For previous refueling outages RF13 and RF14, 75 to 80 locations of large-bore systems were selected for inspection, including 25-30 locations of initial inspection.

An inspection location included the subject component (such as an elbow) and its adjacent area (such as upstream and downstream piping). For small-bore systems, 40 to 50 inspections were selected for previous outages, including 20-30 locations of initial inspection.

The replacements for each outage are scheduled on proactive basis, determined by the projected remaining service life based on FAC analyses and by programmatic strategy based on industry experience and cost comparison to further inspections.

The selection of FAC-resistance material is chrome-moly alloy P22 (2.25% Cr and 1.00% Mo) for most of the replacements.

The improvements of the FAC program since its implementation are: tMPA005 B.2.1.6 1AMPAOO5 1B. 2.1.6 Clarify if there have been any modifications and/or improvements to the Flow Accelerated Corrosion

i. EPRI CHECWORKS software has been improved to better predict Program since its implementation.

wear.Describe the specific reasons (i.e., li. FAC Manager software was purchased about 3-4 years ago and is used lessons learned, operating to monitor (track, trend, and manage) inspection information.

experience, industry experience) for lii. NSAC 202L has been issued to provide program guidelines to the these modifications and/or industry to provide consistent effectiveness.

improvements.

Explain how these Iv. WCGS has increased participation in EPRI CHUG (CHECWORKS changes made the program more Users Group) to better review and respond to issues within the industry.effective with respect to the 3 N I Question.No

[LRA S.c I 1AMPAOO6 IB.2.1.6 Audi1t Qiilltlon management of aging,,_______

Explain how would the sample size be adjusted to address the detected degradation if the thickness measurements during flow accelerated corrosion inspection indicated degradation or wall thinning beyond the predicted~7 ~y ~K >Final Respons The guidance for expanded sample inspection is provided in the procedure Al 23H-002, Rev. 2, Section 6.5.8. The expanded sample should include, if not recently inspected, (1) any component within two pipe diameters downstream or within two pipe diameters upstream if the subject component is an expander or expanding elbow, B. 2.1.6 minimum wall thickness.

Actual wall 1(2) the two highest ranked components from the CHECWORK wear rate thickness data collected during flow !prediction from the train containing the piping component displaying the accelerated corrosion inspections significant wear, and should be available for review during (3) Corresponding components of similar geometry in sister train audit. displaying significant wear.If inspection of the expanded sample detects additional components with significant FAC wear, the sample should be further expanded to include components of the aforementioned items (1) and (2). If additional significant wear is detected, the sample expansion should continue per above until no additional components with significant wear are detected.Summaries of FAC Inspection Results for the following refueling outages lare provided in Section 2 of Program Evaluation Report (PER) for AMP I B2.1.6, FAC Program: (1) RF10 -WCNOC-126 (2) RF11 -WCNOC-147 (3) RF12 -WCNOC-152.. .................) F..... .............................................

(4) R F 13 -W C N O C -155 WCGS document Al 23H 002, The two logic steps are duplicate and identical actions. The second logic Revision 2, Page 34, "Guidelines for box is not needed.Implementation of the Flow Accelerated Corrosion Program," includes a flow diagram for the evaluation process. The diagram shows that if "Tmeas" is not greater than "Tminacc", there are two logic steps to follow which state "Generate WR to document nonconformance".

Please explain the purpose of these two steps and the difference between the two of them..........

No.20002032 s ta es: Ata )..,fe dw eo do ei.h.AMPA007 IAMPAOO8 B2 4 Question No I LRA Spc I Audit Question Final Response IQuesition Nod< \LRA Sec V Audit Question Fft~fl~espmii~

!detailed review of the CHECWORKS model predicted wear rates and estimating the as measured wear rates, significant discrepancies in the predicted vs measured wear rate results were identified." In similar PIR documents that predicted wear rates the actual wear was estimated at:-77% higher for the elbow on line AF 417 GBD 6-263% higher for the elbow on line AF 032 GBD 6 (a) Explain if the Flow Accelerated corrosion Program management team performed evaluation and root cause analyses to establish why the CHECWORKS predicted wear rates were different from the actual wear rates from the two cases quoted.(b) Explain if the modeling verified that similar problems did not exist at other locations.

Explain what corrective actions were taken to assure that the future predictions were realistic and consistent with the actual wear.PIR No. 1999 2958 documents that radiography inspections were performed on high pressure feed water piping as a result of a pipe break at another nuclear power plant. The PIR states: "Wall thickness measurements at the location were estimated between 0.100 to 0.120 inches (Nominal of 0.280 in.). The critical wall thickness based on hoop stresses had been calculated at 0.109 inch. The CHECWORKS predicted wear rates were different from the actual wear rate. The possible cause could be due to backing rings installed during construction.

Other locations were reviewed to verify consistency of the CHECWORKS results with the field-measured data, with no apparent deficiencies in the model identified.(b) An EPRI person was bought on site to review the FAC model in August-September of 1999. The objective of the review was to recommend additional inspection locations and to look for improvements to CHECWORKS FAC model. There were no major findings with the model that affect the predicted wear during the review. In 2006, Wolf Creek contracted CSI Technologies to upgrade to CHECWORKS version SFA 2.1 program, at that time the model was reviewed.

At that same time the system susceptibility evaluation and susceptible non-modeled components were revised.:(a) Critical wall thickness is not a standard term used. "Tmin acceptable" is the design minimum acceptable wall thickness of the component.

The method for determining the design minimum acceptable wall thickness of components inspected for wall thinning in the FAC Program shall be consistent with the ANSI B31.1, ASME Section III or VIII as applicable, Engineering Design Guides and Calculation procedure.

Refer to Al 23H-002 Section 6.6.(b) The line that failed was within the scope of the FAC program, but the subject location was not ranked to be inspected.

Other components within that line were inspected prior to the failure.AMPA009 B.2.1.6 5

-Quq.tion No -LRA Sec Question , -K-. -Final Res .o.. .identified piping was replaced." [c] The components with low thickness readings, including the 45-degree elbow, were replaced with like-for-like immediately (1999). During RF12 (a) Explain what is the definition of (2002) the line was replaced with chrome-moly pipe.critical wall thickness in the Flow Accelerated Corrosion Program. 1(d) This piping was installed as part of the original construction and was The estimated thickness value of 1 placed in service in 1984. Selected piping segments downstream of the 0.100 inch is less than the calculated

!control valve and the first elbow were inspected in RF4 -results were critical thickness reported in the PIR. acceptable.

Explain what is the significance of critical thickness in the In addition to the examination of the location equivalent to Callaway's implementation of this program. I rupture location, piping components potentially susceptible to similar type of degradation contributing to the Callaway failure were selected for (b) Clarify if the subject piping was additional inspections to detect any unexpected pipe wall thinning.part of the Flow Accelerated EPRIIWCGS joint effort evaluations were performed to identify the areas CorrosionProgram or if the lfor improvements to the CHECWORKS FAC prediction model.radiography was performed because I of the failure of similar piping at the IThe detail review of the CHECWORKS model was performed per PIR other nuclear plant. 2000-2032.

The results of the review are summarized in the response to I AMP Audit Question #AMPA008 (#B.2.1.6-6).

No apparent deficiencies in[c] Clarify if the affected piping was the model were identified.

replaced with piping made from the same material or with a corrosion The results of the inspections for additional locations and the resistant material.

The PIR talks recommended corrective actions are provided in PIR 2000-2032.

All about wall thinning at the extrados of subsequent inspections and/or replacements in the affected components the 45 degree elbow. Clarify if this are tracked/trended and implemented under the WCGS FAC program.fitting was also replaced.

The piping associated with the Callaway rupture has been replaced with I FAC resistant material.(d) Clarify how long was this piping in operation before the thickness loss was detected.

Clarify if this piping was inspected earlier; if yes, show the dates and the inspection result. Explain what were the results of the engineering evaluations as referenced in the PIR and the corrective actions taken.The operating experience described in LRA Section B.2.1.30, states that"One gasket degradation has been noted. The gasket was installed in 1989, exhibited an increasing leakae trend since 1993 and was AMPA010 B.2.1.30 The gasket being discussed is for equipment hatch ZX01. The gasket material is an elastomer known as EPDM (Ethylene Propylene Diene Monomer rubber). The manufacturer is Presray Corporation.

EPDM ,grade E-603 (ref: Work Package 111933, Bill of Materials).

The original and replacement gaskets were made of the same material.

The ZX01 Sequipment hatch is tested every refueling outa___ge.

The leakage 6 IQuestion No I, LRA Se~c I ~ Audit Ques~tion I Final ,Response I replaced in 1997." acceptance criteria for the equipment hatch seal is 4,200 sccm. LLRT data for equipment hatch ZX01 from 10/04/1997 failure date to present: AMPA011 B.2.1.30 Clarify which gasket is being discussed and what was the gasket material.

Clarify if the replacement gasket was of the same material.Clarify how frequently has the gasket been inspected after its replacement and show the inspection results.Explain if the containment leakage test program require a local leak rate testing after the maintenance work or repair activities are performed on the containment boundary components (i.e., isolation valves, penetration seals, gaskets etc.)Explain how are the "as found" leakage rates applied if they exceeded the administrative leakage limits.LLRT Date Component Leakage(sccm)

Error(sccm) 11/6/2006 ZX-01 20 3.7 5/11/2005 ZX-01 120 20 11/27/2003 ZX-01 0 4 04/23/2002 ZX-01 170 20 10/27/2000 ZX-01 0 4 05/03/1999 ZX-01 40 3.7 04/03/1999 ZX-01 20 3.7 11/20/1997 ZX-01 20 3.88 10/04/1997 ZX-01 6200 230 Type B & C as-found testing is performed prior to any repair, modification, or adjustment activity, if the activity would affect the penetration/valve leak tightness.

Type B & C as-left testing is performed after any repair, modification, or adjustment activity, if the activity would affect the penetration/valve leak tightness.

The as-found leakage rates, determined on a minimum pathway leakage rate basis, for all newly tested penetrations/valves is summed with the as-left minimum pathway leakage rate for all other penetrations and valves subject to Type B and C tests to calculate the overall Type B & C leakage rate. For Type B or C tests that are not acceptable, the testing frequency shall be set to the initial test frequency (30 months or less). A cause determination in accordance with AP 28A-001, Performance Improvement Request shall be performed and corrective actions identified to eliminate the identified failure cause and prevent recurrence.

For the purpose of the Inservice Testing Program, which utilizes the Containment Leakage Rate Testing Program to satisfy category A isolation valve leakage test, a maximum allowable leakage rate of 10,000 sccm or the administrative limit, whichever is larger is specified for any single component/penetration.

If this maximum allowable leakage rate is exceeded, repair or replacement shall be initiated in accordance with AP 16C-005, MPAC Work Request.(ref: AP 29E-001, Program Plan for Containment Leakage Measurement, Section 6.2, 6.7.2, 6.8.4 & 6.8.6)........carfywhatare the testintealsfor_

Type A test interval frequency is every ten years. If Type A test iAMPA012 B.2.1.30 7

]Questionl Nol LRA Sec Question 4 FinalRes6ao. .Type A, B and C tests for the leak performance is unacceptable, the cause will be identified and corrective rate test program. Explain how is actions taken to restore satisfactory performance.

A subsequent Type A the test interval for the Type A test test must be performed within 48 months following the unsuccessful test.adjusted if the leakage rate testing If the subsequent test is successful, the frequency may be returned to 10 yields unacceptable results. years. (ref: WCGS-AMP-B2.1.30, Section 3.5 and 3.7)Type B & C are conducted at various intervals for the'many different penetrations depending upon various factors for individual containment isolation components.

These factors include past component performance, maintenance history, service environment, design and safety significance.

For penetrations that demonstrate acceptable performance, the Type B test interval can be extended to a maximum of 120 months. For containment isolation valves that demonstrate acceptable performance, the Type C test interval can be extended to a maximum of 60 months. Containment purge and vent valves are tested at a periodicity of not greater than 3 months. Current Type B & C test frequencies are shown below: 1 Description Component Frequency Personnel Air Lock (barrel) ZX-003,L003 RF Emergency Air Lock(barrel)

ZX-002,LOO1 RF Emergency Air Lock (door seal) ZX-02 RF Equipment Hatch ZX-001 ,L002 RF Ctmt Recirc Sump/RHR B Sample EJHV0024 3RF Ctmt Recirc Sump/RHR B Sample EJHV0026 3RF Ctmt Recirc Sump/RHR A Sample EJHV0023 3RF Ctmt Recirc Sump/RHR A Sample EJHV0025 3RF Fuel Transfer Tube Flange RF Loop B Seal Water Injection BBHV8351B 3RF Loop B Seal Water Injection BBV0148 3RF CVCS Letdown BGHV8152 3RF ICVCS Letdown BGHV8160 3RF Seal Water Return BGHV8100 3RF Seal Water Return BGHV8112 3RF Seal Water Return BGV0135 3RF RX Makeup Water BL8046 3RF RX Makeup Water BLHV8047 3RF RX Coolant Drain TK Discharge HBHV7136 3RF RX Coolant brain TK Discharge HBHV7176 3RF ESW To B & D Ctmt Coolers EFHV0032/EFHV0034 2RF ESW From B & D Ctmt Coolers EFHV0046/EFHV0050 RF -_Chane after RF17 8 Question No LRAk Sec. Audit Question1 Insrueinal Re Instrument Air Instrument Air Instrument Air Ctmt Sump Discharge Ctmt Sump Discharge ILRT Pressurization Line ISI Penetration Loop C Seal Water Injection Loop C Seal Water Injection Loop D Seal Water Injection Loop D Seal Water Injection Loop A Seal Water Injection Loop A Seal Water Injection Aux Steam Decon Aux Steam Decon RX Coolant Drain TK N2 Supply RX Coolant Drain TK N2 Supply Accumulator N2 Supply Accumulator N2 Supply ILRT PS (003-HBB-1")

ILRT PS (005-HBB-1")

Fuel Pool Cooling/Cleanup Supply Fuel Pool Cooling/Cleanup Supply Fuel Pool Cooling/Cleanup Return Fuel Pool Cooling/Cleanup Return Fuel Pool Cooling/Cleanup Skimmer Fuel Pool Cooling/Cleanup Skimmer H2 Analyzer Return H2 Analyzer Return CTMT Atmosphere Monitor Return CTMT Atmosphere Monitor Return RX Drain TK Sample RX Drain TK Sample Accumulator Fill From SI Accumulator Fill From SI Pressurizer Relief TK N2 Supply Pressurizer Relief TK N2 Supply Service Air Supply Service Air Supply Pressurizer Liquid Sample Pressurizer Liquid Sample Hydrogen Purge~sponse KAFV0029 KAV0218 KAV0204 LFFV0095 LFFV0096 Flange Flange BBHV8351C BBV0178 BBHV8351 D BBV0208 BBHV8351A BBV0118 HDVO016 HDV0017 HBHV7126 HBHV7150 EPHV8880 EPV0046 Flange Flange ECV0083 ECV0084 ECV0087 ECV0088 ECV0095 ECV0096 GSHV0008 GSHV0009 GSHV0038 GSHV0039 SJHV0131/SJHV0132 SJVo111 EMHV8888 EMV0006 BBHV8026 BBHV8027 KAV0039 KAV0118 SJHV0128 SJHV0129/SJHV0130 GSHV0020/GSHV0021 3RF 3RF 3RF 3RF 3RF 6RF 6RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 6 RF 6 RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 3RF 2RF 2RF 3RF 3RF RF 9 IueQtion No LRASec I Au dt Question F. FinalRes Roe -77 Fire Protection Fire Protection ISI Penetration Pressurizer Liquid Sample Pressurizer Liquid Sample ESW To A & C Ctmt Coolers ESW From A & C Ctmt Coolers CCW Supply CCW Supply CCW Return CCW Return CCW TB Return CCW TB Return Steam Generator Drain Steam Generator Drain CVCS Charging CVCS Charging ECCS Test ECCS Test RX Coolant Loop A Hot Leg Sample RX Coolant Loop A Hot Leg Sample Accumulator Liquid Sample Accumulator Liquid Sample H2 Analyzer Return H2 Analyzer Return CTMT Atmosphere Monitor Return CTMT Atmosphere Monitor Return Breathing Air Breathing Air H2 Analyzer Sample H2 Analyzer Sample H2 Analyzer Sample CTMT Atmosphere Monitor Sample CTMT Atmosphere Monitor Sample H2 Analyzer Sample H2 Analyzer Sample H2 Analyzer Sample CTMT Atmosphere Monitor Sample CTMT Atmosphere Monitor Sample Fiber Optics Shutdown Purge Exhaust ,Shutdown Purge Exhaust KCHV0253 RF KCV0478 2RF Flange 6RF SJHV0012 3RF SJHV0013 3RF EFHV0031/EFHV0033 3RF EFHV0045/EFHV0049 2RF EGHV0058/EGHV01 27 3RF EGV0204 3RF EGHV0059/EGHV0131 3RF EGHV0060/EGHV01 30 3RF EGHV0061/EGHV0133 3RF*EGHV0062/EGHV0132 3RF BMV0045 3RF BMV0046 3RF BG8381 3RF BGHV8105 3RF EMHV8871 3RF EMHV8964 3RF SJHV0005 3RF SJHV0006/SJHV0127 3RF SJHV0018 RF SJHV0019 3RF GSHV0017 3RF GSHV0018 3RF GSHV0033 3RF GSHV0034 3RF KBV0001 3RF KBV0002 3RF GSHV0003 3RF GSHV0004 3RF GSHV0005 3RF GSHV0036 3RF GSHV0037 3RF GSHV0012 3RF GSHV0013 3RF GSHV0014 3RF GSHV0031 3RF GSHV0032 3RF PEFO 6RF GTHZ0008 92 days GTHZ0009 92.days 10 I Queistion No I> L"A Sec I Audit Question-I ~ Final Reip0ns AMPA013 B.2.1.20 AMPA014 B.2.1.20 AMPA015 B.2.1.20 External Surfaces Monitoring Program is credited for aging management of elastomer seals and flex connectors for hardening and loss of strength.

The applicant referenced GALL AMP XI.M36 which is used to monitor external steel surfaces for loss of material and leakage by visual inspection.

Since the elastomers can deteriorate and loose strength without showing a change in the visual appearance, clarify what inspection techniques are used in the External Surfaces Monitoring Program .to detect hardening and loss of strength of elastomers.

iShutdown Purge Supply GTHZ006 92 days iShutdown Purge Supply GTHZ0007 92 days Mini Purge Exhaust GTHZ0011 92 days Mini Purge Exhaust GTHZ0012 92 days iMini Purge Supply GTHZ0024 92 days Mini Purge Supply GTHZ0005 92 days ISouth Electrical Penetrations PES 6RF!North Electrical Penetrations PEN ..... .. 6RF Visual inspections are the primary program method for detecting external corrosion or material aging degradation, such as cracking of elastomers I resulting from hardening or loss of strength.

Physical manipulation during the visual inspection can also be used to verify the absence of hardening or loss of strength for elastomers. (Element 4)The External Surfaces Monitoring iThere are forty-two heat exchanger tube side components that credit Program is credited for aging !External Surfaces Monitoring for aging management.

Thirty-eight of management of tube sides of several those components are heat exchanger heads (e.g. Hx Nos 131,142, 145, heat exchangers (e.g., HX Nos. 131, j& 148) that are described as heat exchanger tube side components only 142, 145 and 148). Clarify what type because they contain the tube side fluid. The heat exchanger heads are of heat exchangers are these. exposed to plant indoor air externally.

The other four components are Clarify if the tube bundles are containment cooler manifolds that are described as heat exchanger tube exposed to the indoor air such that side components only because they contain the tube side fluid. The they are accessible for surface containment cooler manifolds are exposed to plant indoor air externally.

inspections.

Clarify if there are any components covered by the External Surfaces Monitoring Program that are not accessible during both plant!The tube bundles related to these forty-two components are not exposed Ito plant indoor air and are not managed by the External Surfaces.1M-on1 t _rin .P r 'og ram .-.........

.... ....... .. .............

_ ------....

.. ....!There are no components that have been specifically identified as being inaccessible during both plant operations and refueling outages, however, tthe External Surfaces Monitoring Program has provisions for any such cases. (The External Surfaces Monitoring Program has not been credited I1 I'Questibn No RA!Sec .Audit Qi* i n a I Rq'-§""estFnal R 6 7ýAMPA016 B.2.1.20 operations and refueling outages. If yes, explain how the applicant will ensure proper inspection of these components.

Also, discuss how the components covered by insulation are inspected under this AMP.PIR No. 20032733 reports a condition where the essential service water supply piping to the motor driven auxiliary feedwater pump B had not been coated after its linstallation and external corrosion was evident on the welds, heat affected zones, and valve EF V362.Clarify if the corrosion observed was!severe enough to warrant evaluation

!of wall thinning.

Describe what corrective actions were taken to assure that similar problems were avoided in the future.The External Surfaces Monitoring for any components that are either submerged or encased in concrete.)

Components that are inaccessible during both plant operations and refueling outages are evaluated to ensure that they have been/will be inspected at frequencies that provide reasonable assurance that the effects of aging will be managed such that the applicable intended functions will be maintained during the period of extended operation.(Element 4).The program provides clarification for areas, or portions of systems or components, that are difficult to access or are exempted from walkdown inspections based on physical (insulated, shielded, etc.) or environmental constraints (radiation levels, etc.). Exempted areas, or exempted portions of systems or components are to be documented on the walkdown inspection checklist, and an evaluation performed to determine that prior to the next refueling cycle, there is reasonable assurance that the effects of aging are managed such that applicable components will perform their intended function (Element 1).The corrosion was evaluated as minor surface rust. No additional evaluation was undertaken.

The components were determined to have been on the maintenance backlog for the coating. The components were prepped and coated; no further corrective actions were taken.WO 01-224361-000 Pipe Flange bolts need to be checked and at least one replaced due to rust. It appears that the bolts are rusted due to leakage or condensation.

The flange gasket is not leaking at this time. This was written up in 1997, WR#97-126320-002, but it has either rusted again since, or was not replaced at that time.AMPA017 B.2.1.20 I Program operating experience discusses several work orders. The problem descriptions included in WO 01 224361 000, WO 01 226813 000, WO 95 107292 000, WO 98 129513 001, and WO 99 208339 000 are incomplete.

Provide the complete WO 01-226813-000 problem descriptions for these work IA ESW outlet line EF-223-HBC-30 downstream of EFV108 near the wall orders. !penetration, the exterior coating has failed and surface rust is evident.. ..The/loose paint and exterior corrosion should be removed from the pipe 12 MQustion NoýAMPA0 8-sec Audit Question I .Final Response land QC should perform a visual examination prior to application of the coating. Note to QC: UT Activity number 03101 grid markings will be impacted by this activity.iWO 95-107292-000 B.2.1.4.Explain how the vessel head is inspected for evidence of boric acid.Screen requires refurbishment due to corrosion of steel parts. Removal of screen from well is needed. Reference eng dispo 04410-92, rev 0 and rev 1 by Sathi (11-10-95) fef01b WO 98-129513-00 1WS01 PA, Service Water Pump "A" needs packing adjustment to minimize leakage. Water spill in the pump house is degrading the supports for the heat trace panel and cable due to the standing water. Leak off piping needs replacement.

Fin Team -adjust the packing and make a new task to replace the piping and sent to Maintenance Shop.WO 99-208339-000 During the performance of STS MT-011 it was noted that the forward load pin and paddle on a PSA 1 snubber attached to hanger BM18-R513 has moderate to heavy rust build up. This should be cleaned so that it doesn't affect the spherical bearing. CWA notify Robin Rumas when the rust is removed so QC can complete STS MT-1 1.AMP B2.1.4 Element 4 states. that "locating small leaks" is identified

!through walkdowns of systems containing reactor coolant or treated borated water, formalized inspections of reactor coolant and treated borated water systems, and reactor coolant system leak rate monitoring.

AMP B2.1.4 Element 4 also identifies that reactor vessel head examinations are conducted as follows: -(1) Reactor coolant pressure boundary integrity walkdowns are performed 1 1by Level II or Level III VT-2 certified personnel using the examination techniques of QCP-20-520, Pressure Test Examination.

Attachment G of STN PE-040D documents reactor head inspection results. Any evidence that boron leakage from above vessel may have penetrated the mirror insulation SHALL require a head bare metal inspection for the potentially affected areas of the vessel head, and require cleanup of head and mirror insulation.

(2) Additional inspections that are NRC commitments for RPV closure head inspections have been implemented per NRC Order EA-03-009.

1 (See AMP B2.1.5, Nickel-AI

_ yPenetration Nozzles Welded to the Upper 13 iA,6 Qtin No I ec I Audit Q*uestio Fi nl Rl'*sponei AMPA019 B.2.1.4 AMPA020 B. 2.1.4 Vessel Closure Heads of PWRs). This includes bare metal visual examination of the head surface, performed every third refueling or five years, whichever occurs first. Attachment C of STN PE-40E documents reactor head examination results.Clarify if there are plans to replace !Wolf Creek has initiated a project to purchase a reactor vessel head the vessel head. forging as a risk management tool against the increasing world demand 1for ultra heavy forgings.

The decision to finish machining the forging and initiate a project to replace the existing reactor vessel head will be made at a later date.Discuss how the applicant

!Wolf Creek responses to the referenced NRC generic communications are responded to the NRC's orders and contained in the letters referenced below. Copies of the Wolf Creek letters bulletins listed below. Explain how are available on site for review or in ADAMS.these responses have been used to update the component list locations NRC Bulletin 2002-01 and visual inspections within the "Reactor Pressure Vessel Head Degradation and Reactor Coolant scope of the Boric Acid Corrosion Pressure Boundary Integrity" Program. 1. WCNOC Letter ET 02-0018 dated April 03, 2002 Response to NRC Bulletin 2002-01, "Reactor Pressure Vessel Head NRC Bulletin 2002-01, dated March Degradation and Reactor Coolant Pressure Boundary Integrity" 29 and May 16, 2002 2. WCNOC Letter ET 02-0021 dated May 16, 2002 NRC RAI on Bulletin 2002 01, 160 day response to NRC Bulletin 2002-01, "Reactor Pressure Vessel dated January 17, 2003 'Head Degradation and Reactor Coolant Pressure Boundary Integrity" 13. WCNOC Letter ET 03-0007 dated January 31, 2003 NRC Bulletin 2003-02, dated Response to Request for Additional Information for NRC Bulletin 2002-01, September 19, 2003 '"Reactor Pressure Vessel Head Degradation and Reactor Coolant NRC Order EA 03 009, dated !Pressure Boundary Integrity" March 3, April 11, and April 18, 2003 NRC Bulletin 2004-01, dated May 28, 2004 i NRC EA-03-009 1"Issuance of First Revised Order (EA-03-0009)

Establishing Interim inspection Requirements for Reactor Pressure Vessel Heads at'!Pressurized Water Reactors" 1. WCNOC Letter WM 04-0001 dated January 22, 2004 160 Day Report for NRC Order EA-03-009, "Issuance of First Revised Order (EA-03-0009)

Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors" 2. WCNOC Letter WM 04-0004 dated March 04, 2004 Response to NRC Order, "Issuance of First Revised Order (EA-03-0009)

Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors" 3. WCNOC Letter WM 06-0051 dated December 20, 2006 160-Day Report for NRC Order EA-03-009, "Issuance of First Revised 14 I Qvqstjpn Igo ILFRA Sec JAudit IQue4(iibn Fia RepnýOrder Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors"!4. Note: additional letters relative to the Wolf Creek relaxation request are noted in the response to question A057 NRC Bulletin 2003-02"Leakage from Reactor Pressure Vessel Lower Head Penetrations and reactor Pressure Boundary Integrity" 1. WCNOC Letter WM 03-0044 dated September 19, 2003 Response to NRC Bulletin 2003-02, "Leakage from Reactor Pressure Vessel Lower Head Penetrations and reactor Pressure Boundary Integrity" 2. WCNOC Letter WM 04-0002 dated January 22, 2004 160 day Report to NRC Bulletin 2003-02, "Leakage from Reactor Pressure Vessel Lower Head Penetrations and reactor Pressure Boundary Integrity" 3. NRC Letter 05-00051 dated January 20, 2005 Wolf Creek Generating Station -Response to NRC Bulletin 2003-02,"Leakage From Reactor Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity" NRC Bulletin 2004-01"Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at PWRs" 1. WCNOC Letter ET 05-0015 dated July 14, 2005 60 Day Report for NRC Bulletin 2004-01, "Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at PWRs 2. WCNOC Letter WO 04-0039 dated July 27, 2004 60 Day Response to NRC Bulletin 2004-01, "Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at PWRs" Changes to the Wolf Creek Boric Acid Corrosion Control Program as a result of the referenced NRC Generic Communications:

AP 16F-001 Boric Acid Corrosion Control Program Revision 2 was approved December18, 2000 -no change Revision 3 was approved May 5, 2005 and was a major revision that included the changes noted below.Revision 4 was approved October 14, 2005 (current revision -,no change)Revision 3 changes: 1. As part of this revision two additional AIs were prepared: 15

, Quesi No I LRA Sec I Audit iton I ..........

sponse-Al 16F-001 Evaluation of Boric Acid Leakage-Al 16F-002 Boric Acid Leakage Management

2. Section 6.0 was revised to identify the main elements (8) of the program and on a programmatic level, describe how the elements are to be fulfilled.

Revisions also described ties to other processes and procedures which are integral to the ability of the BACC Program to meet the objectives of the program.3. Attachment A was added to provide guidance on leakage 4. Attachment B was added to clarify/capture frequency of program inspections/examinations (references NRC Bulletin 2002-01 & NRC Order EA-03-009 inspections)

AMPA 021 B .2.1.7 STN PE-040D RCS Pressure Boundary Integrity Walkdown Revision 1 was approved July 17, 2001 -no change Revision 2 was approved May 22, 2003 is the current revision and includes the following changes: 1. Added new sections to examine the vessel safe-end nozzles, vessel sides and bottom penetrations.

j2. Added Attachment I for Reactor Vessel Loop Safe-Ends Inspection results and Attachment J for Reactor Vessel Sides and Bottom Head Inspection Results 3. Revised Attachment G, Containment

-Reactor Cavity Inspection Results to note that any evidence of boron leakage from above vessel may have penetrated the mirror insulation shall require a head bare metal inspection of the potentially affected areas.4. Attachment K added to identify components/locations containing Alloy 600 materials which have been shown to be susceptile to PWSCC.Clarify if WCGS has bolting expert in EPRI TR-1 04213 December 1995, Bolted Joint Maintenance

& Application accordance with EPRI Guide section 1.9 recommends providing an on-site bolting coordinator, recommendations.

empowered to implement a program to eliminate failures.

EPRI TR-104213 identifies a bolting coordinator as an individual who has the technical ability and authority to focus on both programmatic issues and day-to-day resolution of problems.

Wolf Creek mechanical design engineering provides the functions of the bolting coordinator consistent with guidance of EPRI TR-10421 3.Clarify if WCGS has ever purchased NRC Information Notice No. 89 59 and the supplements were reviewed for counterfeit bolting. Clarify if WCGS applicability.under the WCGS Industry Technical Information Program has a procedure to identify I(ITIP). It was concluded that WCGS did not have any fasteners supplied counterfeit bolting. Explain what has by the vendors listed in this Notice that had involvement in counterfeit WCGS done in response to NRC bolts/fasteners.

Information Notice No. 89 59, 1"Suppliers of Potentially_

Procedure AP 24D-003, "Receipt Inspections", AttachmentB, provides B.2.1.7 AM PA022 16 I Question N~o I LA.$epc~AMPA023 B. 2.1.7 IAudit Question iMisrepresented Fasteners." Describe the maintenance procedures used to check bolt torque and the uniformity of gasket compression.

Provide the frequenc for the maintenance activity.Clarify how many tubes are plugged in each steam generator.

I ~ Ffnall Respon -se!guidance to identify items that may be substandard, misrepresented, or Isupplied with fraudulent documentation.

If an item exhibits such indications, it directs to procedure AP 24H-003, "Commodity

!Discrepancies", for further investigations and corrective actions.In accordance with plant procedures on bolting installations, proper bolting!practice to provide leak tight pressure retaining joints includes pre-assembly inspection and cleaning requirements, use of specific bolting y Itorquing patterns, increased application of torque through multiple passes,:and verification of uniformity of the gasket compression.

Post-bolting ,inspections include verifying contact between the fastener and flange and 1 proper flange alignment.

Guidance for proper preload is provided with!desired torque values to ensure adequate gasket stress for leak tightness.

iProcedures used are: MPM M711Q-02, "Primary Manway Removal/Installation using HYDRA-TIGHT," Sections 7.6, 7.7, 7.8, 7.9." MPM M711Q-03, "Handhole Cover and Instrument Opening Cover Removal/Installation," Section 7.2., MPM M71 1Q-04, "Steam Generator Secondary Manway Removal/Installation," Section 7.2.* MPM M711Q-06, "Primary Manway Removal/Installation using NES/TENTEC," Sections 7.6, 7.7, 7.8, 7.9.i" MPM M712Q-04, "Reactor Coolant Pump Internal Replacement," Sections 7.10, 7.11, 7.12.S MPM M713Q-01, "Pressurizer Manway Cover Removal/Installation," Section 7.2.' MPM BB-001, "Pressurizer Code Safety Valve Removal and Installation,"'Section 7.3, and* MGM MOOP-08, "Torque Guideline for Bolted Connections," Section 7.0.3AMPA024 rB .2.1.8 These activities are performed when there are opportunities of removal and installation of the subject components for maintenance or scheduled inspections.

The following is the status of Steam Generator tube plugging at the completion of the fourteenth Steam Generator Tube Inspection completed during Refueling Outage 15 (October 2006).A Stearh Generator:

35 tubes plugged (0.62% total percentage plugged)B Steam Generator:

35 tubes plugged (0.62% total percentage plugged)C Steam Generator:

20 tubes plugged (0.36% total percentage plugged)D Steam Generator:

114 tubes plugged (2.03% total percentage plugged)..I Note: an additional 3 plugs are installed in A Steam Generator cold leg 17 I- Quac~tion No I I RA lqc A"~I$Aft 11*inn, I2 Piti Doe >~a I only, due to tube sheet drilling errors during manufacturing.

No tubes are installed in those locations.

Reference:

ET 07-0005 "Results of the Fourteenth Steam Generator Tube Ins The current economic model for the steam generators does not recommend replacement.

This model is updated as conditions change.Wolf C reek has no olans to reolace our steam aenerators, AMPA025 AMPA026 iAMPA027 B.2.1.8 N/A iN/A Discuss if WCGS has plans to replace the existing steam aenerators.

AMPA028 N/A AMPA029 N/A..M..A.3o. N/A Clarify which Regulatory Guide 1.54 USAR Appendix 3A states that WCGS is committed to Rev. 0 of RG 1.54 (i.e., Revision 0 or Revision 1) is as described in Table 6.1-2.WCGS committed to.{_-Clarify if coating inspections are WCGS did not credit NUREG-1801 XI.S8 for aging management.

performed at WCGS. If yes, explain what is the basis for these coating_ inspections.

