ML13135A094

Summary of Telephone Conference Call Held on May 14, 2013, Between the U.S. Nuclear Regulatory Commission and Tennessee Valley Authority Concerning Requests for Additional Information Pertaining to the Sequoyah Nuclear Plant, Units 1 and 2,

ML13135A094
Person / Time
Site:	Sequoyah
Issue date:	06/13/2013
From:	Richard Plasse Division of License Renewal
To:	Tennessee Valley Authority
Richard Plasse 301-415-1427
References
TAC MF0481, TAC MF0482
Download: ML13135A094 (18)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 June 13, 2013 LICENSEE: Tennessee Valley Authority FACILITY:

Sequoyah Nuclear Plant

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON MAY 14, 2013, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND TENNESSEE VALLEY AUTHORITY CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (TAC. NOS. MF0481 AND MF0482)

The U.S. Nuclear Regulatory Commission (NRC) staff and representatives of Tennessee Valley Authority held a telephone conference call on May 14, 2013, to discuss and clarify the staff's requests for additional information (RAls) concerning the Sequoyah Nuclear Plant, Units 1 and 2, license renewal application. The telephone conference call was useful in clarifying the intent of the staff's RAls. provides a listing of the participants and Enclosure 2 contains a listing of the RAls discussed with the applicant, including a brief description on the status of the items.

The applicant had an opportunity to comment on this summary.

Richard A. Plasse, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket Nos. 50-327 and 50-328

Enclosures:

1. List of Participants

2. List of Requests for Additional Information cc w/encls: Listserv

ML13135A094 OFFICE LARPB1 :DLR PM:RPB1 :DLR BC:RPB1 :DLR NAME IKing MYoo YDiaz-Sanabria DATE 05/30/13 05/31/13 06/13/13

Memorandum to the applicant from R. Plasse dated June 13, 2013

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON MAY 14, 2013, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND TENNESSEE VALLEY AUTHORITY CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (TAC. NOS. MF0481 AND MF0482)

DISTRIBUTION:

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PUBLIC RidsNrrDlr Resource RidsNrrDlrRpb1 Resource RidsNrrDlrRpb2 Resource RidsNrrDlrRerb Resource RidsNrrDlrRarb Resource RidsNrrDlrRasb Resource beth.mizuno@nrc.gov brian.harris@nrc.gov john.pelchat@nrc.gov gena. woodruff@nrc.gov siva.lingam@nrc.gov wesley.deschaine@nrc.gov galen.smith@nrc.gov scott.shaeffer@nrc.gov jeffrey.hamman@nrc.gov craig.kontz@nrc.gov caudle.julian@nrc.gov generette.lloyd@epa.gov gmadkins@tva.gov clwilson@tva.gov hleeO@tva.gov dllundy@tva.gov

TELEPHONE CONFERENCE CALL SEQUOYAH NUCLEAR PLANT LICENSE RENEWAL APPLICATION LIST OF PARTICIPANTS MAY 14, 2013 PARTICIPANTS Richard Plasse Mark Yoo Abdul Sheikh William Holston Cimberly Nickell Ching Ng Roger Kalikian Patrick Purtscher Seung Min Alice Erickson James Medoff James Gavula Bart Fu Kimberly Green Gary Adkins Henry Lee Stan Batch Wayne Bichlmeir Dennis Lundy Larry Seamans Leland Loyd Julie Robinson Dave Lach Andrew Taylor Dave Wooten Alan Cox AFFILIATIONS Nuclear Regulatory Commission (NRC)

NRC NRC NRC NRC NRC NRC NRC NRC NRC NRC NRC NRC NRC Tennessee Valley Authority (TVA)

TVA TVA TVA TVA TVA TVA TVA Entergy/Enercon Entergy/Enercon Entergy/Enercon Entergy/Enercon

- 2 REQUESTS FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION MAY 14, 2013 The U.S. Nuclear Regulatory Commission (NRC or the staff) and representatives of Tennessee Valley Authority held a telephone conference call on May 14, 2013, to discuss and clarify the following requests for additional information (RAls) concerning the license renewal application (LRA).

