ML091890836

Request for Additional Information Regarding the Review of the Kewaunee Power Station License Renewal Application

ML091890836
Person / Time
Site:	Kewaunee
Issue date:	11/20/2009
From:	Hernandez-Quinones S License Renewal Projects Branch 1
To:	Heacock D Dominion Energy Kewaunee
Hernandez S, NRR/DLR/REBB, 415-4049
References
TAC MD9408
Download: ML091890836 (14)

Text

November 20, 2009 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Energy Kewaunee, Inc.

Innsbrook Technical Center - 2SW 5000 Dominion Blvd.

Glen Allen, VA 23060-6711

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION (TAC NO. MD9408)

Dear Mr. Heacock:

By letter dated August 12, 2008, Dominion Energy Kewaunee, Inc. (Dominion), submitted an application for renewal of operating license DPR-43 for the Kewaunee Power Station. The staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) is reviewing this application in accordance with the guidance in NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants. During its review, the staff has identified areas where additional information is needed to complete the review. The staffs requests for additional information are included in the enclosure. Further requests for additional information may be issued in the future.

Items in the enclosure were discussed with Paul Aitken, of your staff, and a mutually agreeable date for the response is within 30 days from the date of this letter. If you have any questions, please contact me by telephone at 301-415-4049 or by e-mail at Samuel.Hernandez@nrc.gov.

Sincerely,

/RA/

Samuel Hernández, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-305

Enclosure:

As stated cc w/encl: See next page

November 20, 2009 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Energy Kewaunee, Inc.

Innsbrook Technical Center - 2SW 5000 Dominion Blvd.

Glen Allen, VA 23060-6711

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION (TAC NO. MD9408)

Dear Mr. Heacock:

By letter dated August 12, 2008, Dominion Energy Kewaunee, Inc. (Dominion), submitted an application for renewal of operating license DPR-43 for the Kewaunee Power Station. The staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) is reviewing this application in accordance with the guidance in NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants. During its review, the staff has identified areas where additional information is needed to complete the review. The staffs requests for additional information are included in the enclosure. Further requests for additional information may be issued in the future.

Items in the enclosure were discussed with Paul Aitken, of your staff, and a mutually agreeable date for the response is within 30 days from the date of this letter. If you have any questions, please contact me by telephone at 301-415-4049 or by e-mail at Samuel.Hernandez@nrc.gov.

Sincerely,

/RA/

Samuel Hernández, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-305

Enclosure:

As stated cc w/encl: See next page DISTRIBUTION:

See next page ADAMS Accession Number: ML091890836 OFFICE PM:RPB1:DLR LA:RPOB:DLR BC:RPB1:DLR PM:RPB1:DLR NAME SHernandez SFigueroa BPham SHernandez (Signature)

DATE 11/20/09 11/19/09 11/20/09 11/20/09 OFFICIAL RECORD COPY

Letter to David A. Heacock from Samuel Hernandez dated November 20, 2009

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION (TAC NO. MD9408)

DISTRIBUTION:

HARD COPY:

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S. Hernandez S. Lopas P. Tam S. Burton K. Barclay M. Kunowski V. Mitlyng I. Couret S. Burton P. Higgins J. Medoff J. Dozier

Kewaunee Power Station cc:

Resident Inspectors Office Mr. Paul C. Aitken U.S. Nuclear Regulatory Commission Supervisor - License Renewal Project N490 Hwy 42 Innsbrook Technical Center - 3NE Kewaunee, WI 54216-9510 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Mr. Chris L. Funderburk Director, Nuclear Licensing and Mr. David A. Sommers Operations Support Supervisor - Nuclear Engineering Dominion Resources Services, Inc. Innsbrook Technical Center - 2SE Innsbrook Technical Center - 2SE 5000 Dominion Boulevard 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Glen Allen, VA 23060-6711 Ms. Lillian M. Cuoco, Esq.

Mr. Thomas L. Breene Senior Counsel Dominon Energy Kewaunee, Inc. Dominion Resources Services, Inc.