W ______________________________

Explain what consideration does WCGS did not credit NUREG-1801 XI.S8 foraging management.

WCGS have for transport of coatings to the sump screens.....................

t .s m P s c e es1...........

.. ............

...............

........ ...........

............

..... .........................................

...........

....... ....... ... ....... .Clarify which aging management IWCGS did not credit NUREG-1 801 XI.S8 for aging management.

program will be used to manage the effects of aging of coatings during the period of extended operation.

ASME Code Section Xl, IWE 3510.2, Detailed visual examination acceptance criteria identifies the following"Visual Examination of Coated and Noncoated Areas," states that "Th4 condition of the inspected area is acceptable if there is no evidence damage or degradation which exceeds the visual acceptance criteria specified by the Owner." Explain what is the acceptance criteria for coated surfaces.1conditions as rejectable for coated surfaces: e -Cracking Flaking of I- Blistering I- Peeling Discoloration Deformation I- Other signs of distress 1All rejectable indications require initiation of an Non-Conformance Report (NCR) and evaluation in accordance with the WCGS corrective action process.d The materials included in the buried piping and tanks inspection program include steel, stainless steel, ductile iron and gray cast iron.d The following coatings are used: Stainless steel coatings:.

None e s Steel, ductile iron and gray cast iron coatings:

Coal tar enamel (pipe), _18 AMPA031 i 4 B. 2.1.18 Clarify which materials are include in the Buried Piping and Tanks Inspection Program. The LRA mentions steel, stainless steel, an ductile iron, clarify if there are any other materials.

Clarify which materials are coated and which an not. Explain what types of coating I" esitioribNo LRA Siec. Auditao Quetio Itie jRse AM PA032!B.2.1.18ýAMPA033 B.2.1.18!are used for each type of material.

Coal tar epoxy (steel tanks)Clarify if WCGS has buried tanks The emergency fuel oil storage tanks (carbon steel) are the only tanks in and, if so, what is the material of the scope of the buried piping and tanks inspection AMP..construction.

The LRA states that leaks have been In 1987 the Engineering Study for Galvanic Corrosion on Underground observed in buried piping. Clarify Piping at WCGS discovered corrosion on multiple runs of buried piping where these leaks have been that are in the scope of license renewal in the Fire Protection System and observed and what corrective the Auxiliary Feedwater System. The corrosion discovered in the Fire actions have been taken. Clarify Protection System piping was characterized as galvanic corrosion.

Pitting what is the current frequency of was found on carbon steel piping that was directly connected to ductile buried piping inspections, iron piping. The study postulated that the corrosion in the Auxiliary Feedwater System was either due to stray current from the Fuel Oil System or galvanic corrosion due to the carbon steel piping becoming a sacrificial anode.Since the completion of the 1987 study there have been four occurrences of leakage due to corrosion of the external surface of buried components at Wolf Creek. Three of these leaks occurred in buried portions of the non-essential Service Water System, which are not within the scope of license renewal. An additional leak was discovered in Fire Protection System (KC) outside the Diesel Generator Building in 1997. Subsequent excavation in 1998 discovered loss of material due to pitting corrosion.

ýThe Fire Protection System corrosion resulted from a break in the i protective coating.The Borated Refueling Water System and the Auxiliary Feedwater System have only short runs of pipe between pipe tunnels and buildings.

The 1987 Engineering Study provides the only known documentation of corrosion related failure in the Auxiliary Feedwater System. In this case pitting corrosion was discovered on excavated carbon steel piping. This section of piping was then replaced from the condensate storage tank to the power block. There have been no documented external corrosion related failures of the Borated Refueling Water System.The Emergency Fuel Oil System has only short runs of pipe from between the below grade fuel oil storage tank and the Diesel Generator Building.There have been no documented external corrosion related failures of the Emergency Fuel Oil System piping.The Essential Service Water System has multiple long runs of carbon steel piping. There are no documented external aging failures of the.buried Essential Service Water System piping.19 IQues~tiorn g Rjec J Audit Question Final Response AMPA034 B.2.1.19 Clarify if there are any socket welds identified as high safety significant locations as part of the RI ISI program. If so, clarify how many are there. The EPRI Topical report specifies that high safety significant locations be volumetrically examined.

Explain how socket welds will be examined if they are in a high safety significant location.Clarify if there have been any containment liner plate inspection results since 1996. If not, explain why. If yes, the results should be made available during the audit.MAMPA035 B.2 1.27 The Fire Protection System has four recorded discoveries of pitting corrosion, with two of these resulting in leakage. Three of these discoveries were made during the 1987 Engineering Study with one leakage among that group. The last recorded leakage occurred in 1997;outside of the Diesel Generator Building with pitting corrosion, due to a;break in the protective coating.WCGS has no current buried piping inspection procedures.

However,;work control procedures require evaluation/repair of degraded conditions that are discovered.

There are no socket welds identified as high safety significant locations as part of the RI ISI program.The following Owner's Activity Reports document the containment liner ,plate inspections since 1996.Containment Inservice Inspection Program First Interval, First Period 2002 Findings: There were no components containing flaws or relevant conditions that required an evaluation to determine acceptability for continued service._ There were no Class MC components that required repairs, replacements, or corrective measures for continued service.Containment Inservice Inspection Program First Interval, Second Period 2006 Findings:-A general visual exam found localized pitting in the liner floor of the incore tunnel sump.A detailed visual exam was performed to determine the magnitude and extent of degradation to the incore tunnel sump liner. Pitting was the only degradation found. It is believed that the pitting resulted from nearby welding, which damaged the coating. An evaluation performed by design lengineering determined that the remaining wall thickness is sufficient and that recoating the pitted area with a qualified coating will stop further 20 Questipn No L RA Sec { ~~Audit 0ue't66n AK Final Rikpipirse I ,degradation.

The pitted areas have been recoated with a qualified ,coating.

The incore tunnel sump liner was found to be acceptable for continued service, and the areas containing the pitting were identified for reexamination during the next inspection period.-The WCGS corrective action program addressed programmatic concerns.

Applicable procedures were reviewed and revised as necessary to ensure compliance with IWE requirements and to establish acceptance criteria for pitting of the containment liner plate.Containment Inservice Inspection Program First Interval, Third Period 2007 Findings: " There were no containment liner plate components containing flaws or relevant conditions that required an evaluation to determine acceptability

!for continued service.I- There were no repairs, replacements, or corrective measures performed ion any Class MC or CC items during the period of this report that were required due to an item containing a flaw or relevant condition that exceeded acceptance criteria.A detailed visual exam was performed to determine the magnitude and extent of degradation to the incore tunnel sump liner. Pitting was the only degradation found. It is believed that the pitting resulted from nearby welding, which damaged the coating. An evaluation performed by design engineering determined that the remaining -wall thickness is sufficient and that recoating the pitted area with a qualified coating will stop further degradation.

The pitted areas have been recoated with a qualified coating. The incore tunnel sump liner was found to be acceptable for continued service, and the areas containing the pitting were identified for reexamination during the next inspection period.The WCGS corrective action program addressed programmatic concerns.AMPA036 I B.2.1.27 AMPA037 B.2.1.28 IAMPAO38 IB.2.1.28!The ASME Section Xl, Subsection IWE Program operating experience describes degradation found in the in core instrument tunnel sump in 2002 and 2003. Discuss all preventive maintenance and corrective actions taken for each type of degradation found.The LRA and its commitment list references ASME Code Section Xl, 2003 Edition, which does not exist.Clarify this inconsistency.

The LRA states that in 2005, a 20-year tendon surveillance found some excessive grease void volumes.Explain in detail your surveillance Applicable procedures were reviewed and revised as necessary to ensure i compliance with IWE requirements and to establish acceptance criteria for pitting of the containment liner plate.LRA Section B2.1.28 and LRA Commitment number 15 for ASME Section Xl, Subsection IWL (RCMS 2006-212) will be amended to read, "ASME Code Section Xl, 2001 Edition with 2002 and 2003 addenda." During the twentieth year surveillance of the post-tensioning system, four tendons were found to accept greater than 10% of the tendon duct volume of grease when refilled after testing, with the highest being 17.4%.21 iLýVesthon No J LRA Sec 7I :;Auiidt Qdojftiý,n AM PA039 .B.2. 1.31 results and justify your conclusions.

Provide details on the operating experience relating to the degradation found in 2002-2003.

Explain how does this compare to the 1998 established baseline.Include the acceptance criteria for cracking, deterioration, missing anchor bolts, anchor bolts pop outs, and thepresence of water. Clarify if a scope expansion was required dui to unacceptable conditions identified Identify any additional inspections scheduled for the next inspection period..... ,-sppn-7 These conditions were evaluated by design engineering and found not to be significant conditions.

The apparent cause of these excess voids was determined to be an elevated initial filling temperature along with a short soak time, resulting in increased shrinkage.

Examination of the tendons found no deterioration.

The engineers also consulted a study conducted ,at Callaway Nuclear Station, addressing a similar condition with their unbonded tendons. The essential criterion for the operability of the sheathing filler material is to prevent corrosion of both the tendon wires and the anchorage components.

The material used at the Callaway Plant,;and at WCGS, accomplishes this by a characteristic which gives the filler material an affinity to adhere to steel surfaces, its ability to emulsify any moisture in the system nullifying its rusting ability, and by its resistance to moisture, mild acids, and alkalis. In addition, protection is afforded by each tendon wire being individually pre-coated prior to installation.

Therefore, no further action was recommended.

............

Based on the 1998 baseline inspections, several masonry walls in the Control Building and Turbine Building had aging effects classified as"Acceptable With Degradation." Subsequent inspections that took place between 2002 and 2003 are summarized as follows: A masonry wall in the control building had cracks visible on both sides.The cracks were repaired with grout, but the joint was moving enough to re-crack the repair. The wall is located in an area not subject to weather or a threat to water exposure.

Design engineering evaluated this condition e and determined that there had been no change in the described conditions

since the previous inspection, and the described condition is not indicative of any structural concern. This item was re-categorized as "Acceptable With Minor Degradation," and will be re-inspected during the next scheduled inspection.

Several masonry walls in the turbine building were observed to have minor cracks categorized as "Acceptable With Degradation." In most cases during the 5-year re-inspection, the conditions had stabilized from the baseline observation resulting in a downgraded category.

In the north wall of the southeast turbine building truck bay, a previous attempt had been made to repair the crack and was not accessible from the opposite side due to a building column. No leakage is involved that could lead to corrosion.

The latest inspection reveals that the length and size of crack continues to increase.

Design engineering has evaluated this wall and determined that it will still perform its intended functions..rAsuppotaingeattached to a masonry wall was found to be missing an 22 I Ques~tion No I L1RA Sec I , Audit Questioti F.SIina Response~anchor bolt. The angle supports the building's metal siding and is not a seismic support for the wall. This situation was evaluated by design engineering, who determined that no further action was required due to the redundancy of the design.Several pop outs around anchor bolts or through-bolts were identified.

All of these were determined to have occurred during construction, and not as 1 a result of aging. Design engineering evaluated all of the cases and Idetermined that the damage did not prevent any of the components from performing their intended functions.

None were found to have increased degradation during subsequent inspections.

No operating experience pertaining to the presence of water in masonry walls was found.No scope expansion was required.

All items that remain classified as"Acceptable with Degradation" will be inspected again during the next 1 inspection period. No cases of "Major degradation" were found.The WCGS Structures Monitoring Program identifies each structural component in-scope for license renewal and its inspection attributes.

All iconditions of degradation are identified, assessed, and categorized in Iaccordance with ACI 201.1R, and ACI 349.3R. Specific limits for each itype of degradation are provided in applicable WCGS procedures.

The 1 Structures Monitoring Program also specifies actions to be taken for each icategory of degradation.

These actions may include future monitoring, further assessment, or corrective action. For the two examples cited in the question, the affected areas have been cleaned and re-coated.

AMPA040 B.2.1.32 The Structures Monitoring Program operating experience describes that degradations were addressed (e.g., minor degradation, corrosion on a hanger in the essential service water system, corrosion on a steel column, ietc.) Discuss the above categories, the assessment performed, future monitoring recommended, and any corrective actions taken to prevent B.2.1.32 AMPA041 reoccurrences.........

Provide the following information (a)about the aging management of Groundwater monitoring tests conducted monthly at WCGS from June inaccessible concrete:

2005 to May 2006 show the groundwater and soil to have pH values between 7.0 and 8.7, chloride solutions ranging from 5.0 ppm to 41.2 ppm, (a) Submit the dates and results (at and sulfate solutions from 30 ppm to 717 ppm. These tests were specific locations, not averages or conducted at five different locations on-site.ranges) of all past groundwater monitoring tests. The sulfate concentration of 717 ppm was from a well located north of the circulating water screenhouse.

This well showed sulfate levels that were (b) Discuss why the groundwater is consistently higher than any other sample location.

There are no external non aggressive, and/or aggressive, if sources in the vicinity that could account for the elevated levels of sulfate applicable.

at that location.

Therefore, they are judged to exist as part of the natural......environment.

It should also be noted that the maximum level of sulfate 23

[Que~stion No> I RA Sec, [ Audit Question'1(c) Clarify if the Structures Monitoring Program will continue to perform the groundwater monitoring and inspect all inaccessible areas that may be exposed by excavation, whether the environment is considered aggressive or not.concentration of 717 ppm is less than half of the limit of 1500 ppm as specified in NUREG 1801, Item II.A1-4.(b)Question withdrawn by NRC.[c]The structures monitoring program will be enhanced to monitor 1groundwater for pH, sulfates, and chlorides.

Two samples of groundwater will be tested every five years.For inaccessible areas opportunistic inspections will be performed, if practical, whenever the area becomes accessible as a result of refueling (d) Clarify if the Structures Monitoring Program will inspect any inaccessible areas that are exposed ito the same environment which has caused significant concrete degradation in accessible areas. outages, power curtailments, maintenance activities, excavations, etc.(d)Evaluation of inaccessible areas provides justification for their adequacy, which might include site-specific characteristics, accessible areas subject to similar conditions, industry experience, industry guidance and previous inspections of similar areas. The responsible-in-charge engineer initiates activities necessary to enable an inspection of any inaccessible areas that the evaluation can not provide reasonable assurance that the inaccessible 1components would be able to continue to perform their intended functions.

LRA Sections A1.32 and B.2.1.32 and LRA commitment number 17 for Structures Monitoring Program (RCMS 2006-214) will be enhanced to monitor groundwater for pH, sulfates, and chlorides.

Two samples of__groundwater will be tested every five years.Provide detailed operating All concrete structures and components that are in-scope for license ,experience for the degradation found !renewal, and covered by the Structures Monitoring Program, are in 2002/2003.

Clarify if a scope I inspected and compared to acceptance criteria that are in accordance with lexpansion was required due to 1ACt 201.1R and ACl 349.3R. Specific limits for each type of degradation unacceptable conditions identified.

are provided in applicable WCGS procedures.

Identify any additional inspections scheduled for the next inspection During the five-year reinspection in 2002/2003, only four items were period. identified to have increased aging effects. Two of those items previously IAMPA042 B.2.1.32 categorized as "Acceptable with degradation" are not within the scope of license renewal. Two items that were previously categorized as"Acceptable with minor degradation" were noted to have increased aging effects and reclassified as "Acceptable with degradation".

One was corrosion on an ESW hanger in the communications corridor, and the other was corrosion on a steel column in the turbine building.24 I QupstionN~o4 LRA> Sec Audit Quest~ion

+77Final Resgonse Five new items categorized as "Acceptable with degradation" were reported during the 2002/2003 inspection.

Platforms and ladders in the Auxiliary Building require painting.

Grating in the Auxiliary Building has missing clips. Grating in the Diesel Generator Building has a loose clip.Structural steel in the Turbine Building has corrosioh.

These items have been corrected.

Flashing on a roof hatch in the Auxiliary Building is cracked. This item will be monitored for future changes in aging effects.No scope expansion was required.

All items that remain classified as"Acceptable with Degradation" will be inspected again during the next*inspection period. No cases of "Major degradation" were found.The Structures Monitoring Program includes all concrete components in astructures that are within the scope Of license renewal and within the scope of the structures monitoring program.IkAMPA043 B.2.1.32 AMPA044 B .2.1.32 Clarify if WCGS have any concr~beams, columns, and structure components (e.g., floor barriers, stairs, sumps, etc.) that are not currently identified in the Structu Monitoring Program. The curren program evaluation report for the Structures Monitoring Program is clear on this account.Explain why the Structures Monitoring Program does not ma reference to documents(s) or code(s) to be used as guidance conducting a concrete condition survey and to evaluate the existi safety related concrete structure Explain what is the baseline, the past, and the present survey rea (i.e, vertical movements) of the ultimate heat sink dam. Clarify v is the acceptance criteria and provide any operating experienc related to this dam.ýte res It s not ike for t The inspection methods, inspection frequency, and inspector qualifications are in accordance with WCGS procedures, which reference ACI 349.3R-196, ASCE 11-90, and ACI 201.1R-92.

AMPA045 B&2.1.33 LRA Appendix B Section B2.1.32, Program Description, will be amended ng to include the above statement.

S. " The UHS dam is a normally submerged seismic Category I earthen ding structure whose side slopes and crest are protected with riprap. The crest of the dam was surveyed before being covered with riprap. The baseline vhat survey of the settlement monuments was completed after construction and before filling of the cooling lake and the submergence of the UHS dam e within the cooling lake. The settlement monuments are anchored within the dam embankment and project above the riprap.Current dam elevations are determined by subtracting the as-built top .of monument elevation and as-built top of dam elevation from the current monument elevation.

The UHS dam elevation is required to be at or above elevation 1070 MSL.The baseline elevation for the crest of the dam was 1070.30 MSL. The a 25 I' %Q t N;Iijhi LR ASeci I < 'A4, it Qu4st6hnI Final~e~ s ,AMPA046 B.2.1.33 imost recent elevation was found to be 1070.24. The top of dam elevation!has always been acceptable.

AMPA047 The ultimate heat sink is currently Question withdrawn by NRC.using ACI 201.1R as a guide for conducting concrete condition surveys. The LRA does not mention how the condition of existing concrete structures will be evaluated.

Provide a description of these evaluations and its justifications.

The Water Control Structures The upstream main dam surface was repaired in 2001 near the water line Program operating experience with additional riprap due to the degradation and exposure of the sand and indicates that the main dam, service gravel riprap base at several locations.

The 2004 surveillance report and auxiliary spillways were noted that riprap slope protection was in good condition and the repair Irepaired.

Discuss when these 1work completed in 2001 has adequately corrected deficiencies noted in repairs occurred and why the repairs !the 1999 inspection.

The main dam is not in scope for license renewal as were made it is not relied upon to safely shut down the plant and is under the jurisdiction of the Kansas Department of Agriculture, Division of Water Resources.

B.2.1.33.A.I..A.048

.............. .B .2.1.1.....

.......1AMPA48 B2.1.The 1999 surveillance report discusses the condition of the service ,spillway.

Some popouts and spalling have occurred and are being 1 repaired as needed. The ogee crest was grouted prior to 1999 and some minor seepage is returning.

Emerging trees have been removed along the spillway channel between 1994 and 1999. The 2004 report stated that previous patching and grouting was holding up well. However, in 2006, it was found that the previous repairs at joints in the floor of the service spillway chute have numerous shrinkage cracks. Some of the repairs have broken loose exposing the original concrete.

A Work Order was generated to address this condition.

Some random cracking and spalling along the concrete auxiliary spillway have been noted several times. The cracks were evaluated in 1999 as not likely to indicate any serious deficiencies.

The approach and discharge Ichannels have had vegetation removed in the past and were reported clear of obstructions in the 2004 surveillance.

The LRA will be amended to incorporate changes to Sections A1.1 and B2.1.1 to remove reference to ASME code cases, RI-ISI, or alternatives required by 10CFR50.55a.

There will be one exception to NUREG 1801 as follows: Inh Section B2. 1.1 (ASMVE Section Xl Inservice Inspection, Subsections IWB, IWC and IWD), the LRA identifies six (6) exceptions to GALL[AMP XI.MI. These exceptions 26 I-Question No~ I LRA S§ec I Audit Quqstion~

I iFinal Rqisponse include use of specific ASME NUREG 1801 AMP XI.M1 specifies the use of ASME Section XI 2001 Section XI code cases, use of risk Edition with addenda 2002 and 2003. WCGS ASME Section XI ISI informed ISI, and use of alternatives Program uses ASME Code 1998 Edition through the 2000 addenda for the!required by 10CFR50.55a.

third 10 year inspection interval.

WCGS will use the ASME Code Edition Consistent with the provisions of 1OCFR50.55a during the period of The license renewal process has not extended operation.

included approval to use risk-informed ISI or approval to use (a) The above stated exception applies to NUREG 1801 Elements 1, 3, 4, specific ASME Section XI code 5, 6, and 7.cases.Please clarify why these items are included in the LRA description of the program.ý(b) The same exception statement applies to each of the NUREG 1801'Elements 1, 3, 4, 5, 6, and 7 as folows: NUREG 1801 AMP XI.M1 specifies the use of ASME Section Xl 2001 Edition with addenda 2002 and 2003. WCGS third interval ISI Program is using ASME Section Xl 1998 Edition through 2000 addenda. Use of the 1998 Code through 2000 addenda is consistent with provisions in 1OCFR50.55a to use the ASME Code in effect 12 months prior to the start of the inspection interval.

WCGS will use the ASME Code Edition consistent with the provisions of 1OCFR50.55a during the period of extended operation.

AMPA049 1B.21.1 LRA Table 3.1.1, item 3.1.1.16, The upper and lower steam generator shell to transition cone welds are states that, for Westinghouse Model part of the WCGS ISI program. The subject welds of one steam generator 44 and 51 steam generators, if are 100% UT examined per examination category C-A, Item C1.10. There general and pitting corrosion of the have been no rejectable indications identified in the UT inspections of the i shell is known to exist, additional upper and lower steam generator shell to transition cone welds.inspection procedures are to be developed.

LRA Section 3.1.2.2.2.4 WCGS is not aware of any industry operating experience that has states that "the steam generators at identified the presence of general or pitting corrosion of Westinghouse WCGS are Model F, so the Model F steam generators.

augmented inspection is not applicable." The GALL Report, Volume 2, Line IV.D1 12 states that"This issue is limited to Westinghouse Model 44 and 51 Steam Generators where a high stress region exists at the shell to transition cone weld." However, USAR Section 5.4.2.2 states that"the Model F steam generator is similar in configuration to the Modell 51 steam generator in Westinghouse i__27 I UUOStIOIV NO> [ LI ~eC 1~ Audit ~lUGStIOIV~

~Inar~espons~

I I Q40,%ýQlrl NO I LRe $qpIl Aucilt Qupstion Final Response I supplied plants." The operating experience described in the LRA does not include any discussion of WCGS steam generator inspection results.(a) Provide additional information about the recent inspection results for the Model F steam generators.

Address whether the inspection methods used would be able to detect general and pitting corrosion of the shell and whether any general or pitting corrosion of the shell has been found in the past.(b) Discuss any operating experience regarding the high stress region at the shell to transition cone weld that is mentioned in the GALL Report, Volume 2, Line IV.D1 12.[c] Discuss any industry operating experience found related to general or pitting corrosion of Westinghouse Model F steam qgenerators License renewal program evaluation report WCGS AMP B2.1.1 Rev. 1 describes the open items. However, the information seems to be incomplete.(a) Please review the document and determine whether some of the text is missing, or clarify the intention of the item as written.IAMPA050 8B2 1.1 (a) For clarification, the item refers to the initial issue of the WCGS document that specifies the ISI classification bases for the third WCGS ISI interval.

The document has not yet been issued.(b) There is only one open item.(b) The open item is numbered 1.Clarify if there are additional open items for this program.Si~nce use of specific ASME Section The LRA will be amended to incorporate changes to Section B2.1.3 to Xl code cases is approved under 10 remove reference to ASME code cases. There will be two exceptions to AMPA051 B.2.1.3 28 i

wj No A SecLPA Sec Audit Question I FiK 'Pni.-al e 2 >CFR 50.55a, not as part of the 10 NUREG 1801 as described below.CFR 50.54, please clarify why discussions of specific code cases are included in the LRA.First NUREG 1801 exception:

NUREG 1801 AMP XI.M1 specifies the use of ASME Section Xl 2001!Edition with addenda 2002 and 2003. WCGS ASME Section Xl ISI Program uses ASME Code 1998 Edition through the 2000 addenda for thei Ithird 10 year inspection interval.

WCGS will use the ASME Code Edition i consistent with the provisions of 1OCFR50.55a during the period of extended operation.(a) The above stated exception applies to NUREG 1801 Elements 1, 3, 4, 5, 6, and 7.(b) The same exception statement applies to each of the NUREG 1801 Elements 1, 3, 4, 5, 6, and 7 as follows: NUREG 1801 AMP XI.M1 specifies the use of ASME Section XI 2001 Edition with addenda 2002 and 2003. WCGS third interval ISI Program is using ASME Section XI 1998 Edition through 2000 addenda. Use of the 1998 Code through 2000 addenda is consistent with provisions in 10CFR50.55a to use the ASME Code in effect 12 months prior to the start lof the inspection interval.

WCGS will use the ASME Code Edition I consistent with the provisions of 1OCFR50.55a during the period of extended operation.

Second NUREG 1801 exception:

NUREG 1801,Section XI.M3 specifies the use of NRC Regulatory Guide 1.65, "Material and Inspections for Reactor Vessel Closure Studs" for reactor head closure studs and nuts. WCGS uses NRC Regulatory Guide 1.65 except (a) modified SA-540, Grade B-24 stud material is used, (b)stud bolting material was procured with a minimum yield strength of 130 ksi and a minimum tensile strength of 145 ksi, (c) volumetric inspection of!removed studs is performed per the ASME Section XI Code.(a) The above stated exception applies to NUREG 1801 Elements 1 and 7.(b) The same exception statement applies to NUREG 1801 Elements 1 and 7 as follows: NUREG 1801,Section XI.M3 specifies the use of NRC Regulatory Guide 1.65, "Material and Inspections for Reactor Vessel Closure Studs" for 29 1I QueistI67n N~o I LR~A $3c I~~ Audit Question ~j[ ~Final Response *., ___reactor head closure studs and nuts. WCGS is committed to Regulatory Guide 1.65 with three exceptions.

These are discussed in USAR Appendix 3A as follows: 1. Modified SA-540, Grade B-24 stud material is used -The use of this material is within the limitations discussed in Regulatory Guide 1.85, Materials Code Case Acceptability

2. Stud bolting material that does not exceed 170 ksi tensile strength is used -The closure stud bolting material is procured to a minimum yield strength of 130 ksi and a minimum tensile strength of 145 ksi. This strength level is compatible with the fracture toughness requirements of 1OCFR50, Appendix G (paragraph I.C), although higher strength level bolting materials are permitted.

Additional design considerations that permit visual and/or nondestructive inspection and prevent exposure to borated water also apply 3. Inservice Inspection of the reactor vessel closure studs is performed with the ASME Code 1998 Edition through the 2000 addenda for the third 10 year inspection interval.

Volumetric inspection of removed studs is[performed.

Copies of Certified Material Test Reports (CMTRs) are provided in the AMP Program Evaluation Report (PER) binder showing that the maximum tensile strength of the reactor closure studs and nuts is less than 170 ksi.There is no documented staff response to Wolf Creek letter WM 89-0015 dated January 18, 1989. There have been no Wolf Creek submittals amending letter WM 89-0015 dated January 18, 1989.AMPA052 B.2.1.3 iAMPA053 B.2.1.21 Provide additional information (e.g., results of testing on the actual WCGS stud and nut material)beyond the discussion provided in USAR Appendix 3A to substantiate that the maximum tensile strength of the reactor closure studs and nuts is less than 170 ksi.The GALL Report scope of the program description for AMP XI.M37 makes reference to "the licensee responses to Bulletin 88-09, as accepted by the staff in its closure letters on the Bulletin, and any amendments to the licensee responses as approved by the staff." A WCNOC response to NRC Bulletin 88-09 is provided in its letter WM 89-0015, dated January 18, 1989.Clarify if the letter dated January 18, 1989 is the response as accepted by the staff and if there have been any subsequent amendments to this 30 I Question No L ~RA Sqc ; , >AL4,4t Q4esi h FIinl Res ens.1AMPAO54 B.2.1.21 response.

Provide a copy of the staffs acceptance of the letter dated January 18, 1989, and any amendment, if applicable.

Supplemental Request: Provide documentation of NRC acceptance of WCNOC response to Bulletin 88-09.The NRC has accepted an action item to determine if a generic response was issued.The monitoring and trending of the Flux Thimble Tube Inspection Program license renewal program evaluation report states: "During each outage, all flux thimble tubes are inspected.

If the predicted wear (as a measure of percent through wall) for a given flux thimble tube is projected to exceed the established acceptance criteria prior to the next outage, corrective actions are taken to reposition, cap or replace the tube." However, WCNOC procedure RXE 03-006, "Incore Flux Thimble Wear Assessment," step 6.2.5, appears to implement a conditional eddy current testing.Describe the inspections discussed in the license renewal program evaluation report. Clarify if this is an inspection using eddy current tests performed during the outage.. Clarify the intention of step 6.2.5 in the procedure discussed above and whether this means that eddy current testing is conditional (i.e., based on predicted wear) rather than Derformed every outage.The Wolf Creek Flux Thimble Tube Inspection Program performs eddy current testing that is conditional (i.e., based on predicted wear). The Flux Thimble Tube Inspection Program calculates predicted wear and verifies that wear is acceptable for the next two subsequent refuel outages. The refueling at which eddy current testing will be required is determined and will be one refueling before the wear reaches 60% through wall for the thimble with the greatest projected wear. Wear Trending of thimble tubes is documented as well as projected wear (% through wall) at the next cycle. Any thimble with wear in an active location greater than 60%through wall or projected to be greater than 60% before the next outage should be repositioned.

Any thimbles with greater than 80% through wall or projected to be greater than 80% before the next outage are capped or equivalent and considered for future replacement.

LRA sections B2.1.21 and A1.21 will be amended to state: "During each outage, flux thimble tube wear is evaluated and inspections performed based on evaluation results." 31 QquetioPn No [L RA Seqc AuditQuestion F/ n PI I IResponse

_____1AMPA055 B.2.1.21 Provide the following documentation A copy of RXE 03-006 including Attachment A (Wolf Creek Flux Thimble during the audit: Wear Trending) that was completed during the October 2006 outage has been provided.examples of flux thimble wear trending data sheets (e.g., RXE 03-006. Attachment A)* representative Flux Thimble Tube Program problem identification reports, work orders, etc, completed during previous refueling outages.Supplemental Request: Provide additional detail (narrative) concerning data collected during RF15.Operating history summary.1AMPA056 B.2.1.5 The PWSCC in nickel alloy penetration nozzles in the upper reactor vessel head currently is categorized as with low susceptibility.

The revised NRC Order EA 03 009 requires that a bare metal visual examination meeting the requirements of IV.C.(5)(a) be performed every third refueling outage or every five years.In addition, it requires that a non visual NDE meeting the requirements of IV.C.(5)(b) be performed every four refueling outages or every seven years. The Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program operating experience provides a limited, somewhat indirect, discussion of the bare metal visual examination and no discussion of the non visual NDE.A bare metal visual examination of the top of the Reactor Vessel Closure Head meeting the requirements of IV.C.(5)(a) was performed during RF15 (October 2006). No evidence of leakage was found.With exception of Vessel Head Penetration nozzles 77 and 78, a non-visual NDE examination of the Nickel Alloy penetration nozzles of the Reactor Vessel Closure Head meeting the requirements of IV.C.(5)(b) was I performed during RF1 5 (October 2006). No indication of cracking was identified during the examination.

See the response to question AMP 1 A057 (B2.1.5-2) for the NRC staff authorized relaxation of the requirement for NDE inspections of VHP nozzles 77 and 78.32 I QuestionNo, I LRA Sec AMPA057 IB.2.1.5 Discuss the results of these examinations.

If they have not been performed, discuss the current schedule for each of these examinations.

WCNOC letter dated October 5, 2006, "Relaxation Request from the First Revised NRC Order EA 03 009 Regarding Requirements for Nondestructive Examination of Nozzles Below the J Groove," requested a contingency relaxation of examination requirements for reactor pressure vessel penetration nozzles 74, 75, 76, 77, and 78.Provide a discussion on the current istatus of this renuest and whether During Refueling Outage 15, Wolf Creek performed a nonvisual NDE of Nozzles 74, 75, and 76 that met First Revised NRC Order EA-03-009.

In NRC letter dated December 7, 2006, the NRC staff authorized relaxation of the requirement for NDE inspections of VHP nozzles 77 and 78 until inspection technology is developed to a state where the examination volume for the nozzles can be extended to be in full compliance with the order. The NRC staff safety evaluation found that Wolf Creek's proposed alternate inspection for VHP nozzles 77 and 78 to perform an ultrasonic examination from 2 inches above the highest point of the root of the J groove weld to the maximum extent practical, but not less than 0.30 inches below the toe of J-groove weld on the downhill side provides reasonable assurance of the structural integrity of the VHP nozzles.L Qu~stI6Wo t~tRA~&Final Respoiisi

,.AMPA058 B. 2.1.25 the contingency relaxation of The relaxation of the requirement for NDE inspections of VHP nozzles 77 examination requirements was Iand 78 is not an exception because NUREG-1801 XI.M11 A element 4 needed. If relaxation of examination (Detection of Aging Effects) states in part: "Any deviations from requirements was needed, discuss implementing the appropriate required inspection methods of the Order, whether this relaxation is an as amended, will be submitted for NRC review and approval in exception to the recommendations in accordance with the Order, as amended." NRC letter dated December 7, GALL AMP XI.M1 1A and justify the 2006 authorized relaxation of the requirement for NDE inspections of VHP exception.

nozzles 77 and 78.

Reference:

1. NRC incoming letter 06-00684, dated 12/07/2006

12. WCNOC letter ET 06-0035, dated 10/05/2006 The scope of GALL AMP XI.E2 The cables and connections associated with the in-scope High Range includes electrical cables and !Area Radiation Monitors (GTRE59, GTRE60) are subject to 10 CFR 50.49 connections (i.e., cable system) environmental requirements and therefore are not included in this aging used in circuits with sensitive, high management program. The EQ package for the High Range Area voltage, low level signals such as Radiation Monitors is EQWP J-361A. See Program Evaluation Report radiation monitoring and nuclear (PER) B2.1.25 Section 5.1.instrumentation that are subjected to aging management review. The scope of the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in _33 Question No L RA Sec .AuitWQ~uestion K~> < Final Response I iAMPAO59 AMPA060 B.2.1.25 B. 2.1.25 Instrumentation Circuits Program only includes the ex core neutron monitoring system. Explain why high radiation monitor cables and connections are not included in the scope of the program.Identify any other sensitive, high voltage, low level signal circuits in addition to ex core neutron monitoring system at WCGS.Explain why these circuits are not within the scope of this program.The following is a list of the equipment which uses coax cables that could have sensitive, high voltage, low level signal circuits in addition to ex core neutron monitoring system at WCGS High Range Area Radiation Monitors Containment Atmosphere Humidity Detectors Unit Vent Radiation Monitors Solid Radwaste System Radwaste Effluent Radiation Monitors Post Accident Sample System Sampling Panels Loose Parts Monitoring Solid Radwaste Spent Resin Primary Storage Tank Inlet Element and Control Station Balance of Plant Computer Public Address System (Intercom)

Plant Security System Equipment.