DRAFT RAI 8.1.6*1

Background:

10 CFR 50.55a(b)(2)(ix), "Examination of metal containments and the liners of concrete containments," references ASME Code Section XI, Subsection IWE and specifies additional inspection requirements for inaccessible areas. It states that the licensee is to evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. ASME Code Subsection IWE*1240 discusses surface areas requiring augmented examinations that include concrete-to steel shell or liner interfaces, embedment zones, and leak chase channels. In addition, the applicant stated in IWE AMP, 8.1.6, that, "SQN has augmented the IWE program to emphasize the inspection of the steel shell at the concrete floor embedment and inaccessible portions (behind mechanical equipment) of the sheiL" Issue:

a) The carbon steel pressure test piping that connect to the embedded leak chase channels in the containment base slab concrete were found to be corroded. Some of the pipes had thru wall corrosion. The applicant has issued a DeSign Change Notice (DCN) that allows, as an option, permanent sealing the pressure test piping by a steel plate after removing a portion of the piping. It is not clear how this change will prevent further corrosion of the pressure test piping, containment liner plate, including the full penetration welds in the base slab, and associated embedded leak chase channels.

b) During the audit, the staff reviewed photographs that show evidence of corrosion in the steel containment shell at the moisture barrier due to water leakage. The moisture barrier had been found to be degraded in certain areas. The water may have also leaked beyond past the degraded moisture barrier into the inaccessible area of steel containment embedded in the concrete resulting in corrosion of the liner plate.

Request:

Discuss the actions the applicant has initiated or planned to ensure that the steel containment pressure boundary integrity will be maintained during the period of extended operation. The response should include:

1. Details of any periodic tests to be performed on the liner plate and leak chase channel

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2. Plans, if any, for UT examination of the steel containment below the moisture barrier from the annulus area, exposure of a portion of the embedded liner plate and rebars in concrete to determine the presence and extent of corrosion.

Discussion: The staff determined that clarification was needed on the request section of the question to better connect the request to the issue section of the question. As a result of the discussion, the staff has replaced the request section of the question with the following:

Discuss the actions the applicant has initiated or planned to ensure that the steel containment pressure boundary integrity will be maintained during the period of extended operation relative to the issues noted above. The response should include:

1. details of any periodic tests to be performed on the liner plate and leak chase channel; and

2. plans, if any, for UT examination of the steel containment below the moisture barrier from the annulus area, exposure of a portion of the embedded liner plate and rebars in concrete to determine the presence and extent of corrosion.

DRAFT RAI 8.1.6-2

Background:

LRA Section B.1.6 states that the applicant's Inservice Inspection - IWE program, with enhancement, is consistent with the program described in NUREG-1801 (GALL Report),

Section XI.S1, ASME Section XI, Subsection IWE. GALL Report AMP XI.S1 "scope of program," program element includes examinations of Class MC, steel containment pressure-retaining components and their integral attachments, metallic shell and penetration liners of Class CC concrete containments and their integral attachments, containment hatches and airlocks, containment moisture barriers, containment pressure-retaining bolting, and metal containment surface areas, including welds and base metal. 10 CFR 50.55a imposes inservice inspection (lSI) requirements per ASME Code,Section XI, Subsection IWE, which in Article IWE-2412, has specific recommendations for examination of welds that are added to the Inspection Program during an inspection interval.

Issue:

During steam generator replacement (SGR) for SQN Units 1 and 2 in 2004 and 2012 respectively, the steel containments dome were cut and full penetration welds were added. The LRA section 8.1.6, "Containment Inservice Inspection - IWE," states that in 2011, the program was revised to change the scope of examinations performed on the containment vessel dome cut welds, based on operating experience. However, the details of the change are not identified in the AMP. It is not clear whether the change satisfies the requirements of IWE-2412 for welds added during an inspection interval.

Request:

1. Describe the details of the change in scope of the examinations performed and will continue to be performed on the containment vessel dome cut welds during the period of extended operation.

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2. The response should include the operating experience across the fleet that was used to implement a change in the scope and whether this change meets the requirements of IWE-2412.

Discussion: The staff and the applicant discussed the clarification of the request section of the issue. As a result of the discussion, no action was required.

RAI B.1.40-4

Background:

A review of the Structures Monitoring AMP plant operating experience has shown that the Turbine Building at Sequoyah Nuclear Plant has been experiencing groundwater infiltration through degraded expansion/isolation joints for at least 16 years. During a walkdown of the Turbine Building, the staff observed dampness and water in-leakage through degraded expansion/isolation joints and cracks in exterior walls. In addition, the staff noted the presence of concrete leaching, spalling, and rust colored stains on the walls. In some areas, groundwater was seeping through cracks in the basement floor. Audited "Maintenance Rule Structural Inspection" revisions 0 and 7 indicate that this groundwater in-leakage and the resulting aging effects continue to be an issue.