Kewaunee Power Station 120 Tredegar Street N490 Highway 42 Riverside 2 Kewaunee, WI 54216 Richmond, VA 23219 Mr. Michael J. Wilson, Director Mr. Stephen E. Scace Nuclear Safety & Licensing Site Vice President Dominion Energy Kewaunee, Inc. Dominion Energy Kewaunee, Inc.

Kewaunee Power Station Kewaunee Power Station N490 Highway 42 N490 Highway 42 Kewaunee, WI 54216 Kewaunee, WI 54216 Mr. William R. Matthews Mr. David R. Lewis Senior Vice President - Nuclear Operations Pillsbury Winthrop Shaw Pittman, LLP Innsbrook Technical Center - 2SE 2300 N Street, N.W.

5000 Dominion Boulevard Washington, DC 20037-1122 Glen Allen, VA 23060-6711 Mr. Ken Paplham Mr. Alan J. Price E 4095 Sandy Bay Rd.

Vice President - Nuclear Engineering Kewaunee, WI 54216 Innsbrook Technical Center - 2SE 5000 Dominion Boulevard Mr. Jeff Kitsembel, P.E.

Glen Allen, VA 23060-6711 Public Service Commission of Wisconsin P. O. Box 7854 Mr. William D. Corbin Madison, WI 53707-7854 Director - Nuclear Engineering Innsbrook Technical Center - 3NE 5000 Dominion Boulevard Glen Allen, VA 23060-6711

KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION REQUEST FOR ADDITIONAL INFORMATION RAI B2.1.31-1a - Updated Safety Analysis Report (USAR) Supplement, Section A2.1.31 Background/Issue The applicant responded to RAI B2.1.31-1 in a letter dated August 17, 2009. The applicants response has covered only Structures Monitoring Program. Descriptions for masonry wall and water-control structures are not included in the response.

Request Revise LRA Appendix A, USAR Supplement, Section A2.1.31 to incorporate the summary of AMP XI.S5, Masonry Wall Program, and AMP XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plant.

RAI B2.1.31-2a - Implementation of Inspection of Water-Control Structures Background/Issue The applicant responded to RAI B2.1.31-2 in a letter dated August 17, 2009. The applicants response did not address all the elements of AMP XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plant. The applicant has added RG 1.127 for Element 4 only.

Request

• List the parameters of AMP XI.S7; Element 3 that are applicable to KPS and describe how they will be implemented by the Structures Monitoring Program.

• Describe how Element 10 of AMP XI-S7 will be implemented in Structures Monitoring Program.

RAI B2.1.31-3a - Ground Water Quality Background/Issue In response to RAI B2.1.31-3, the applicant stated that the groundwater samples taken in June 2007; March, July, August, and October 2008; and March and June 2009 indicate a chloride range from 34 ppm to 1240 ppm. The average chloride readings from the eight wells selected for monitoring for license renewal are varying from 120 ppm to 640 ppm. The applicant has also stated that use of deicing salt is the most likely contributor to the elevated chloride concentration found in these wells. Use of salt, instead of sand as a deicer for the paved area began sometime between 1992 and 2000. Furthermore, the applicant has stated that 40 mil thick ENCLOSURE

polyvinyl chloride waterproofing membrane was installed to the concrete surface which minimizes direct contact between the concrete structures and the groundwater environment.

Request

• Show the well locations with reference to the structures on the Plant General Arrangement Plan Drawing and indicate the maximum and average chloride content of the groundwater.

This should indentify the safety-related structures that are located in the areas where the chloride content has been found to be >500 ppm.

• Demonstrate that the current level of chloride in the groundwater is not causing any degradation to the structures.

• Address the ability of water proofing membrane to resist ingress of water in the concrete structure based on the plant-specific or/and industry wide experience.