Generator Hydrogen & Carbon Dioxide System Miscellaneous Control Panels (Rad Cameras)In-Core Neutron Monitoring System Condensate Demineralizer System Acid Day Tank Level The cables and connections associated with the in-scope High Range Area Radiation Monitors (GTRE59, GTRE60) are subject to 10 CFR 50.49 environmental requirements and therefore are not included the NUREG 1801 XI.E2 aging management program.Containment Atmosphere Humidity Detectors, Unit Vent Radiation Monitors, Radwaste Effluent Radiation Monitors, Post Accident Sample System Sampling Panels, Loose Parts Monitoring, Solid Radwaste Spent Resin Primary Storage Tank Inlet Element and Control Station, Balance of Plant Computer, Public Address System (Intercom), Plant Security System Equipment, Generator Hydrogen & Carbon Dioxide Systefri, Miscellaneous Control Panels (Rad Cameras), In-Core Neutron Monitoring System, and Condensate Demineralizer System Acid Day Tank Level provide no license renewal intended functions and do not meet any_criterion found in 1OCFR54.4(a)(1 , 10CFR54.4(a)(2), or 10CFR54.4(a)(3)

GALL AMP XI.E2 states, in part, that The ex core neutron monitoring system cables are not disconnected 34 QuAestin No 1AMPA061 I LRA Sec I Audit aQultiono in cases where a calibration or surveillance program does not include the cabling system in the testing circuit, the applicant will perform cable system testing.Clarify if ex core neutron monitoring system cables are disconnected Finial Rq~sponse<

K7>during calibration surveillance.

Ref Procedures:

STS IC-431 "Channel Calibration NIS Source Range N-31" STS IC-432 "Channel Calibration NIS Source Range N-32" STS IC-440 "Channel Calibration NIS Intermediate Range and Power Range Detector High Voltage Plateaus" B.2.1.26 during calDration surveiiance.

IT they are, explain why testing of .these cables are not proposed.GALL AMP XI.E3 defines medium The only medium voltage cables that are from 2 kV to 35 kV at WCGS are voltage as voltage from 2 kV to 35 5 KV and 15 KV cables. The scope of this program includes all of the in-kV. The Inaccessible Medium scope inaccessible medium voltage cables at the WCGS.Voltage Cables Not Subject to 10 CFR 50.49 Environmental i Qualification Requirement Program I states that the in scope non EQ inaccessible medium voltage cables exposed to significant moisture simultaneously with significant voltage are 5 kV and 15 kV. Identify any inaccessible medium voltage cables that are from 2 kV to 35 kV.Explain why these cables are not subject to water tree aging effect and justify why they are not within the scope of the program. [ ....-- ..Clarify when the EPRI 102134,. P ressurized Water Reactor Secondary Water Chemistry Guideelines

-Revision 6, was implemented.

Revision 6 (EPRI 1008224) was incorporated in Revision 11 to the IAMPAO63 B.2.1.2 Follow Up Question B.2.1.2-1:

In response to the question on when EPRI 102134, Revision 6 was implemented, the response stated that EPRI 102134, Rev. 6 does not exist. However, EPRI 100824, Rev.6 replaced EPRI 102134 and was implemented on 10/11/2005.

The program description in the application, and in the ten-element evaluation, EPRI 102134, Rev. 6 is referenced.

Please clarify this Secondary Chemistry Control procedure (AP 02B-001) on 10/11/2005.

Response to Followup Question: In the LRA and in the 10-element review, where "EPRI 102134, Rev. 6", is used or referenced, it is incorrect.

The correct reference in the LRA and 10-element review should be "Revision 6 of the EPRI Pressurized Water Reactor Secondary Water Chemistry Guidelines" (1008224).

IThe Strategic Secondary Water Chemistry Plan, Rev. 2, was based on Rev 5 of the. EPRI Secondary Water Chemistry Guidelines (102134).

The Strategic Secondary Water Chemistry Plan, Rev. 3, was issued Mar. 13, 12007, and addresses Rev 6 of the EPRI Secondary Water Chemistry!Guidelines (1008224).

The LRA will be amended to reflect this 35

>Q uesti*in No LLRA Sec V Audit Qiies tibji F .~inal ResponseI

___discrepancy.

Furthermore, the Strategic Secondary Water Chemistry Plan -Rev 2 still addresses Rev. 5 of the EPRI guidelines, which we assume is EPRI 102134.Followup question for AMPA063 The GALL AMP XI.M2 "scope of program" program element states that water chemistry control is performed in accordance with the guidelines in (1) EPRI TR 105714, Revision 3, for primary water chemistry, (2) EPRI TR 102134, Revision 3, for secondary water chemistry, or (3) later revisions or updates of these reports as approved by the staff. The applicant's Water Chemistry Program description states that the program monitors and controls known detrimental contaminants lik chlorides, fluorides, and dissolved oxygen, by following the guidelines provided in EPRI TR 105714, Revision 5, for primary water chemistry and EPRI TR 102134, Revision 6, for secondary water chemistry.

The LRA claims consistency with the GALL Report.Justify why the LRA does not take an exception when WCGS is not using the EPRI revisions recommended in the GALL Report.Provide a comparison of the GALL AMP referenced revisions to the LRA referenced revisions and explain why the use of a later version is acceptable by verifying that none of the controlled information.

Response to Followup Question 2: The GALL wording in the question was taken from NUREG-1801, Rev. 0.The GALL (NUREG-1801, Rev. 1) AMP XI.M2 "scope of program" program element states that "water chemistry control is in accordance with industry guidelines such as... EPRI TR-105714 for primary water chemistry I in PWRs, and EPRI TR-102134 for secondary water chemistry in PWRs." No EPRI revisions are specified in the scope of program element, therefore, no exception was taken with respect to EPRI revisions.

The WCGS Water Chemistry Program is currently based on the EPRI PWR Primary Water Chemistry Guidelines, Rev. 5 and EPRI PWR Secondary Water Chemistry Guidelines, Rev. 6, with one exception as discussed in LRA B2.1.2.The following summarizes the key technical changes from Revision 5 to Revision 6 of the EPRI Secondary Water Chemistry Guidelines:

Guidance was added in Chapters 1, 5, and 6 to clearly indicate the elements of the Guidelines that are mandatory and "shall" requirements under NEI 03-08, and those that are recommendations.

The only mandatory requirement is to have a Strategic Water Chemistry Plan.e "Shall" requirements include the Action Level 1, 2, and 3 control parameters and responses and the hold parameters in the control tables of Chapter 5 and 6, including both values and monitoring frequencies for these parameters, unless otherwise specifically indicated.

The balance of the guidance elements provided in the Guidelines are recommendations.

Chapter 2 was revised to reflect recent research regarding specific impurity effects on IGA/SCC, the effects of hydrazine on flow accelerated corrosion, and regarding the effects of amines on secondary side deposition processes.

The treatment of deposit control practices was significantly modified in Chapter 3 to reflect current practices and currently available methods.Chapter 3 also contains an expanded discussion on thermal performance issues, and new sections on the loss of hydrazine scenario and startup oxidant control.The main discussion of integrated exposure was relocated from Appendix IA to Chapters 4 and 7, and the discussion was revised to reflect its_removal as a diagnostic parameter from Chapters 5 and 6. Chapter 4 was 36 QuestionNo6 .Sec K .. i i -Final Res onse .. K parameters are relaxed in the later also revised to include a list of items that should be covered in strategic version. water chemistry plans.Chapter 5 was revised to incorporate additional guidance regarding control of wet layup during short outages. The condition to which plants should go to as part of an Action Level 3 response was changed to "<5%power" from "hot or cold shutdown." The control tables for RSGs in Chapter 5 were thoroughly reviewed and edited. Some of the more significant changes to the tables were:* Inclusion of Action Level 2 and 3 actions for loss of hydrazine.

• Addition of a requirement that plants reduce power to below 5% if sodium, chloride, or sulfate exceed 250 ppb, or if they exceed 50 ppb for more than 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />, while between 5% and 30% power.* Reduction in the blowdown impurity level for sodium at the 30% hold from 20 to 10 ppb, and addition of an explicit recommendation that plants;achieve sodium, chloride, and sulfate blowdown concentration below their respective Action Level 1 concentrations prior to exceeding 30% power.* Additional guidance was added such that plants are no longer required to go to Action Level 3 as long as the impurity concentration remains below Action Level 2 values.* Deletion of integrated exposure as a diagnostic parameter, and inclusion of lead and integrated corrosion product transport as diagnostic parameters.

• Addition of a footnote to allow reduced frequency for sampling for copper for plants that are copper free or have confirmed low levels of copper transport

(<20 ppt).Chapter 6 -changes to Chapter 6 are not included as this refers to OTSGs and is not applicable to WCGS.Chapter 7 was revised to delete tables detailing sampling data requirements, to add more guidance regarding hideout returns, species to!analyze in deposits, and integrated exposure evaluations, and to add a new section regarding effectiveness assessments.

A discussion of lead sampling and additional recommendations on corrosion product transport lsampling was also added.37 Iu GetrionNo I L.RA Sec IAudi~t Qu~estion I Final Response -_AMPAO64 B. 2.1.2!Explain the intent of the exception in The exception is to taking three samples per week. As explained in the the element of scope of the program. evaluation, three samples per week are not necessary to demonstrate The exception states that WCGS is adequate mixing.meeting the requirements for mixing the steam generator bulk solution.

This exception has been taken against Element 1, Scope of Program, and Clarify if this exception is related to not against Element 3, Parameters Monitored or Inspected, although the mixing or to the three samples technically, the requirement the exception is taken against is contained in per week. Clarify if this exception is the EPRI Secondary Water Chemistry Guidelines, and not NUREG-1801.

also applicable to the parameters Imonitored or inspected program Follow up response: element. Clarify if this is an exception to GALL AMP XI.M2 Wolf Creek Generating Station has taken exception to the Guideline "The element of scope of the program or if steam generator bulk solution should be mixed and sampled three times it is an exception to the EPRI per week (after parameters are in the normal range) until the parameters 102314 guidelines.

are stable, then mixed and sampled weekly." This statement is found in'Section 5.5.1.2 of Revision 6 of the Guidelines as well as in Table 5-1.Follow-up Question B2.1.2-2:

What !This exception is documented in the Strategic Secondary Water Chemistry is the basis for this exception?

Do !plan. The exception was initially taken for Revision 5 of the Guidelines.

you have an analysis that states that a 33-hour recirculation of stem generators followed by weekly sampling is better than or equivalent to obtaining three samples per week until values are stable when in cold ,shutdown conditions?

The PIR operating experience report summary states that this PIR does not address any license renewal aging effect. Clarify this statement.

!For example, PIR 20030900;addresses/long standing anomalies This exception was taken based on operating experience/history.

Prior to initial fill of the steam Generators (SG) during plant construction, calculations were performed to determine the required recirculation time to achieve mixing of the bulk solution.

This calculation was based on the SG volume, flow-rate of the mix pumps, and recirculating three volumes of the bulk solution.

The result was that a 33 hour3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> recirculation time would thoroughly mix the bulk solution.The use of the 33 hour3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> mix time became standard practice.

Once in wet layup with chemicals added, SGs are mixed for 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> and then sampled to analyze for the desired chemical environment.

Recirculation and sampling are then done weekly in accordance with AP 02-002, Chemistry Surveillance Program. Experience has shown that once the SG bulk solution meets required specifications, it remains satisfactory.

If the parameters set forth in AP 02-003, Chemistry Specification Manual, ,are not met, adjustments aremade and the recirc/sampling is repeated...

Specific operating experience items were said to address a license renewal aging effect only when an explicit mention of the aging was made.None of these PIRs identified any actual aging. In cases like the ones noted, where there was direct discussion of programmatic elements or the potential to affect aging, the operating experience item was linked to the AMP, designating it for further consideration during the AMP review.AMPA065 B.2.1.2 38

[ QuestionNo I LRA Sec Audit Quetion IFiqal Responsi regarding plant chemistry where increased levels of aggressive impurities such as chlorides and sulfates have been identified which could increase corrosion.

Also, PIR 20021583 and PIR 20020270 address chemistry control issues of out of specified conditions that could impact corrosion.

Follow-up Question 2.1.2-3: Response indicates hat specific operating experience items were said to address a license renewal aging effect only when an explicit mention of the aging was made.None of these PIRs identified any actual aging.Review of PIR 20021583, under problem description section d, there are words that state that chiller chemistry analysis indicate hat excessive corrosion and possibly crud deposits may have occurred due to level of chloride detected and the amount of solids in the chemistry sample. It also states that chemistry problems may be broader than simple chemical contamination.

PIR 20020270 addresses higher pH.It also states that potential consequences are higher corrosion rate.Other PIRs reviewed address similar chemistry issues. Yet, element 10 evaluation states that there have been no major chemical excursions during WCGS operating history.Please explain what "Major" means.Follow up Response: Although the water chemistry program is intended to maintain water chemistry parameters within specifications, it is recognized that water chemistry parameters may occasionally exceed the limits specified in the plant procedures.

As the amount of departure from specifications increases action levels increase.

Prompt graduated corrective actions are specified at each action level to eliminate or mitigate degradation from the out of specification condition.

A "major' chemical excursion as discussed in the license renewal application is an event where one or more chemical species exceeded an action level and the procedurally specified corrective actions were not complied with. None of the PIRs identified address events when the procedurally specified corrective actions were not 1complied with.39 lQ46stio'n to LRA SEpc jAuoltuetol 0"6 F Finall Re r*pos AMPA066 B.2.1.2 Also, please justify in light of the PIRs identified above, why you believe there are no major chemistry excursions.

Water Chemistry Program operating experience describes that the program was developed using industry experience.

However, it does not address plant specific operating experience to confirm that the program, as implemented, will adequately manage aging effects.The 10 elements evaluation only addresses industry operating experience.

Provide a summary of plant specific operating experience to provide reasonable assurance that aging effects will be adequately managed.Follow-up Question 2.1.2-4: In response to the request to provide a summary of plant operating experience in element 10, you responded that plant operating experience is referenced in AMP element 10. There is no reference to plant experience in element 10, except for one statement that there have been no major chemical excursions during WCGS operating history. Please provide specific plant experience that was used to determine that the program will adequately manage the aging effects.jPlant specific operating experience is referenced in AMP element 10.IThe evaluation provides a pointer to detailed discussions of numerous plant chemistry operating history issues and their resolution as described in station strategic plans. The discussion concludes by indicatirig that no major chemistry excursions have occurred during WCGS' operating history.Individual plant operating experience items were evaluated to determine relevance to actual aging effects/mechanisms and/or WCGS aging management programs.

A particular operating experience item may have been linked to a specific AMP(s) and/or to one or more material/environment/aging effect combinations based on the actual content of the item. Operating experience items were said to address a license renewal aging effect only when an explicit mention of the aging was made. Likewise, where there was direct discussion of programmatic elements or the potential conditions to affect aging that were within the control of the program, the operating experience item was linked to the AMP.The operating experience items that were thusly linked to any material, environment, aging effect combinations, or to an AMP, were considered further during either the AMR phase, regarding which aging effects/mechanisms to assign, or during the AMP phase, as a potential input to Element 10.JA number of plant corrective action documents and work orders that were evaluated as relating to the chemistry program are included on the Plant Aging Management Document Retrieval and Research System and will be included in hardcopy form in the AMP binder provided during the AMP audit. These operating experience items involve the areas of system chemistry performance, chemistry related system operation, chemistry control technical details, equipment degradation, benchmarking, self assessments, and program enhancements.

The operating experience does not include any examples of equipment degradation challenging an intended function that is related to deficiencies in the chemistry program.The evaluation of this operating experience contributed to the conclusion that there is a reasonable assurance that aging effects will be adequately.Imanaqed.

40 IQ47e~stion No IRA Se I~ Audit Question I~~i~~< Final Respons Follow up response: AMPA067 B2110!Low flow and stagnant areas of plant heating and central chilled water systems could show crud build up.Explain why a verification program such as a one time inspection is not used to confirm that significant

'degradation is not occurring.

Furthermore, explain why this is not considered as an exception to the detection of aging effects program element.Follow-up Question B2.1.10-1:

The response does not address the question.

The GALL Report AMP XI.M21 in element 4, "detection of aging effects" states: Control of water chemistry does not preclude corrosion or SCC at ,locations of stagnant flow conditions or crevices.

Degradation of a component due to corrosion or SCC would result in degradation of system or component performance.

The extent and schedule of inspections and testing should Out of specification values and unexplained adverse trends in water;chemistry parameters are documented by a Condition Report. Two recent examples of this process include Condition Report 2006-001764 and Condition Report 2006-002233.

The former example noted a large increase in turbine driven auxiliary feed water pump discharge conductivity, which was determined to be due to a leaking isolation valve from the emergency service water system (ESW). The corrective action I included corrective maintenance to eliminate the in-leakage of ESW. The latter example documents the corrective actions taken in response to out of specification results for lithium concentration in the reactor coolant system. The action taken was to adjust the cation ion exchanger time in service...Preliminary Response IThe plant heating and central chilled water systems are within the scope of license renewal per 10 CFR 54.4(a)(2) for spatial interaction concerns only. Therefore, the only component intended function applicable to these systems is (a)(2) pressure boundary.

Crud buildup would not directly affect the intended function of these components. (Element 4)NUREG-1801 does not suggest that an inspection is the only satisfactory option in this situation.

Specifically, Element 4 states "The extent and schedule of inspections and testing should assure detection of corrosion or SCC before the loss of the intended function of the component." This was interpreted to mean inspections and/or testing, as long as the loss of the intended function of the component was prevented.

Periodic monitoring of the diagnostic chemistry parameters (testing) of copper and iron in the closed cooling water systems provides an indication of corrosion occurring on the system, and will assure detection of corrosion before the loss of the intended function of thecomponent.

Follow-up Response LRA B.2.1.10.will be amended to state the following exception to inspections and testing for systems in scope of license renewal due to 10CFR 54.4(a)(2) due to spatial interactions such as plant heating and central chilled water systems. LRA B.2.1.10 will be amended as follows to include this exception.

Exceptions to NUREG-1801 Parameters Monitored or Inspected

-Element 3, Detection of Aging ...41 Question.N6 Y LftA.SecI Audit Question QK'iA Final Response assure detection of corrosion or SCC Effects -Element 4, Monitoring and Trending -Element 5, and before the loss of intended function Acceptance Criteria-Element 6 of the component."WCGS will not perform inspection or testing of plant heating and central Therefore, please explain why this is chilled water systems. Plant heating and central chilled water systems are not considered an exception if you in the scope of license renewal due to 1 OCR 54.4(a)(2) due to spatial are not performing any inspection for interactions only. Therefore the only intended function applicable to these plant heating and central chilled systems is pressure boundary.

Crud buildup would not directly affect the water system. intended function of these components." The periodic sampling and Imaintenance of system chemistry within specified limits is adequate to.......................................................

.. .............

..............

.. m anage aging before the loss of intended function.AMPA068 B.2. 1.10 For the exception on the parameters It is not clear if this question is referring to the main CCW heat exchangers monitored or inspected, confirm if all only, or all heat exchangers that credit this AMP, so the answer will component cooling water heat address both.exchangers are periodically tested to measure heat transfer capability.

The CCW heat exchangers are periodically tested to measure heat Clarify if all heat exchangers are transfer capability.

Flow and temperature measurements are used to periodically NDE tested. If not, how calculate heat exchanger performance in terms of a fouling factor. Tube are the heat exchangers selected for side (raw water) flow and differential pressure are also measured and testing and inspection, and how are used as an indicator of tube fouling. (Element 3)the results correlated to other component cooling water heat Emergency Diesel Generator (EDG) performance testing monitors and exchangers.

trends various engine parameters to ensure target availability goals are met or exceeded.

The monitored engine parameters include intercooler water pump pressure, jacket water pump pressure, intercooler temperatures, and jacket water temperatures.

Trending of these parameters will detect component aging prior to a loss of intended function. (Element 3)The CCW, EDG intercooler, and jacket water cooler heat exchangers (meaning all) are periodically NDE tested (ECT) to detect aging of the tube pressure boundary. (Element 4)GALL AMP XI.M21 states, for the "parameters monitored or inspected" program element, that this program should monitor the effects of corrosion i by surveillance testing and inspections in accordance with standards in EPRI TR-107396 to evaluate system and component performance.

For heat exchangers, the parameters monitored include flow, inlet and outlet temperatures, and differential pressure.

Various CCW supplied heat exchangers, such as the letdown heat exchangers, residual heat removal heat exchangers, safety injection pump coolers, and the PASS sample_coolers, are not periodically tested for flow, inlet and outlet temperatures, 42 IQqies~tion Noj I LRA Sc I -A~udit Question I I> Final Response and differential pressure.

The CCW heat exchangers are periodically tested to measure heat transfer capability.

Shell-side (closed-cycle cooling water) flow and temperature measurements are used to calculate heat exchanger performance in terms of a fouling factor. Tube side (raw water) flow and differential pressure are also measured and used as an indicator of tube fouling. The CCW heat exchangers are periodically NDE tested (ECT) to detect aging of the tube pressure boundary.The performance monitoring and NDE of the CCW heat exchangers will provide a leading indicator that aging resulting in a loss of material and fouling of heat exchangers is effectively managed in the CCW system. An enhancement to the WCGS closed-cycle cooling water system program, identified in Element 5, to specify inspection of the internal surfaces of the CCW pump return line check valves during In-Service Testing activities will also provide additional indicators of the effective management of the effects of aging due to loss of material and fouling in the CCW system. A ,review of WCGS plant specific operating experience indicates there has been no evidence of significant fouling or loss of material observed in the closed cooling systems. In conclusion, the current heat exchanger performance monitoring, internal inspections activities (in conjunction with check valve IST), and CCW system operating experience will be proposed instead of performance testing of all CCW supplied heat exchangers to demonstrate that CCW chemistry program is effective in managing the aging effects in the CCW system. (Element 3)FIRE BARRIER PENETRATION SEALS The requirement for penetration seal inspection is contained in Section 6.3.11.8 of AP 10-100, Fire Protection Program, which states the frlluAuin

'4AMPA069 B.2.1.12 LRA Section B2.1.12 states that"approximately 10 percent of each type of penetration seal (electrical and mechanical as practical) is visually inspected at least once every 18 months." GALL AMP XI.M26 states that 10 percent of "STN FP-452, FIRE BARRIER PENETRATION SEALS INSPECTION, is each types of penetration seal performed at least once per 18 months to visually inspect approximately should be visually inspected to 10% of electrical and mechanical Penetration Seals. If Fire Protection examine any degradation.

Since 10 determines that inspection results present an adverse trend, an additional percent of each type (electrical and population of the affected penetration sealing device type shall be mechanical as practical) of inspected for acceptability.

The number of penetration sealing devices penetration seal is not the same as inspected in this effort shall meet or exceed the total number of the 10 percent of each type of seal, affected type inspected in the original set. This process shall be repeated please clarify if the 10 percent until satisfactory results are obtained for the affected penetration sealing population of penetration seal device type. Samples shall be selected such that each Penetration Seal includes all types of seals (e.g., will be inspected every 15 years." cables trays, corndu its, pipes, ducts, 43 Question No LRA Sec F.;ul~isii

'Tinal Res pns ~ ~ i~and seismic gaps.)An approximate 10% inspection arrangement for mechanical and electrical penetration seals allows flexibility in development and maintenance of the penetration seal inspection sets. Ten inspection sets have been developed by Fire Protection to ensure that all penetration seals separating safety-related fire areas or separating portions of redundant systems important to safe shutdown are inspected every 15 years. The inspection sets were developed based on previous penetration seal inspection dates with each set approaching an approximate 10% sample of electrical and mechanical penetration seals. As penetrations are added, revised, or deleted, throughout plant life, the total number of mechanical and electrical penetration seals change and resulting inspection set totals change. It is not prudent to shift penetrations from one selection set to another just to maintain a 10% overall selection set.Additionally, some seal types have been used on a limited basis, which would result in repeat inspections of seals within the 15 year time frame, if selection sets were solely based on seal type.The AP 10-104 penetration seal surveillance requirements provide an acceptable methodology for implementation of the penetration seal inspection program, while ensuring that each penetration seal separating safety-related fire areas or separating portions of redundant systems important to safe shutdown be inspected every 15 years. Additionally, these seal surveillance requirements are consistent with NUREG-1552, where the NRC documented their assessment of fire barrier penetration seal programs'in nuclear power plants. Specifically, relevant excerpts from Section 5.7 of NUREG-1552 state the following:

"....In general, the licensees inspect a portion of the total population of seals every refueling outage (about every 18 months). If penetration seals;are found to be degraded or inoperable (e.g., breached, degraded, or improperly repaired), the licensees document the deficiencies and take the appropriate corrective actions.....""The staff had previously addressed potential problems in IN 88-04, IN 88-56, and IN 94-28 (See Appendix A). On the basis of the assessment documented here, it is the staffs view that existing licensee and vendor seal installation programs are adequate to prevent potential penetration seal installation problems.

In the event seals are improperly installed or breached, or become degraded, existing licensee surveillance, maintenance, and repair programs are adequate to reveal and correct potential problems." 44 Q~uestioni No IL~RA Secj 1AMPA07o AMPAO7f B.2.1.12 B.2.1.12 Auadit Question F( , Yinal Resp olns e- %,ui FIRE BARRIERS At least once per 18 months Wolf Creek performs a visual inspection of the exposed surface of each fire rated assembly (fire barriers separating redundant Post-Fire safe shutdowns systems) for the presence of breaches and gross deterioration.

The 18 month fire rated assembly inspections include such items as seismic gap seals, cable tray fire stops,_ _ _ steel pipe caps, etc.PIR 20012577 recommended Grouted penetration seals are part of the Fire Barrier visual inspections removing penetration seals that are that are performed at least once per 18 months to detect the presence of sealed with grout from the periodic breaches and gross deterioration.

18 month penetration seal inspection.

Confirm if this recommendation was implemented, and if so, clarify what is the inspection frequency for this type of penetration seals. If this frequency is different than the GALL Report recommended frequency, justify why this is not an exception.

The GALL Report states that no Penetration Seals corrosion and mechanical damage of NUREG-1801 XI.M26 element 6 (acceptance criteria) states: "Inspection halon system is acceptable; no results are acceptable if there are no visual indications (outside those corrosion is acceptable in the fuel allowed by approved penetration seal configurations) of cracking, supply line; and no visual indications separation of seals from walls and components, separation of layers of outside those allowed by approved material, or ruptures or puncture of seals." penetration seal configurations for Acceptance criteria are defined in the WCGS procedures used to perform penetration seals. The Fire tests and inspections of the fire protection system. Fire barrier penetration Protection Program License seals inspection results are acceptable if there are no cracking, separation Renewal Evaluation Report states of seals from walls, separation of layers of materials, ruptures, or differently in the 10 program punctures of seals observed that might impact the seals fire protection elements evaluation where the functionality.

Penetration seal inspection acceptance criteria is evaluated degradation is not acceptable if it in M-663-00017A, Penetration Seal Typical Details.prevents the system or penetration Inspections are performed by Level II (minimum)

QC personnel certified seal or fuel line from performing its for the type of sealing device being inspected.

intended function.

Furthermore, the same document states for fuel Diesel-driven fire pump fuel supply line: supply line that leakage would NUREG-1801 XI.M26 element 6 (acceptance criteria) states: "No indicate the potential of age related corrosion is acceptable in the fuel supply line for the diesel-driven fire loss of material and would be pump." observed and documented in the NUREG-1 801 XI.M26 element 4 (detection of aging effects) states: monthly operation of the diesel "Periodic tests performed at least once every refueling outage, such as f driven fire pump and corrective

!flow and discharge tests, sequential starting capability tests, and controller 45 I'uestlon No I ~LRA Sec I 2 Audit Questiout>

K~ FinialResponse' laction would be initiated.

Explain why these are not exceptions to the acceptance criteria program element, and provide a basis for why these are acceptable.

Clarify who determines how significant the corrosion or leakage is before the intended function is impaired.Followup Questions:

The response to question B2.1.12-3 does not answer the question.The GALL AMPXIM.26 element"detection of aging effects" recommends visual inspection of the halon system to detect any sign of degradation such as corrosion, mechanical damage, or damage to dampers. Also, element"Acceptance criteria" recommends any sign of corrosion and mechanical damage is not jacceptable.

function tests performed on diesel-driven fire pump ensure fuel supply line performance.

The performance tests detect degradation of the fuel supply lines before loss of the component intended function." Performance testing of the diesel-driven fire pump is used to detect degradation (corrosion) of the fuel supply lines. Satisfactory performance of the diesel driven fire pump means that no degradation (corrosion) was detected.

A monthly operation and fuel level check is performed on the diesel-driven fire pump and any leakage or any signs of corrosion that would prevent the system from performing its intended function are not acceptable.

Leakage would indicate the potential of age related loss of material and would be observed and documented in the monthly operation of the diesel-driven fire pump and corrective action would be initiated.

Diesel fire pump day tank level is checked once per shift in accordance with CKL ZL-009. This is also a data point for identifying system leakage.Halon System:*NUREG-1801 XI.M26 element 6 (acceptance criteria) states: "Also, any signs of corrosion and mechanical damage of the halon/C02 fire suppression system are not acceptable." NUREG-1801 XI.M26 element 4 (detection of aging effects) states: "Visual inspections of the halon/C02 fire suppression system detect any sign of added degradation such as corrosion, mechanical damage, or damage to Idampers.

The periodic function test and inspection performed at least!,once every six monthsdetects degradation of the halon/C02 fire!suppression system before the loss of the component intended function." Wolf Creek performs a functional deluge test of the halon fire suppression system to identify any mechanical damage of the halon fire suppression system that prevents the system from performing the intended functions.

The response stated that WCGS performs a functional deluae test to identify any mechanical damage. !Follow-up response: The halon system surveillance procedures STN FP-400A, 400B, The halon system has the internal environments of plant indoor air and dry 400C, etc. were reviewed.

Neither gas. The following halon system materials have an internal environment of these procedures addresses of plant indoor air: galvanized carbon steel, and copper alloy. The visual inspection.

Section 6.0, following halon system materials have an internal environment Of dry gas: Acceptance Criteria, does not bronze, carbon steel, galvanized carbon steel, cast iron, elastomer, provide any criteria for corrosion or copper alloy, and stainless steel. The material and environment mechanical damage. combinations listed above do not require aging management per the AMR.Please clarify how WCGS meets this Carbon steel and cast iron materials in the halon system are exposed to GALL Report recommendation and if an external environment of plant indoor air and will be visually inspected not, ple~a~sejustify why anexcep~tionwbytheXL.M36 External Surfaces MonitoringProgram

__......._

46 I Qusto NoI LA e Audit Question I /Final Responsel

_______to the GALL Report is not taken.The external surfaces of the diesel-driven fire pump fuel oil supply line will 1 For diesel driven fire pump, the be visually inspected by the XI.M36 External Surfaces Monitoring GALL Report element "acceptance Program.criteria" recommends no corrosion is acceptable in the fuel oil supply line The diesel-driven fire pump fuel oil supply line has an internal environment for the diesel driven fire pump. of fuel oil and is made of carbon steel. The NUREG-1801 row referenced ifor this components configuration is VII.G-21, which recommends the The response stated that ;aging management programs of XI.M26, Fire Protection, and XI.M30, Fuel I performance testing of the diesel- Oil Chemistry.

XIM30 Fuel Oil Chemistry utilizes the XI.M32 One-Time driven fire pump is used to detect Inspection to verify the effectiveness of the Fuel Oil Chemistry Program degradation (corrosion) of the fuel using a representative sample of components in systems that contain fuel supply lines. Please explain how the joil.performance test will detect corrosion.

The first paragraph of LRA Section A1.12 will be amended to state the following: "The Fire Protection program manages loss of material for fire rated doors, fire dampers, diesel-driven fire pump, and the halon fire suppression system, cracking, spalling, and loss of material for fire barrier walls, ceilings, and floors, and hardness and shrinkage due to weathering of fire barrier penetration seals. Periodic visual inspections of fire barrier penetration seals, fire dampers, fire barrier walls, ceilings and floors, and periodic visual inspections and functional tests of fire-rated doors are performed.

The internal surface of the diesel-driven fire pump fuel oil supply line is managed by the XI.M30 Fuel Oil Chemistry aging management program, which utilizes the XI.M32 One-Time Inspection to verify the effectiveness of the Fuel Oil Chemistry Program using a representative sample of components in systems that contain fuel oil, ensuring that there is no loss of function due to aging of diesel fuel oil supply line." IThe first paragraph of LRA Section B2.1.12 will be amended to state the following:

'The Fire Protection program manages loss of material for fire rated doors, fire dampers, diesel-driven fire pump, and the halon fire suppression system, cracking, spalling, and loss of material for fire barrier walls, ceilings, and floors, and hardness and shrinkage due to weathering of fire barrier penetration seals. Periodic visual inspections of fire barrier penetration seals, fire dampers, fire barrier walls, ceilings and floors, and!.periodic visual inspections and functional tests of fire-rated doors are -1 47

[Question No I' tRU .AS .c -, Audit Question i i i r ......I Final Respnsek ~A<performed.

The internal surface of the of the diesel-driven fire pump fuel loil supply line is managed by the XI.M30 Fuel Oil Chemistry aging management program, which utilizes the XI.M32 One-Time Inspection to verify the effectiveness of the Fuel Oil Chemistry Program using a representative sample of components in systems that contain fuel oil, ensuring that there is no loss of function due to aging of diesel fuel oil supply line."-j AMPA072 1AMPA073 B. 2.1.13 B.2.1.13 The Fire Water Program license i renewal program element report refers to Fire Protection Program in all elements.

Clarify if the Fire Protection and Fire Water System Programs are interchangeable.