The staff also noted a large diagonal crack on the north wall extending upward and eastward approximately 6 feet, which appeared to be much greater than 40 mils.

Issue:

Concrete exposed to groundwater in-leakage over a period of time can lead to corrosion of rebars, concrete cracking, loss of material (spalling, scaling), aggregate reactions, and leaching resulting in increased porosity and permeability and loss of strength. As stated in ACI 349.3R, for concrete "if this leaching progresses without mitigation, the leaching process can produce a loss of mechanical properties, such as compressive strength and modulus of elasticity." ACI 349.3R also states that "leaching is a concern for potentially increasing the exposure of steel reinforcement to corrosion cell formation."

For observed concrete surface conditions that exceed the acceptance limits provided in Section 5.2 of ACI 349.3R (e.g., cracks widths greater than 40 mils), conditions should be considered unacceptable and need further technical evaluation. Cracks of this size expose rebar to corrosion and concrete to further deterioration that may affect the structural integrity of affected structures.

LRA Sections 3.5.2.2.1.9, 3.5.2.2.2.1.4, and 3.5.2.2.2.3.3, address leaching in inaccessible areas of concrete and state that increase in porosity and permeability due to leaching is not an applicable aging effect requiring management. Based on the observed leaching and water infiltration in accessible areas of concrete, the staff does not understand how this conclusion was reached.

Request:

1. In areas susceptible to moisture or groundwater infiltration, describe and provide the technical basis for actions that have been and will be taken to assure that reinforced concrete walls and floor retain their strength and durability, and that there is no active

- 5 corrosion of the rebar taking place. Ensure that the response includes an explanation of how this will be accomplished for inaccessible concrete areas susceptible to moisture or groundwater infiltration.

2. For the diagonal crack on the north wall of the Turbine Building as described above, provide a summary of any evaluation that may have been performed documenting the acceptability of the crack. Describe and justify any actions that will be taken to demonstrate that for this and other similar cracks, the effects of aging will be adequately managed, during the period of extended operation.

Discussion: The staff determined that clarification was needed on the issue section of the question to maintain consistent language throughout the question. As a result of the discussion, the staff has replaced the first paragraph of the issue section of the question with the following:

Concrete exposed to groundwater in-leakage over a period of time can lead to corrosion of rebars, concrete cracking, loss of material (spalling, scaling), aggregate reactions, and leaching resulting in increased porosity and permeability and loss of strength. As stated in ACI 349.3R, for concrete "if this leaching progresses without mitigation, the leaching process can produce a loss of mechanical properties, such as compressive strength and modulus of elasticity." ACI 349.3R also states that "leaching is a concern for potentially increasing the exposure of steel reinforcement to corrosion cell formation."

DRAFT RAI B.1.40-5

Background:

During a walkdown of the spent fuel pool, the staff noted concrete leaching on the outer surfaces of the spent fuel pool walls. The staff also noted that one of the open tell tale drains was not collecting borated water leakage, which may indicate that the leak chase channel is clogged or blocked.

Issue:

Concrete leaching of the spent fuel pool walls, is indicative of leakage originating from the spent fuel pool. If the leak chase channels are clogged or blocked, borated water leakage could accumulate in the channels, behind the liner, and eventually migrate through the concrete, possibly causing degradation of the leak chase system, concrete, and reinforcing steel.

Request:

1. Indicate whether the concrete leaching is active and explain how the borated water leakage may have affected the condition of the concrete and rebar. Describe what steps have been taken, or will be taken, to ensure that there would be no loss of strength for the concrete, no bond deterioration between rebar and concrete, and no active corrosion of steel rebars and embedded leak chase channels, during the period of extended operation.

2. Discuss actions that have been or will be taken to ensure the leak chase system (channels, tubes, trenches, valve bodies, etc) remains free and clear so that it can

-6 effectively prevent borated water from seeping into and thus contributing to the aging of the reinforced concrete.

Discussion: The staff determined that clarification was needed on the request section of the question to clarify the intent of the question. As a result of the discussion, the staff has replaced the first request of the question with the following:

1. Indicate whether the concrete leaching is active, and explain how the borated water leakage may have affected the condition of the concrete and rebar, by describing what steps have been taken, or will be taken, to ensure that there would be no loss of strength for the concrete, no bond deterioration between rebar and concrete, and no active corrosion of steel rebars and embedded leak chase channels, during the period of extended operation.