RAI B2.1.3-4a - Reactor Refueling Cavity Leakage Background/Issue In Dominion Energy Kewanee, Inc. Letter 09-469, dated August 17, 2009, Response to Request for Additional Information for Review of the Kewaunee Power Station License Renewal Application- Aging Management Program, the applicant submitted responses to RAI B2.1.3-1 and B2.1.31-4. In response to RAI 2.1.3-1, the applicant stated that in the fall of 2006 and again in 2008, the area below the reactor cavity/refueling pool and the aluminum conductor steel reinforced loop vault were identified as the two most likely locations for leakage and extent of leakage was evaluated. The amount of leakage was categorized as minimal (streaking of the walls). However, in response to RAI 2.1.31-4, the applicant stated that crack location on the south side of the outer concrete surface of the reactor cavity wall was first discovered in April 2003 and a follow-up inspection was performed in 2004 which concluded that there was no active leak from any source going thru the crack. Based on the inspection results, it was also concluded that no further action was required. During the fall 2006 and spring 2008 outages, regularly scheduled inspections did not identify any noticeable boric acid at the crack location.

Request In order to complete its review, the staff requests the applicant to provide additional details about the reactor cavity/refueling pool leakage. Specifically, the staff requests response to the following:

• Provide more details about the leakage volume and path observed in 2003, 2004, 2006, and 2008 outages.

• Details of any remedial actions or repairs performed during 2003 and 2004 to stop the leakage.

• Plans to verify the structural integrity of the concrete and rebar at the cracked locations by core drills or other means.

• Plans for permanent remediation of reactor cavity/refueling pool leakage.

RAI B2.1.31 White Substance on Wall and Ceiling of the Waste Drumming Room Background/Issue In response to RAI B.2.1.31-5, the applicant has stated that on December 28, 2007, the white substance was observed on the wall and ceiling of the waste drumming room, below the spent fuel pool. The area was cleaned and inspected. The applicant concluded that structural integrity of the concrete was not adversely affected and structure was sound on the basis that the concrete did not display visible spalling (which would indicate that the reinforcing is corroding and causing pop outs of the concrete), deformed surfaces (which would indicate that the reinforcement is in distress), or widening of cracks. Additionally, the applicant stated that the rebar in reinforced concrete is normally protected against corrosion by the alkalinity of the concrete, which is typically in the range of pH 12.5 or more.

In the response, the applicant further stated that residue rebuilt after cleaning, did not indicate active dripping. The applicant has stopped cleaning the area because it increases the personnel dose. Instead of cleaning, the applicant is monitoring the change in size, shape, and color.

Request

• Verify the condition of the concrete and rebar at the crack locations by appropriate non-destructive examination.

• Leakage of boric acid water could change the pH and could be potential cause for the corrosion of the rebar. Staff requests the applicant to clarify the basis for assuming the reinforcing bars will remain protected by concrete even when they come in contact with boric acid water for a sustained period.

• Describe the plan for permanent remediation.

• Describe the functioning of leakchase channels and monitoring of water level in the spent fuel pool.

RAI 3.6.2.2.3-1

Background

In LRA Section 3.6.2.2.3, the applicant stated that switchyard buses have terminations that are evaluated as part of the cable and connections component types.

Issue The scope of the cable and connection program B2.1.20 does not include high-voltage connections. The scope of the cable and connection program only includes medium and low voltage connections.

Request Explain how switchyard bus terminations are evaluated as part of the cable and connection component types.

RAI 3.6.2.2.3-2

Background

In LRA Section 3.6.2.2.3, the applicant states that increased resistance of aluminum conductor connections due to oxidation or loss of pre-load is minimized through the use of compatible aluminum hardware, the use of lock washers in bolted connections, and no-oxide compounds at connection surfaces in all termination types. The applicant also states that increased resistance of aluminum conductor connections due to oxidation or loss of pre-load is not a credible aging mechanism requiring management.

Issue Failures of locked washers (Bellville washers causing loose connections) were noted from industry operating experience, whereby hydrogen entrapment with plated steel washers causing embrittlement and stress cracking of the plated washer leading to loose connections. In addition, EPRI TR-104213 also identifies this problem with galvanized/electroplated Belleville washers.

Request Explain if electroplated/galvanized Belleville washers are currently used at KPS. If so, explain why hydrogen embrittlement is not a problem at KPS. In addition, describe switchyard maintenance activities used to confirm the effectiveness of bolted connections in the switchyard.

RAI 3.6.2.1.2-1.

