ML12314A141

Responses to RAI Set #15 and Amendment 15 to the Callaway LRA

ML12314A141
Person / Time
Site:	Callaway
Issue date:	11/08/2012
From:	Kanuckel L H Ameren Missouri, Union Electric Co
To:	Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML123140212	List: ML12314A141 ULNRC-05928, Enclosure 2 to ULNRC-05928, Amendment 15, LRA Updates
References
TAC ME7708, ULNRC-05928
Download: ML12314A141 (15)

Text

WAmeren MISSOURI Callaway Plant **************************************************************************************************************************************************************************************************************************************************

November 8, 2012 ULNRC-05928 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Ladies and Gentlemen:

10 CFR2.101 10 CFR 2.109(b) 10 CFR 50.4 10 CFR 50.30 10 CFR 51.53(c) 10 CFR 54 DOCKET NUMBER 50-483 CALLA WAY PLANT UNIT 1 UNION ELECTRIC CO. FACILITY OPERATING LICENSE NPF -30 RESPONSES TO RAI SET #15 AND AMENDMENT 15 TO THE CALLA WAY LRA

References:

1) ULNRC-05830 dated December 15, 2011 2) NRC Letter, "Request for Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal Application, Set 15 (TAC No. ME7708)," dated October 12, 2012. By the Reference 1letter, Union Electric Company (Ameren Missouri) submitted a license renewal application (LRA) for Callaway Plant Unit 1. Reference 2 dated October 12, 2012 transmitted the fifteenth Request for Additional Information (RAJ) related to our application.

Enclosure 1 contains Ameren Missouri's responses to the individual requests contained in the October 12, 2012 RAI, with the exception ofRAI 2.3.4.2-1a.

At the staffs request, the response to RAI 2.3.4.2-1a will be provided at a later date, following further discussions.

There are no responses in Enclosure 1 that required changes to the LRA; however, Enclosure 2 contains LRA Amendment 15 which includes the following updates: o Incorporate XI.M18 Bolting Integrity AMP Enhancements, o Revised LRA Table 3.5-1 item 027 and Table 3.5.2-1 to add cracking (due to cyclic loading) as an aging effect for mechanical penetrations consistent with GALL line II.A3.CP-37.

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ULNRC-05928 November 8, 2012 Page2 It should be noted that a change to one (1) commitment (Item #5) is reflected in Table A4-1 (within Enclosure 2). Commitment

1. 5 and LRA Section B2.1.8 (Bolting Integrity) ofthe LRA have been revised as noted by the first bullet above. If you have any questions with regard to these RAI responses, or Amendment 15, please contact me at (573) 823-9286 or Ms. Sarah Kovaleski at (314) 225-1134.

I declare under penalty of perjury that the foregoing is true and correct. Sincerely, Executed on:

B) 2012. Les H. Kanuckel Manager, Engineering Design DS/SGK/nls

Enclosures:

1) Request for Additional Information (RAI) Set #15 Responses

2) Amendment 15, LRA Updates ULNRC-05928 November 8, 2012 Page3 cc: U.S. Nuclear Regulatory Commission (Original)

Attn: Document Control Desk Washington, DC 20555-0001 Mr. Elmo E. Collins Regional Administrator U.S. Nuclear Regulatory Commission Region IV 1600 East Lamar Boulevard Arlington, TX 76011-4511 Senior Resident Inspector Callaway Resident Office U.S. Nuclear Regulatory Commission 8201 NRC Road Steedman, MO 65077 Mr. Samuel Cuadrado De Jesus Project Branch 1 Division of License Renewal Office ofNuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mail Stop 0-11Fl Washington, DC 20555 Mr. Fred Lyon Project Manager, Callaway Plant Office ofNuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop 0-8B 1 Washington, DC 20555-2738 Mr. Gregory A. Pick U.S. Nuclear Regulatory Commission Region IV 1600 East Lamar Boulevard Arlington, TX 76011-4511 ULNRC-05928 November 8, 2012 Page4 Index and send hardcopy to QA File A160.0761 Hardcopy:

Certrec Corporation 4150 International Plaza Suite 820 Fort Worth, TX 76109 (Certrec receives ALL attachments as long as they are non-safeguards and may be publicly disclosed.)