RAI 8.1.23-1

Background:

LRA Section B.1.23 and applicant's program basis document state that the Nickel Alloy Inspection Program detects reactor coolant pressure boundary cracking and leakage due to primary water stress corrosion cracking (PWSCC). LRA Section B.1.23 states that the program uses the examination and inspection requirements of 10 CFR 50.55a and industry guidelines (e.g., MRP-139), consistent with GALL Report AMP XI,11 B, "Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components (PWRs only)."

During the audit, the staff noted that evidence of borated-water leakage and corrosion was identified in the visual inspection of the Unit 1 reactor vessel bottom head and keyway area during the 2006 refueling outage. The applicant's plant event record (PER) related to this inspection indicates that the affected components were the reactor vessel, vertical and horizontal section of mirror insulation surrounding the reactor vessel, thimble tubes and thimble tube support structure, and concrete wall surrounding the reactor pressure vessels.

Issue:

The LRA does not address which component was the source of the borated-water leakage discussed above or whether the leakage resulted from aging-related degradation of reactor vessel and piping components. The staff also needs confirmation on whether the applicant took adequate corrective action for the observed leakage.

In addition, the staff needs to clarify how the applicant's program manages and resolves the situation that borated-water leakage and associated corrosion products interfere with the visual examination of the components within the scope of the program (e.g., the visual examination of ASME Code Cases N-770-1, N-729-1 and N-722-1).

Request:

1. Describe the source of the borated-water leakage that was observed during the 2006 refueling outage for Unit 1.

- 7 a) As part of the response, clarify whether the leakage resulted from aging-related degradation of reactor vessel and piping components.

b) If so, identify the component and aging effect that induced the leakage.

2. Clarify whether the applicant has cleaned the past borated-water leakage residues and corrosion products. If not, justify why borated-water leakage residues and corrosion products left in service would not interfere with the visual examination that are included in the program.

3. Clarify how the program manages and resolves the situation that borated-water leakage and associated corrosion products interfere with the visual examination of the components that are included in the scope of the program.

Discussion: The staff and the applicant discussed the clarification of requests 2 and 3 of the question. The discussion was to clarify that the different intents of each request. As a result of the discussion, no action was required.

DRAFT RAI 8.1.30-1

Background:

Applicant's LRA Sections B.1.30 and A.1.30 do not provide the number of in-scope small-bore piping welds for its two units. The GALL Report AMP, "detection of aging effects" program element recommends that if an applicant's units have not experienced a failure of its ASME Code Class 1 piping, and it has extensive operating history (>30 years) at time of submitting the application, the inspection sample size should be at least 3% of the weld population or a maximum of 10 welds of each weld type for each operating unit.

In addition, the "detection of aging effects" program element of the GALL AMP recommends that for socket welds, opportunistic destructive examination can be performed in lieu of volumetric examination. Because more information can be obtained from a destructive examination than from nondestructive examination, the applicant may take credit for each weld destructively examined equivalent to having volumetrically examined two socket welds.

Issue:

It is not clear to the staff how the inspection sample size would be calculated, since the total population of Class 1 butt welds and socket welds for each unit within scope of the program are not provided in the applicant's LRA. In addition, it is not clear to the staff if the applicant will use opportunistic destructive examination for butt welds, and how it will be credited when they are performed in lieu of volumetric examinations.

Request:

1. Provide the type and number of in-scope small-bore piping welds for each of the units.

2. In addition, clarify if opportunistic destructive examinations will be used for butt welds, and how they will be credited.

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3. Amend LRA Sections 8.1.30 and A 1.30 accordingly, to include the total population for both units, and to clearly state how opportunistic destructive examination will be credited, if they are performed in lieu of volumetric examinations for butt welds and/or socket welds.

Discussion: The staff and applicant discussed the clarification of the issue section of the question. The discussion was based on the sample size calculations and the examination methods. As a result of the discussion. no action was required.

DRAFT RAI 8.1.35-1

Background:

The "Detection of Aging Effects" program element of GALL Report AMP XI.M31 states, in part.

that:

1)

2)

The withdrawal schedule shall be submitted as part of a license renewal application for NRC review and approval in accordance with 10 CFR Part 50, Appendix H, and The program withdraws one capsule at an outage in which the capsule receives a neutron fluence of between one and two times the peak reactor vessel wall neutron fluence at the end of the period of extended operation (PEO) and tests the capsule in accordance with ASTM E 185-82.