Background

GALL Report, Vol. 2, Rev. 1, Item VI.A-8, Fuse Holders (Not Part of a Larger Assembly; Metallic Clamp, identifies the aging/effect mechanism as fatigue,/ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical contamination, corrosion and oxidation. The associated AMP XI.E5, Fuse Holders, states that fuse holders within the scope of license renewal should be tested to provide an indication of the condition of the metallic clamps of fuse holders. In LRA, Section 3.6.2.1.2, Fuse Holders, the applicant states that there are no aging management programs required for fuse holders based on a review of the environment of the fuse holders. Table 3.6.1, Item 3.6.1-06 of the LRA concludes that only fuse holders located in two enclosed cabinets in the Relay Room required evaluation and concludes that these fuse holders are in a controlled environment, and are not subject to the aging effect/mechanisms as identified in Item VI.A-8 of GALL Report, Vol. 2, Rev. 1.

Issue Although the applicant concludes in Section 3.6.2.1.2 that the aging effects/mechanisms identified by the GALL Report are not applicable to the fuse holders at KPS, the applicant does not provide an evaluation to substantiate the conclusion. Table 3.6.1, Item 3.6.1-06 of the LRA provides the same conclusion.

Request Provide an evaluation that addresses the aging effect/mechanisms identified in GALL Report, Vol. 2, Rev. 1, Item VI.A-8 that supports the conclusions made in LRA Section 3.6.2.1.2 and Table 3.6.1, Item 3.6.1-06.

RAI 3.6.2.3-1

Background

In LRA Table 3.6.2-1, Electrical Components - Cables and Connections - Aging Management Evaluation, the applicant indicated that fuse holders (insulation) are not in an adverse localized environment and denoted Note H. Note H means the aging effect not in the GALL Report for this component, material and environment combination.

Issue GALL Report, Vol. 2, Rev 1, Item VI.A-6 identifies embrittlement, cracking, melting, or loss of dielectric strength leading to reduced insulation resistance for insulation materials of fuse holder in an adverse localized environment due to heat, radiation, or moisture in the presence of oxygen.

Request Explain why the aging effects identified in the GALL Report in adverse localized environment are not applicable to the insulation materials of fuse holder at KPS.

RAI B2.1.5 Bolting Integrity Program

Background

By letter dated September 28, 2009, the applicant responded to RAI B2.1.5-5 by stating that an exception would be needed to account for the use of aging detection methods different than in the GALL Report Section XI.M18 program with respect to the management of stress corrosion cracking (SCC) in high strength bolts. The GALL Report relies on volumetric and visual examinations to detect stress corrosion cracking in high strength bolts. However the GALL Report also allows for a waiver of the volumetric examination with sufficient plant-specific justification. The applicant has requested an exception to perform periodic visual inspections only.

Issue The applicants response to RAI B2.1.5-5 included discussion of the possibility of the existence of residual stresses from the fabrication process of these high strength steel bolts, but the applicant could not definitively conclude that they did not exist. Knowledge of the exact material and how the threaded rod was manufactured is important to the staffs determination of a possible crack initiation and as a result, it is necessary for determination of the sufficiency of the plant-specific justification. For example, certain types of manufacturing will lead to an increase or decrease in ductility, or affect crack initiation. Therefore, a description of the type and extent of the hardening process, thread rolling/machining process, and any heat treating will provide additional information for the staff to review.

Request Please provide the exact material of these high strength bolts, and the details of how they were manufactured (from heat treating to machining).

RAI 3.1.2.2.2.4-2

Background:

The LRA, especially Section 3.3.2.2.2.4, does not provide any information nor discuss inspections regarding the new weld generated by the cut made in the middle of the transition cone at the time of steam generator replacement, specified as transition weld in KPS USAR Section 4.2.2.6 and Drawing LRXK-100-10.