Electronic distribution for the following can be made via Tech Spec ULNRC Distribution:

A. C. Heflin F. M. Diya C. 0. Reasoner III D. W. Neterer L. H. Graessle J. S. Geyer S. A. Maglio R. Holmes-Bobo NSRB Secretary L. H. Kanuckel S. G. Kovaleski T. B. Elwood G. G. Yates E. Blocher (STARS PAM COB) Mr. Bill Muilenburg (WCNOC) Mr. Tim Hope (Luminant Power) Mr. Ron Barnes (APS) Mr. Tom Baldwin (PG&E) Mr. Mike Murray (STPNOC) Ms. Linda Conklin (SCE) Mr. John O'Neill (Pillsbury Winthrop Shaw Pittman LLP) Missouri Public Service Commission Mr. Dru Buntin (DNR)

ULNRC-05928 November 8, 2012 Enclosure 1 CALLAWAY PLANT UNIT 1 LICENSE RENEWAL APPLICATION Page 1 of 11 REQUEST FOR ADDITIONAL INFORMATION (RAI) Set #15 RESPONSES ULNRC-05928 November 8, 2012 Enclosure 1 RAI B2.1.7-4a

Background:

Page 2 of 11 Based on Callaway Action Requests (CARs) contained in Callaway's operating experience review document, RAI B2.1.7-4 requested Callaway to discuss whether the Flow-Accelerated Corrosion (FAC) program manages aging mechanisms other than FAC. The response dated August 21, 2012, stated that the FAC program does not manage aging mechanisms other than FAC and that none of the CARs cited in the RAI identified wall thinning due to mechanisms other than FAC in components within the scope of license renewal. Based on the response, the staff is now of the understanding that none of those CARs were associated with components within the scope of license renewal, since the CARs did identify wall thinning due to mechanisms other than FAC. The staff notes that Callaway's operating experience review section for FAC program contains all of the CARs cited in the RAI. In addition, although NUREG-1801 "Generic Aging Lessons Learned (GALL) Report," Revision 2, aging management program (AMP) XI.M17 does not specifically incorporate applicants' responses to IE Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants," the GALL AMP cites the bulletin in the "operating experience" program element and in its reference section. Callaway's response to IE Bulletin 87-01, dated September 1 0, 1987, states that the scope of the Erosion/Corrosion program includes plain carbon steel piping, which is "inspected for erosion due to flow assisted corrosion (FAC) and/or cavitation," and stainless steel piping, which is "inspected for erosion due to cavitation." The response included the results of several inspections for essential service water (ESW) piping in Table 1, "Erosion/Corrosion Inspection Results." The staff acknowledges that industry terminology has changed since 1987. Issue: Although the specific components associated with the cited CARs may not be within the scope of license renewal, Callaway's inclusion of these CARs in the AMP's operating experience review indicates that the program includes the associated mechanisms.

Title 10 of the Code of Federal Regulations Part 54.37 (10 CFR 54.37), "Additional records and record keeping requirements,"§ 54.37 (a) states that information documenting compliance with this part shall be retained by licensee in an auditable and retrievable form. STARS procedure PAMCOBP-PI-2, "Aging Management Review," Section 3.2 states that operating experience reviews are performed to demonstrate the effects of aging are being adequately managed by existing programs.

For each operating experience document, the procedure asks whether it addresses a license renewal aging effect, and a license renewal AMP. Callaway Plant License Renewal Aging Management CAR Operating Experience Report for AMP XI.M17, "Flow Accelerated Corrosion (FAC)" B2.1. 7, includes CAR 2006-08992, and states that the FAC program manages "loss of material due to erosion" for components in a raw water environment.

The report also states that CAR 2010-04190, which documented erosion in a valve and in adjacent piping is addressed by the FAC program. Since the RAI response states that the FAC program only addresses FAC and does not include erosion mechanisms, the information contained in the operating experience review section for this program appears to be incorrect.

In addition, stainless steel components and raw water systems are typically not susceptible to FAC. However, Callaway's response to IE Bulletin 87-01 specifically states that the scope of its Erosion/Corrosion program includes erosion due to cavitation for both carbon steel and stainless steel components.

In addition, Callaway's bulletin response contains a table with program inspection results that includes measurements from the ESW system, which is a raw ULNRC-05928 November 8, 2012 Enclosure 1 Page 3 of 11 water system. Since IE Bulletin 87-01 did not discuss cavitation, only addressed carbon steel piping, and limited the systems to those with oxygen content less than 50 parts per billion, Callaway's inclusion of the additional scope indicates that plant-specific operating experience warranted consideration of these aspects. Consequently, it is unclear to the staff how the current licensing basis (CLB) associated with Callaway's Erosion/Corrosion program correlates with the FAC program and where the activities associated with wall thinning due to mechanisms other than F AC are being managed. Request: a) Discuss whether information in the FAC program's operating experience review incorrectly ascribed aging mechanisms to the FAC program, and if appropriate verify that the information will be corrected.

b) Discuss the CLB associated with Callaway's Erosion/Corrosion program as documented in response dated September 10, 1987, to IE Bulletin 87-01, and how it correlates to the FAC program. If the associated activities discussed in the bulletin response are not currently part of the FAC program, provide the details regarding how these activities are accomplished.