Issue:

The applicant's program, as modified by the enhancements. includes:

1)

An enhancement to the "Detection of Aging Effects" program element that has a general discussion of a change to be made to the capsule withdrawal schedule, but no specifics. and

2)

An enhancement to the "Monitoring and Trending" program element for withdrawal and testing of a standby capsule to cover the peak fluence expected at the end of the period of extended operation During the audit, the staff noted that by letter dated January 10. 2013, the applicant submitted to the NRC its proposed changes to the surveillance capsule withdrawal schedule that does demonstrate that a capsule will be withdrawn and tested at a fast neutron fluence level between one and two times the peak neutron fluence for the PEO. However, the LRA with its enhancements does not include specific discussion of these recommended items from GALL Report AMP XI.M31.

Request:

1. The staff requests that the applicant include a specific reference to the January 10. 2013 submittal.

2. Clarify whether these proposed changes to the capsule schedule are consistent with GALL Report AMP XI.M31.

- 9 Discussion: The staff determined that clarification was needed on the issue section of the question to specify general terms and references. As a result of the discussion, the staff has replaced the last paragraph of the issue section of the question with the following:

During the audit, the staff noted that by letter dated January 10, 2013, the applicant submitted to the NRC its proposed changes to the surveillance capsule withdrawal schedule that does demonstrate that a capsule will be withdrawn and tested at a fast neutron fluence level between one and two times the peak neutron fluence for the PE~.

However, the LRA with its enhancements does not include specific discussion of items 1 and 2 shown above from GALL Report AMP XI.M31.

DRAFT RAI B.1.11-2

Background:

Enhancement 3 of the Fatigue Monitoring program stated that "[f]atigue usage factors for the RCS limiting components will be determined to address the Cold Overpressure Mitigation System (COMS) event (Le., low temperature overpressurization event) and the effects of the structural weld overlays." The applicant identifies that Enhancement 3 is included on the "scope of program" program element of the AMP. The "scope of program" program element of GALL Report AMP X.M1, "Fatigue Monitoring," states that the program monitors and tracks the number of critical thermal and pressure transients for the components that have been identified to have a fatigue TLAA.

Issue:

The applicant has not identified the components that are within the scope of the stated enhancement. Furthermore, the staff noted that the effects of the structural weld overlays for fatigue usage factors may include, but are not limited to, the update or addition of components and transients to existing fatigue analyses. The staff seeks further clarifications on the impacts that the presence of structural weld overlays will have on the following aspects of the program:

(a) list of components, (b) design transients, (c) cycle counting activities, and, (d) CUF analyses.

Without such information, the staff cannot determine whether the "scope of program" element of the Fatigue Monitoring program, when enhanced, would be consistent with that of GALL Report AMP X. M1.

Request:

1. Identify all plant systems and components that are within the scope of license renewal that have been affected by or will be affected by occurrences of COMS events.

a) With respect to these components, clarify and define what is meant by the statement: U[f]atigue usage factors for the RCS limiting components will be determined to address the Cold Overpressure Mitigation System (COMS) event."

2. Identify all systems and components that are within the scope of license renewal that have been or will be subjected to structural weld overlay modifications.

a) With respect to these components, identify and explain all impacts (effects) that the presence of structural weld overlays will have on the scope of the Fatigue Monitoring program, including (but not limited to) impacts of the following aspects of the prog ram:

1) list of components,

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2) design transients,

3) cycle counting activities, and

4) CUF analyses.

b) Clarify how the AMP will be adjusted to address and manage these effects.

3. In light of the responses that will be made to Parts (a) and (b), justify why the proposed enhancement, when implemented, provides assurance that the "scope of program" element of the Fatigue Monitoring program will be consistent with that in GALL Report AMP X. M1, "Fatigue Monitoring." Revise LRA Section A.1.11 accordingly.

Discussion: The staff determined the revision to the request section of the question was needed. The staff and applicant discussed that response to request 2(a) will provide the same information to adequately address request 2(b). As a result ofthe discussion, the staff removed request 2(b) from the question.

DRAFT RAI 8.1.13-1

Background:

The program description of the Fire Water System program, LRA Section B.1.13, states that the program manages loss of material and fouling for fire protection components that are tested in accordance with the Fire Protection Report.