Issue:

In LRA Table 3.1.2-4, the applicant addresses the aging effect of loss of materiel due to general, pitting and crevice corrosion by the ASME Section XI In-service inspection, subsections IWB, IWC, and IWD for the upper, lower and transition cone shells. From the LRA, the new transition weld from the steam generator replacement would have the same conditions as the original upper shell-to-transition cone girth weld, and therefore, would be susceptible to the same aging effects (even if the shell geometry is less severe for the new weld). From Drawing LRXK-100-10, the new transition weld appears to be located in a gross structural discontinuity because the transition cone is by definition a junction between shells of different diameters (as defined is ASME NB-3213.2).

Request:

Describe the inspections that will be performed on the transition weld during the renewed license period.

RAI B2.1.30-16

Background

LRA Table 3.1.2-4 addresses AMR items for loss of material due to pitting and crevice corrosion for nickel alloys components exposed to treated water and/or steam-secondary for the following seven steam generator components: Feedwater inlet ring J nozzles, Feedwater nozzle (and nickel alloy cladding), Feedwater nozzle thermal sleeve, Steam nozzle flow restrictor, Tube bundle support hardware, Tube plugs, Tube and sleeves.

The staff reviewed LRA Table 3.1.2-4 against the criteria of SRP-LR Table 3.1.1. Instead of the two aging effects described in SRP-LR and LRA Tables 3.1.1-72 and 3.1.1-74 (e.g. cracking due to stress corrosion cracking and loss of material due to fretting and wear/crevice corrosion and fretting), the applicant identified the aging effects of cracking and proposed another type of loss of material, due to pitting and crevice corrosion for these seven components.

Although the GALL report does not have a corresponding AMR for these seven steam generator components, the staff finds the applicants identification of aging effects acceptable according to the selection criteria of the applicant. However, the applicant stated it would manage the aging effect of loss of material due to pitting and crevice corrosion using the Secondary Water Chemistry program described by the AMP for SRP-LR and LRA item 3.4.1-37 without providing any explanation or justification for the adequacy of this program.

The staff notes that the specific item described in the LRA from the SRP-LR and the GALL report (e.g., SP-18) relates to aging management of nickel alloy components exposed to dry steam, whereas the seven components listed above are exposed to treated water and/or steam-secondary, as indicated in LRA Table 3.1.2-4. For example, the tube plugs are clearly not exposed to dry steam. In spite of this environmental inconsistency with the GALL report, the applicant stated that this AMP is consistent with the GALL report in all aspects (note A) for five of these seven steam generator components.

Issue The staff considers that the environment identified in LRA item 3.4.1-37 (e.g., dry steam) is not appropriate for the seven steam generator components listed above in accordance with the environment they are exposed, i.e. treated water and/or steam-secondary. The staff also finds the applicant did not provide enough information to verify whether the Secondary Water Chemistry program AMP is sufficient to manage the aging effect of loss of material due to pitting and crevice corrosion for these components, or whether, alternatively, the applicant should utilize a condition monitoring or an in-service inspection program to confirm that the cited Secondary Water Chemistry program is achieving its preventive purposes.

Request

• Explain why your choice of AMP for the seven steam generator components listed above is appropriate when the environment associated with LRA item 3.4.1-37 (e.g., dry steam) and that to which these components are exposed (e.g., treated water and/or steam-secondary)

are different, and this AMP does not provide for any other actions (e.g., in-service inspections) to confirm its effectiveness.

• Justify why the Secondary Water Chemistry program is sufficient to manage the loss of material due to pitting and crevice corrosion for these components, without any other condition monitoring or in-service inspection-based program, or describe plans to implement a condition monitoring or in-service inspection-based program.

RAI B.2.1.9-6

Background

The staff issued RAI B.2.1.9-5 by letter dated July 13, 2009, requesting the applicant to clarify whether relevant acceptance criteria are established and documented for the parameters such as compressor load and unload times, minimum operational time for each special service air accumulator and its associated check valves upon loss of the main air system, and Inlet and outlet coolant temperatures of the coolant in the compressor intercoolers and aftercoolers.

In the RAI, the staff also requested that if any of the parameters does not have an acceptance criterion the applicant should justify why lack of the acceptance criterion for the parameter is acceptable for the aging management or describe the actions for the applicant to take in relation to the acceptance criterion.