Clarify if this the same Fire Protection Program addressed in LRA Section B2.1.12.The fifth paragraph of LRA Section B2.1.12 will be amended to state the following:

'The Fire Protection program performs a visual inspection, at least once!per year, on fire rated doors to verify the integrity of door surfaces and for clearances to detect aging of the fire doors. The internal surface of the of the diesel-driven fire pump fuel oil supply line is managed by the XI.M30 ,Fuel Oil Chemistry aging management program, which utilizes the XI.M32 One-Time Inspection to verify the effectiveness of the Fuel Oil Chemistry Program using a representative sample of components in systems that contain fuel oil, ensuring that there is no loss of function due to aging of diesel fuel oil supply line. A visual inspection and function test of the halon Lfire suppression system is performed every 18 months."!The Fire Water system is a subsystem of the Fire Protection system. The i Fire Water AMP (XI.M27, LRA Section B2.1.13) addresses water-based fire protection components such as sprinklers, nozzles, hydrants, standpipes, hose stations and water storage tanks (buried fire water piping lexternal surfaces are managed by the Buried Piping and Tanks Inspection Iprogram).

The Fire Protection AMP ( XI.M26, LRA Section B2.1.12)addresses fire rated doors, fire dampers, diesel-driven fire pump, fire barrier walls, ceilings and floors, barrier penetration seals and the halon fire suppression subsystem.

Although both AMPs manage components in the WCGS Fire Protection system, they are not interchangeable because NUREG-1801 creates a separate division of responsibility for managing aging of the Fire Protection system components.

Although NUREG-1801 creates this division, at WCGS there is no division between the two and all Fire Protection system components are governed by one program procedure (AP 10-100, Fire Protection Program).

Thus, both the Fire Protection AMP XI.M26, and Fire Water AMP XI.M27 will refer to the "Fire 1Protection Program".NUREG 1801, XI.M27, Fire Water System states that fire protectioh system piping is to be subjected to required flow testing in accordance with guidance in NFPA 25 to verify design pressure or evaluated for wall!thickness, and that visual inspections can be used to satisfy this Describe how the visual inspection performed under the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 48

[1-ues=onN I LRA Soc I~ Audit Qotj9,n F~inal Response p AMPA074 B.2.1.13 AMPA075 B.2.1.13 Program referenced in the Fire Water System Program evaluates wall thickness.

The Fire Water System Program description states that visual inspections of the fire protection system exposed to water, evaluating wall thickness to identify evidence of loss of material due to corrosion, is covered by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program.However, the detection of aging effects program element in the GALL AMP states that these inspection must be capable of evaluating (1)wall thickness to ensure against catastrophic failure and (2) the inner diameter of the piping as it applies to the design flow of the fire protection system.Since the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is a new program, discuss how this program will evaluate wall thickness and the inner diameter of the piping by only performing visual inspection.

The GALL AMP recommends annual fire hydrant hose hydrostatic tests.The Fire Water Program states that hydrostatic test of hoses occurs once every 3 years. Justify and provide a basis for this 3 year evaluation.

Visual inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program would detect wall thinning by identifying corrosion, surface or finish discontinuities, or a lack of symmetry of the component dimensions.

If degradation is unacceptable, deficiencies would be resolved via WCNOCs, corrective action program. The WCNOC corrective action program may then specify mechanical or NDE methods to be used in quantifying the degradation consistent with QCP 20-518, "Visual Examination of Heat Exchangers and Piping Components" or other approved station procedures. (WCGS-AMP-B2.1.22, Section 3.6, QCP 20-51 8).Visual inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program would detect wall thinning by identifying corrosion, surface or finish discontinuities, or a lack of symmetry of the component dimensions.

If degradation is unacceptable, deficiencies would be resolved via WCNOCs corrective I action program. The WCNOC corrective action program may then specify mechanical or NDE methods to be used in quantifying the degradation consistent with QCP 20-518, "Visual Examination of Heat Exchangers and Piping Components" or other approved station procedures. (WCGS-AMP-B2.1.22, Section 3.6, QCP 20-518).WCGS USAR Table 9.5E-1,Section III.E, 'WVCGS Fire Protection Comparison to 1 OCFR50 Appendix R', states that interior standpipe hose is tested every three years or the fire hose is replaced every five years.This is part of the WCGS current licensing basis. Since this is part of the iapproved licensing basis, clarification as to previous branch technical 1 positions and commitments would not be applicable.

However, for 49 LQuestion No. I UA SecW iAMPA076 Audit Que§stiqn frequency.

Clarify if hydrostatic test information frequency of hoses once every 3 the Branch years is documented in the WCGS Appendix A Fire Protection Program and in fire hose is commitments to 10 CFR 50.48 using Couplings a the Branch Technical Position (BTP) hydro-testin Auxiliary and Power Conversion

!years there Systems Branch (APCSB) 9.5 1, !hose every"Guidelines for Fire Protection for associated

'Nuclear Power Plants," dated May 1, 11976, and BTP APCSB 9.5 1, Appendix A, dated August 23, 1976.WCGS also states that it may replace an existing fire hose with a new fire hose every five years in lieu of performing a hydrostatic test.This implies that the fire hydrant hose will not be tested in five years.Justify how WCGS ensures that the hose has not degraded within these five years and will perform its intended function if no testing has been performed.

The LRA states that the One Time As stated in Inspection Program is a new AMP. Inspection, However, in the 21 years of plant that the Wa operation, WCGS must have I Programs v collected information on the aging of of extended systems and components in primary 4, one time water, secondary water, lube oil and 110 years pr fuel oil environments as part of system surveillance tests or the maintenance program. Furthermore, as part of evaluating industry experience, WCGS may have also evaluated these systems. Provide industry and plant operating experience that could be relied on to verify the effectiveness of the Water lChemistry, Fuel Oil Chemistry, and jLubricating-Oil Analysis Programs.

......7' FintalResponse purposes, hydrostatic testing of fire hoses is not discussed in Technical Position (APCSB) 9.5-1 (May 1976) or 9.5-1 (August 1976). The basis for testing/replacement of interior from NFPA 1962, Inspection, Care, and Use of Fire Hose nd Testing of Fire Hose. Specifically, Section 4.3.2 requires ig not to exceed 5 years from manufacture date and every 3 after. WCGS addresses this requirement by replacing the 5 years. It is more economical than the manpower cost with performing hydro-testing.

B.2.1.16 the Program Evaluation Report (PER) B2.1.16, One Time Section 3.10, there is no operating experience that indicates ter Chemistry, Fuel Oil Chemistry, and Lubricating Oil iill not be effective in preventing aging effects during the period operation.

In accordance with NUREG-1801 XI.M32, element inspections will be implemented and completed no earlier than ior to the period of extended operation.

50 Q'6uestiboiNo LRA Sec I. Audit Question IFinal Response ~ ;~ ~AMPA077 B.2.1.23 AMPA078 AMPA079 1AM PA080 B.2.1.23 B.2.1.9 The Lubricating Oil Analysis License Renewal Program Evaluation Report states that the plant's Predictive Maintenance Group reviews lubricating oil analysis results and determines the acceptability for ,continued service using engineering judgment.

Provide documentation that shows the analyses trending performed by the Predictive JMaintenance Group.Provide the basis and associated documentation for the oil sampling frequencies IA review of QCP 20 518, "Visual Examination of Heat Exchangers and Piping Components," indicates that visual inspection can detect wall thinning.

Explain and provide supporting documentation that show how visual inspection will be able to detect wall thinning".

The Open Cycle Cooling Program description states that NDE examinations are not performed in containment coolers. Performance testing can indicate if a leak is present; however, it cannot detect an.eminent leak due to wall thinning.Examples of lube oil analysis results documents have been provided in ,the hardcopy AMP binder available at the site during the audit for the'Turbine Driven Auxiliary Feedwater Pump and Safety Injection Pumps.Oil analysis results are reviewed by the predictive maintenance group to determine if alert levels have been reached or exceeded.

This review checks for unusual trends.Lube oil sampling frequencies were initially established using a combination of EPRI guidance, equipment vendor recommendations, and the oil supplier's assessment based on equipment usage patterns.

These sampling frequencies are evaluated on an ongoing basis based on plant operating experience.

In most cases, these original frequencies have proven to be adequate and have not been changed. However, frequencies may be adjusted towards more frequent sampling if sample results (for example, an unexpected increase in wear particle concentration) or operating history (oil-related equipment failure) warrant.Industry benchmarking and self assessments have also been performed to evaluate the sample frequencies within the total context of all the preventive and predictive activities for the components.

There is no formal document reflecting a basis for the sampling'frequencies.

Individual sampling frequencies are identified in the 1preventive maintenance requirements for each component.

!QCP 20-0518 states that "Where practical, component wall thinning shall be quantified to determine the extent of condition.

Depth of thinning may be determined by mechanical means or other suitable NDE methods.".(Step 6.5) Visual inspection would detect wall thinning by identifying ,corrosion, surface or finish discontinuities, or a lack of symmetry of the component dimensions.

Mechanical means or NDE methods could then be used to further quantify the degradation.,The relevant text from NUREG-1 801 Xl.M20 element 4 states: Inspections for biofouling, damaged coatings, and degraded material condition are conducted.

Visual inspections are typically performed; however, nondestructive testing, such as ultrasonic testing, eddy current testing, and heat transfer capability testing, are effective methods to measure surface condition and the extent of wall thinning associated with the ,service water system piping and components, when determined 51

~Question No LRASec. < Audit questlofr Fi~~/ nal Response, Explain how wall thinning is detected necessary.

and trended for this component.

The introduction to NUREG-1801 element 5 states: Inspection scope, method (e.g., visual or nondestructive examination

[NDE]), and testing frequencies are in accordance with the utility commitments under NRC GLý89-13.Performance of the containment coolers is monitored utilizing hydraulic ,and thermal testing methodologies.

The containment coolers are tested ifor hydraulic performance using the pressure drop method. The containment coolers are tested for thermal performance using the heat transfer method. Visual inspection, periodic cleaning, and NDE (ECT) are not performed on the containment coolers. ECT is not viable for the Containment Coolers due to accessibility constraints, therefore wall thinning cannot be directly measured.1AMPA081 B.2.1.9 Procedure AP 23L-001, Revision 2, Section 2.0, "Lake Water Systems Corrosion and Fouling Mitigation Program" and the Open Cycle Cooling License Renewal Evaluation Report indicate a difference in the components and systems that are subject to the scope of this program.Clarify the discrepancy and clearly identify which components and systems are managed under this program.Inspection scope, method, and testing frequency are consistent with the Wolf Creek commitments identified in Wolf Creek letter ET 99-0042, Updated Response to Generic Letter 89-13 dated November 17, 1999.Procedure, AP 23L-001, "Lake Water Systems Corrosion and Fouling Mitigation Program", establishes the general requirements for implementation of and maintenance of programs which monitor the performance and structural integrity of lake water systems which provide cooling for plant components.

Procedure AP 23L-001, Revision 2, Section 2.0, identifies that the procedure applies to the following systems:-Service Water (WS & ES)-Essential Service Water (EF)-Circulating Water (CW & DA)-Fire Protection (EP & KC)AMP B2.1.9 Open-Cycle Cooling Water AMP section 3.1 identifies the plant systems that receive cooling water (raw water environment) from the Essential Service Water System and Service Water Systems. AMP B2.1.9 is credited with managing the aging of components and heat exchangers that are exposed to a raw water environment in those systems. Element 1 identifies that the AMP manages aging in the following systems:-Essential Service Water-Chemical and Volume Control (CVCS chiller supply and Return Piping)-Service Water-Essential Service Water Chemical Addition-Component Cooling Water (Corponent Cooling Water Heat 52 ruestion G LRA Sec Audit Question Fina Resp onse Exchangers)

-Spent Fuel Pool Cooling and Cleanup (Spent Fuel Pool Make-Up Piping)-Stand-by Diesel Engine (DG Intercoolers, DG Lube Oil Coolers, and DG Jacket Water Heat Exchangers)

-Auxiliary Building HVAC (CCW Pump Room Coolers, Centrifugal Charging Pump Room Coolers, Containment Spray Pump Room Coolers, Electrical Penetration Room Coolers, RHR Pump Room Coolers, and',Safety Injection Pump Room Coolers)-Containment Cooling (Containment Coolers)-Control Building HVAC (Control Room A/C Unit Condensers and Class 1 E Switchgear A/C Unit Condensers)-Fuel Building HVAC (Spent Fuel Pool Pump Room Cooler)-Miscellaneous Buildings HVAC (AFW Pump Room Cooler)1AMPA082 B.2.1.9 The Open Cycle Cooling Program PIR No. 2002-0407 describes'operating experience with de-ialloying of heat exchanger tubing.The applicant credits a one time inspection in the Selective Leaching of Materials Program and committed to expand the inspection scope and to develop an inspection schedule if de-alloying is found. As a result of this operating experience described in PIR No. 2002-0407, provide the plan and schedule for these additional inspections.

Based on comparison of the list given in the Procedure to the list given in the AMP there appears to be a discrepancy.

However, while the procedure describes the scope at the system level, the AMP lists the;components that the systems serve. At Wolf Creek, the components atid heat exchangers are assigned to the functional system, not the cooling system (i.e., ESW and SW).iAMP B2.1.12, Fire Water System Program provides aging management of fire protection components exposed to a raw water environment (lakeýwater). The Circulating Water System is not within the scope of License Renewal.The indications described in PIR 2002-0407 in the copper-nickel tubes were suspected to be the result of dealloying but that assumption was never verified.It was concluded that the degradation had not caused significant deterioration of the tube walls. The corroded areas were not significant enough to determine wall loss or tube wall thinning or if significant deterioration had taken place. The suspected dealloying shows up as a bright area on the inside of the tube walls, therefore it is easily observed.The normal oxidized coating isn't present. For these heat exchangers the lidentified corrosion appeared to be in the early stages (occurring within ithe last few years). WCGS continues to monitor the condition, and compares new test data with past data in order to help determine if deallOy, conditions are causing further degradation of heat exchanger tubes.As a result, the Selective Leaching of Materials Program was not credited 53 uAMPonANO AMPA083 1AM PA084 LRA Sec B.2.1.17 B. 2.117 S Aud~it Questfion Fiqal Re~sponiswiK for any of the heat exchangers identified in the PIR. If it is eventually ,verified that dealloying is in fact occurring, and that the projected Idegradation could affect these components intended functions, the Selective Leaching, of Materials Program may be credited at that time.Provide additional information that When selective leaching occurs in gray cast iron components, the iron is demonstrates that alternative dissolved leaving behind a porous mass, consisting of graphite, voids and mechanical methods to hardness 1rust. This is known as graphitization.

Additionally, selective leaching in itesting are reliable for detecting

'copper alloys occurs when zinc is dissolved in the liquid solution that selective leaching.

comes in contact with the copper alloy component.

When the.zinc is removed a weakened and corroded structure is left behind. This is known as dezincification.

The combination of visual inspections in conjunction with mechanical methods will result in selective leaching being detected.IThe visual inspection will detect visible corrosion while the chipping and I scraping of the mechanical methods will detect a corroded component!structure.

If these methods detect dezincification or graphitization then a follow up examination/evaluation will be performed.

The examination/evaluation may require confirmation of selective leaching with la metallurgical evaluation (which may include a microstructure lexamination.)

IThere are no aluminum-bronze (greater than 8% aluminum) components in the scope of license renewal at WCGS.LRA Section A.1.17 and the The term (visual, mechanical methods) as seen in LRA Section A.1.17'Selective Leaching Program License I means "visual and mechanical methods".

Please see the response to i Renewal Evaluation Report, WCGS ýquestion 83 for clarification of the visual and mechanical inspection.

1AMP B2.1.17 Rev 1, address "visual, 1 mechanical methods." Clarify the LRA section A. 1.17 will be amended to change "visual, mechanical

!meaning of this term (i.e., "visual and! methods" to "visual and mechanical methods"!mechanical methods" or "visual or I imechanical methods-." The applicant stated that no The diesel fire pump fuel oil tanks have similar internal material of preventive action is taken for the construction and environment as the emergency fuel oil day tanks.,diesel fire pump fuel tank because Periodic sampling and testing for water and sediment has demonstrated

'the internals are inaccessible.

The that neither the fuel oil day tanks nor the diesel fire pump fuel tanks have applicant also stated that biocides any history, within the last ten years, of water and sediment levels and/or corrosion inhibitors have not exceeding the normal chemistry level of 0.05%. This demonstrates that been used to mitigate corrosion.

both tanks have the same material and internal environment.

The staff noted that since water and particulate contamination and The periodic sampling, cleaning, and visual inspection of the emergency corrosion has been detected in other ifuel oil day tanks will act as a representative sample and ensure that WCGS fuel oil tanks, it is possible 1significant aging isnot occurring in other fuel oil day tanks. The that MIC, pittin _and general lemergency fuel oil tanks inspection results will be of value in assessing AMPA085 B.2.1.14 54

[Que!stion No LRA Sec~ Audit ~Quesýtion ,IFinal Resoe!corrosion might be present in the the condition of the diesel fire pump fuel oil tanks since these tanks have diesel fire pump fuel tank as well. similar internal materials and environments.

Undetected degradation could be progressing through the tank wall Any adverse condition found in the inspected emergency fuel oil day tanks since cleaning and visual inspection will be assumed to be occurring in the emergency fuel oil day tanks and has not been performed in the diesel preventive actions will be taken in accordance with the WCGS corrective fire pump fuel tank. The applicant action program.indicated that operating experience for the other fuel oil tanks justifies One-time inspection of the bottom of the diesel driven fire pump fuel oil not having to implement preventive tank will confirm the effectiveness of this approach.

LRA Sections A1.14 actions. Provide additional and B2.1.14 and LRA commitment number 6 for Fuel Oil Chemistry information that justify not having to (RCMS 2006-203) will be amended to include a one time ultrasonic (UT)implement preventive actions such or pulsed eddy current (PEC) thickness examination on the external as cleaning and visual inspections surface of engine driven fire pump fuel oil tank (1DO002T) to detect on a periodic basis if alternate corrosion related wall thinning.

If UT is used, the examination will be on a inspection methods such as UT are 4 inch grid. The examination will be performed once during the 8 years not employed, between 10 years prior to the period of extended operation and 2 years tAMPA086 AMPA087 AMPA088 B 2 1.14...... ... .B.2.1.14 iB.2.1.14 Provide the acceptance criteria and the basis for minimum wall thickness.

Clarify if microbiological activity will be monitored and biocide and corrosion inhibitors be added if reduction of thickness is discovered during UT. If not, please provide a justification.

prior to the period of extended Operation.

-The acceptance criteria and the basis for minimum wall thickness have not!,yet been determined.

STN MT-002 inspection procedure provides for supplemental ultrasonic thickness measurements if there are indications of reduced cross sectional thickness found during the visual inspection land requires that Engineering evaluate all indication and specify required irepair._When fuel oil particulate levels equal or exceed 6 mg/L and have been verified by a second particulate analysis, the Procedure, AP 02-003,"Chemistry Specification Manual", requires a system engineer be contacted for possible corrective actions, including biological testing of fuel. Corrective actions are taken to prevent recurrence when the specified limits for fuel oil standards are exceeded or when water is;drained during periodic surveillance.

Additionally, when the presence of biological activity is confirmed, a biocide is added to fuel oil.When reduction of thickness is discovered during UT, an engineering evaluation of all indications is required.

Specific corrective actions are implemented in accordance with the plant quality assurance (QA)USAR, Section 9.5.4.1.2 indicates B es are not added on a routine basis. Biocides are only added when that biocides are used to mitigate testing indicates biological activity.

Per the chemistry requirements when corrosion.

However, the exception operations removes water from the diesel storage tank during to the GALL Report described in performance of either STS JE-004A or STS JE-004B, the water removed peetvaction program element shall be tested for biological activity.

Test results at 10 3 or greater 55 i~L Qu~estion No LRA Se , A~udit Questi~on of the Fuel Oil Chemistry Program indicates that biocides are not added on a routine basis. Provide additional information and supporting documentation related to biocide additions to diesel fuel.FinalResponse CFU/ml, for a treated tank, or 10ý or greater CFU/ml, for an untreated tank, shall be cause to have operations treat the affected tank with Kathon FP 1.5. The recommended dosing level is one gallon of Kathon FP 1.5 per 10,000 gallons of fuel in the tank.The Emergency Diesel Generator Fuel is analyzed for particulate when received and is also tested monthly. Procedure AP 02-003, section 6.43.1 states.Note 1: If the value is 6 mg/L or greater, resample and verify TSS results.Note 2: Pull an extra liter from the bottom of the tank for possible biological testing.Note 3: If 6 mg/L or greater particulate is verified by a second analysis, contact System Engineering for possible corrective actions, including biological testing of fuel.I Procedures, STS JE-004A/B, "Emergency Fuel Oil Storage Tank Water Check/Removal"'

directs for Operations personnel to contact Chemistry if water is detected during the monthly surveillance.

1AMPA089 B.2.1.14 The Diesel Fire Pump Fuel is analyzed for acceptance prior to the new Ifuel being offloaded into the day tank. This activity is controlled by Procedure, SYS DO-1 10, "Diesel Fire Pump Day Tank". Additionally, the!day tank fuel is sampled every 92 days per Procedure ,STN FP-600, "Fire I Pump Diesel Fuel Storage Tank".The Fuel Oil Chemistry Program Emergency Fuel Oil Tanks operating experience shows that corrosion has been discovered in the UT inspections are only required if indications of reduced cross sectional emergency fuel oil storage tank. thickness is found. The frequency at which UT is performed on the Provide the frequency at which UT is I Emergency Fuel Oil Tanks has not been determined because performed when degradation is ,degradation, which requires a UT, has not been found.'discovered in diesel fuel tanks.A visual inspection in 2002 revealed that the interior coating of one of the!emergency fuel oil storage tanks was deteriorated and some rust had developed in the interior walls of the tank. An engineering evaluation determined that the failure of the interior coating of the emergency fuel oil storage tank should not result in degradation or failure of the diesel system to perform its intended functions.

It was also determined that the rust identified during this inspection was an acceptable condition because it is not at a stage that could result in the component failures to perform its intended function and any degraded conditions in future inspections will be documented in a non-conformance work order. Upon the discovery of the_condition of the emergeoating, a biocide 56 Question No IRA Sec Audit Question>....... I i y I i 1 L i F nal. Respons e <J: >. .1was added to that tank and all of the diesel fuel in the emergency fuel oil ,storage tanks was subsequently replaced with new fuel. Since the'discovery of the condition of the emergency fuel oil storage tank interior coating, one of the emergency fuel oil day tanks has been visually 1 inspected, and no coating degradation was found. In 2006 both day tanks ,were inspected and no debris was found and no degradation of the[coatings was found.iThe acceptance criteria for the Emergency Diesel Generator Fuel and the ,Diesel Fire Pump Fuel are as follows. Reference Procedure, AP 02-003,"Chemistry Specification Manual"' page 51 and 63.!Emergency Diesel Generator Fuel AMPA090 B.2.1.14 Provide the acceptance criteria and the basis for all fuel quality parameters such as flash point, sulfur content, total particulate, water and sediment content, etc.ParameterýAPI gravity Kinematic visc.lWater & Sediment!Flash Point Particulates mg/I'Cloud Point Carbon Residue Ash Dist.Temp.@

90%Sulfur Copper Corrosion Cetane Number Limit 270 -390 API 1.9 <= x <= 4.1 Cst @ 401C<= 0.05%>= 51.70C<= 10 mg/I (Normal Value <5 mg/I, Supv Value <6 5<= -9°C (Supv Value -1 3 0 C< = 0.35%<= 0.01%Point 282.2 0 C <= x <= 338 0 C<= 0.5%Max. No. 3 Min. 40 (Supv Value >= 45 Diesel Fire Pump Fuel Parameter Kinematic visc.Water & Sediment Particulates Limit 1.3 <= x <= 4.1 Cst @ 40 0 C<= 0.05%<=10 mg/liter (supv limit <=6 mg/liter)WCGS uses the recommendations and methodology of D1 796-83 to determine the amount of contamination due to water and sediment in Idiesel fuel. The testing conducted using ASTM D1796 gives quantitative ,results, whereas D2709 testing gives only pass-fail results; therefore, the ID1 796 method gives more descriptive information about the fuel oil condition than the D2709 method. WCGS uses the recommendations and methodology of the modified 02276-78 Method A for determination of 57

~Question Noi LRA Sec Audit Question 4 Fiqal Responsep 1AMPA091 N/A Jackson: (1) Several of the License Renewal Program Evaluation Reports identify "Open Items" in section 5.2 of the report. The open items typically identify need (or potential need) to revise specified plant procedures or similar documents.

Explain which processes are used to ensure that these open items are tracked and closed. Clarify if the License Renewal Program Evaluation Reports will be updated to reflect closure of these open items.particulates in diesel fuel.The purpose of the AMP open items was to track progress of an item as information became available.

AMP open items were used to identify items that might change shortly before or shortly after issue of the LRA.Significant open items were entered in one of the following Wolf Creek processes for tracking:-Corrective Action process as a Performance Improvement Request (PIR) or Condition Report Regulatory Commitment Management System (RCMS number assigned),The License Renewal Program Evaluation Reports would be updated if!the open item is completed prior to issue of the LRA annual update and the update changes the content of the WCGS evaluations for one of the AMP 10 elements.The following is a listing and/or status of AMP open items: B.2.1.1 -XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Supporting information for 3rd Interval ISI -non-significantAMP impact.B.2.1.3 -XI.M3 Reactor Head Closure Studs Revisions issued -no AMP impact B.2.1.5 -XI.M1 1 Nickel-Alloy Penetration Nozzles Welded To The Upper Reactor Vessel Closure Heads Of Pressurized Water Reactors Editorial change for consistency

-non-significant AMP impact.B.2.1.8 -XI.M19 Steam Generator Tube Integrity Coordination with AMP XI.M2 Water Chemistry AMP -Water Chemistry AMP submitted with exception

-no AMP impact.B.2.1.9 -XI.M20 Open-Cycle Cooling Water System Condition Report 2006-000489 B.2.1.10 -XI.M21 Closed-Cycle Cooling Water System RCMS 2006-200 B.2.1.11 -XI.M23 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems PIR 05-3094 58 Question No~ iLKA §ec, ~ A udit Q;eto B.2.1.22 -X.M38 Inspection Of Internal Surfaces In Miscellaneous Piping And Ducting Components.

iRCMS 2006-208 B B.2.1.25 -XI.E2 Electrical Cables and Connections Not Subject to 10 1CFR 50.49 EQ Requirements Used in Instrumentation Circuits RCMS 2006-210 1 AM PA092 AMPA111'B.2.1.27 -XI.S1 ASME Section Xl, Subsection IWE One procedure changed no AMP impact -one procedure in revision B.2.1.32 -XI.S6 Structures Monitoring Program RCMS 2006-214 PIR 20052848 Plant Specific -PSNI Nickel Alloy Aging Management

__ _ _'Editorial change for consistency between_procedures N/A Patel: PIRs through PIR 20051006 dated April 12, 2005 (in AMP 8.2.1.32 Structures Monitoring) were reviewed for AMP 10 element evaluations.

(1) The PIR operating PIRs for the remainder of 2005 and all of 2006 were reviewed to identify experience reports for several AMPs PIRs that explicitly identify an aging effect or identify an AMP issue that include PIRs up to 2004 only. can be attributed to managing an aging effect. Results of the review were Please provide additional PIRs made available during the AMP audit.issued during 2005 and 2006 pertinent to the respective AMPs. -B.2.1.21 Please provide additional details to supplement the Operating A) The first thimble tube inspection using eddy current testing (ECT) with Experience in the LRA for WCGS recorded wear results was performed during Refuel 4, Spring 1990.AMP B2.1.21, Flux Thimble Tube'Inspections:

1 B) Eddy current testing has been performed on every flux thimble at every A) When was inspection in laccordance with NRC IE Bulletin 88-j09 first performed at WCGS?B) Has inspection using eddy current testing been performed on every flux thimble at every outage since such testing was first begun?!C) The Operating Experience in the ILRA states that eleven flux thimble Soutage since such testing was first begun.IC) The ten thimbles replaced due to thimble wall thinning were ordered jwith the chrome plating and available for replacement during RF12.I However, during cycle 12, after the new chrome plated thimbles had been ordered, thimble J08 developed an obstruction which would not allow the incore detector to traverse the thimble. The eleventh thimble, J08, was replaced due to the obstruction, and not due to through wall wear. Since a chrome plated thimble was not available and thimble wear was not a concern for this thimble, an available thimble of original design and manufacturing was used to replace the obstructed thimble.59 I Question No I <LRA Sec~ I Audit ~Question' U 7 Final Response 7 tubes have been replaced and that ten were replaces with chrome plated tubes in identified wear areas which are more wear resistant.

Why was the eleventh flux thimble tube not replaced with more wear resistant material in wear areas?What was the material of construction for the eleventh flux thimble tube replacement?

D) Please provide a summary of additional operating experience from the Fall 2006 refuelingoutage

.B.2.1.10-3:

The 'monitoring and trending" element enhancement states that new periodic preventive maintenance activities will be developed to specify performing inspections of the internal surfaces when valves are disassembled for operational readiness inspections.

However, the "acceptance criteria" element is not enhanced to indicate that new acceptance criteria will be D) All 58 thimbles were ECT inspected during Refuel 15, Fall 2006. All thimbles met acceptance criteria for an additional cycle of operation.

No thimble tubes were repositioned or replaced.As stated in Sections A1.10 and B2.1.10 of the LRA, a new periodic Preventive Maintenance activity will be developed to specify performing inspections of the internal surfaces of valve bodies and accessible piping while the valves are disassembled for operational readiness inspections.

The acceptance criteria will be specified in this Preventive Maintenance activity.Section Al. 10 of the LRA and LRA commitment number 3 for the Closed-Cycle Cooling Water System (RCMS 2006-200) will be amended to include the following statement: "The acceptance criteria will be specified in this Preventive Maintenance activity." AMPA112 B.2.1.10 developed for these new I inspections.

Please explain where Section B2. 1.10 of the LRA in the Enhancement for Monitoring and the acceptance criteria for these new Trending -Element 5, the paragraph will be amended as follows: inspections will be provided.

I"A new periodic preventive maintenance activity will be developed to specify performing inspections of the internal surfaces of the valve bodies and accessible piping while the valves are disassembled for operational readiness inspections to detect loss of material and fouling. The acceptance criteria will be specified in this Preventive Maintenance activity." Question deleted by WCGS 1 Question deleted by WCGS In WCGS-AMP-B.1.2.26, Revision 1, The evaluation of PIR 1998-1790 was based on the criteria available at Section 3.10 under Operating that time. Since 1998 additional guidance and information has become Experience, you have stated that a available.

Based on this information, Wolf Creek initiated a preventive review of plant operating experience maintenance (PM) program to inspect applicable manholes containing history determined that water has medium-voltage cables. This PM program was revised to include accumulated in cable manholes.

In information from draft procedure MPE CI-004. This inspection includes 2004, the cable manholes for the in- removal of water, if required, visual inspection for corrosion and AMPA113 B.2.1.32 AMPA114 B.2.1.26 60 Queqtion No LRA Sec ~ Audi tQuestion FinaltRespose+&

.scope medium voltage cables Idegradation of cable tray supports and visual inspection for cable jacket exposed to significant moisture !degradation.

Procedure MPE CI-004 will be implemented before the simultaneously with significant period of extended operation.

voltage were inspected for degradation of the cable support member to water.However, in PIR No. 19981790, you have stated that you identified a substantial amount of water in Man-Hole 119. This manholes contain 13.8 kV cable that go to the circulation water. This manhole also does contain other in-scope of medium-voltage cables. It appears that no corrective action was taken and an evaluation was performed and concluded that cable was o.k. to be submerged.

If these cables are allowed to be wet for a period of time, there is a possibility of cable degradation that can effect their safety-functions during the current and period of extended operation..

Describe corrective actions taken to address water problem in manholes.Will Procedure MPE CI-004 be implement during the current and..............

.B 2during period of extended operation?-AMPA115 B.2.1.26 Describe a program used to capture Wolf Creek's existing corrective action program captures internal and internal and external plant operating external plant operating experience issues.experience issues. ___AMPA1 18 B.2.1.36 GALL XI.E6 states that the specific LRA sections B2.1.36 and A1 .36 will be amended to include contact type test is to be a proven test such resistance testing, or other appropriate testing methods for low voltage low as thermography, contact resistance current or low load circuit.testing, or other appropriate testing justify in the application.

In addition, EPRI TR-104231, "Bolted Joint Maintenace

& Application Guide," recommend measure contact resistance using low ohm meter to detect loose connections.

In 61 I Question Sqc AMPA119 B.2.1.36 A' MP2O B.2.1.26 Audit Question B2 1.36, you states that infrared thermography testing is used to identify loose connection.

Explain how thermography is an effective method for detecting loose connections or high resistance for cable connections in low current or low load circuit where temperature

rise may not be detectable.

GALL XI. E6 states that the location (high temperature, high humidity) be considered for cable connection sampling.

In AMP B2.1.36, you have stated that the selected sample include plant indoor air environment.

Explain how aging effect of loose connections and/or high resistance due to corrosion are not a potential aging require management for electrical cable connections in outdoor environment.

ISG-2 states, in part, that restoration of offsite power paths be included in the scope of license renewal. These paths typically consist of. the first breaker in the switchyard to the start up transformers to the safety-related 4.16 kV buses. The scope of your Inaccessible Medium Voltage Cables not Subject to 10 CFR 50.49 EQ requirements only include underground cables from disconnection switch 13-23 to ESF transformer to 4.16 kV safety buses.It does not include underground cables from secondary side of transformer No. 7 to disconnection switch 13-23 which provide the remaining part for SBO restoration.

When underground cables are subject to water tree, no matter how many redundancy path it have, I I Quetion b I LA Sec1/2 FinalIResponse'>&

LRA section B2.1.36 will be amended to include electrical cable connections in outdoor air.iThe WCGS per ISG-2 includes in the scope of License Renewal two paths 1 of SBO restoration power. The WCGS connections to the switchyard are through disconnects not circuit breakers.

One path is from disconnect 345-163 via overhead lines to the station start-up transformer.

The other path is from disconnects 13-21 or 13-23 via underground cable to the station ESF transformer.

This configuration conforms to the requirement of Criterion 17 that states, "the onsite electrical distribution system shall be supplied by two physically independent circuits designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions."'The entire WCGS plant system portion of the SBO restoration power system is within the scope of license renewal. This is consistent with ISG-2 Staff Position which states "Consistent with the requirements specified in 10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), the plant system portion of the offsite power system should be included within the scope of license renewal".

The 345KV switchyard system equipment beyond disconnect 345-163 and the 13.8KV switchyard system equipment beyond!disconnects 13-21 and 13-23 including the 13.8KV switchgear, circuit';breaker 13-48, transformers No4/No 5/No. 7 and the underground cables 62

~Que~stion No LIRA Sec.> Audit Question~

Figa Res o~nsie common mode failures may occur to are part of the offsite transmission system (grid) and are not part of the jall underground cables. If the Iplant system portion of offsite power and therefore not within the scope of underground cables connecting License Renewal. Westar Energy is the owner of the Wolf Creek'disconnect switch 13.23 are not switchyard and is responsible for switchyard equipment design, operations AMPA121 AMPA122 iB.2.1.9 B. 2.1.9 managed/tested, provide your land maintenance.

technical justification how you satisfy ,with ISG-2 to ensure that SBO restoration paths are maintained during the extended period of operation.