Callaway Response a) The two CARs cited in this RAI incorrectly assigned XI.M17, Flow-Accelerated Corrosion, as the aging management program relevant to the condition prompting the CAR. The results of the operating experience review of these two CARs have been revised to remove XI.M17 as the relevant aging management program. CAR 200608992 identified a pinhole leak in an elbow of the service water piping downstream of the 'B' stator cooling water heat exchanger.

The service water piping at this location is not within the scope of license renewal. If this component were within the scope of license renewal, the relevant program for monitoring this location would be the Cycle Cooling Water program. CAR 201004190 identified wall thinning due to leakage from an upstream valve. The wall thinning was discovered when maintenance was being performed on the upstream valve. The upstream valve was repaired, eliminating the cause of the wall thinning.

After the repairs were completed, further monitoring was not necessary.

The leaking valve is an isolation valve for a short drain line coming off the discharge line from a first stage reheater drain tank. The drain line downstream of the isolation valve is excluded from the FAC program because it does not normally experience flow, and is not within the scope of license renewal. b) The original program at Callaway for monitoring wall thinning addressed erosion and corrosion of piping and components.

Components selected for monitoring included those identified in EPRI NP-3944, Erosion/Corrosion in Nuclear Plant Steam Piping: Causes and Inspection Program Guidelines, and other locations determined from operating experience.

All the locations identified in the initial procedure were subject to flow-accelerated corrosion (FAC), or were in raw water systems. This procedure was issued in April, 1987, approximately three months prior to the issuance of IE Bulletin 87-01, Thinning of Pipe Walls in Nuclear Power Plants. The Callaway response to IE Bulletin 87-01 described the existing program, and included the raw water components subject to wall-thinning due to mechanisms other than FAC.

ULNRC-05928 November 8, 2012 Enclosure 1 Page 4 of 11 The NRC issued Generic Letter 89-13, Service Water System Problems Affecting Related Equipment, in July, 1989. In response to Generic Letter 89-13, Callaway established a raw water program. The new raw water program included inspections of the raw water components.

The inspections for wall thinning in raw water systems were moved to the raw water program at this time because raw water operating conditions such as temperature and oxygen levels are not consistent with those causing FAC. Corresponding Amendment Changes No changes to the License Renewal Application (LRA) are needed as a result of this response.

ULNRC-05928 November 8, 2012 Enclosure 1 RAI 82.1.7-Sa

Background:

Page 5 of 11 AMP XI.M17, "acceptance criteria" states that corrective actions should be considered if the minimum allowed wall thickness will be reached before the next scheduled outage. Callaway's implementing procedure for this AMP, EDP-ZZ-01115, "Flow-Accelerated Corrosion of Piping and Components Predictive Performance Manual," defines the design minimum wall thickness (T oMw) as the calculated minimum wall thickness required as determined from the primary stress equations of the applicable construction code and predicates actions based on that value. RAI B2.1. 7-5 requested information regarding the use of certified test material report (CMTR) data to reduce the minimum wall thicknesses for American Society of Mechanical Engineers (ASME) Code Class 2 and Class 3 and American National Standards Institute (ANSI) B31.11 application as given in Design Guide ME013, "Pipewall Thickness." The RAI response stated that the bases for determining the allowable stress limits are defined in ASME Section Ill, Appendix Ill, Article 3000, and would be applicable to situations where acceptance limits must be established for materials that are not listed in the stress tables. Based on this concept, the applicant stated that CMTR data can be applied when the documented material strength is greater than the minimum required strength for that particular standard, and that use of CMTR data does not result in any reduction of conservatism.

The response also stated that engineering evaluations performed on components for reduced thickness or unanticipated loads are beyond the scope of ASME Section Ill, and that such evaluations should be based on engineering judgment.

Issue: Engineering evaluations that determine operability of components due to degraded conditions, such as reduced thickness or unanticipated loads, should be consistent with the NRC Inspection Manual, Part 9900, "Operability Determinations

& Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety." As noted in the above guidance, a nonconforming condition occurs when a component does not conform to all aspects of its CLB, including applicable codes. The ASME Code, Section Ill, for Class 2 and Class 3 and ANSI B31.1 Piping Code consistently state that the allowable stress values to be used for the design of piping systems are given in the tables of either, ASME Section II, Part D "Maximum Allowable Stress Values," or ANSI Appendix A, "Allowable Stress Tables." Although the ASME Code may provide guidance for establishing acceptance limits for materials not listed in the allowable stress tables, the Code does not address the use of CMTR data for materials that are listed in the allowable stress tables. It is not clear to the staff whether the use of CMTR data to increase the allowable stress values is in accordance with Callaway's CLB. In addition, the staff noted that Design Guide ME013 also stated the allowable stresses may be increased by 10 percent above the ASME Code specified allowable stress. It is unclear to the staff whether this increase in allowable stress values above those used in the original code of construction are in accordance with Callaway's CLB. Request: Provide the documentation, either NRC-approved code cases or CLB information that establishes the use of certified test material report data to increase the allowable stresses above the values given for materials listed in the allowable stress tables for the applicable code ULNRC-05928 November 8, 2012 Enclosure 1 Page 6 of 11 of construction.