During its review of the UFSAR, the staff noted that the two safety-related standby fire/flood mode pumps are used to provide makeup to the steam generators and reactor coolant system during a flooding event. Based on the staff's review of LRA Sections 2.3.3.2, 3.3, 3.4, and LRA Drawing 1,2-47W850-24, "Mechanical Flow Diagram Fire Protection," it appears that the pumps, and suction and discharge piping of these pumps, are being age-managed by the Fire Water System program.

The "scope of program" program element in GALL Report AMP XI.M27 states, "[t]he AMP focuses on managing loss of material due to corrosion, MIC, or biofouling of steel components in fire protection systems exposed to water."

GALL Report Item VIII.G.SP-136 recommends GALL Report AMP XI,M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to age-manage steel piping exposed to raw water. GALL Report Table VII. E1, "Chemical Volume and Control System (PWR)," does not include steel piping exposed to a raw water environment.

Issue:

It is not clear to the staff that given the scope of inspections recommended in GALL Report AMP XI,M27, that the Fire Water System program is appropriate to manage the portion of a system whose intended functions as described in 10CFR 54.4 are to support auxiliary feedwater and reactor coolant system make-up.

Request:

1. State whether the safety-related standby fire/flood mode pumps and associated suction and discharge piping will be age-managed by the Fire Water System program.

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2. State why reasonable assurance can be established that the components will meet their intended function consistent with the current licensing basis, or propose an alternative aging management program if the components will be age-managed by the Fire Water System program,.

In considering the response to question 2, review the changes to programs such as GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," included in draft LR-ISG-2012-02, "Aging Management of Internal Surfaces, Service Level III and Other Coatings, Atmospheric Storage Tanks, and Corrosion under Insulation."

Discussion: The staff determined that clarification was needed on the request section of the question to replace terms and phrases within the requests to increase the focus and readability.

As a result of the discussion, the staff has replaced the request section of the question with the following:

1. State whether the safety-related standby fire/flood mode pumps and associated suction and discharge piping aging effects will be managed by the Fire Water System program.

2. State why reasonable assurance can be established that the components will meet their intended function consistent with the current licensing basis, or if the aging effects of the components will be managed by the Fire Water System program, propose an alternative aging management program.

In conSidering the response to question 2, review the proposed changes to GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," included in draft LR-ISG-2012-02, "Aging Management of Internal Surfaces, Service Level III and Other Coatings, Atmospheric Storage Tanks, and Corrosion under Insulation."

RAJ 8.1.4-3

Background:

During the audit, the staff noted the following with regard to the "preventive actions" program element of the Buried and Underground Piping and Tanks Aging Management Program:

a) Section 4.7.5, Category I Backfill of procedure G9, "Earth and Rock Foundations and Fills During Construction, Modification and Maintenance for Nuclear Plants," states that, U[u]nless otherwise specified by engineering documents, earthfill, fine granular fill, coarse granular fill, and rockfill may be used as Category I fill, and the particular type suited for the conditions shall be specified in engineering documents." Earthfill is, in part, defined as possibly containing organic material. Rockfill has no size limit except for the longest dimension must be less than three times the thickness.

b) Problem Evaluation Report (PER) 63662 stated that the granular backfill for the refill of a fire protection piping excavation did not meet specifications for the number 16 and 30 sieve requirements. The initiator requested that the engineering organization accept the back fill as-is.

c) PER 525994 stated that coating damage occurred to buried radioactive waste piping due to fretting from a copper grounding wire.

- 12 d) PER 22693 stated that damage occurred to buried nonsafety-related essential raw water cooling piping that is used to fill the safety-related fire pump forebay during a flooding event.

During the audit, the applicant stated that this piping is in scope because the pumps are used to fill the steam generators and reactor coolant system during a flood event. The PER further stated that the damage occurred because the piping is not coated.

LR-ISG-2011-03 recommends that backfill in the vicinity of buried steel pipe meet ASTM 0448-08, size 67. In addition, it is recommended that coatings meet Table 1, "Generic External Coating Systems with Material Requirements and Recommended Practices for Application" of NACE SP0169-2007, "Control of External Corrosion on Underground or Submerged Metallic Piping Systems," or use of other coatings is justified in the License Renewal Application.