During review of operating There was one indication in the Emergency Diesel Generator Intercooler experience, it was noted that in PIR Heat Exchanger that was called a stress corrosion crack. It was an axial 20020407 there was degradation crack. The exact initiation mechanism could not be conclusively discovered during visual examination established since the original ID surface was lost due to flow-assisted that appeared to be resulting from corrosion.

de-alloying in the Emergency Diesel Generator Heat Exchanger train "A" On-going corrective actions include preventive maintenance to eddy tubing (copper alloy C44300). current test, analyze the data, and take corrective actions for any tubes Subsequent eddy current testing that do not meet acceptance criteria.revealed multiple degradation indications.

Metallurgical evaluation

!Also, the Emergency Diesel Generator Heat Exchangers are being of the tubing showed no de-alloying.

replaced with AL6X tubing material.

The Intercooler Heat Exchangers Most indications were identified as were replaced during RF15, in 2006. The Lube Oil Coolers are targeted erosion-corrosion.

One indication for replacement in RF16, in 2008 or during a planned maintenance outage was a stress corrosion crack. SCC lat power. The Jacket Water Coolers are targeted for replacement in of copper alloys is usually RF1 8, in 2011 or during a planned maintenance outage at power.associated with ammonia or polluted waters. Please provide the details of augmented inspection, trending, mitigation etc. resulting from this_egradatio incident.

_During review of operating About half of the room cooler leaks are the result of an isolated pit going experience, it was noted that in PIR 'through wall in the tubing. In the remaining half of the leaks, we 20040688 that there was an encountered through wall pitting combined with some flow erosion in the increase in leakage trend in the H-bend areas. Tubes with deep through wall pitting were allowed to Electrical Pen Room cooler, the remain in service because past Eddy Current acceptance criteria allowed RHR Pump "A" cooler, the CCP "A" it. The Eddy Current acceptance criteria was changed and past ECT data Room cooler and the Containment

!was reviewed to select room coolers for replacement.

The RHR pump "A" Air "D" Cooler. What was the cause !cooler leak caused a lot of unavailability time and Room Coolers were of the leaks? What actions are 1declared a Maintenance Rule (a)(1) issue. Corrective action consists of being taken to address the increased

'changing out degraded coolers. Out of sixteen total room coolers, eleven leak trend? I have been replaced, three are scheduled to be replaced by RF16 (2008)63 Qusto N jR Sqc J'~ Audit Questibn Final Re~ose __7 and the remaining two are being targeted for replacement by the end of 2008. New cooler bundles are procured with AL6XN tube materials.

On-going actions include preventive maintenance to eddy current test, analyze the data, and take corrective actions for any tubes that do not meet acceptance criteria.Containment Air "D" Cooler The failure mechanism of pitting and erosion for the tubes and U-bends is assumed to be consistent with other copper nickel tube bundles in the room coolers. This assumption is based on same materials and same water source being used in the containment coolers and the room coolers.'Apparent cause is planned for the tube bundles being replaced in RF16 1(2008). Future corrective actions will be based on the apparent cause.IAMPA123 There is no aging man program to manage th coatings.

Please justil an aging management coatings.

The failure could result in aging e steel shell in containm failure of coatings cou the failure of safety sy, perform their intended instance, safety injecti iagement e aging of fy not having program for of coatings Due to the configuration of these coolers, eddy current testing is not possible.

Flow and dP and heat transfer capability are periodically verified per Wolf Creek's commitment to Generic Letter 89-13. Any leakage is detected early by continuous monitoring leak detection systems.Coatings of the Wolf Creek Reactor Building steel liner are not within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3).

Coatings of the Wolf Creek Reactor Building steel liner do not have an intended function.ffects for the LRA Table 3.5.2-1 notes that consistent with GALL line item I1.A1-1 1, loss ent. The of material due to general, pitting, and crevice corrosion of the Wolf Creek Id also result in Reactor Building steel liner is managed by AMP B2.1.27, ASME Section stems to Xl Subsection IWE. The coated surfaces of the Wolf Creek Reactor functions (for Building liner are visually examined by AMP B2.1.27, ASME Section Xl on). Subsection IWE as an indication of the condition of the steel surfaces underneath the coating. Reactor Building ASME Code Section Xl, IWE 3510.2, "Visual Examination of Coated and Non-coated areas," states that"The condition of the inspected area is acceptable if there is no evidence of damage or degradation which exceeds the visual acceptance criteria specified by the Owner." Detailed visual examination acceptance criteria at Wolf Creek identifies the following conditions as rejectable for coated surfaces:-Cracking-Flaking-Blistering

-Peeling-Discoloration

" 64 Question No fLRAXsec ~>Audit Quq4ion \~ ~Final Roesponse

~ .~-Deformation

-Other signs of distress AMPA124 B.3.1 In elements "Detection of aging leffects" and "corrective action program", the application states that action levels of the Fatigue Management Program will be enhanced to ensure that... Please explain what you mean by action levels.'All rejectable indications require initiation of a Non-Conformance Report (NCR) and evaluation in accordance with the WCGS corrective action process.The effects of containment debris on the intended function of the RHR &Containment Spray sump screens is being addressed by industry efforts to resolve GSI-191. The contribution of coatings to the containment debris.is event driven and is not related to aging .. .......................................

..............

'The WCGS Fatigue Management Program provides for periodic evaluation (once per operating cycle) of fatigue usage and cycle count tracking of critical thermal and pressure transients to verify that design limits on fatigue usage will not be exceeded.

The program will be enhanced to include action limits (values for accrued transient cycles and!calculated cumulative fatigue usage (CUF) that require initiation of corrective actions) and definition of acceptable corrective actions that may be implemented to assure that ASME Code limits on CUF are not exceeded.

For locations identified in NUREG/CR-6260, action limits will be based on fatigue usage calculated including the environmental effects-of the reactor coolant.1. Cycle Count Action Limits: A limit will be established that requires corrective action when the cycle count for any of the critical thermal and pressure transients is projected to reach a high percentage (e.g., 90%) of the design specified number of cycles before the end of the next operating cycle. Appropriated corrective actions if this limit is reached include: a. Review of fatigue usage calculations to determine whether the transient in question contributes significantly to CUF or to identify the components and analyses (e.g., HELB screening calculations and LBB crack propagation) that are affected by the transient in question.b. Evaluation of remaining margins on CUF based on cycle based or stress based CUF calculations using the fatigue monitoring program software.c. Redefinition of the specified number of cycles (e.g., by reducing specified numbers of cycles for other transients and using the margin to increase the allowed number of cycles for the transient that is approaching its specified number of cycles).12. Cumulative Fatigue Usage Action Limits: _65 Lý Qusiop fP L.RA Sec j udtuetonI4 Final Resporksp~

!A limit will be established that requires corrective action when calculated CUF (from cycle based or stress based monitoring) for any monitored location is projected to reach 1.0 within the next 2 or 3 operating cycles.Appropriate corrective actions if this limit is reached include those listed below. These corrective actions are equally applicable to WCGS NUREG/CR-6260 locations with consideration of the environmental effects!of reactor coolant.a. Determine whether the scope of the monitoring program must be enlarged to include additional affected reactor coolant pressure boundary locations, to ensure that other locations do not approach design limits without an appropriate action.b. Enhance fatigue monitoring to confirm continued conformance to the code limit.c. Repair the component.

d. Replace the component.

e. Perform a more rigorous analysis of the component to demonstrate that the design code limit will not be exceeded.f. Alter plant operation to reduce the rate of fatigue usage accumulation rate.g. Perform a flaw tolerance evaluation and impose component-specific inspections.

AMPA125 AMPA126 B. 2.1.22 ILRA Chapter 4.3.1, Appendix A.2.1, and Appendix B.3.1 will be amended!to conform to this response.In elements "detection of aging !The response to AMPA124 describes action limits that will be incorporated effects" and "corrective action into the fatigue monitoring aging management program and specifies the program", the application states that corrective actions that are appropriate in response to each action limit.corrective actions of the Fatigue Management program will be enhanced to ensure that... Please clarify where these corrective actions are identified?

Please explain why the pertinent The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting operating experience related to Components Program is a new program. Therefore no programmatic internal surface inspections of piping operating experience has been gained.and ducting components that may have been performed during the The Inspection of Internal Surfaces Program will be implemented via plant maintenance and surveillance existing predictive maintenance, preventive maintenance, surveillance i activities is not included in the testing and periodic testing work order tasks. Such tasks have been in joperating experience section of the place at Wolf Creek since the plant began operation.

These activities have I.LRA? Currently, no operating proven effective at maintaining the material condition of systems, ...66 Quemston No >1LRA Se-C7 -Audi1t 0usli §09, Fina~tIKes onfse;experience has been included.AMPA127 ,B.2.1.22 NUREG-1801, element 6 recommends that indications of various corrosion mechanisms or fouling that would impact component intended function are reported and will require further evaluation.

Does the WCGS aging management program include monitoring of fouling? If not, please justify why this is not an exception to element 6 of NUREG-1801?

istructures, and components and detecting unsatisfactory conditions.

A review of PIRs from 1995 to 2006 for HVAC components in the scope of license renewal and within the scope of this AMP did not identify any loss of intended functions due to loss of material in HVAC ducting, nor hardening and loss of strength associated with elastomers used in HVAC flexible connections.

Operating experience from mechanical components in other mechanical systems (non-HVAC) within the scope of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Icomponents AMP will be reviewed during implementation of the AMP prior to the period of extended operation.

System Engineers review operating experience for possible impact to the equipment in their systems. The basis for parameters monitored and inspection intervals is based on vendor recommendations, historical performance, and industry wide operating experience.

The new program will be!reviewed to account for industry and station operating experience.

Monitoring for fouling was not included because it was not identified as a n aging effect for any component currently in scope for this AMP. The LRA will be amended to reflect this fact and to eliminate any concern that this might be an exception.

The first sentence of LRA Section A1.22 will be amended to state: "The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, fouling, loss of material and hardening

-loss of strength." LRA Section B2.1.22 will be amended as follows: The first sentence changed and a second sentence added to state: "The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, fouling, loss of material and hardening

-loss of strength.

Fouling has not been identified as an aging effect in any component currently in scope for this AMP." The Wolf Creek comparison to NUREG-1 801 under section 2.1 of WCGS-AMP-B2.1.22 is amended as follows: The first sentence changed and a second sentence added to state, "The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, fouling, loss of material and hardening

-loss of strength.

Fouling has not been identified as an aging effect in any component currently in scope for this AMP." The WCNOC Preventative Maintenance (PM) program manages age related replacement

/ refurbishment of equipment and surveillance AMPA128 B.-3.2 Provide examples of operating experiences showing that the 67 6 uesiion N; LRA Sec Auidit Qtwe~tio r ,i ?FinaI'R~esponse LAMPA129 B. 3.2 Environmental Qualification (EQ) of Electrical Components Program has succeeded in managing aging degradation in a timely manner.Also, describe any corrective action or program enhancement as a result of these operating experiences.

Provide a sample of electrical components in EQ master list including EQWP J-361A for high-range radiation monitor cables.These cable were excluded from the Iscope of AMP B2.1.25. Also, provide a sample of maintenance performed on some EQ electrical components to maintain their qualified life.Under "acceptance criteria" element, you have stated that an enhancement will be made to be consistent with GALL's acceptance criteria element. Specially, the enhancement states that the program documents will be enhanced to describe methods that Smay be used for qualified life activities based on a schedule dictated by the WCNOC EQSD-I11 document.

Any unexpected adverse conditions that are identified during operational and maintenance activities in regards to aging degradation issues would be managed through the plant's corrective action program or ,via work orders generated and assigned to the EQ Program Engineer.IThe EQ Program Engineer also reviews and evaluates industry operating!experience and other sources of information (such as Scientec's monthly newsletter) for applicability to WCNOC, and where necessary implements the necessary corrective actions.No examples of age related failures of EQ equipment could be identified for the life of the plant. There are several examples of industry operating experience that were reviewed that required no action due to already sufficient requirements, such as identified in PIR 2002-2756

("Normally Energized ASCO Solenoid Valves (SOV) That Are in Service Beyond Their Qualified Life") and ITIP 5025 (generated for NRC Regulatory Issue Summary 2003-09 "Environmental Qualification of Low-Voltage Instrumentation and Control Cables").

There is reasonable assurance that Ithe existing WCNOC EQ Program is sufficient, and able to manage age related issues prior to actual equipment failures.Provided hard copy of pages 65 and 66 of the EQ master document 1EQSD-II (Revision 25). This document identifies how Wolf Creek classifies the components in regards to the accident conditions along with room locations and environments.

These two pages include the high radiation monitor components (J-361A) along with some other components.

Provided the first five pages of EQSD-II (Revision

8) that shows the Ireplacement/refurbishment schedule for the age restricted parts of valve ABHV00111.

In addition to these sheets four pages from a sample Work Order (WO 98-128835-001) are provided.

This WO performed the EQ maintenance activity for valve ABHV001 1. These pages identify the WO number and the scope of the work.i B.3.2 AMPA130 I LRA sections A2.3 and B3.2 and LRA commitment number 22 for Environmental Qualification of Electrical Components (RCMS 2006-219)will be amended to remove the stated enhancement.

The current WCGS EQ program methods will be used for qualified life evaluation in the period of extended operation.

68 68 IQuestipip No ~j>LRA Sgec 1AMPA1 31 B.3.1 Apodit Queio~n Fnal s~k~iinse<

evaluation for the period of extended operation.

Describe methods that may be used for qualified life evaluation for the period of extended operation.

How these methods are consistent with GALL's AMP X.E1 under the "acceptance criteria" element.In LRA Section B3.1, the applicant WCGS will supplement LRA Appendix A2.1 and Appendix B3.1 as credited an enhancement Idescribed in the response to AMPA124..'confirmation process

program element stating that "The WcGS Commitment No. 21, Item 1 corresponds to the first bullet of LRA Metal Fatigue of Reactor Coolant Appendix A2.1 and to the first paragraph of LRA Appendix B3.1 under Pressure Boundary program will be "Enhancements," "Oetection of Aging Effects, Element 4, and Corrective enhanced to invoke Appendix B Actions -Element 7." procedural and record requirements." However, the Commitment No. 21, Item 2 corresponds to the second bullet of LRA enhancement description provided in Appendix A2.1 and to the second and third paragraphs of LRA Appendix Commitment No. 21, item 4, is B3.1 under "Enhancements," "Detection of Aging Effects, Element 4, an(different.

Clarify this discrepancy Corrective Actions -Element 7." and justify the differences between the enhancement description in the Commitment No. 21, Item 3 corresponds to the third bullet of LRA LRA and the one in the commitment Appendix A2.1 and to the fourth paragraph of LRA Appendix B3.1 under list. "Enhancements." "Detection of Aaina Effects. Element 4. and Corrective d Actions -Element 7." Commitment No. 21, Item 4, "10 CFR 50 Appendix B procedural and record requirements," corresponds to the fourth bullet of LRA Appendix A2.1 and to LRA Appendix B3.1, "Enhancements," "Confirmation Process-Element 8." These are consistent.

The sentence following Commitment NO. 21, Item 4 should be a separate paragraph:

Prior to the period of extended operation, changes in available monitoring technology or in the analyses themselves may permit different action limits and action statements, or may re-define the program features and actions!required to address the fatigue time-limited aging analyses (TLAAs)" IThis sentence anticipates future events that may require adjustments to i 69 IQuestfion No LRA Sac IAud0it ~Q4Wsion I < Fiqal R6esponseý AM PA132 B.2.1.21 WCGS' letter WM 89-0015,"Response to NRC Bulletin 88-09,"!dated January 18, 1989, states, in part, "The thimble tube inspection program requires that of [sic] any tubes with wall loss of 60 percent or more be removed from service." The Flux Thimble Tube Inspection Program implementing procedure RXE 03-006 states "Any thimbles with wear in an active location greater than 60 percent through wall or projected to be greater than 60 percent before next outage should be repositioned.." It also states,"Any thimbles with wear greater than 80 percent through wall or projected to be greater than 80 percent before next outage shall be capped, or equivalent, and considered for future replacement." GALL AMP XI.M37, under"acceptance criteria" program element, states "Acceptance criteria different from those previously documented in NRC acceptance letters for the applicant's response to Bulletin 88-09 and amendments thereto should be justified." a. Provide a technical justification for the change from 60 percent to 80 percent through wall wear criteria for removing a flux thimble tube from service.the program. It applies to the first three of these items, not to Item 4.WCGS does not anticipate any future events that would affect the commitment to 10 CFR 50 Appendix B procedural and record requirements.

a. WCAP-12866, Bottom Mounted Instrumentation Flux Thimble Wear, was used to justify the change from 60% to 80% through wall wear criteria at Wolf Creek for removing flux thimble tubes from service. Appendix A of jWCAP-12866 provides the results of pressure testing and a finite element analysis and determined the maximum allowable wall loss. Based on the Westinghouse tests results, it was conservatively determined that a flux thimble can remain in service with up to 80% wall loss. The 80% wall loss acceptance criteria will maintain the structural and functional integrity of the flux thimble tubes and the flux thimble tubes can remain in service up to 80% wall loss.It is noted that Wolf Creek procedures address corrective actions at 60%indicated wall loss to prevent further through wall loss by wear.b. Based on the Westinghouse tests, eddy current data over estimates the depth of actual wear scars. Using eddy current thimble wear data to I predict wear will result in very conservative predictions of wall loss.!Although the WCAP states, " it is not necessary to add additional uncertainty margin to the eddy current wall loss indications...," Wolf Creek uses an uncertainty margin of 5% for conservatism.

Conservatism of the methodology for projecting wear for the following operating cycles is confirmed by WCAP test data that exhibits an exponentially decreasing curve of flux thimble wall loss versus operating 1time 70

[ Question No I LRA Se~c I[$ Audit Question I (Final Response;

________b. Address whether the 80 percent acceptance criteria includes the allowances for uncertainties that are recommended in the GALL Report and whether the methodology for projecting wear for the following operating0cycles is conservative.

_Provide the limit on maximum The maximum number of thimbles that can be removed from service can number of flux thimble tubes that can be as high as 14 as specified in the basis for Technical Requirement (TR)AMPA133 B.2 121ýAMPA134 B.2.1.4 be removed from service. Exple what is the basis for that limit.Within the Boric Acid Corrosion Monitoring Program, WCGS is treating fasteners too difficult to remove for engaged thread inspection as "seized" in the coi of being interference fit or stake prevent backing out. This pract based on an interpretation of a footnote on page 4 of NRC inspected in place." As a result engaged threads of certain stuc fasteners designed to be remov but are difficult to remove, are n being inspected as required by ASME Section Xl.3 i 3 13.3.10 Movable I ncore Detectors: "TR 3.3.10 specifies that the Movable Incore Detection System shall be OPERABLE.

OPERABILITY with greater than or equal to 75% of the detector thimbles, a minimum of two detector thimbles per core quadrant, and sufficient movable detectors, drive, and readout equipment to map these thimbles ensures that measurements obtained from use of this system accurately represent the spatial neutron flux distribution of the core when the system is used for the specified activities" Although TR 3.3.10 permits as many as 14 (25%) of the 58 thimbles to be!out of service, Wolf Creek strives to maintain all thimbles operable and takes timely corrective actions to return inoperable thimbles to service as Isoon as practical.

In Refuel 11 Wolf Creek had to cap two thimbles.Those two thimbles and nine additional thimbles were replaced in the next refueling outage (Refuel 12) per WO 00-221918-000.

That was the only Itime to date that thimbles were removed from service (capped) due to 1fretting wear. --- ----[This question originated from a review of WCGS OE. PIR 1997-3658 problem initiation stated that within the Boric Acid Corrosion (BAC)Monitoring Program, WCNOC is treating fasteners too difficult to remove for engaged thread inspection as "seized" in the context of being ntext interference fit or staked to prevent backing out. This practice is based on d to ian interpretation of a footnote on page 4 of NRC IE Bulletin 82-02, which ice is I states "fasteners seized or designated with interference fit may be inspected in place." As a result, the engaged threads of certain stuck fasteners designed to be removable, but are too difficult to remove, are ,the not being inspected as required by ASME Section XI.able, The PIR resolution is as follows: iot "The statement within this PIR which implies that this is an ASME Section Xl inspection is incorrect.

The inspection was required by NRC Bulletin 82-02 which stated that Section XI acceptance criteria was to be utilized.71 I- 64"ti" On NI ~LRA 5,o I Audit Quesi6n ~ i Final Res54otis Are these fasteners being inspected in place? If not, has WCGS requested relief from the Section Xl requirement?

The Bulletin also stated that fasteners which were seized or interference fit could be inspected in place. This indicates that either excessive force would be required to remove the fastener (seized) or the fastener was designed to be difficult to remove or back out (interference fit). In either case this allowance is technically justified when considering that a borated water path into the fastener threads would have to begin at an exposed surface. Also, boric acid corrosion needs oxygen which also is not present in sufficient quantities internal to a seized fastener.

Both the borated water path and oxygen supply would be present at the exposed surface of the fastener thus the Bulletin was correct in allowing such'fasteners to be inspected in place." Based on the above, seized or interference fit fasteners are inspected in place, and no ASME relief is required since the BAC AMP inspection is not a code requirement.

72 Wolf Creek AMR Audit Questions and Responses!I Question ýNo I L1RA Sec~ I Auqit pgstion AMRA001 13.1 LRA Table 3.1.1, item 3.1.1.63, states that this line is consistent with the GALL Report with AMP exceptions.

This line corresponds toGALL Report, Volume 1, Table 1, item 63, 1which identifies the Inservice Inspection (IWB, IWC, and IWD) as the AMP. This line includes GALL Report Volume 2, item IV.B2-26, lower internal assembly, radial keys and clevis inserts made of stainless steel.LRA Table 3.1.2-1 does not appear!to include any lower internals lassembly components that references to LRA Table 3.1.1, item 3.1.1.63; and it does hot include any line corresponding to GALL Report, Volume 2, item IV.B2-26.

However, I It does include a line (page 3.1-62)Ifor "lower internals assembly (clevis!insert bolts, radial keys, clevis!inserts)" made of nickel alloys, where the aging effect is identified as "loss of material" and the AMP is identified as the Water Chemistry Program.For the components "lower internals assembly (clevis insert bolts, radial keys, clevis inserts): a. Explain whether the components are subject to aging effect of loss of material due to wear? Provide a justification for your conclusion.

I Final Reqpofls~e.(a) The clevis insert bolts, radial keys and the clevis inserts are subject to aging effect of loss of material due to wear. LRA Table 3.1.2-1 will be amended to include a new line for clevis insert bolts, radial keys, clevis inserts made of nickel alloy in a reactor coolant environment with an aging effect of loss of material that is managed by the ASME Section XI ISI AMP. The new line will reference GALL Report, Volume 2, item IV.1B2-34.(b) The line in LRA page 3.1-62 for "lower internals assembly (clevis insert bolts, radial keys, clevis inserts)" of nickel alloys with the aging effect of"loss of material" is due to the aging mechanism of pitting and crevice corrosion.

Based on GALL Report, Volume 2, item IV.B2-32, the Water Chemistry Program would provide adequate aging management for pitting]and crevice corrosion.

The new line to be added for item (a) above will rely!on the ASME Section Xl ISI AMP to manage the aging effect due to wear.[c] The components are included within the scope of the ISI Program under examination Category of B-N-2 and B-N-3. The clevis, clevis insert, and clevis insert bolts are inspected every 10 years under Category of B-N-2 and the radial keys attached to the core barrel are inspected under Category of B-N-3 with same interval.(d) There is no operating experience with regard to failure of these components that has been identified by WCGS. They have been;inspected three times, once at initial installation, and twice since then. No wear has been detected.73 I Question Noj I LRA Sec I Audit Questio I >Final Responi~se

~~ ~b. Justify why the Water Chemistry Program by itself would provide adequate aging management for those components.

1AMRA002 IAMRA0O3 3.1 ic. Explain if the components are included within the scope of the ISI Program. If so, clarify under what examination category are they included?d. Describe any site-specific or industry operating experience with regard to failure of these components that has been identified by WCGS.GALL Report, Volume 2, Item IV.A2- !(a) The vessel flange leak detection line is addressed by the RV Closure 5, lists a vessel flange leak detection

!Head (O-Ring Leak Monitoring Tubes) in LRA Table 2.3.1-1. It is made of line and recommends a plant- inickel alloy, thus is not associated with GALL Report, Volume 2, Item specific AMP be evaluated.

This line IV.A2-5, which is based on the material of stainless steel. The RV Closure references to GALL, Volume 1, Head (O-Ring Leak Monitoring Tubes) is evaluated with GALL Report, Table 1, Line 23. LRA Table 3.1.1, Volume 2, Items IV.A2-14 and IV.A2-18 (see LRA Table 3.1.2-1, page 3.1-item 3.1.1.23, identifies the ASME 43), and is referenced to LRA Table 3.1.1, items 3.1.1.83 and itemsSection XI 151, Subsections IWB, 3.1.1.65, respectively.

IWC and IWD, and Water Chemistry as the plant-specific AMPs. (b) High Pressure Conduits are the guide tubes that enclose the flux However, item 3.1.1.23 only thimble tubes from the bottom of the vessel and provide a pressure identifies the following components:

boundary function for the reactor coolant system."RV penetrations (instrument tubes (top head), high pressure conduits)" a. Explain why the LRA does not include a vessel flange leak 13.1!detection line in this item b. Explain the function and configuration of the components identified as_'highpressure conduits'GALL Report, Volume 2, items IV.A2-6, IV.A2-7 and IV.A2-8, lists three aging effects for the "control rod drive head penetration

-flange Based on the description of the reactor vessel closure head in USAR 5.3.3.1 and CRDM housing in USAR 3.9(N).4.1, the lower portion of latch ,housings are seal-welded to the vessel closure head adapters.

GALL Report, Volume 2, items IV.A2-6, IV.A2-7 and IV.A2-8, for the "control rod 74 IQuestion No I7JLRA Seci I j Au~dit Question I Final Response bolting" and identifies the AMP as drive head penetration

-flange bolting" are not applicable to WCGS.XI.M18, "Bolting Integrity." However, comparable line items have not been found in LRA Table 3.1.2-1: a. Explain why comparable line items for control rod drive head penetration

-flange bolting is not included in LRA Table 3.1.2-1.b. If there are comparable line items for control rod drive head penetration

-flange bolting, please identify the material, environment, aging effect(s) and AMP for these components at WCGS.GALL Report, Volume 2, item IV.A2- GALL Report, Volume 2, item IV.A2-10, is a line for material of CASS with 10, provides the MEAP combination aging effect of cracking.

The following components of the "control rod for component "control rod drive drive head penetration

-pressure housing" are not CASS and IV.A2-10 is head penetration

-pressure not applicable for "control rod drive head penetration

-pressure housing" housing." However, the LRA does of WCGS: not contain a comparable line.(1) Latch Housing, Travel Housing, CRDM Cap and CRDM Flange are a. Explain why WCGS does not have made of SA-182, F304 stainless steel. The corresponding GALL lines for a line comparable to the one in the the applicable aging effects are IV.A2-11 and IV.A2-14.GALL Report.AMRA004 3.1 AMRA005 3.1 GALL Section XI.M12, "Thermal Aging Embrittlement of CASS," states that for low molybdenum content (0.5 wt percent max.) steels, only static-cast steels with more than 20 percent ferrite are potentially susceptible to thermal embrittlement.

The discussion in LRA Table 3.1.1, line 3.1.1.57, states that this aging effect is not applicable at WCGS because the molybdenum and ferrite values are below the threshold for thermal aging embrittlement.

(2) CRDM Tubes are made of nickel alloy and the corresponding GALL lines for the applicable aging effects are IV.A2-9 and IV.A2-14.The WCGS reactor coolant loop pipe fittings are static castings.

The WCGS reactor coolant loop straight piping sections are centrifugal casings.The actual maximum reported molybdenum and ferrite values for static cast CASS Class 1 piping at WCGS are 0.35% molybdenum and .19.5%ferrite. WCGS Certified Material Test Reports supporting the limiting values of molybdenum and ferrite content of CASS Class 1 piping at WCGS were made available for NRC review during the site visit.75 L66eston No IKRA SepcV Audit Qu;est Iion Finj ~ ~ ~ al Respoone 7 1,AMRA006 i.1 The LRA states (Note 2, page 3.1-94) that WCGS Certified Material Test Reports support the limiting values of molybdenum and ferrite content of CASS Class 1 piping at WCGS.What are the actual maximum reported molybdenum and ferrite values for static cast CASS Class 1 piping at WCGS? Provide a copy of the supporting documentation for review during the site visit.*~.... .r v! d rng e t .... ....... ........ .. .---- ----Lines in LRA Table 3.1.2-2 for piping and valves made of stainless steel in a demineralized water (treated water) environment have an aging!effect of "loss of material due to pitting and crevice corrosion" and the effect is managed by the Water Chemistry and One-Time Inspection Programs.

These lines appear to have the same component and MEAP combinations as GALL Report, line V.C-4. However, LRA Table 3.1.2-2 refers to Note G inrqif-nfin f4nh t hin onvirnnmanf ic nn4+The Lines in LRA Table 3.1.2-2 for piping and valves made of stainless steel in a demineralized water in LRA Table 3.1.2-2 (the last line in page 3.1-76 and the last line in page 3.1-91) will be amended with the new lines using GALL Report, line V.C-4 and the Note changed to D.AMRA007 3.1 in the GALL Report for this component and material.Explain why Note G was used for these lines in the LRA.LRA Table 3.1.2-2 does not appear (a) The material of the subject components are not nickel alloy or nickel to include a line that is comparable alloy cladding.

Thus GALL Report, Volume 2, item IV.C2-21 is not to GALL Report, Volume 2, item applicable to these components of WCGS.IV.C2-21, which includes pressurizer instrumentation penetrations, heater I(b) The subject components of WCGS are within the scope of license sheaths and sleeves, etc. Irenewal and are evaluated in LRA Table 3.1.2-2 from page 3.1-81(the last Iline) to page 3.1-85 (the first line).a. Explain why WCGS does not have I a line comparable to the one in the ,GALL Report.76

[Qqqestio'n o, 'LRA Sec j AMRA008 3.1 AMRA009 3.1 , Audilt Question I Final R0spon->, I b. If the components listed in GALL Report, Volume 2, item IV.C2-21, are within the scope of license renewal at WCGS, please provide the AMR results.Provide a technical or CLB reference to support the following statement from LRA Table 3.1.1, item 3.1.1.80: "WCGS reactor vessel internals are forged stainless steel not cast austenitic stainless steel." LRA Table 3.1.2-2 has several components (corresponding to GALL Report, Volume 2, item IV.C2-22)associated with the pressurizer relief tank which references LRA Table 3.1.1, item 3.1.1-68.

These components can be divided into two categories with respect to AMPs identified in the LRA. One category is those that are managed by the ASME Section Xl ISI, Subsections IWB, IWC and IWD and the Water Chemistry Programs.

These components reference Note D, and the AMPs (with exceptions) are consistent with the GALL Report recommendations.

The other LRA Table 3.1.1, item 3.1.1.80 is a roll-up summary for the applicable

!GALL lines IV.B2-21 and IV.B2-37.!GALL lines IV.B2-21 is for aging evaluation of (1) Lower Support Casting land (2) Lower Support Plate Columns. The lower support assembly of WCGS is equipped with Lower Support Forging instead of Lower Support Casting. Based on Design Specification for Nuclear Reactor Internals, M-703-00207, the Lower Support Forging and the Lower Support Plate Columns are designed with 300 series stainless steel. Thus the GALL line IV.B2-21 is not applicable to WCGS.'GALL lines IV.B2-37 is for aging evaluation of. Upper Support Columns.Based on Design Specification for Nuclear Reactor Internals, M-703-00207, the Upper Support Plate Columns are designed with 300 series stainless steel. Thus the GALL line IV. B2-37 is not applicable to WCGS.In summary, CASS is not applicable to the subject components and the GALL lines IV.B2-21 and IV.B82-37 are not applicable to WCGS. Thus, LRA Table 3..1. 1, item 3.1.1.80 is also not applicable to WCGS.The affected items of LRA Table 3.1.2-2 regarding non-ASME components of Stainless Steel in the environment of Treated Borated Water for aging effect of Cracking are: (1) Component Type of Flow Element with Intended Function of LBS in page 3.1-73.(2) Component Type of Piping with Intended Function of SIA and LBS in page 3.1-78..(3) Component Type of Pressurizer Relief Tank with Intended Function of SIA in page 3.1-79.(4) Component Type of Rupture Disc with Intended Function of LBS in page 3.1-88.(5) Component Type of Thermowell with Intended Function of LBS in page 3.1-90.(6) Component Type of Valve with Intended Function of LBS and SIA in page 3.1-93.77

-Question No ~LRA Sec 3/4 Audit Question F inial Response category of components are those For these components, the aging evaluation for the aging effect of that are managed by the Water Cracking due to SCC will use GALL line V.D1-31 which relies on Water Chemistry Program only. These Chemistry for managing the aging effect of Cracking.components reference Notes E and!1. Note 1 explains that these are not LRA Table 3.1.2-2 will be amended to use GALL line V.D1-31 for the ASME Section XI components; above listed lines. The Standard Note will be "B" instead of "E" and Plant therefore, the ASME Section XI ISI Specific Note #1 following Table 3.1.2-2 will be changed to indicate #1 is AMP will not be used. not used, without renumbering other Specific Notes.a. For the components managed only by the Water Chemistry Program, provide a technical justification to support that the Water i Chemistry Program by itself provides adequate aging 'management during the period of extended operation.

lb. Provide a justification for not performing an inspection to confirm the effectiveness of the Water Chemistry Program to manage the aging° effect of cracking..

... _AMRA010 3. 1 GALL Report, item IV.C2-1 1, is (a) As defined at the end of LRA Table 3.1.2-2, Note 0 is used for the described as "piping, piping !cases where the subject components are different from the subject GALL components, and piping elements." item, but consistent with the GALL item for material, environment, and The comparable line item in LRA laging effect. AMP takes some exceptions to GALL AMP. Copper-Nickel is Table 3.1.2-2 (page 3.1-74) is "heat a type of copper alloy, thus the material, environment and aging effect are exchanger tube side (HX # 3, 4, 6, 7, consistent with GALL IV.C2-1 1. The AMP of Closed-Cycle Cooling Water 8)" for the reactor coolant pump i System is credited for aging management.

According to LRA Section bearing heat exchangers.

i B2.1.10, WCGS AMP of Closed-Cycle Cooling Water System is consistent

!with exception to GALL,Section XI.M21, "Closed-Cycle Cooling Water." a. Justify the reference to Note D for Since heat exchanger tube is not included in the definition of "piping, this line item. piping components, and piping elements" in GALL Table IX.B, Standard_Note D is selected.AMRA01 1 3.1 In the LRA tables 3.1.2-X, there is no (a) LRA Table 3.1.1 items 54 and 56 are the summary of aging evaluation component line item similar to GALL regarding GALL items IV.C2-1 land IV.C2-12 for copper alloy components Report, item IV.C2-12.