Issue The applicant responded to RAI B.2.1.9-5 by letter dated on August 17, 2009. However, the applicants response to the RAI did not clarify whether the applicants program has acceptance criteria for the load time of the station and instrument air system compressors. The staff noted that the monitoring of the compressor load and unload times with acceptance criteria can identify adverse trends or the system and component degradation due to aging effects. In addition, the staff noted that ASME OM-S/G-1998, Part 17, Section 5.3 and Table 1, which the applicant committed to incorporate as the program enhancement, recommend tests for the compressor load and unload time.

Request

1. Clarify whether the applicants program with the program enhancement has acceptance criteria for the load time of the station and instrument air system compressors.

2. If the program with the enhancement has no acceptance criteria for the load time of the station and instrument air system compressors, provide the justification why the aging management program is adequate to manage the aging effects of the station and instrument air system without the acceptance criteria that can be used to identify adverse trends or the system and component degradation due to aging effects.

RAI B.2.1.9-7

Background

As addressed in RAI B.2.1.9-4 sent by letter dated June 13, 2009, LRA Section B.2.1.9 described the exception of the applicants Compressed Air Monitoring Program that leak testing is not performed for the station and instrument air system distribution network. In comparison, as an enhancement of the program, the applicant committed to incorporate the compressed air system testing and maintenance recommendations from ASME OM-S/G-1998, Part 17 and EPRI TR-108147 and to identify these documents as part of the program basis.

However, the staff noted that ASME OM-S/G-1998 and EPRI TR-108147 address the conduct of leak tests as described in Sections 5.3.1(b) and 5.3.2 of the ASME document and Section 8.9.2 of the EPRI report. Therefore, the staff issued RAI B.2.1.9-4 to resolve the potential conflict between the exception and the enhancement that the applicant claimed regarding leak testing.

By letter dated August 17, 2009, the applicant responded to RAI B.2.1.9-4 and the response included the following information:

NUREG-1801,Section XI.M24 is explicit that frequent leak testing is intended to be part of the program.Though both [ASME] OM-S/G-1998 and [EPRI] TR-108147 address leak testing, both documents advocate leak testing as part of a troubleshooting process when leakage is suspected and not as a periodic preventive maintenance activity. Therefore, there is a technical difference between guidance in NUREG-1801,Section XI.M24 and the two industry documents.However, as noted above, performing leak testing as part of a troubleshooting activity is a tool to be used to locate a suspected leak.

Issue The applicant stated ASME OM-S/G-1998, Part 17 advocates leak testing as part of a troubleshooting process. However, the staff noted that Section 5.3.1(b)(1) and Table 1 in ASME OM-S/G-1998, Part 17 require that special service air accumulators and the associated check valves should be leak tested using pressure decay test of paragraph 5.2.3(b) every refueling outage, which is consistent with the recommendation of GALL AMP XI.M24 that frequent leak testing be performed for valves, piping and other system components.

In addition, the applicants response to RAI B.2.1.9-5, by letter dated August 17, 2009, stated that the minimum operational time for each special service air accumulator and its associated check valves upon loss of the main air system is a design consideration for the station and instrument air system and is not related to plant aging. However, the staff notes that the minimum operational time for special service air accumulators and their associated check valves upon loss of the main air system is the acceptance criterion and baseline data to be compared with periodic leak test data such that the aging management program can ensure that the system meets the acceptance criteria and identify adverse trends or the system and component degradation due to aging effects.

Request

1. Clarify whether the applicants program with the program enhancement includes the leak tests for special service air accumulators and associated check valves as described in Section 5.3.1(b)(1) and Table 1 in ASME OM-S/G-1998, Part 17.

2. Clarify whether the applicants program with the program enhancement compares periodic leak test data with the minimum operational time for special service air accumulators and their associated check valves upon loss of the main air system.

3. If the applicants program with the program enhancement does not perform the periodic leak tests that are consistent with ASME OM-S/G-1998, Part 17 and the GALL Report or does not compare periodic leak test data with the minimum operational times for special service air accumulators and their associated check valves, justify why the applicants aging management program is adequate to maintain the intended functions of the system including the accumulators and their associated check valves without significant system degradation due to aging effects.