Issue:

a) It is not clear to the staff that earthfill (due to the potential presence of organic materials) and rockfill (due to its size) are consistent with the backfill recommendations of LR-ISG-2011-03, or whether either of these types of backfill was or could be used in the vicinity of in-scope components.

b) It is not clear to the staff how the backfill described in PER 63662 compares to that recommended in LR-ISG-2011-03 and whether the backfill was subsequently used as backfill in the vicinity of in-scope piping.

c) The piping described in PER 525994 is not in scope; however, it is not clear whether the procedure controls for backfill in the vicinity of this piping are the same as for those of in-scope piping, and if this is the case, whether the condition was an isolated event.

d) It is not clear to the staff how much in-scope buried piping is not coated or how the program, when implemented, will account for non-coated buried piping.

Request:

1. State if earthfill or rockfill has been or will be used as backfill in the vicinity of buried in-scope components. If this backfill had or will be used, state the basis for why reasonable assurance can be established that the buried in-scope components will meet their intended function consistent with the current licensing basis.

2. If the nonconforming backfill described in PER 63662 was used in the vicinity of buried in-scope piping, state how it compares to the recommendations for backfill quality in LR-ISG-2011-03. If the nonconforming backfill is not consistent with the backfill quality recommendations in LR-ISG-2011-03, state the basis for why reasonable assurance can be established that the buried in-scope components will meet their intended function consistent with the current licensing basis.

3. State if the procedure controls for backfilling buried in-scope piping components are or were similar to those for the piping described in PER 525994. If they are or were, state the basis for why reasonable assurance can be established that the buried in-scope components will meet their intended function consistent with the current licensing basis.

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4. State the plant system, material type, and quantity of in-scope buried piping that is not coated. State what adjustments will be made to the Buried and Underground Piping and Tanks Program to account for uncoated, buried in-scope piping.

Discussion: The staff and the applicant discussed the clarification of the request to state how the Buried and Underground Piping and Tanks Program will be adjusted to address uncoated, buried, in-scope piping. As a result of the discussion, no action was required.

DRAFT RAI 8.1.4-4

Background:

LRA Section B.1.4 states, "[i]f cathodic protection is not provided prior to the period of extended operation, the program will include documented justification that cathodic protection is not warranted."

LR-ISG-2011-03 states that the justification for not having cathodic protection must be provided in the LRA.

Issue:

During the audit, the staff reviewed a Corrpro Report titled, "TVA - Sequoyah Nuclear Plant - Buried Piping Integrity Program Corrosion Assessment Report." This report cited several examples demonstrating that the soil at Sequoyah is corrosive and recommended installation of cathodic protection in some locations with in-scope piping. Based on input received during audit breakout sessions, it was noted that a new study was recently completed by a different vendor. The new study was not available for review by the staff during the audit.

Request:

1. If cathodic protection will not be installed, provide an analysis for not providing cathodic protection 10 years prior to commencing the period of extended operation consistent with the recommended detail in LR-ISG-2011-03 Section 2.a.iiL

2. If cathodic protection will not be installed, state the results of a 10-year search of plant-specific operating experience related to in-scope and out-of-scope buried piping consistent with the recommended detail in LR-ISG-2011-03 Section 2.a.iv.

3. Based on the results of (a) and (b) above, state what adjustments to the program will be implemented if cathodic protection is not installed and the study results demonstrate adverse results. If no adjustments will be made, state the basis for why reasonable assurance can be established that the buried in-scope components will meet their intended function consistent with the current licensing basis.

Discussion: The staff and the applicant discussed the clarification of the background section of the question. The discussion was based on LR-ISG-2011-03 and the need to justify not having cathodic protection. As a result of the question, no action was required.

- 14 DRAFT RAI LR-ISG-2012-02-1

Background:

Based on recent industry operating experience (OE) and the staff's review of several LRAs, the staff developed LR-ISG-2012-02, "Aging Management of Internal Surfaces, Service Level III and Other Coatings, Atmospheric Storage Tanks, and Corrosion under Insulation." On April 15, 2013, the staff issued a Federal Register notice (78 FR 21980) to request public comments on the draft ISG, which is available under ADAMS Accession No. ML12291A920.

This LR-ISG revised four existing GALL Report aging management programs (AMPs);

developed a new GALL Report AMP for Service Level III and Other coatings; developed a new further evaluation (FE) aging management review (AMR) item to address recurring internal corrosion; developed new, and revised many SRP-LR and GALL Report AMR items; revised the Final Safety Analysis Report (FSAR) Supplement description for the affected AMPs and developed the FSAR supplement description for the new AMP; and revised three GALL Report definitions and developed four new definitions.