The in Reactor Coolant system. It does not include all in-scope copper alloy discussion in LRA Table 3.1.1.56 components exposed to closed cycle cooling water at WCGS. There are states that WCGS does not have copper alloy components of Auxiliary System addressed in LRA Section copper alloy components (more than 3.3 that are exposed to closed cycle cooling water. They are summarized 15 percent Zn) exposed to closed in LRA Table 3.3.1, items 51and 84.-... -----------.--....-.....

c................

--c °°le cooling w ater w ithin the sco pe ..78 Question No I..RA Sec I Audit Question Finl ... .F Res onse ..of license renewal. (b) The subject copper alloy components in Reactor Coolant system are cooling tubes for RCP pump motor air cooling and bearing oil cooling. The a. Confirm that the components that material is copper-nickel of ASME Spec SB-111-706 and SB-171-706.

references to LRA, item 3.1.1.54, are The reference of the material is QR-54586 (Quality Release/Certification the only in-scope copper alloy [of Compliance).

components exposed to closed cycle cooling water at WCGS.AMRA012 3.1 b. Explain, what documentation supports a determination that the copper alloy in these components contains less than 15 percent Zn.GALL Report, item IV.C2-18, I.(a) (b) As described in WCGS USAR, Section 5.4.10.4, the weld between identifies the ASME Section Xl ISI, the surge nozzle to the pressurizer lower head is designed and Subsections IWB, IWC and IWD and constructed to present a smooth transition surface for ultrasonic inspectionI Water Chemistry Programs as the to implement the requirements of the ISI program. As demonstrated by applicable AMPs for pressurizer

!the third interval ISI program plan, WCRE-16, Table 1 of BB system, the I components.

The LRA is consistent 1 UT inspection for the subject weld is scheduled for once for every ISI plan with the GALL Report in that it !interval, i.e., once every 10 years.identifies the same AMPs. However, the GALL Report includes a further I [c] The ISI category for the inspection of the weld between the surge discussion stating that the area of nozzle to the pressurizer lower head is B-D, Code Item number of B3.110.the weld metal between the surge nozzle and the lower vessel head is (d) No indications were found in the inspection of Refueling Outage 13 periodically inspected as part of the (the second ISI interval).

The inspection results were available during the ISI program. site audit.a. Confirm if WCGS performs periodic inspection in the area of the weld metal between the surge nozzle and the lower vessel head as part of the ISI program.b. Clarify, what is the periodicity of the inspection.

c. Clarify what is the ASME Section Xl examination category for this component.

d. Discuss any adverse indications ,found in the area of the described 79 Quesirq-i No IL~RA $Sec I A p-4 dit Q4uesi,4.6 Fh; naRs oý40 AMRA013 13.1 IAMRA014 13.1 weld and any repairs made or flaw indications found and evaluated as acceptable.

LRA Table 3.1.2-3 (page 3.1-101), contains two lines corresponding to GALL Report, item IV.D1-6. The component descriptions and MEAP combinations for both lines are identical and are consistent with the GALL Report. The only differences between the lines are the intended functions and the Notes. Explain why Note B is used for one of these lines and Note D is used with the second of these two lines.The LRA does not include a comparable line to GALL Report, item IV.D1-16, "steam generator structure

-tube support lattice bars." This is discussed in LRA Table 3.1.1, item 3.1.1.78, which states that "WCGS steam generator does not contain lattice bars, so the applicable NUREG-1 801 line was not used." In addition, the LRA does not include a component similar to that in GALL Report, item IV.D1-17, "steam generator structure

-tube support plate." a. Clarify if the WCGS steam generators include the lattice support bars identified in the GALL Report.If so, what are those components, and where are the AMR results discussed in the LRA.b. Clarify if the WCGS steam generators include a component comparable to GALL Report, item The subject items in LRA Table 3.1.2-3 (page 3.1-101) will be amended to clarify that (1) the item with a function of DF is the Primary Channel Divider Plate. It matches the component description of GALL Report, item IV.D1-6. With the exception of the "Water Chemistry" AMP, a Standard Note of "B" is used. (2) the item with a function of NSRS is the SG Primary Nozzle Closure Ring. It does not match the component description of GALL Report, item IV.D1-6. With the exception of the "Water Chemistry" AMP, a Standard Note of "D" is used.The last item in page 3.1-100 with a function of PB also needs to be amended to clarify that component is the Tubesheet

-Primary Face.(a) The steam generator of WCGS is a Westinghouse Model F design.There are no lattice support bars identified in WCGS USAR, the design specification, M-71 1-0011, or the stress analysis, M-711-0008.(b) WCGS steam generators include a component comparable to GALL Report, item IV. D1-17, "steam generator structure

-tube support plate" and is addressed in LRA Table 3.1.2-3, page 3.1-108. The material is stainless steel instead of carbon steel used in GALL Report, item IV.D1-17. This issue of ligament cracking was identified in Supplement i to NRC IN 96-09 and applicable to the plants with carbon steel support plates.WCGS steam generator tube support plate is made of stainless steel, thus ligament cracking is not an applicable aging effect.80 I Question No I LRA Sec IQuestioni Final Resoonse i I ~QuostIonNo l~ LRA Sec~ '~Au7dIt1Question

~Finat~F~esoonse~

AMRA015 13.1 IV.D1-17, "steam generator structure-tube support plate," that might be subject to the aging effect of ligament cracking due to corrosion.

In the LRA Table 3.1.2-3, page 3.1- The AMPs of "Steam Generator Tube Integrity and Water Chemistry 97, there are two line items Programs" are credited for managing the aging effect of wall thinning of corresponding to GALL Report, item the feedrings.

As indicated in LRA Section 3.1.2.2.14, the AMPs are IV.D1-26, "steam generator feed ring conservatively credited to manage wall thinning of feedrings although wall made of carbon steel," with internal !thinning is not applicable to Model F steam generators.

and external environments of"secondary water" for which the To clarify, the Plant Specific Note 1 for LRA Table 3.1.2-3 will be amended aging effect is wall thinning.

The to indicate "no further evaluation is recommended" instead of "no further GALL Report recommends a plant- action is required" at the end of the statements.

specific AMP be evaluated for this component, material, environment The Steam Generator Tube Integrity and Water Chemistry Programs are and aging effect combination.

The sufficient to manage the aging effect of wall thinning in the steam AMPs listed in the LRA for these generator feed ring during the period of extended operation based on lines are the Steam Generator Tube GALL item IV.D1-16, which credits the AMPs of the Steam Generator Integrity and Water Chemistry Tube Integrity and Water Chemistry Programs to manage the aging effect Programs.

The Notes associated of wall thinning for the same material and environment, with these lines are E and 1. Note 1 states, "Feedring wall thinning was described in NRC IN 91-19. This aging has been detected only in certain CE System 80 Steam Generators.

The WCGS steam generators are Westinghouse Model F. No plant specific experience at WCGS or other units with Model F steam generators suggests wall thinning of the Model F is occurring.

Therefore WCGS has determined this condition is not applicable and no further action is needed." It is not clear whether WCGS is crediting the listed AMPs for managing the aging effect of wall thinning in the components during the period of extended operation.

If the AMPs are being credited, then Note A would seem appropriate

.._._.__ ...._._.......

81 IQuestion No 4RA Sec 1AMRA016 3.1 Audit Question ~~~rather than Note 1. If the AMPs are not being credited, then it is not cleary why they are listed on the applicable lines in LRA Table 3.1.2-3.Explain why the Steam Generator Tube Integrity and Water Chemistry Programs are sufficient to manage the aging effect of wall thinning in the steam generator feed ring during the period of extended operation.

Please justify your response.LRA Section 3.1.2.2.16.1 states that control rod drive mechanism and pressurizer components are stainless steel [not nickel alloy] for WCGS and; therefore, no additional commitments or further evaluation are required.a. LRA Section 3.1.2.2.16.1 is titled"steam generator heads, tube sheets, and welds made or clad with stainless steel." Explain why control rod drive mechanisms and p pressurizer components are discussed in this subsection.(a) Based on items #34 and #35 of NUREG-1800, Table 3.1-1, Further Evaluation recommended in NUREG-1800, subsection 3.1.2.2.16.1 is addressed in items #34 and #35 of LRA Table 3.1.1. The details are provided in LRA Section 3.1.2.2.16.1.

Item #35 is applicable to once-through steam generator only. Pressurizer components are not involved i either item #34 or #35 of LRA Table 3.1.1. To clarify, LRA Section 3.1.2.2.16.1 will be amended: n~><~ < ~ Final~e R;Ionse (1) The title of LRA Section 3.1.2.2.16.1 will read "Cracking on steam generator heads, tube sheets, control rod drive head penetration pressure housings and welds." (2) The statement will read "These control rod drive mechanism housings are stainless steel for WCGS, therefore no additional commitments or further evaluation is required." t JAMRA017 3.2 b. Provide technical or CLB (3) Add the statement.of "WCGS has a recirculating steam generator, not documentation that supports the la once-through steam generator, so the further evaluation for steam.LRA statement that the control rod Igenerator components is not applicable to WCGS." drive mechanism and pressurizer components are stainless steel. (b) A copy of CLB document regarding CRDM housing was available Please have a copy or summary of Iduring site audit.that documentation for review at the site.LRA Table 3.2.2-2 designates Note a.) According to WCGS system flow drawings, the maximum temperature G for stainless steel piping, valves, !that the stainless steel containment spray system components exposed to and tanks in the containment spray a sodium hydroxide environment would experience is 125 F.system because the environment is not in the GALL Report for this b.) An internet search of the Hendrix Group Corrosion and Materials component and material..

.Technology Site lists stainless steel as a common material for use up to 82 1Qu~tonNo~.L~A!ecj~

Audit Q0iestion h ~Fin~l fjspohse.a. Provide the temperature range of operation for these components.

b. Provide references that indicate industry applications where there are no considerations for aging FollowupQuestion:

Provide source documents to substantiate max temp stainless steel in EN system is 125F for components.

a. Exposed to sodium hydroxide b. Internet search or Hendrix Ground corrosion

& Materials lists stainless steel as a common material for use up to 200F and 50% W NaOH.c. Evaluation of WCGS stainless steel components in EN system exposed to sodium hydroxide is consistant with VC summer LRA, Table 3.2-2, item 5.The GALL Report,Section V.Dl, does not include any nickel alloy components.

The applicant credits the Water Chemistry Program for managing loss of material caused by pitting and crevice corrosion.

The Water Chemistry Program effectively manages aging effect of loss of material of nickel alloys in treated borated water only when there is not any stagnant flow. Accumulators typically have low flow; therefore, additional action may be necessary to verify that long term corrosion is not occurring.

Explain what additional provisions WCGS will be taken to ensure that corrosion is not slowly progressing.

200F and 50%w NaOH. The aging effect and AMP were conservatively assigned.

The WCGS stainless steel containment spray components

exposed to a sodium hydroxide environment were evaluated consistent with the Virgil C. Summer license renewal application Table 3.2-2, AMR Item 5 and associated SER (NUREG-1787).

Follow up response: a) Piping Class Summary sheets for system EN (HPCI) show that the piping design temperature is 125 F. Piping normal operating temperature is listed as 100 F. The Tank Data Sheet for the Containment Spray Additive Tank (plant tag TEN01), indicates that the normal tank operating temperature is 120 F.b) Hendrix corrosion and material data was provided at the site audit.I Internet links to the pertinent data are: http://www.hghouston.com/naohtbl.html http ://www. hghouston.com/naoh.html

c) VC Summer LRA Table 3.2-2 was provided at the site audit.:Accumulator tank nickel alloy components in a treated borated water environment, require aging management of cracking and loss of material.The loss of material aging effect will be managed by the Water Chemistry AMP. The cracking aging effect will be managed by the Water Chemistry AMP augmented by the plant specific Nickel Alloys AMP. The plant:specific nickel alloy AMP periodically inspects the accumulator tank nickel alloy components.

Follow up response: The Water Chemistry AMP will be augmented by the One-Time Inspection AMP for verification that loss of material is not occurring in accumulator tank nickel-alloy components.

LRA Table 3.2.2-10 will be amended to include the One-Time Inspection AMP in addition to the Water Chemistry AMP for managing the aging effect of loss of material.

As a result, the One-Time Inspection program will include a One-time inspection of selected accumulator tank nickel-alloy components at susceptible locations.

1AMWRAO18i 43.2 83 I QqPiQn 0 1 LKA beýC.AMRAO19 13.3 i' ,,t soin Followup Question: The water chemistry AMP provides verification of the lack of LOM through the OTI program. However, the OTI AMP applicability does not provide for inspection of nickel-based alloys in treated borated water in the high pressure injection system. What actions are taken to verify that LOM is not occurring on the inside of nickel-based alloy com ponents?............

............

LRA Table 3.3.1, item 3.3.1.07, lists stainless steel non regenerative heat exchanger components exposed to treated borated water greater than 60C (greater than 140F). In the discussion column, the LRA states that "this line item is not applicable.

Other available applicable NUREG 1801 lines were used." Clarify if this means that WCGS does not have any non regenerative heat exchangers exposed to treated borated water greater than 60C (greater than 140F).uuesionIyo I'LKA c~" ~1 Fiual Response'The Letdown, Excess Letdown and Seal Water heat exchangers are exposed to treated borated water greater than 1400 F (tube-side) and Component Cooling Water (shell-side).

The shell-side is managed by the Closed-Cycle Cooling Water Program using item number 3.3.1.46.

The tube-side is managed by Water Chemistry and One-Time inspection Programs using item number 3.3.1.08.

The Closed-Cycle Cooling Water Program (B2. 1.10) includes eddy current testing for heat exchanger shell-side components exposed to Component Cooling Water. Radiation monitors are installed in each train of the Component Cooling Water System and alarm when abnormal radioactivity levels are detected.

Heat exchanger outlet temperature of the heat exchangers are not typically monitored, this was noted as a program exception to the Closed-Cycle Cooling Water Program.The LRA item number 3.3.1.07 discussion column will be amended to read the following: "Not applicable.

The Letdown, Excess Letdown and Seal Water heat exchangers are exposed to treated borated water greater than 140 F (tube-side) and Component Cooling Water (shell-side).

The shell-side is managed by the Closed-Cycle Cooling Water Program using item number 3.3.1.46.

The tube-side is managed by Water Chemistry and One-Time inspection Programs using item number 3.3.1.08.

The Closed-Cycle Cooling Water Program (B2. 1.10) includes eddy current testing for heat exchanger shell-side components exposed to Component Cooling Water.Radiation monitors are installed in each train of the Component Cooling Water System and alarm when abnormal radioactivity levels are detected.Heat exchanger outlet temperature of the heat exchangers are not typically monitored, this was noted as a program exception to the Closed-ýCycle Cooling Water Program." --------------

84

[ QuestioniNo I RA S0c 1AMRAO20 3.3 3.3 AMRA02 1 Audit Question IFinal Response LRA Table 3.3. 1, item 3.3.1.10, lists The high pressure pumps associated with the Chemical and Volume high strength steel closure bolting Control System are the Boric Acid Transfer Pumps, Normal Charging exposed to air with steam or water Pump, Centrifugal Charging Pumps, and Boron Injection Makeup Pump.leakage. Clarify what is the material Bolting for these pumps is stainless steel grades ASTM A564 Gr. 630 and of the closure bolting used in high ASTM Al194, Gr. 6.pressure pumps in the chemical and volume control system. _LRA Table 3.3.1, item 3.3.1 46, lists The Closed Cycle Cooling Water System Program is credited for stainless steel and stainless clad managing the aging effect of cracking due to SCC. QCP-20-518 is a steel piping, piping components, visual inspection procedure and prescribes visual examination piping elements, and heat exchanger requirements for the detection of cracking (and other indications).

The components exposed to closed cycle procedure documents "as-found" conditions, provides trend data to cooling water greater than 60C Iengineering, and where practical, creates video or photographic records of (greater than 140F). The Closed the examination.

Unacceptable conditions such as cracks are Cycle Cooling Water System documented through the corrective action program. The corrective action Program is credited for managing program would assess the components condition and any aging effects the aging effect of cracking due to would be evaluated.

SCC. One of the implementing procedures referenced in this OCP-20-518 will be revised to define cracking, provide additional program is QCP-20-518, Visual guidance for detection of cracking and specific acceptance criteria relating Examination of Heat Exchangers to "as-found" cracking.

A new commitment for this procedure revision was and Piping Components." However, added to the License Renewal Application listof regulatory commitments.

it is not clear how the use of this ,procedure will manage cracking as tin the definition section of this document, cracking is included under general corrosion.

Please clarify. -b 3 ---- -e 3- ----- ---- I- ...........

LRA Table 3.3.1, item 3.3.1.53, lists The piping in question is service air containment penetration piping and steel compressed air system piping, components on License Renewal Boundary Drawing LR-WCGS-KA-M-piping components, and piping 12KA02 (D-6). The containment isolation piping is safety-related but is elements exposed to condensation attached to non-safety related structural integrity attached (SIA) piping.(internal).

The LRA states that the 10 CFR 50 Appendix J Program is WCGS containment isolation valve testing test procedures pressurize the credited in lieu of the Compressed entire safety-related containment isolation piping section. Not only is Air Monitoring Program isolation valve seat leakage tested but the entire pressure boundary is recommended in the GALL Report to tested. The safety-related piping and valves are in-scope for pressure manage the aging effect of loss of boundary.

10 CFR 50 Appendix J Program testing of containment material due to general corrosion for isolation piping and valves provides a positive means for detection of loss containment isolation piping and Iof pressure boundary integrity intended function.valves. The 10 CFR 50 Appendix J Program onlyeensures that the [The`LRA will be amended to add AMP XI.M38 (Inspection of Internal AMRA022 3.3 85 IQue.tion No

... t.question Fiinl JAMRA023 3.3 containment isolation valve does not leak through the seat and performs the containment isolation function.The visual inspection performed in this AMP only detects aging in the external surface, not in the internal surface, of piping and valves. Please explain how loss of material on the inside surface of piping and valves will be detected. (This item applies t(LRA Table 3.3.2.6, compressed air system, for containment isolation piping and valves).LRA Table 3.3.1, item 3.3.1.68, states that this line is consistent with the GALL Report except that a different AMP is credited to manage steel piping, piping components, and piping elements with internal surfaces exposed to raw water. The LRA states that the Fire Water System Program will be credited in conjunction with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effects. This corresponds to several line items in LRA Table 3.3.2-14 for the fire protection system for which Note E is referenced.

Explain how these two programs are lused in conjunction to manage these aging effects.t Surfaces in Miscellaneous Piping and Ducting Components) for loss of material inspection of the service air containment penetration piping internal surfaces.

Credit will be taken for both the 10 CFR 50 Appendix J Program testing and AMP XI.M38 internal inspection.

!The Fire Water System program manages loss of material for water-based afire protection systems. Periodic hydrant inspections, fire main flushing, sprinkler inspections, and flow tests considering National Fire Protection Association (NFPA) codes and standards ensure that the water-based fire protection systems are capable of performing their intended functions.

The Fire Water System program conducts an air or water flow test through each open head spray/sprinkler rozzle to verify that each open head spray/sprinkler nozzle is unobstructed.

The Fire Water System program tests a representative sample of fire protection sprinkler heads or replaces those that have been in service for 50 years, using the guidance of NFPA 25 2002 Edition, and tests at 10 year intervals thereafter during the period of extended operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.Visual inspections evaluating wall thickness to identify evidence of loss Of material due to corrosion, ensuring against catastrophic failure, are covered by the aging management program XI.M38 "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components".

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP manages cracking, loss of material and hardening

-loss of strength for components whose internal inspections are not covered by other aging management programs.

Thus, the Fire Water System program internal visual inspections are covered by the Internal Inspection program. Other inspections such as, fire detection and suppression testing and maintenance, yard fire hydrant inspections and flushing, powerblock fire hose testing, hose station gasket inspections andI sprinkler/spray nozzle inspections are covered by the Fire Protection program.86 Qusto No LRA Sec A ;udit Question IFinal Res~pons~e

'AMRA024 AMRAO25 3.3 3.3 In LRA Table 3.3.2-1, fuel storage and handling system, the applicant credited the Structures Monitoring Program to manage the aging effect of loss of material for carbon steel new fuel racks in a plant indoor air -external environment.

This AMP references implementing procedure Al 23M-007; however, the procedure does not specifically identify new fuel racks in the component or structure list. Identify where are the new fuel racks listed as within the scope of the Structures Monitoring Program.In LRA Table 3.3.2-2, fuel pool cooling and cleanup system, the applicant credited the Closed Cycle Cooling Water System Program to manage the aging effects of loss of material and reduction of heat transfer for piping, thermowell, valves, and heat exchanger components in a closed cycle cooling water internal and external environment.

However, the fuel pool cooling and cleanup system is not included within the scope of the Closed Cycle Cooling Water System Program. Please clarify.Internal visual inspections will be conducted during periodic maintenance, surveillance testing and corrective maintenance to the fire protection system components in the program.WCGS carbon steel fuel racks are evaluated as structural steel, consistent with NUREG-1801 line VII.A1-1.

The scope of Al 23M-007 applies to structures, passive components and civil engineering features in-scope for the Maintenance Rule and additional structures and components in-scope Ifor License Renewal. Although the new fuel racks are not specifically listed in the procedure, the carbon steel new fuel racks are included with procedure Al 23M-007 Attachment C, Fuel Building structural steel components.

The component cooling water system provides closed cycle cooling water to the fuel pool cooling and cleanup system. According to the WCGS Strategic Closed Cooling Water Chemistry Plan, "The component cooling water systems (CCWs), A and B systems, are closed loop systems designed to remove heat from various plant components during plant operation, plant cool-down and during post accident conditions." The component cooling water system in the scope of the Closed Cycle Cooling Water System AMP and the associated WCGS Strategic Closed Cycle Cooling Water Chemistry Plan refer to all components that receive component cooling water.The Closed Cycle Cooling Water System AMP will be used to manage fuel pool cooling and cleanup system components within the scope of license renewal that receive closed cycle cooling water from the component cooling water system.A STARS License Renewal Project Change Tracking Form (PCTF-0179) was created to revise the 10 element review for AMP B2. 1.10 as follows: The program is credited with managing the aging of components that are exposed to closed cycle cooling water. (

Reference:

Strategic Closed Cycle!I Cooling Water Chemistry Plan, Sections 2.0, 7.0, 8.0, 9.0, and 12.0):-Component Cooling Water (CCW)Emergency Diesel Engine (EDE) Cooling Water System P -Plant Heating*__J 87 IQuestionJ No ILRA Sec I Audit Quiestion 7- F ' in~alResponse~

~AM. A3...............

3 1AMRA026 13.3-Central Chilled Water System *-Miscellaneous Buildings HVAC* **-Fuel Building HVAC * **Control Building HVAC *, **Auxiliary Building HVAC *, **-Containment Purge HVAC *, **,- Reactor Coolant System Chemical & Volume Control System-Fuel Pool Cooling and Cleanup System Residual Heat Removal System High Pressure Coolant Injection System Central Chilled Water System*Liquid Radwaste System........ .... .... -Nuclear Samplinga System.In LRA Table 3.3.2-7, chemical and iThe component cooling water system provides closed cycle cooling water volume control system, the applicant Ito the chemical and volume control system. According to the WCGS credited the Closed Cycle Cooling Strategic Closed Cooling Water Chemistry Plan, "The component cooling Water System Program to manage water systems (CCWs), A and B systems, are closed loop systems the aging effects of loss of material, designed to remove heat from various plant components during plant reduction of heat transfer and operation, plant cool-down and during post accident conditions." The cracking for several stainless steel component cooling water system in the scope of the Closed Cycle Cooling components in a closed cycle Water System AMP and the associated WCGS Strategic Closed Cycle cooling water internal and external Cooling Water Chemistry Plan refer to all components that receive environment.

However, the chemical component cooling water.and volume control system is not I included within the scope of the The Closed Cycle Cooling Water System AMP will be used to manage Closed Cycle Cooling Water System chemical and volume control system components within the scope of Program. Please clarify, license renewal that receive closed cycle cooling water from the 1component cooling water system.A STARS License Renewal Project Change Tracking Form (PCTF-01 79)was created to revise the 10 element review for AMP B2.1.10 as follows: The program is credited with managing the aging of components that are exposed to closed cycle cooling water. (

Reference:

Strategic Closed Cycle Cooling Water Chemistry Plan, Sections 2.0, 7.0, 8.0, 9.0, and 12.0):-Component Cooling Water (CCW)-Emergency Diesel Engine (EDE) Cooling Water System-Plant Heating *-Central Chilled Water System*Miscellaneous Buildings HVAC *, **I- Fuel Building HVAC* **88 iQesttion No I iR < :Sec:I Audit Question I Final Res pnse I AMRA027 3.3 IAMRA028 3.3 In LRA Table 3.3.2-7, chemical and volume control system, the applicant referenced Note I for stainless steel heat exchanger components in an internal environment of treated borated water and has also referenced a GALL Report, Volume 2 item, and a Table 1 item. However, Note I is not defined at the legend of Table 3.3.2.7. Since Note I implies that this line item is not consistent with the GALL Report, please clarify why a GALL Report, Volume 2 item, and a Table 1 item is referenced for these Notes.In LRA Table 3.3.2-7, chemical and volume control system, the applicant referenced Notes G and 1, which implies that these items are not consistent with the GALL Report, for Ian MEAP combination of copper lalloy (brass copper less than 85 percent) in an external environment of plant indoor air with no aging effects and no AMP credited.However, in other tables the applicant references Note A for the same MEAP combination.

I For example: ia. In LRA Table 3.3.2-14, this-Control Building HVAC *, **-Auxiliary Building HVAC **Containment Purge HVAC *, **Reactor Coolant System 7 Chemical & Volume Control System-Fuel Pool Cooling and Cleanup System Residual Heat Removal System High Pressure Coolant Injection System-Central Chilled Water System*-Liquid Radwaste System-Nuclear Sampling System Note i1 Aging effect in NUREG-1 801 for this component, material and environment combination is not applicable.

No vessel, tank, pump, or heat exchanger designs at WCGS are ,supported by TLAAs as defined in 10 CFR 54.3 except ASME Class 1 ,components and the Class 2 portions of the steam generators.

The design of this WCGS component is therefore not supported by TLAAs.The LRA Table 3.3.2-7 will be amended as follows: Delete TLAA Line with component type of Heat Exchanger (HX # 45, 46, 47, 49, 51, 52, 53, 54, 55, 6, 57, 58, 59, 60, 61, 62, 63, 64, 65, 66, 67, 68)land Notes I and 7.LRA Table 3.3.2-7 will be amended to reference Note A and GALL Report Item VIII.I-2.LRA Table 3.3.2-16 will be amended to reference Note A and GALL ,'Report Item VIII.I-2.LRA Table 3.3.2-14 remains unchanged and currently references Note A and GALL Report Item VIII.I-2.

The existing note definitions will be Samended to update and make consistent.

i 89 I[Question No [ LRA Sec IA~udit ueti7Qfh ,combination references Note A and GALL Report, item VIII.I 2 b. In LRA Table 3.3.2-7, this combination references Note 1 stating that "This non NUREG-1801 line was used to account for copper alloy in plant indoor air (external) in the chemical and volume control system. See precedent of NUREG 1801, line VIII.l 2" c. In LRA Table 3.3.2-16, this combination references Notes G and 3 iAlthough it is the same combination, the staff notes that the definition of Note 3 in LRA Table 3.3.2-16 is Idifferent than the definition of Note 1 in LRA Table 3.3.2-7. Also, the staff notes that the applicant uses different notes (A or G) for the same combination.

If the same MEAP combination is applicable, explain why Note A is not used consistently.

Clarify this discrepancy and justify 1 your response.In LRA Table 3.3.2-9, control building HVAC system, the applicant referenced Note I for elastomer flex'connectors in an environment of plant indoor air and ventilation atmosphere and referenced a GALL Report item and a Table 1 item.Since Note I implies that this line item is not consistent with the GALL report, clarify why a GALL Report item and a Table 1 item is referenced.

FiqI aRqsp~onse rAM-RA029 3.3 Flexible connectors for the Control Building HVAC system are synthetic elastomers (neoprene) in an environment of air-indoor-uncontrolled.

The general thermal environment in the Control Building is maintained less than 95 F.The aging effect listed for GALL line VII.F1-7 is hardening and loss of strength / elastomer degradation.

NUREG-1801 Chapter IX.C, defines Elastomers as "materials rubber, EPT, EPDM, PTFE, ETFE, viton, vitril, neoprene, and silicone elastomer.

Hardening and loss of strength of elastomers can be induced by elevated temperature (over about 95°F (35 0 C), and additional aging factors such as exposure to ozone, oxidation, and radiation." NUREG-1801, Chapter IX.D, has a definition for Air-indoor-uncontrolled

(>95 F). This definition discusses the temperature threshold for elastomer thermal aging, "If ambient is <95°F, then any resultant thermal aging of organic materials can be considered to beover the 60-yr period of interest." The EPRI guideline, Non-90 I 6uptip N; [ LRA Soc& IJ Audit Quiestion Final Respoinse___

Class 1 Mechanical Implementation Guideline and Mechanical Tools, Appendix D Section 2.1.8 states in part that, "synthetic rubbers are not affected by ozone and are typically much more resistant to sunlight (or other forms of ultraviolet radiation)." NUREG-1801 GALL line VII.F1-7 specifies hardening and loss of strength as the aging mechanism.

However the GALL also states that if the temperature threshold is not exceeded, that elastomer thermal aging is insignificant.

The EPRI guide states that synthetic rubbers such as neoprene are not affected by ozone, sunlight or other forms of ultraviolet radiation.

Thus, hardening and loss of strength of the Control Building I HVAC flexible connectors is not expected.The LRA will be amended as follows:-LRA Table 3.3.2-9, Control Building HVAC System, Component Type"Flexible Connectors" will be amended to eliminate reference to GALL line VII.F1-7.

A Non-GALL row will be created. The Non-GALL row will have the identical material, environment, aging effect and AMP as currently listed for the flexible connectors.

Notation will also be included describing 1why these elastomers are not subject to hardening (similar to discussion above).-LRA Table 3.3.1 item 3.3.1.11 will be amended to remove discussion of the exception to NUREG-1801 forq Control Building Flexible Connectors.

Note A was inadvertently used. Unlike other carbon steel ventilation components, it is unlikely that an adsorber would have condensation as an internal environment.

The adsorbers 1st stage contain moisture separators to ensure moisture does not impregnate the charcoal filters.Therefore, a separate plant specific aging evaluation was created.AMRA030 3.3 AMRA031 3.3 In LRA Table 3.3.2-10, fuel building HVAC system, the applicant referenced Note A for carbon steel adsorber in an internal environment of ventilation atmosphere; however, a GALL Report item and a Table 1 item were not referenced.

Note A The LRA will be amended as follows: implies that this line is consistent LRA Table 3.3.2-10, Fuel Building HVAC System, Component Type with the GALL Report. Therefore, if "Adsorber" will be amended to use note "G" in lieu of note "A". A plant the line is consistent with the GALL specific note will be added that states, "GALL row VII.F2-3 has an internal Report, identify the GALL Report environment of condensation.

Unlike other carbon steel ventilation and the Table 1 items. If the line is components, it is unlikely that an adsorber would have condensation as an not consistent, clarify the internal environment.

The adsorbers 1st stage contain moisture discrepancy.

separators to ensure moisture does not impregnate the charcoal filters.Therefore, a separate (non condensation) row needed to be created since_ _ _ _ the ventilation atmosphere is dry and no aging effects are expected." In LRA Table 3.3.2-16, emergency Note D was incorrectly used. GALL does not consider reduction of heat diesel engine system, the applicant transfer/fouling for copper alloy heat exchanger tubes in lubricating oil.jreferenced Note D for copper alloy Therefore, a separate plant specific aging evaluation was created.91 Qiist;oNo iLRA Sec Audit Quesion Finl1 Rep5oner ..AMRA032 13.3 heat exchanger component in an external environment of lube oil;however, a GALL Report item and a Table 1 item were not referenced.

Note D implies that this line is consistent with the GALL Report.Therefore, if the line is consistent with the GALL Report, identify the GALL Report and the Table 1 items.If the line is not consistent, clarify the discrepancy.

In LRA Table 3.3.2-16, emergency diesel engine system, the applicant referenced Note A for stainless steel valve in an internal environment of wetted gas; however, a GALL Report item and a Table 1 item were not referenced.

Note A implies that this line is consistent with the GALL Report. Therefore, if the line is consistent with the GALL Report, identify the GALL Report and the Table 1 items. If the line is not consistent, clarify the discrepancy.

In LRA Table 3.3.2-16, emergency diesel engine system, the applicant credited the Open Cycle Cooling Water System Program to manage the aging effect of loss of material for carbon steel piping and valves in an environment of raw water. However, the Open Cycle Cooling Water System Program includes standby diesel engine within the scope of the program, but not the emergency diesel engine system. Clarify if the standby diesel engine is considered as part of the emergency diesel engine system. Explain why the emergency diesel engine system is not included within the scope of this..program.The LRA will be amended as follows: LRA Table 3.3.2-16, Emergency Diesel Engine System, Component Type"Heat Exchanger Tube Side HX#1 50) will be amended to use note "H,4" in lieu of note "D,4". Plant specific note #4 already exists for this row. No changes to the existing plant specific note are required.Note A was incorrectly assigned to this non-GALL aging evaluation line.The LRA will be amended as follows: ILRA Table 3.3.2-16, Emergency Diesel Engine System, Component Type!"Valve", environment "wetted gas" will be amended to use note "G, 1" in!lieu of note "A, 1". Plant specific note #1 already exists for this row. No changes to the existing plant specific note are required.The Emergency Diesel Engine System is also known as the Standby Diesel Engine System. LRA Section 2.3.3.16 states this fact in the first sentence of the system description.

AMRA033 3.3 92 question No I L.A Sec I .Audit Q -e"tion I , ,Final Res. nse ..1AMRA034 13.3 In LRA Table 3.3.2-17, floor and The stainless steel reactor coolant pump drain tank receives lubricatin equipment drains system, the leakage from the reactor coolant pump motors. The Inspection of Inte applicant credited the Inspection of ISurfaces in Miscellaneous Piping and Ducting Components AMP will Internal Surfaces in Miscellaneous Imanage the loss of material due to pitting and crevice corrosion for Piping and Ducting Components ,stainless steel components in a lubricating oil environment by visual Program in lieu of the Lubricating Oil inspections for loss of material.

If internal inspections detect loss of Analysis and One Time Inspection material, the aging would be resolved via the WCGS corrective action Programs to manage loss of material program.in stainless steel tanks. The bottom I of the tanks are very susceptible to ;See also AMRA038.this aging effect. Clarify if the credited program will include wall thickness measurement of the bottom of the tanks.In LRA Tables 3.3.2-8, 3.3.2-9, The heat exchanger tube side components assigned to the External 3.3.2-10, and 3.3.2-12 reference Surfaces Monitoring Program are not heat exchanger tubes, but the h4 Note E and GALL Report item exchanger header assembly.

This assembly protrudes through the g oil rnal IAMRA035 3.3 eat VII.F2-14 for copper and copper nickel heat exchanger tube side component.

These tables also credit the External Surfaces Monitoring Program to manage loss of material in an external environment of plant indoor air. The GALL Report recommends a plant specific AMP for item VII.F2 14. The External Surfaces Monitoring Program description states that visual inspections conducted during system engineer walkdowns are used to identify aging effects. The external surface of heat exchanger tubes would normally be inside the heat exchanger shell and would not be visible during a typical system engineer walkdown.

Clarify how a visual inspection during a system walkdown would identify this aging effect. (Please note that LRA Table 3.3.2 5 for the same component and material in a similar external environment, credits the Inspection ductwork and connects to the cooling water supply. Drawings M618-0001 and M618-0002 show typical details of the coil and header assembly.Review of the drawings show that the header assembly only protrudes approximately 3" outside of the ducting. This is the location of the flanged header and where it is connected to plant cooling water piping. Thus, the majority of the header assembly is located inside the ducting. LRA Tables 3.3.2-8, 3.3.2-9, 3.3.2-10 and 3.3.2-12 will be amended to place these components in an environment of Ventilation Atmosphere (external) and assign the Inspection of Internal surfaces in Miscellaneous Piping and Ducting ComponentsProgram as the aging management program. The following components are affected: Auxiliary Building HVAC System (GL) -LRA Table 3.3.2-8 1 GALL VII. F2-14 -Heat Exchanger Tube Side (HX# 93,95,97,99,101,103)

Component Component Name No.SGL09A-02 SAFETY INJECTION PUMP ROOM COOLER HEAD sGL-0913-02, SAF..ETY.INJ.E.CTIO.NPU.MP RO. OM COOLE-R'HE'AD.)

SGL10A-02 IHl PUMP ROOM COOLER HEAD SGL1OB-02 RHI.PUMP ROOM COOLER HEAD SGL11A-02 COMPONENT COOL. WATER PUMP ROOM CQQLER HEAD SGLI 1 B-02 COMPONENT COOL. WATER PUMP ROOM COOLER HEAD 1 SGL12A-02 CHARGING PUMP ROOM COOLER HEAD 93 I Question No I LIRA Sect I Audit Questioni ii Final Response of Internal surfaces in Miscellaneous Piping and Ducting Components Program, which includes visual inspection when component is disassembled as part of the surveillance procedure.)

SGL12B-02 CHARGING PUMP ROOM COOLER HEAD SGL13A-02 CONTAINMENT SPRAY PUMP ROOM COOLER HEAD SGL13B-02 CONTAINMENT SPRAY PUMP ROOM COOLER HEAD SGL15A-02 PENETRATION ROOM COOLER HEAD SGL15B-02 PENETRATION ROOM COOLER HEAD Control Building HVAC System (GK) -LRA Table 3.3.2-9 GALL VII.F1-16

-Heat Exchanger Tube Side (HX# 117,122,123)

Component Component Name No.SGK04A-06 CONTROL ROOM A/C UNIT CONDENSER CHANNEL HEAD SGKo4B-06 CONTROL ROOM A/C UNIT CONDENSER CHANNEL HEAD SGK05A-06 CLASS IE ELEC. EQUIP. A/C UNIT CONDENSER CHANNELHEAD SGK05B-06 CLASS IE ELEC. EQUIP. A/C UNIT CONDENSER CHANNEL HEAD SGK05A-02 CLASS IE ELEC. EQUIP. A/C UNIT COOLING COIL HEADER SGK05B-02 CLASS IE ELEC. EQUIP. A/C UNIT COOLING COIL HEADER Fuel Building HVAC System (GG) -LRA Table 3.3.2.10 GALL VII.F2-14

-Heat Exchanger Tube Side (HX# 131)Component Component Name No.SGGO4A-02 FUEL POOL COOLING PUMP RM COQLER HEAD SGG04B-02 FUEL POOL COOLING PUMP RM COOLER HEAD Miscellaneous Buildings HVAC System (GF) -LRA Table 3.3.2-12 GALL VII. F2-14 -Heat Exchanger Tube Side (HX# 137)Component Component Name No.SGF02A-02 AUX FW PUMP ROOM COOLER HEAD SGF02B3-02 JAUX FW PUMP ROOM COOLER HEAD 94 IQipiiitiioti Ko I LRA Sec~ ~ Audit Qustion I, Final Resporis~e 1AMRA036 3.3 IAM RA037 In LRA Table 3.3.2-6, compressed air system, the LRA references Note E and GALL Report item VII.D-2 for carbon steel piping, orifice and valve components.

It also credits the Inspection of Internal surfaces in Miscellaneous Piping and Ducting Components Program to manage loss of materials in an internal environment of wetted gas in lieu of the Compressed Air Monitoring Program as recommended by the GALL Report. The AMP recommended by the GALL Report states that checks of air quality is performed as part of preventive actions to ensure that oil, water, rust, dirt, and other contaminants are kept within the specified limits. Since the LRA credits a different AMP, clarify if the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will perform air quality checks as recommended by the GALL Report.In LRA Table 3.3.1, items 3.3.1-8 and 3.3.1-9, the AMP column did not reflect what is recommended in the GALL Report for the same items.The GALL Report, Volume 1, Table 3, for these lines recommends the Air quality checks are not part of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP (XI.M38).

The AMP conducts internal visual inspections of compressed air system piping and components to manage cracking, loss of material, and loss of strength.The AMP inspections are not one-time inspections but are periodic inspections.

The wetted gas environment listed in LRA Table 3.3.2-6 for the compressed air system applies to two sections of piping and components as discussed below: 1.) Dry nitrogen vent piping off the safety-related auxiliary feedwater and main steam atmospheric relief valve accumulators that discharge to atmosphere.

See License Renewal Boundary Drawing LR-WCGS-KA-M-12KA05 (B-7, H-7, H-8, D-7, D-8, F-6, F-7, A-4, B-4, and C-4). The internal environment is dry nitrogen that discharges to atmosphere.

A wetted gas environment was conservatively chosen since there could be moisture introduced from the outside atmosphere that mixes with the dry nitrogen.

Air quality checks based on compressed air from instrument air compressors do not apply. Periodic internal visual inspection of the piping and components I provides a positive means for detection of aging effects that could lead to loss of system intended function.2.) Service air containment penetration piping and components on License Renewal Boundary Drawing LR-WCGS-KA-M-12KA02 (D-6).A portion of the piping is safety-related for containment isolation and the attached piping is non-safety related structural integrity attached (SIA).The SIA piping sections are relatively short sections that are easily accessible for periodic internal visual inspection.

Periodic internal visual inspection of the piping and components provides a positive means for detection of aging effects that could lead to loss of the SIA intended function.Performance of the Inspection of Internal Surfaces in Miscellaneous J Piping and Ducting Components AMP (XI.M38) periodic internal inspections will provide reasonable assurance that compressed air system intended functions are maintained.

_LRA Table 3.3-1, items 3.3.1.08 and 3.3.1.09 AMP columns are incorrect and should reference the Water Chemistry (B2.1.2) and One-Time Inspection (B2.1.16) programs.

The discussion column of LRA Table 3.3-1, items 3.3.1.08 and 3.3.1.09, specify that the aging management program(s) used to manage aging include the Water Chemistry (B2.1.2)and One-Time Inspection (B2.1.16) pprograms.

These programs are also 3.3 95 Q4 sU n No LRA Spc Water Chemistry Program and a identified for the Chemical and Volume Control System in LRA Section plant specific verification program. 3.3.2.1.7.

LRA Table 3.3.1, only credits a plant specific program. The GALL Report Chemical and Volume Control system stainless steel high pressure pumps!also states that this line item applies (meeting the conditions of 3.3.1.09) were assigned GALL line VII.E1-7 and to the GALL Report, Volume 2, items identified both the XI.M2, Water Chemistry and XI.M32, One-Time VII.E1-5 and VII.E1-7.

Clarify this Inspection aging management programs.discrepancy and confirm if the information provided in the LRA Chemical and Volume Control system regenerative heat exchangers Table 3.3.1 AMP column is incorrect. (meeting the conditions of 3.3.1.08) were assigned GALL line VII.E1-5 and!identified both the XI.M2, Water Chemistry and XI.M32, One-Time Inspection aging management programs.IAMRA038 3.3 In LRA Table 3.3.2-17, floor and equipment drains system, the LRA references Note E and GALL Report, item VII.G-18, for stainless steel itank. The table also credits the JInspection of Internal Surfaces in IMiscellaneous Piping and Ducting Components Program to manage loss of materials in an environment lof contaminated lubricating oil. The GALL Report item VII.G-18 is for component type piping, piping jcomponents, and piping elements.The GALL Report, Chapter IX,Section IX.B, provides definitions of..... ..structures and components, the term The LRA will be amended as follows:-LRA Table 3.3.1, item 3.3.1.08 aging management column to state, ,"Water Chemistry (B2.1 .2) and a plant specific verification program. The'AMP is to be augmented by verifying the absence of cracking due to Istress corrosion cracking and cyclic loading. A plant specific aging management program is to be evaluated."-LRA Table 3.3.1, item 3.3.1.09 aging management column to state,"Water Chemistry (B2.1.2) and a plant specific verification program. The AMP is to be augmented by verifying the absence of cracking due to stress corrosion cracking and cyclic loading. A plant specific aging management program is to be evaluated." -_',_ J_ ;The stainless steel reactor coolant pump drain tank receives lubricating oil3 leakage from the reactor coolant pump motors. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP will manage the loss of material due to pitting and crevice corrosion for stainless steel components in a lubricating oil environment by visual inspections for loss of material.

If internal inspections detect loss of material, the aging will be resolved via the WCGS corrective action program.See also AMRA034.96 I Question No I : LRA Sec I IAMRAO39 3.3~'Audit Question.piping, piping components, and piping elements; but it does not include tanks. GALL Report,Section IX.B, defines tanks separately from piping and piping components due to the potential need for a different AMP. The bottom of the stainless steel tank, where contaminated lubricating oil and sediment would collect, is more susceptible to loss of material due to pitting and crevice corrosion than piping components.

Confirm if wall thickness of the bottom of the tank is measured as part of the proposed AMP.In LRA Table 3.3.2-14, fire protection system, the LRA references Note J and 1 for elastomer flex hoses in an external environment of plant indoor air. The table also states that there are no aging effects and no AMP required.

Note 1 indicates that these components are in an environment of less than 95oF. The normal plant indoor air environment could see high humidity and higher temperatures.

In LRA Table 3.3.2 8, for elastomer material in plant indoor air environment, the applicant identified an aging effect of hardening and loss of strength and credited an AMP.Identify where the flex hoses are located in LRA Table 3.3.2 14 and justify why an aging effect is not considered.

Final Response i~~ ~ .............--

IThe flex hoses are associated with the Halon cylinder banks. Halon cylinder banks are located in the Auxiliary Building, Communications Corridor and Control Building.

The general thermal environment in the Control Building is maintained less than 95 0 F. The general thermal environment in the Auxiliary Building is less than 104 0 F.!Elastomer degradation

-hardening and loss of strength.

NUREG-1801 Chapter IX.C, defines Elastomers as "materials rubber, EPT, EPDM, PTFE(Teflon), ETFE, viton, vitril, neoprene, and silicone elastomer.

Hardening and loss of strength of elastomers can be induced by elevated temperature (over about 957F (35°C), and additional aging factors such as exposure to ozone, oxidation, and radiation." NUREG-1801, Chapter IX.D, has a definition for Air-indoor-uncontrolled

(>95 0 F). This definition discusses the temperature threshold for elastomer thermal aging, "If ambient is <95°F, then any resultant thermal aging of organic materials can be considered to be insignificant, over the 60-yr period of interest." The EPRI guideline, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Appendix D Section 2.1.8 states in part that,"synthetic rubbers are not affected by ozone and are typically much more resistant to sunlight (or other forms of ultraviolet radiation)." Flexible hoses for Halon storage cylinders in areas other than the Control Building may exceed the temperature threshold for elastomer degradation.

Thus, for Halon cylinder flexible hoses in the Auxiliary Building and Communications Corridor, thermal aging must be considered since it cannot be shown that the equipment spaces are below 95 0 F.97

[~etQn; N~o I >LRA Sqc~ j uWusion.Flexible hoses for Halon storage cylinders in the Control Building do not exceed the temperature threshold for elastomer degradation.

NUREG-1801 states that if the elastomer temperature threshold is not exceeded, thermal aging is insignificant.

The EPRI guide states that synthetic rubbers such as PTFE (Teflon) are not affected by ozone, sunlight or other forms of ultraviolet radiation.

Thus, for Halon cylinder flexible hoses in the IControl Building, thermal aging need not be considered and hardening

-loss of strength is not expected.Changes required: (1) A generic component for flexible hoses will be added for Halon flexible hoses susceptible to thermal aging (Auxiliary Building/Communications Corridor).

This generic flexible hose component will be assigned an!environment of air-uncontrolled (external) and an aging effect of hardening-loss of strength.

The Fire Protection AMP (XI.M26) will be the program used to manage aging. Note "E" will also be used in lieu of Note "J".(2) A generic component for flexible hoses will be added for Halon flexible hoses in the Control Building.

This generic flexible hose component will be assigned an environment of air-uncontrolled (external) and the aging;effect and aging management programs will be changed to "None". Note I"I" will be used in lieu of Note "J".(3) Both new generic components will have an internal environment of dry gas. Note "G" will be assigned since the environment is not in NUREG-1801 for the component and material combination.

The aging effect and aging management programs will be changed to "None".The LRA will be amended as follows:-LRA Table 3.3.2-14, Fire Protection System, Component Type "Flexible Hoses" (Control Building), environment "dry gas" will be amended to use Note "G, 1" in lieu of note "J". Plant specific note #1 will be amended to state, "Ambient temperature in Control Building spaces is expected to be below 95 degrees. Below 95 degrees, thermal aging of elastomers is not considered significant."-LRA Table 3.3.2-14, Fire Protection System, Component Type "Flexible Hoses" (Control Building), environment "plant indoor air" will be amended to use Note "G,1" in lieu of note "J". Plant specific note #1 will be 98 6uestiio No ~iLRA Sec 7 AuditQuestion.

Final Response amended to state, "Ambient temperature in Control Building spaces is expected to be below 95 0 F degrees. Below 95 0 F degrees, thermal aging of!elastomers is not considered significant." LRA Table 3.3.2-14, Fire Protection System -A new generic component type will be added. Component type: "Flexible Hoses" (Auxiliary Building/Communications Corridor)Material:

Elastomer Environment:

Plant indoor air (external)

Aging Effect: Hardening and loss of strength -elastomer degradation Aging Management Program: XI.M26 -Fire Protection NUREG-1801 Vol. 2 No.: VII.F2-7 Table 1 Item: 3.3.1.11 Note: E,3 Plant Specific Note: #3 -Thermal aging of Halon flexible hoses in the Auxiliary Building and Communication Corridor must be considered because it cannot be shown that these areas are below 95 F.LRA Table 3.3.2-14, Fire Protection System -A new generic component!type will be added. Component type: "Flexible Hoses" (Auxiliary

',Building/Communications Corridor)Material:

Elastomer;Environment:

Dry gas (internal)

Aging Effect

Hardening and loss of strength -elastomer degradation

'Aging Management Program: XI.M26 -Fire Protection

'NUREG-1801 Vol. 2 No.: None!Table 1 Item: None'Note: G,3 Plant Specific Note: #3 -Thermal aging of Halon flexible hoses in the Auxiliary Building and Communication Corridor must be considered because it cannot be shown that these areas are below 950F.-LRA Section B2.1.12 Fire Protection aging management program will be amended to include discussion of hardening

-loss of strength for elastomers.

The WCGS system that is equivalent to the NUREG 1801 extraction steam system is the Feedwater Heater Extraction, Drains and Vents (AF)System. The purpose of the WCGS AF System is to provide preheated feedwater to the steam generators to improve cycle efficiency and to minimize thermal stresses on the feedwater piping and steam generator feedwater nozzles. The AF System serves no safety function, has no safety design basis, and does not meet the criteria of 1OCFR54.4(a)(1).

ItýAMRA040 3.4 The GALL Report includes the extraction steam system as part of the steam and power conversion system. Explain why the extraction steam system is not included within the scope of LRA Section 3.4.99

~Qu~estion Nol LRA Sec..1 Audit Question AMRAO4 1[AM RA042 13.4 LRA Section 2.1.4.1 states "Thermal insulation was treated as a passive, long-lived component during the scoping and screening process. For systems where it has an intended function, insulation was considered in the scope of license renewal and subject to aging management review..." Explain why there is no aging effect requiring management identified for insulation line items included in LRA Tables 3.4.2-2, 3.4.2-3 and 3.4.2-5.is not required to support the requirements of the criteria of 10CFR54.4(a)(3).

The components of the AF System are located completely within the turbine building.

There are no safety related systems or components located in the turbine building.

Any failure of AF System components will not affect any safety related equipment of the plant, thus!not meeting the criteria of 1OCFR54.4(a)(2).

Therefore, the Feedwater Heater Extraction, Drains and Vents System is not included in the scope of license renewal.The piping insulation identified in LRA Tables 3.4.2-2 (main steam system), 3.4.2-3 (feedwater system) and 3.4.2-5 (steam generator blowdown system) is located indoors and is credited for limiting temperatures to containment building system containment penetrations.

The insulation also limits steam generator blowdown system piping overpressurization in the containment building during accident conditions.

The plant indoor environment is a non-aggressive environment that does!not promote aging of the foamglass or calcium silicate insulation materials.

'There is no industry experience or WCGS operating experience that 1 indicates insulation materials of calcium silicate sheathed in aluminum or foamglass sheathed in stainless steel in non-aggressive environments experience aging effects that require management.

The following SERs identified insulation in the scope of license renewal and determined there Iwere no aging effects:-NUREG 1785 (H.B. Robinson)-NUREG 1831 (D.C. Cook)NUREG 1838 (Millstone 2 and 3)NUREG 1839 (Point Beach 1 and 2)NUREG 1856 (Brunswick)

NUREG 1801 does not evaluate calcium silicate or foamglass insulation materials.

NUREG 1801 does conclude there are no aging effects that require management for stainless steel (sheathing) and aluminum (sheathing) in plant indoor air. The calcium silicate and foamglass insulation materials in LRA Tables 3.4.2-2, 3.4.2-3 and 3.4.2-5 are jacketed with stainless steel or aluminum.

Therefore, it is concluded that there are no aging effects requiring management for the insulation materials in LRA Tables 3.4.2-2, 3.4.2-3 and 3.4.2-5.IThe purpose of the WCGS main turbine system is to convert steam ithermal energy from the main steam system to mechanical energy to drive the main generator.

The main turbine system serves no safety function, has no safety design basis, and does not meet the criteria of 1 10CFR54.4(a)(1).

The components of the main turbine systemare____

100 3.4 LRA Section 3.4.2.1.1 describes!materials, environment, aging effects requiring management, and AMPs pertaining to the main turbine system. The environments listed in I Question No I ILRA Sec I~ Audit Question 1 Final Re~sponse 1AMRAO43 13.4 this section are the plant indoor air I located completely within the turbine building.

Any failure of main turbine and the secondary water. The GALL system components will not affect any plant safety-related equipment and Report,Section VIII. A, which covers ,does not meet the criteria of 10CFR54.4(a)(2).

Portions of the main the main turbine system, also turbine system are in-scope of license renewal to support the includes components exposed to the requirements of fire protection and ATWS based on the criteria of steam and the lubricating oil 10CFR54.4(a)(3).

Fire protection requires the turbine to be tripped to environments.

Explain why these support controlled depressurization of the secondary side systems. The environments are not addressed in fire protection trip function has no in-scope mechanical equipment.

ATWS the LRA description and the tables related mechanical equipment is turbine impulse piping and valves with an I pertinent to the main turbine system. internal environment of secondary water and external environment of plant indoor air. Secondary water includes steam per LRA Table 3.0-1, Mechanical Environments.

Therefore the only environments associated 1with the main turbine system are secondary water (includes steam) and plant indoor air. _LRA Table 3.4.2-5, steam generator The pumps listed in Table 3.4.4-5 for the steam generator blowdown blowdown system, includes stainless system are the steam generator drain pumps. The pump bodies are cast steel pumps exposed to secondary austenitic stainless steel (CASS) with an internal environment of water environment.

According to secondary water when in use. These pumps are not used during normal this table, the aging effect requiring plant operation and do not experience elevated temperatures above room management is loss of material, ambient temperature during plant operation.

The pumps are used for Clarify what is the temperature of the draining the steam generators after the steam generators have been treated water to which these cooled down to near ambient conditions.

The pumps are in-scope for components are exposed to. Justify spacial interaction since the pumps and piping are not drained after use.why cracking is not identified as the !The maximum temperature experienced by the pumps is well below the aging effect requiring management threshold temperature of 482 degrees F for thermal embrittlement of for these components.

iCASS. Cracking is not a consideration for the steam generator drain pumps since they are not normally used to drain the steam generators at fluid temperatures above 140 degrees F. However, WCGS Procedure SYS BM-201, Steam Generator Draining, has a precaution that fluid temperatures could be as high as 150 degrees F. Since steam generator draining is a limited duration evolution not accomplished during normal plant operations, cracking is not a consideration for the steam generator__drain pumps.LRA Table 3.4.2-6, auxiliary The line items in LRA Table 3.4.2-6 all relate to the turbine lube oil cooler feedwater system, includes several !which is a shell and tube heat exchanger.

Multiple heat exchangers are line items pertaining to heat i not being addressed in the table only the turbine lube oil cooler. The heat exchangers.

exchanger (HX) numbers in LRA Table 3.4.2-6 apply to HX subcomponents of the turbine lube oil cooler. The terminology for HX #a. Clarify what type of heat 154, # 155, # 156, and # 157 is explained in LRA Table 2.3.4-6. The HX exchanger is HX # 154. If it is a shell (#154) is carbon steel, the HX head (#155) is carbon steel, the HX shell and tube heat exchanger, tube sheet (#156) is carbon steel, and the HX tubes (#157) are carbon explain what is flowing through the 1steel.101 AMRA044 3.4 I Quesiion No ILRA Sec [ Audit Qu~estion

-J -~Fiunal Response tubes and which line item addresses the aging management of tubes for this heat exchanger.

b. There is one item on tube sides for HX # 155, 156 and 157 exposed to lubricating oil. Reduction of heat transfer or fouling is only addressed for HX # 157. Explain why is the reduction in heat transfer not addressed for HX # 155 and 156.Justify why an aging management is not required for the shell sides of these three heat exchangers.

c. There are two line items addressing tube side of heat exchangers (HX # 155, 156, 157)exposed to secondary water (internal) and plant air (external).

Clarify what type of heat exchangers are these.d. Provide operating experience (including maintenance) for HX #154, 155, 156 and 157.LRA Table 3.4.2-6, auxiliary feedwater system, includes a line item for turbine exposed to lubricating oil. Explain which specific components of the turbine are subject to loss of material for exposure to lubricating oil. Confirm that the internal surfaces of these components are within the scope of the One Time Inspection Program.LRA Table -34.2-3, feedwate-r system, includes several line items pertaining to tube sides of heat exchangers HX # 152 and HX # 153.Describe the type of these heat exchangers and flow conditions in Turbine lube oil flows into the inlet HX head, the turbine lube oil flows through the HX tubes, and out the outlet HX head. Secondary water from downstream of the auxiliary feedwater pump flows into the HX shell and returns to the auxiliary feedwater pump suction. The interior of the HX tubes have an environment of turbine lube oil and an external environment of secondary water. The HX heads have an internal environment of turbine lube oil. The HX shell has an internal environment of secondary water. The HX tube sheets have turbine lube oil on one side and secondary water on the other side. The external environment for both the heads and shell is plant indoor air.Loss of heat transfer applies to the turbine lube oil cooler based on NUREG 1801 line VIII.G-15.

Maintenance records and operating experience for the turbine lube oil cooler do not indicate any issues of note. Turbine lube oil sample analyses have been within specifications.

Lube oil cooler inspections during turbine overhaul periods have identified no issues.The auxiliary feedwater steam turbine is included as a component in the main steam system in LRA Table 3.4.2-2. The turbine component type listed in LRA Table 3.4.2-6 for the auxiliary feedwater system is for the auxiliary feedwater turbine lube oil support subcomponents.

Included subcomponents are lube oil piping, lube oil sump and lube oil bearing reservoirs.

The lube oil pump is a separate item in LRA Table 3.4.2-6.The internal surfaces of the auxiliary feedwater turbine lube oil subcomponents in the auxiliary feedwater system are included in the One Time Inspection Program.The line items in LRA Table 3.4.2-3 all relate to the High Pressure (HP)ifeedwater heaters which are shell and tube heat exchangers.

Multiple heat exchangers are not being addressed in the table only the HP feedwater heaters. The heat exchanger (HX) numbers in LRA Table 3.4.2-3 apply to HX subcomponents of the HP feedwater heaters. The terminology for HX # 152 and # 153 is explained in LRA Table 2.3.4-3.ýAMRA045 3.4 AMRA046 i3.4 102 6 upsiion No I J.RA Sk [ 7Au~dit Quq;sio~n

.1 ~ ~Final R~esponise.

AMRA047 AMRA048...... .........1AMRA049 3.5'3.5 3.5 tube and shell sides.a ie ..........

..-_ _-----------

---

LRA Table 3.5.1, item 3.5.1.33, Group 1-5: concrete, states that aging effect is reduction of strength and modulus of concrete due to elevated temperature.

Identify which plant specific AMP is being used to manage this aging effect. Explain why Notes E and 3 were used for this item.LRA Table 3.5.2-22, containments, structures, and component supports, lists a component type of "supports ASME 2 and 3" (page 3.5-166).

The LRA references Table 1, item 3.5.1.42, and Notes I and 4.However, the table does not provide a definition for Note I. Provide the definition for Note I and explain why this Note was used.LRA Table 3.5.1, item 3.5.1.43, corresponds to GALL Report, items III.A3-11 and III.Al-11, which state that masonry block walls are subject to cracking, due to restraint HX head (#151) is carbon steel, the HX tube sheet (#152) is carbon steel, the HX tubes (#153) are stainless steel, and the HX shell (#158) is carbon steel. HP secondary water going to the steam generators flows into the inlet HX head, the secondary water flows through the HX tubes, and out the outlet HX head. Secondary water from extraction steam flows into and out of the HX shell. The interior of the HX tubes has an environment of HP secondary water (going to the steam generators) and an external ienvironment of secondary water from extraction steam. The HX heads have an internal environment of secondary water going to the steam generators.

The HX shell has an internal environment of secondary water from extraction steam. The HX tube sheets have secondary water on both sides. The external environment for both the heads and shell is plant indoor air.As noted in the Discussion column of LRA Table 3.5.1, Item 3.5.1.33, the plant-specific aging management program used to manage this aging effect is the Structures Monitoring Program (B2.1.32).

[Note E: Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.]This note was used because NUREG-1801, item III.A4-1, specifies a plant-specific aging management program.[Note 3: Concrete is monitored for visible signs of aging effects due to increased temperature by Structures Monitoring Program (B2.1.32).]

This note was used to clarify the action to be performed by the Structures.Monitori.ng Program as it pertains to this item...The list of Standard Notes for LRA Table 3.5.2-22 will be amended to add Note I: "Aging effect in NUREG-1801 for this component, material and environment combination is not applicable." Some Masonry Walls at WCGS are credited as fire barriers, therefore, they must be inspected in accordance with the Fire Protection program (B2.1.12).

J[Note 1: NUREG-1801 does not provide a line in which concrete masonry 103 I Questicon No LRA S6c [Audit Qotion FyiinaI Respoise, shrinkage, creep, and aggressive environment.

The GALL Report recommends the Masonry Wall Program to manage this aging effect.The lines referencing item 3.5.1.43 manage this aging effect with the Masonry Wall and the Fire Protection Programs, with no further evaluation recommended.

Explain why Notes E and 1 were used for this line item.In LRA Table 3.5.2-14, a line references to item 3.5.1.45.

Explain why Notes E and 3 were used instead of Note A.is inspected per the Fire Protection program (B2.1.12).]

This note was used to explain the addition of the Fire Protection AMP to this line instead of using another line.[Note E: Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management program.]This note was used because a different AMP (Fire Protection) is credited.LRA Table 3.5.1, Item 3.5.1.45, will be amended to revise the Aging Management Program entry to read: "Inspection of Water-Control Structures (B2.1.33)." This amendment to the LRA will correctly align this item with the SRP.[Note E: Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.]This note was used because the Structures Monitoring Program is credited instead of Water-Control Structures.

AMRA051 13.5 3.5[Note 3

WCGS inspects the submerged portions of the Circulating Water Screen House as part of the Structures Monitoring Program (B2.1.32).]

!This note was used to identify the AMP that is used at WCGS to inspect Ithe CWSH.______

In LRA Section- 35, Table2s, tiere-I NUREG 1801lin-elll.A6-1 specifies Regulatory Guide1..1.27,Inspction are several lines that reference Note of Water-Control Structures Associated with Nuclear Power Plants E and GALL Report, item 3.5.1.47, (B2.1.33) as the aging management program for metal components in for aging management of loss of water-control structures.

Regulatory Guide 1.127, does not address metal material due to general (steel only), components, so the Structures Monitoring Program (B2.1.32) is used.pitting and crevice corrosion.

For WCGS does not rely upon protective coatings to manage the effects of this specific item, the GALL Report laging.recommends the use of the Regulatory Guide 1.127, Inspection of Water Control Structures and a protective coating monitoring and maintenance program. Explain why the Structures Monitoring Program (Note E) was credited instead of the programs recommended by the GALL Report........

............

104 IQuestionNo ILRA Sec I Audit Quest4ýýtion FinialRes Rponse-, 1AMRA052 3.5 1AMRAO53 3.5 For LRA Table 3.5.1, item 3.5.1.33, provide the maximum temperature that concrete experience in Group 1-5 structures.

jIIn LRA Table 3.5.2-16, there i n line that references item 3.5.1.28 land states that crack and distortions

!will be managed by the Regulatory IGuide 1.127, Inspection of Water -Control Structures Associated with Nuclear Power Plants Program.Explain why this AMP is used instead of the Structures Monitoring Program recommended by the GALL Report.Provide the following information regarding LRA Section 3.5.2.2.2.6:

a. Additional information about the bolting material used in structural applications, including group B1.1 application at WCGS: USAR Section 3.8.3.4.2 discusses loading on the primary shield wall.'During normal plant operation, the primary shield wall concrete temperatures are limited to 150°F except for the area directly below the seal ring support which is limited to 220 0 F. High energy line containment penetrations have been designed with flued heads to dissipate the heat from these process pipes, and insulation has been installed to further limit the exposure of the concrete.

WCGS Technical Specifications require that, the containment average air temperature be less than or equal to 120 0 F.In the auxiliary building, concrete temperatures are limited to 150°F excepts for local areas, which are limited to 2000 F. These limits are maintained by insulation installed on high temperature lines and the plant ventilation system.'There are no other in-scope structures that house high temperature lines. I The ESW Discharge Structure is normally submerged and is inspected by divers It is inspected under WCGS's program that is based on RG 1.127.IThe Structures Monitoring program credits this program for the ESW Discharge Structure.

LRA Table 3.5.2-16 line item that refers to Table 1 line item 3.5.1.28, will!be amended to revise the Aging Management Program entry to read: "Structures Monitoring Program (B2.1.32)" and to reference Note A instead of Note E and delete reference to Note 1.!The list of Standard Notes for LRA Table 3.5.2-16 will be amended to delete note 1. .a. LRA Table 3.5.2-22 includes a line item for high strength bolting made from high strength, low alloy steel. These bolts are also addressed in LRA Table 3.5.1, Item 3.5.1.51.

At WCGS, the maximum ultimate tensileýstrength for bolts was limited to 170 ksi. Specifications C-134A (Bechtel)and M-730 (Westinghouse), as well as USAR App. 3A, pg 3A-53, limit the bolting materials that can be used at WCGS. Of the bolting materials specified, only SA-540 Grade 21 has a specified minimum yield of equal toi or greater than 150 ksi. All other bolting material used at WCGS has a lyield strength less than 150 ksi.iAMRA054 i3.5 (i) Clarify what is the bolting material.(ii) Clarify what is the normal yield 1For high strength bolting to be susceptible to SCC, material with an actual strength and upper-bound as ,yield strength of greater than 150 ksi must be subjected to excessive bolt received yield strength.

!preload and contaminants, such as molybdenum sulfide in the thread (iii) Describe the WCGS resolution of lubricants.

Bolt preload was managed by procedural controls, and Sthe bolting integrity generic issue as lubricants containing detrimental contaminants were not used. Therefore, 105 IQ=,1140o No]I LRAk Sec~ I AOit Q4uestlO-l.

,< ~ FiiiaI Res~ponse1 1AMRA055 1AMRAO56 ,AMRA057 3.5 3.5 53.6 it relates to structural bolting. cracking due to SCC is not an aging effect requiring management for high (iv) Clarify if any structural bolting 'strength bolting at WCGS.has been identified as potentially susceptible to cracking due to SCC. 1A review of plant operating experience has not found any instances of List any structural bolting replaced SCC, and no structural bolting has been replaced due to this concern.as part of the resolution.

lb. There is no class MC pressure retaining bolting at WCGS. Loss of b. Describe the scope and aging preload is managed by the Bolting Integrity AMP (LRA Section B2.1.7)management review performed for class MC pressure retaining bolting.Explain how WCGS manages loss of pre-load.

_LRA Table 3.5.2-1, containments, The list of Standard Notes for LRA Table 3.5.2-1 will be amended to add structures, and component supports, Note H: "Aging effect not in NUREG-1 801 for this component, material lists a component type of penetration land environment combination." which makes reference to Note H.However, the table does not provide a definition for Note H. Provide a I definition for this note and justify its use for this specific component.

LRA Table 3.5.2-12, containments, The list of Standard Notes for LRA Table 3.5.2-12 will be amended to add structures, and component supports, Note H: "Aging effect not in NUREG-1801 for this component, material lists a component type of liner spent and environment combination." fuel pool which makes reference to Note H. However, the table does notl provide a definition for Note H.Provide a definition for this note and justify its use for this specific'component.