The LR-ISG addresses the following areas that affect the consistency of the LRA:

1. Recurring internal corrosion

2. A representative minimum sample size for periodic inspections in GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components"

3. Loss of coating integrity for Service Level III and Other coatings

4. Flow blockage of water-based fire protection system piping

5. Scope and inspection recommendations of GALL Report AMP XI.M29, "Aboveground Metallic Tanks"

6. Corrosion under insulation

7. External volumetric examination of internal piping surfaces of underground piping The changes to the SRP-LR and GALL Report in LR-ISG-2012-02 affect the LRA consistency with the staff's guidance.

Request:

1. Recurring Internal Corrosion a) Based on the results of a review of the past five years of plant-specific OE, state whether recurring internal corrosion aging effects have occurred, as described in LR-ISG-2012-02 and.

b) If recurring internal corrosion aging effects have occurred, describe each aging effect and its related acceptance criterion for being considered as recurring internal corrosion.

c) If recurring internal corrosion aging effects have occurred, state how the new further evaluation AMR items, 3.2.2.2.9, 3.3.2.2.8, and 3.4.2.2.6, as applicable, will be addressed.

2. A representative minimum sample size for periodic inspections in GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components"

- 15 a) State how LRA Sections A.1.19 and B.1.19 will be revised to be consistent with the changes to GALL Report AMP XI,M38 in LR-ISG-2012-02. Alternatively, state and justify exception(s) to portions that will not be consistent.

3. Loss of coating integrity for Service Level III and Other coatings a) If any in-scope components have internal Service Level III or Other coatings, as described in LR-ISG-2012-02, describe the system and type of coating and respond to the following.

b) Propose a program to manage the aging of coatings -- either one that is consistent with GALL Report AMP XI.M42, "Service Level III and Other Coatings Monitoring and Maintenance Program," or a plant-specific AMP. State and justify exception(s) to portions of AMP XI,M42 that will not be consistent.

c) State how LRA Appendix A will be revised to address the program used to manage the aging of coatings.

d) State how the LRA Section 3 Table 2s will be revised.

4. Flow blockage of water-based fire protection system piping a) State how LRA Section 3 Table 2s and Appendices A.1.13 and B.1.13 will be revised to address the changes to GALL Report AMP XI.M27, "Fire Water System," (e.g., elimination of wall thickness measurements in lieu of flow testing or internal inspections, augmented inspections for normally dry piping that is not configured to drain, scope includes fire water storage tank inspections to NFPA 25 in lieu of GALL Report AMP XI.M29), and its associated AMR items and FSAR Supplement as described in LR-ISG-2012-02. Alternatively, state and justify exception(s) to portions that will not be consistent.

5. Scope and inspection recommendations of GALL Report AMP XI.M29, "Aboveground Metallic Tanks" a) State how LRA Section 3 Table 2s and Appendices A.1.1 and B.1.1 will be revised to address the changes to GALL Report AMP XI.M29, "Aboveground Metallic Tanks," (e.g., increased frequency of tank bottom inspections, surface examinations, internal inspections) and its associated AMR items and FSAR Supplement as described in LR-ISG-2012-02. Alternatively, state and justify exception(s) to portions that will not be consistent.

6. Corrosion under insulation a) State how LRA Section 3 Table 2s and Appendices A.1.10, and B.1.10 will be revised to address the changes related to corrosion under insulation for outdoor insulated components and indoor insulated components operated below the dew point as described in LR-ISG-2012-02. Alternatively, state and justify exception(s) to portions of the LRA that will not be consistent with the revised AMPs XI.M29 and XI.M38.

7. External volumetric examination of internal piping surfaces of underground piping a) State how the internal surfaces of underground piping will be age managed Discussion: The staff and the applicant discussed requests 1, 2, 3, and 5 of the question. The discussion was to clarify the intent of each of the requests. The applicant also noted that the LR-ISG-2012-02 is in draft stage, which should be reflected in the question. As a result of the question, the question was revised to reflect that the LR-ISG is in draft stage, i.e., the term "LR-ISG-2012-02" was replaced with "draft LR-ISG-2012-02," and the term "recommendation[s]"

was replaced with "proposed recommendation[s]."