In LRA Table 3.61, item 3.6.1.6, the a) The electrical containment penetration assemblies at WCGS do not applicant stated that all fuse holders incorporate self-fusing characteristics and must be protected externally.

including the fuses installed for 'The fuses that are used to protect the electrical containment penetrations electrical penetration protection are are installed in larger assemblies (i.e. motor control center cubicles, main part of larger assemblies, so the control boards, distribution panels, etc.).applicable GALL Report items were not used. In Interim Staff Guidance b) The WCGS controlled fuse list does not identify which of the over 2500 (ISG)-5, "Identification and fuses are used as isolation devices between Class 1E and non-Class 1E Treatment of Electrical Fuse Holders electrical circuits.

The fuse list does identify the locations for all of the for License Renewal," the staff Ifuses. A review of this list determined that there are no fuses in the scope provides examples of fuse holders of license renewal that are not installed as part of a larger assemblies.

that require an AMR. These are The aging of the components including the fuse holders within these fuses that are installed in fuse holder iassemblies is managed as part of the active component.

The WCGS 106 QusinNo >LRA $Sep Aoudit Qo~t~ ] _K,6- Final kles -onse panels which are used as protective does not install fuse in standalone fuse panels or cabinets.devices to ensure the integrity of containment electrical penetration or c) Drawings E-13LF08, E-13BB03 and E-13EP02B show typical as isolation devices between Class arrangements of the electrical containment penetration protection circuits.1 E and non-Class 1 E electrical circuits.a. List all components in an electrical containment protection assembly and explain why fuse holders installed in this assembly are considered part of a larger active assembly.b. Identify fuse holders installed as isolation devices between Class 1 E and non-Class 1 E electrical circuits.Explain why these fuse holders do not require an AMR.c. Provide a schematic diagram for electrical containment protection for review during the site visit.rAMRA058 3.6 In LRA Table 3.6.1, item 3.6.1.12, a) Torque relaxation for bolted connections of switchyard bus and the applicant takes an exception to transmission conductors is not a concern at WCGS because stainless the GALL Report for the steel bolts with stainless steel washers are used to maintain the proper transmission conductors.and torque and prevent loss of pre-load.

The in-scope bolted transmission connections, and switchyard bus and connections are at the startup transformer XMR01 and disconnect 345-connections.

In addition, the 163. These connections are periodically evaluated via thermography as applicant states that the aging effect part of the preventive maintenance activities performed on the startup in the GALL Report for this material transformer and disconnect.

Based on temperature data in the USAR and environment combination is not Chapter 2.3, the transmission connections do not experience thermal applicable.

In LRA Section cycling. The transmission connections are subject to average monthly 3.6.2.2.3, the applicant further states temperatures ranging from 80 OF in July and August to 29 °F in January that transmission conductor with minimal ohmic heating.connections at the time of installationI are treated with corrosion inhibitors b) The corrosion inhibitors compound (a grease-type sealant) is a to avoid connection oxidation and consumable which is used for initial assembly of bolted connections and is are torqued to avoid loss of pre-load.

replaced as required when connections are taken apart and reassembled (e.g., during routine maintenance).

The compound is weather resistant SRP Section 3.6.2.2.3 states that and adheres to the connection to ensure low contact resistance.

Based increased resistance of connections

!on operating experience, this method of installation has been shown to 107 I ~ ~ s ~. toAo4 UASc I KAuit Qizestion Final Response ~due to oxidation or loss of pre-load could occurs in transmission conductors and connections; and in switchyard bus and connections.

Further, EPRI document TR-104213,"Bolted Joint Maintenance

&Application Guide," states that increased temperature difference in lelectrical bolted joints is due to high Icircuit rating or increased current duration.

The temperature of an electrical bolted joint will rise and stress will increase with increasing current duration.

If this temperature increase is not taken into consideration, loose or failure joints will result.!provide a corrosion resistant low electrical resistance connection.

The IWCGS outdoor environment is not subject to industry air pollution or isaline environment.

The connections do not experience any appreciable laging effects in this environment.

Therefore, it is concluded that general corrosion resulting in the oxidation of transmission connection surface metals is not an aging effect requiring management at WCGS. The in-!scope bolted connections are at the startup transformer XMR01 and disconnect 345-163. These connections are periodically evaluated via thermography as part of the preventive maintenance activities performed on the startup transformer and disconnect.

Periodic thermography will continue into the period of extended operation.

A copy of the Infrared Thermography Report dated 10/23/03 for the Startup Transformer was provided along with a copy of the work order Ihistory.

The thermography results show that based on the transmission line capacity vs the connected load these connections experience minimalýto no ohmic heating. These electrical bolted joints do not experience high.circuit rating or increased current duration as discussed in EPRI document TR-104213, "Bolted Joint Maintenance

& Application Guide." The last paragraph of LRA further evaluation 3.6.2.2.3 will be amended to ,read the following.

iThe WCGS outdoor environment is not subject to industry air pollution or saline environment.

Aluminum bus material, galvanized steel support hardware and stainless steel connection material do not experience any appreciable aging effects in this environment.

These connections are periodically evaluated via thermography as part of the preventive maintenance activities performed on the startup transformer and 1disconnect.

The periodic thermography will continue into the period of ,extended operation.

a. Explain why torque relaxation for bolted connections of switchyard bus and transmission conductors is not a concern at WCGS.b. Provide a discussion about the iqualified life of corrosion inhibitors.

Explain why increased resistance of bolted connections due to oxidation is not a concern for switchyard bus and transmission connections.

Follow-up:

1AMRA059 Question 58 -Provide thermographic data for startup XFMR high voltage GALL Report, Chapter VI, item VI.A- LRA Table 3.6.2-1 will be amended to include electrical cable connections 1, cable connections (metallic parts), n outdoor air.lists air indoor and air outdoor as the environment.

LRA Table 3.6.2-1, lists air indoor; however, it does not include air outdoor environment.

Justify why oxidation of cable connections is not an aguing effect for _108

~Que'stion No~ LRAA$ec ~ Audit Question~

_T_ :>~~ Final Res onse.AMRA060 3.6 3.3 cable connections in an outdoor environment.

GALL Report, Chapter VI, item VI.B-1, identifies adverse localized environment due to heat, radiation, or moisture in the presence of oxygen. LRA Table 3.6.2-1 only lists adverse localized environment (ext).Justify why aging caused by heat, radiation, or moisture is not a__J cncernat WC _G_.LRA Table 3.3.1, item 3.3.1.69, states that this line is consistent with the GALL Report except that a different AMP is credited for stainless steel piping, piping components, and piping elements exposed to raw water on the internal surfaces.

The Fire Water System Program will be credited along with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components to manage the aging effects. This corresponds to several line items in LRA Table 3.3.2-14, fire protection system, where Note E is referenced.

Describe how these two programs are used in conjunction to manage these aging effects.iLRA Table 3.0-3 defines an Adverse Localized Environment as follows:!Adverse localized environments can be due to any of the following:

(1)exposure to moisture and voltage (2) heat, radiation, or moisture, in the ,presence of oxygen (3) heat, radiation, or moisture, in the presence of;oxygen or >60-year service limiting temperature, or (4) adverse localized ,environment caused by heat, radiation, oxygen, moisture, or voltage. The i term ">60-year service limiting temperature" refers to that temperature that exceeds the temperature below which the material has a 60-year or greater service lifetime.

I The Fire Water System program manages loss of material for water-based fire protection systems. Periodic hydrant inspections, fire main flushing, sprinkler inspections, and flow tests considering National Fire Protection

ýAssociation (NFPA) codes and standards ensure that the water-based fire 1 protection systems are capable of performing their intended functions.

The Fire Water System program conducts an air or water flow test through each open head spray/sprinkler nozzle to verify that each open head spray/sprinkler nozzle is unobstructed.

The Fire Water System program tests a representative sample of fire protection sprinkler heads or replaces Ithose that have been in service for 50 years, using the guidance of NFPA 25 2002 Edition, and tests at 10 year intervals thereafter during the period of extended operation to ensure that signs of degradation, such as!corrosion, are detected in a timely manner.Visual inspections evaluating wall thickness to identify evidence of loss of material due to corrosion, Iensuring against catastrophic failure, are covered by the aging management program XI.M38 "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components".

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP manages cracking, loss of material and hardening

-loss of strength for 1components whose internal inspections are not covered by other aging ,management programs.

Thus, the Fire Water System program internal Ivisual inspections are covered by the internal Inspection program. Other inspections such as, fire detection and suppression testing and maintenance, yard fire hydrant inspections and flushing, powerblock fire hose testing, hose station gasket inspections and sprinkler/spray nozzle inspections are covered by the Fire Protection program.Internal visual inspections will be conducted during periodic maintenance, surveillance testing and corrective maintenance to the fire protection 109

~Qetion Nop L rA 9cf, Audit Qizestion

~[AMRA062 13.3ýAMRA063 3.4 LRA Table 3.3.1, item 3.3.1.70, states that this line is consistent with the GALL Report except that a different AMP is credited for copper alloy piping, piping components, and piping elements exposed to raw water on the internal surfaces.

The Fire Water System Program will be credited along with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effects. This corresponds to several line items in LRA Table 3.3.2-14, fire protection system, where Note E is referenced.

Describe how these two programs are used in conjunction to manage these aging effects.sstmFinealt ithsons6eoa system components in the program.The Fire Water System program manages loss of material for water-based fire protection systems. Periodic hydrant inspections, fire main flushing, sprinkler inspections, and flow tests considering National Fire Protection Association (NFPA) codes and standards ensure that the water-based fire protection systems are capable of performing their intended functions.

The Fire Water System program conducts an air or water flow test through each open head spray/sprinkler nozzle to verify that each open head spray/sprinkler nozzle is unobstructed.

The Fire Water System program tests a representative sample of fire protection sprinkler heads or replaces those that have been in service for 50 years, using the guidance of NFPA 25 2002 Edition, and tests at 10 year intervals thereafter during the period of extended operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.Visual inspections evaluating wall thickness to identify evidence of loss of material due to corrosion, IUI VUI III avai" L CI I p %II I CllUl;:, Cdll %JV, I qU UY LI IC 9yll "q management program XI.M38 "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components".

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP manages cracking, loss of material and hardening

-loss of strength for components whose internal inspections are not covered by other aging management programs.

Thus, the Fire Water System program internal visual inspections are covered by the Internal Inspection program. Other inspections such as, fire detection and suppression testing and maintenance, yard fire hydrant inspections and flushing, powerblock fire hose testing, hose station gasket inspections and sprinkler/spray nozzle inspections are covered by the Fire Protection program.Internal visual inspections will be conducted during periodic maintenance, surveillance testing and corrective maintenance to the fire protection Isystem components in the program.LRA Tables 3.4.2-3 and 3.4.2-6 list NUREG 1801 Table VIII.D for PWR Feedwater System has no HX lines, several line items related to therefore Table line VIII.D1.8 (steel piping in a treated water environment) management of loss of material in was used for steel heat exchanger in a treated water environment.

steel heat exchanger components NUREG 1801 Table VIII.G for PWR Auxiliary Feedwater System has HX exposed to secondary water. These lines but not for steel in treated water, therefore Table line VIII.G-38 was line items refer to LRA Table 3.4-1, used for steel piping in a treated water environment.

Lines VIII.D1.8 and item 3.4.1.04, with Note D. VIII.G-38 provide aging effects/aging mechanism of loss of material/general, pitting, and crevice corrosion and aging management LRA Table 3.4-1, item 3.4.1.04, programs of water chemistry and one-time inspection.

110 Ouiesition No jL~RA Sec: A oAdtQufktivn

--Final Rq~pion$S AMRA064 13.4 addresses management of loss of material for steel piping, piping components, and piping elements exposed to treated water. LRA Table 3.4.1, item 3.4.1.03, however;covers loss of material for steel heat exchangers.

Even though the line item in LRA Table 3.4-1 is listed for condensate and steam generator blowdown systems, it has the same component, material, environment land aging effect as the line items in Table 3.4.2 3. Explain why LRA Table 3.4.1, item 3.4.1.03, has not been used instead of item 3.4.1.04.I LRA Tables 3.4.2-2, 3.4.2-3 and 13.4.2-5 include several line items I related to insulation materials exposed to the plant indoor air.These items reference Note J and state that there are no aging effects to be managed.Degradation of the thermal insulation on piping and equipment can result in the loss of insulating capability which may cause the area temperature to increase.a. Justify why the degradation of insulating properties is not an issue.lb. Provide plant specific and industry operating experience relative to this aspect.c. Clarify if there is environmentally qualified equipment in the vicinity of the insulation and if the temperature rise been evaluated.

i LRA Table 3.4.1, item 3.4.1.03 addresses components in the condensate and blowdown system. NUREG 1801 lineVIIl.E-37 for the condensate system and NUREG 1801 lineVIIl.F-28 for the blowdown system evaluate steel. HX components in a treated water environment.

These lines provide aging effects/aging mechanism of loss of material/general, pitting, and crevice corrosion and aging management programs of water chemistry land one-time inspection.

The aging effects, aging mechanism, and aging management programs from NUREG 1801 lines VIII.D1.8 and VIII.G-38 (LRA Table 3.4.1, item 3.4.1.04 ) are the same as those associated with LRA Table 3.4.1, item 3.4.1.03.The piping insulation identified in LRA Tables 3.4.2-2 (main steam system), 3.4.2-3 (feedwater system) and 3.4.2-5 steam generator blowdown system is located indoors and is credited for limiting temperatures to containment building system containment penetrations.

The insulation also limits steam generator blowdown system piping loverpressurization in the containment building during accident conditions.

The plant indoor environment is a non-aggressive environment that does not promote aging of the foamglass or calcium silicate insulation materials.

There is no industry experience or WCGS operating experience that indicates insulation materials of calcium silicate sheathed in aluminum or foamglass sheathed in stainless steel in non-aggressive environments lexperience aging effects that require management.

The following SERs identified insulation in the scope of license renewal and determined there were no aging effects:-NUREG 1785 (H.B. Robinson)NUREG 1831 (D.C. Cook)NUREG 1838 (Millstone 2 and 3)NUREG 1839 (Point Beach 1 and 2)-NUREG 1856 (Brunswick)

NUREG 1801 does not evaluate calcium silicate or foamglass insulation materials.

NUREG 1801 does conclude there are no aging effects that require management for stainless steel (sheathing) and aluminum (sheathing) in plant indoor air. Therefore, it is concluded that there are no aging effects requiring management for the insulation materials in LRA Tables 3.4.2-2, 3.4.2-3 and 3.4.2-5.III

~Questi No I LRA $ec ~iAMRA065 13.4 AMRA066 13.4 Atdit QWe4t46 <K&K Finial Res onse LRA Table 3.4.2-4 includes a line tem pertaining to stainless steel tank exposed to outside atmosphere and weather. The LRA references Note G and states that there are no aging effects requiring management.

a. Describe the location of the tank (e.g., above ground, partially buried, bottom touching the soil).b. Justify why no aging effect requiring management is considered for the tank exterior.LRA Table 3.4.2-4 includes a line tem pertaining to carbon steel closure bolting exposed to atmosphere and weather. The LRA states that loss of preload is an aging effect requiring management and references Notes H and 1.Identify in which equipment these closure bolts are located on. Include a brief discussion as to how the AMP credited for aging management will address this specific aging effect.WCGS calcium silicate and foamglass insulation have no aging effects that require aging management.

Therefore, there is no loss of intended function and there are no impacts to room temperatures or nearby equipment or structures due to aging of insulation.

a.) The tank in LRA Table 3.4.2-4 is the Condensate Storage Tank (CST).The CST is constructed of stainless steel and is located above ground outside on a concrete foundation.

The external environment is atmosphere/weather.

Stainless steel exposed to attmosphere/weather has no aging effect or aging mechanism.

Note G was selected since the atmosphere/weather environment is not in NUREG 1801 for stainless steel components.

b.) NUREG 1801 does not address this environment.

The WCGS plant outdoor environment is not subject to industrial air pollution or saline environment.

The CST is a Stainless Steel tank located in an outside air environment and are is not exposed to aggressive chemical species.,Alternate wetting and drying resulting from rain has shown a tendency to wash" the exterior surface material rather than concentrate contaminants.

This is consistent with NUREG-1 843, the Browns Ferry SER, section 3.5.2.3 (pages 3-303 and 3-304) that identifies stainless steel components exposed to an outside air environment are not subject to aging.Closure bolting is a generic component that is created to cover closure bolting applications under applicable material and environment combinations.

In this case closure bolting was created for applications that use carbon steel bolts or studs subject to an atmosphere/weather environment.

Examples of plant components include valves and flanges exposed to atmosphere and weather.NUREG 1801 does not have a loss of preload line for closure bolting using carbon steel in an atmosphere/weather environment.

This condition resulted in the use of Standard Note H. Plant Specific Note 1 explains that loss of preload applies to this application even though NUREG 1801 does not evaluate steel closure bolting in atmosphere/weather environments.

AMP XI.M.18, Bolting Integrity is credited for aging management of this loss of preload application.

The requirements of the i AMP apply completely for this loss of preload application.

The AMP requires that bolting installation plant procedures control joint assembly land control of preload. This includes pre-assembly inspection and icleaning requirements, use of specific bolt torque patterns, use of increased torque application through multiple passes, and verification of.unformity of gasket compression.

Post-bolting inspections include 112 I %Qijestkpn No IAMRAO67 IAMRA068 4LRA Sec 3.4 i3 vfnotAutdit Question Fi<V :e n the fal Rasponse g a verifying contact between the fastener and flange and proper flange LRA Table 3.4.2-3 includes several IThe High Pressure (HP) feedwater heaters are in-scope for feedwater heat exchanger components which !system pressure boundary integrity to support post fire safe shutdown are exposed to plant indoor air and !requirements per 10CFR54.4(a)(3).

Heat transfer is not an intended secondary water. The LRA states !function for the HP feedwater heaters.,that loss of material and cracking (in 1* ~~ -., I I one case) are aging effects requiring management.

Justify why heat transfer is not stated as the intended function for these and why loss of heat transfer is not considered as an aging effect requiring management

• ._.... .____ __SRP-LR Section 3.2.2.2.6 states that iThe High Pressure Safety Injection pumps are not used for normal loss of material due to erosion may charging.

The normal and centrifugal charging pumps are part of the occur in the stainless steel high- Chemical & Volume Control System. USAR Section 9.3.4.2.1.1 discusses pressure safety injection (HPSI) the Chemical & Volume Control System Charging, Letdown and Seal pump miniflow recirculation orifice Water subsystems.

From USAR Section 9.3.4.2.1.1

-Three charging exposed to treated borated water, pumps (one "normal" pump and two standby pumps) are provided to take LRA Section 3.2.2.2.6 addresses suction from the volume control tank and return the purified reactor loss of material due to erosion. The coolant to the RCS. Normal charging flow is handled by the normal applicant stated that this aging effect !charging pump.is not applicable because WCGS does not use the safety injection The HPSI mini-flow recirculation lines containing the flow orifices are only pumps for normal charging; used during the Emergency Core Cooling System injection phase when therefore, the applicable GALL RCS pressure is above pump shutoff head, or during safety injection Report line item was not used. pump testing. (ref. USAR Section 6.3.2.1)Provide procedures and/or other documentation that show infrequent use of the HPSI pumps.SRP-LR Section 3.2.2.2.9 states that Section 3.2.2.2.9 is a roll-up of V.B-9 for Standby Gas Treatment Systems loss of material due to general, jwhich is a BWR specific system. See NUREG-1800 Table 3.2-1 Item 17;pitting, crevice, and MIC may occur NUREG-1801 Table 2 Item 17; NUREG-1801 line V.B-9. In addition, in steel (with or without coating or there is no buried carbon steel piping associated with ESF systems at wrapping ) piping, piping WCGS.components, and piping elements buried in soil. Buried piping and tanks inspection programs rely on industry practice, frequency of pipe excavation, and operatin .113 AMRA069 13.2 Question No ,,,tRA Seci Audit Question~

FA~inal Re~sponse experience to manage the aging effects of loss of material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection program should be verified by evaluation of an applicant's inspection frequency and operating experience with buried components to ensure that loss of material does not occur. LRA Section 3.2.2.2.9 addresses loss of material due to general, pitting, icrevice, and MIC. The applicant stated that this aging effect is not applicable because WCGS is a PWR. Provide an explanation as to 1why buried piping is only found at.BWRs.Table 3.3.2-16, page 3.3-163, includes a component item"Insulation" of ceramic fiber'insulation material.

Please explain where this insulation material is used. Also, note 2 at the bottom of Table 3.3.2-16 does not include ceramic fiber insulation materials.

Does note 2 apply to this item?AMRA070 3.3'The ceramic fiber insulation is used for diesel generator exhaust line at the penetration of the diesel generation room to prevent overheat of the surrounding concrete.

It is made of Kaowool ceramic fiber blanket.,The Note 2 of LRA Table 3.3.2-16 will be amended as follows: i2 "NUREG-1801 does not consider mechanical insulation.

The in-scope thermal insulation is located in areas with non-aggressive environments (meaning the insulation is not exposed to contaminants).

Based on the Ireview of the site operating experience, it was determined that for stainless steel insulation, closed cell foam, quilted fiberglass insulation, calcium silicate, ceramic fiber and insulation jacketing in non-aggressive ienvironments, there were no aging effects requiring management." 114 Attachment I to ET 07-0020 Page 1 of 11 LICENSE RENEWAL APPLICATION

-LIST OF REGULATORY COMMITMENTS The following table identifies a summary of those actions committed to by Wolf Creek Nuclear Operating Corporation (WCNOC) in the License Renewal Application (LRA) and subsequent LRA correspondence.

Any other statements in this submittal are provided for information purposes and are not considered to be commitments.

Please direct questions regarding these commitments to Mr. Kevin Moles at (620) 364-4126.COMMITMENT LRA, -SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 1 Boric Acid Corrosion A1.4 Prior to the period of extended operation, Program procedures will be enhanced to state that (RCMS 2006-198) susceptible components adjacent to potential leakage sources will include electrical components and connectors.

Reference:

ET 06-0038 Due: March 11, 2025 2 Nickel-Alloy Penetration A1.5 Prior to the period of extended operation, Nozzles Welded To The procedures will be enhanced to indicate that Upper Reactor Vessel detection of leakage or evidence of cracking Closure Heads of in the vessel head penetration nozzles or Pressurized Water associated welds will cause an immediate Reactors reclassification to the "High" susceptibility (RCMS 2006-199) ranking, commencing from the same outage in which the leakage or cracking is detected.

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 2 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 3 Closed-Cycle Cooling A1.10 Prior to the period of extended operation, a Water System new periodic preventive maintenance (RCMS 2006-200) activity will be developed to specify performing inspections of the internal surfaces of valve bodies and accessible piping while the valves are disassembled for operational readiness inspections to detect loss of material and fouling. The acceptance criteria will be specified in this Preventive Maintenance activity.

Reference:

ET 06-0038 Due: March 11, 2025 Revised ET 07-0020 4 Inspection of Overhead A1.11 Prior to the period of extended operation, Heavy Load and Light procedures will be enhanced to: (1) identify Load (Related to industry standards or Wolf Creek Refueling)

Handling Generating Station (WCGS) specifications Systems that are applicable to the component, and (RCMS 2006-201)

(2) specifically inspect for loss of material due to corrosion or rail wear.

Reference:

ET 06-0038 Due: March 11, 2025 5 Fire Protection A1.12 Prior to the period of extended operation: (RCMS 2006-202)

(1) fire damper inspection and drop test procedures will be enhanced to inspect damper housing for signs of corrosion, (2)fire barrier and fire door inspection procedures will be enhanced to specify fire barriers and doors described in USAR Appendix 9.5A, 'WVCGS Fire Protection Comparison to APCSB 9.5-1 Appendix A", and WCGS Fire Hazards Analysis, and (3)training for technicians performing the fire door and fire damper visual inspection will be enhanced to include fire protection inspection requirements and training documentation.

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 3 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 6 Fuel Oil Chemistry A1.14 Prior to the period of extended operation: (RCMS 2006-203 (1) the emergency fuel oil day tanks will be added to the ten year drain, clean, and internal inspection program, and (2)procedures will be enhanced to provide for supplemental ultrasonic thickness measurements if there are indications of reduced cross sectional thickness found during the visual inspection of the emergency fuel oil storage tanks. A one time ultrasonic (UT) or pulsed eddy current (PEC) thickness examination on the external surface of engine driven fire pump fuel oil tank (1 DO002T) will be performed to detect corrosion related wall thinning.

If UT is used, the examination will be on a 4 inch grid. The examination will be performed once between 10 and 2 years prior to the period of extended operation.

Reference:

ET 06-0038 Due: March 11, 2025 Revised ET 07-0020 7 One-Time Inspection A1.16 The One-Time Inspection program (RCMS 2006-204) conducts one-time inspections of plant system piping and components to verify the effectiveness of the Water Chemistry program (Al.2), Fuel Oil Chemistry program (Al.14), and Lubricating Oil Analysis program (Al.23). This new program will be implemented and completed within the ten-year period prior to the period of extended operation.

Reference:

ET 06-0038 Due: March 11, 2025 8 Selective Leaching of A1.17 The Selective Leaching of Materials Materials program is a new program that will be (RCMS 2006-205) implemented prior to the period of extended operation.

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 4 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 9 Buried Piping and Tanks A1.18 The Buried Piping and Tanks Inspection Inspection program is a new program that will be (RCMS 2006-206) implemented prior to the period of extended operation.

Within the ten-year period prior to entering the period of extended operation, an opportunistic or planned inspection will be performed.

Upon entering the period of extended operation a planned inspection within ten years will be required unless an opportunistic inspection has occurred within this ten-year period.

Reference:

ET 06-0038 Due: March 11, 2025 10 One-Time Inspection of A1.19 The fourth interval of the IS[ program at ASME Code Class 1 WCGS will provide the results for the one Small-Bore Piping (RCMS time inspection of ASME Code Class 1 2006-207) small-bore piping.

Reference:

ET 06-0038 Due: March 11, 2025 11 Inspection of Internal A1.22 The Inspection of Internal Surfaces in Surfaces in Miscellaneous Miscellaneous Piping and Ducting Piping and Ducting Components program is a new program Components that will be implemented prior to the period (RCMS 2006-208) of extended operation.

For those systems or components where inspections of opportunity are insufficient, an inspection will be conducted prior to the period of extended operation to provide reasonable assurance that the intended functions are maintained.

Reference:

ET 06-0038 Due: March 11, 2025 12 Electrical Cables and A1.24 The Electrical Cables and Connections Not Connections Not Subject Subject to 10 CFR 50.49 Environmental to 10 CFR 50.49 Qualification Requirements program is a Environmental new program that will be implemented prior Qualification Requirements to the period of extended operation.(RCMS 2006-209)

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 5 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 13 Electrical Cables Not A1.25 A review of the calibration surveillance test Subject to 10 CFR 50.49 results will be completed before the period Environmental of extended operation and every 10 years Qualification Requirements thereafter.

Used in Instrumentation

Reference:

ET 06-0038 Circuits Due: March 11, 2025 (RCMS 2006-210)14 Inaccessible Medium A1.26 The Inaccessible Medium Voltage Cables Voltage Cables Not Not Subject to 10 CFR 50.49 Environmental Subject to 10 CFR 50.49 Qualification Requirements program is a Environmental new program that will be implemented prior Qualification Requirements to the period of extended operation.(RCMS 2006-211)

Reference:

ET 06-0038 Due: March 11, 2025 15 ASME Section Xl, A1.28 Prior to the period of extended operation, Subsection IWL procedures will be enhanced to include two (RCMS 2006-212) new provisions regarding inspection of repair/replacement activities.

The 2001 Edition with 2002 and 2003 addenda of ASME Section Xl, Subsection IWL, Article IWL-2000, includes two provisions that are not required by the 1998 edition. IWL-2410(d) specifies additional inspections for concrete surface areas affected by a repair/replacement activity, and IWL-2521.2 specifies additional inspections for tendons affected by a repair/replacement activity.

In accordance with 10 CFR 50.55a, WCGS will revise their CISI program prior to the next inspection interval to incorporate the ASME Code edition and addenda incorporated into 10 CFR 50.55a at that time.

Reference:

ET 06-0038 Due: March 11, 2025 Revised ET 07-0020 16 Masonry Wall Program A1.31 Prior to the period of extended operation, (RCMS 2006-213) procedures will be enhanced to identify un-reinforced masonry in the Radwaste Building within the scope of license renewal that requires aging management.

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 6 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 17 Structures Monitoring A1.32 Prior to the period of extended operation, Program procedures will be enhanced to add (RCMS 2006-214) inspection parameters for treated wood and to monitor groundwater for pH, sulfates, and chlorides.

Two samples of groundwater will be tested every five years.

Reference:

ET 06-0038 Due: March 11, 2025 Revised ET 07-0020 18 RG 1.127, Inspection of A1.33 Prior to the period of extended operation, Water-Control Structures procedures will be enhanced:

(1) so that the Associated with Nuclear main dam service spillway and the auxiliary Power Plants spillway will be inspected in accordance (RCMS 2006-215) with the same specification, (2) to clarify the scope of inspections for the spillways, (3) to add the 5 year inspection frequency for the main dam service spillway, and (4) to add cavitation to the list of concrete aging effects for surfaces other than spillways.

Reference:

ET 06-0038 Due: March 11, 2025 19 Reactor Coolant System A1.35 WCNOC will: Supplement A. Reactor Coolant System Nickel Alloy (RCMS 2006-216)

Pressure Boundary Components Implement applicable (1) NRC Orders, Bulletins and Generic Letters associated with nickel alloys and (2) staff-accepted industry guidelines, and B. Reactor Vessel Internals (1) Participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, WCNOC will submit an inspection plan for reactor internals to the NRC for review and approval.

Reference:

ET 06-0038 A, B(1), B(2) Due: March 11, 2025 3B(3) Due: March 11, 2023 Attachment I to ET 07-0020 Page 7 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 20 Electrical Cable Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements (RCMS 2006-217)A1.36 Prior to the period of extended operation, the infrared thermography testing procedure will be enhanced to require an engineering evaluation when test acceptance criteria are not met. This engineering evaluation will include identifying the extent of condition, the potential root cause for not meeting the test acceptance, and the likelihood of recurrence.

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 8 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 21 Metal Fatigue of Reactor Coolant Pressure Boundary (RCMS 2006-218)A2.1 Prior to the period of extended operation, the Metal Fatigue of Reactor Coolant Pressure Boundary program will be enhanced to include: (1) Action levels to ensure that if the fatigue usage factor calculated by the code analysis is reached at any monitored location, appropriate evaluations and actions will be invoked to maintain the analytical basis of the leak-before-break (LBB) analysis and of the high-energy line break (HELB) locations, or to revise them as required, (2) Action levels to ensure that appropriate evaluations and actions will be invoked to maintain the bases of safety determinations that depend upon fatigue analyses, if the fatigue usage factor at any monitored location approaches 1.0, or if the fatigue usage factor at any monitored NUREG/CR6260 location approaches 1.0 when multiplied by the environmental effect factor FEN, (3)Corrective actions, on approach to these action levels, that will determine whether the scope of the monitoring program must be enlarged to include additional affected reactor coolant pressure boundary locations in order to ensure that additional locations do not approach the code limit without an appropriate action, and to ensure that the bases of the LBB and HELB analyses are maintained, (4) 10 CFR 50 Appendix B procedural and record requirements.

Prior to the period of extended operation, changes in available monitoring technology or in the analyses themselves may permit different action limits and action statements, or may re-define the program features and actions required to address the fatigue time: limited aging analyses (TLAAs).

Reference:

ET 06-0038 Due: March 11, 2025 22 I Deleted Attachment I to ET 07-0020 Page 9 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 23 Concrete Containment A2.3 Prior to the period of extended operation, Tendon Prestress procedures will be revised to: (1) extend the (RCMS 2006-220) list of surveillance tendons to include random samples for the year 40, 45, 50, and 55 year surveillances, (2) explicitly require a regression analysis for each tendon group after every surveillance, (3)invoke and describe regression analysis methods used to construct the lift-off trend lines, (4) extend surveillance program predicted force lines for the vertical and hoop tendon groups to 60 years, and (5)conform procedure descriptions of acceptance criteria action levels to the ASME Code, Subsection IWL 3221 descriptions.

Reference:

ET 06-0038 Due: March 11, 2025 24 ASME III Subsection NG A3.2.2 WCNOC will obtain a design report Fatigue Analysis of amendment to either quantify the increase Reactor Pressure Vessel in high-cycle fatigue effects, or to confirm Internals that the increase will be negligible.(RCMS 2006-221)

WCNOC will complete this action before the end of the current licensed operating period.

Reference:

ET 06-0038 Due: March 11, 2025 25 Assumed Thermal Cycle A3.2.4 WCNOC will complete the reanalysis of the Count for Allowable reactor coolant sample lines and any Secondary Stress Range additional corrective actions or Reduction Factor in B31.1 modifications indicated by them, before the and ASME III Class 2 and end of the current licensed operating 3 Piping (RCMS 2006-222) period.

Reference:

ET 06-0038 Due: March 11, 2025 Attachment I to ET 07-0020 Page 10 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 26 USAR Supplement A0 Following issuance of the renewed (RCMS 2006-223) operating license in accordance with 10 CFR 50.71 (e), WCNOC will incorporate the USAR supplement into the WCGS USAR as required by 54.21(d).

Reference:

ET 06-0038 Due: USAR update following issuance of the renewed operating license in accordance with IOCFR 50.71(e).Revised ET 07-0020 27 Pressure-Temperature (P- A3.1.3 WCNOC will revise the Pressure and T) Limits (RCMS 2006- Temperature Limits Report for a 60-year 224) licensed operating life.

Reference:

ET 06-0038 Due: March 11, 2025 28 Implementation of New N/A Implementation of new programs may Programs require additional action items not included (RCMS 2006-225) in this list. WCGS is committed to including new program elements in the corrective action program.

Reference:

ET 06-0038 Due: March 11, 2025 29 LRA Amendment N/A License Renewal Application changes (RCMS 2007-250) discussed in ET 07-0011 will be submitted in an amendment to the Application.

Reference:

ET 07-0011 Due: July 20, 2007 30 Nickel Alloy Aging A1.34 The WCGS Nickel Alloy Aging Management Management Program inspection plan will be submitted for NRC (RCMS 2007-251) review and approval at least 24 months prior to entering the period of extended operation

Reference:

ET 07-0016 Due: March 11, 2023 31 LRA Amendment N/A License Renewal Application changes (RCMS 2007-252) discussed in ET 07-0020 will be submitted in an amendment to the Application.

Reference:

ET 07-0020 Due: August 31, 2007 Attachment I to ET 07-0020 Page 11 of 11 COMMITMENT LRA, SUBJECT Appendix A, COMMITMENT DESCRIPTION Section 32 Closed-Cyle Cooling Water N/A WCNOC Procedure QCP-20-518, "Visual System Examination of Heat Exchangers and (RCMS 2007-253)

Piping Components", will be revised to define cracking, provide additional guidance for detection of cracking and specific acceptance criteria relating to "as found" cracking.

Reference:

ET 07-0020 Due: March 11, 2025