Provide similar documentation regarding the use of the 10 percent increase given in Design Guide ME013. Alternatively, provide the limitations on the applicability for the use of this approach for evaluations of degraded conditions during the period of extended operation.

Callaway Response Callaway Engineering Design Guide ME-013, "Pipewall Thickness," has been revised to limit applicability of the use of Certified Material Test Reports (CMTRs). The Purpose, Scope, and Methodology sections each limit the use of CMTR material stresses to Operability Determinations and evaluations used to support continued plant operation until repairs can be implemented.

Callaway does not use CMTRs in the design of piping systems or to increase the allowable stress above values given for materials listed in the allowable stress tables. Corresponding Amendment Changes No changes to the License Renewal Application (LRA) are needed as a result of this response.

ULNRC-05928 November 8, 2012 Enclosure 1 RAI B2.1.5-4a

Background:

Page 7 of 11 By its letter dated August 21, 2012, the applicant responded to RAI B2.1.5-4 which, in part, addressed the inspection method and frequency for the cladding degradation indications in the reactor vessel bottom head region. The applicant stated that the indications are inspected opportunistically when the core barrel is pulled during a refueling outage (RFO) such as for ASME category B-N-3 examinations, and that the prior RFO 13 and RFO 15 evaluations of the indications determined that there is no growth expected.

In its response, the applicant also indicated that the cladding thickness is 0.22 inch, and 0.28 inch defect depth is conservative for the two indications.

The applicant further indicated that the degraded cladding area dimensions of the first and second indications are 1.5 inch x 0.625 inch x 0.28 inch (deep) and 0.53 inch x 0.3 inch x 0.10 inch (deep), respectively.

The applicant further indicated that it will assume that the low-alloy steel base metal is reduced by 0.14 inch in addition to the cladding thickness.

Issue: LRA Section A 1.5 or B2.1.5 does not identify the inspections of the degradation indications (including the exposed steel vessel portion) in the reactor vessel bottom head region as a program enhancement to NUREG-1801 "Generic Aging Lessons Learned (GALL) Report," Revision 2, AMP XI.M11 B. It is not clear what inspection methods will be used by the applicant's program. The staff also needs justification for why the opportunistic inspections without a specific inspection frequency are sufficient to manage loss of material of the reactor vessel bottom head that has the degradation indications.

In addition, the staff needs clarification for why the size (1.5 inch x 0.625 inch) of the first indication, which is described in the applicant's response, is different from the size stated in LRA Section 4.7.3 (1.5 inch x 0.75 inch). The staff also needs clarification for why the conservative total depth for the indications is 0.28 inch rather than 0.36 inch if the base metal reduction is assumed to be 0.14 inch beyond the cladding (0.22 inch thick). Request: a) Justify why the inspections of the degradation indications in the reactor vessel bottom head are not identified as a program enhancement to GALL Report AMP XI.M11 B. b) Identify the inspection methods that will be used to manage loss of material due to boric acid corrosion of the degradation indications.

As part of the response, clarify whether ultrasonic examination will be performed to measure the reactor vessel thickness at the indication locations.

c) Justify why the opportunistic inspections without a specific inspection frequency are sufficient to manage loss of material due to boric acid corrosion of the degradation indications in the reactor vessel bottom head.

ULNRC-05928 November 8, 2012 Enclosure 1 Page 8 of 11 As part of the response, provide additional information to confirm that the proposed inspection method and frequency are sufficient to manage the aging effect of the reactor vessel bottom head (internal surfaces).

d) Provide clarification for the following items: ( 1) clarification for why the size (1.5 inch x 0.625 inch) of the first indication, which is described in the applicant's response, is different from the size stated in LRA Section 4.7.3 (1.5 inch x 0.75 inch), and (2) clarification for why the conservative total depth for the indications is 0.28 inch rather than 0.36 inch if the base metal reduction is assumed to be 0.14 inch beyond the cladding (0.22 inch thick). If the dimensions of the degradation indications have increased since the initial detections of the indications, describe the changes in the size and depth. If available, provide schematic illustrations of the degradation indications, including the top view and side view (that is, depth profile characteristics), in order to provide the baseline information for degradation morphology and to support the applicant's claim that the degradation indications were not initiated by aging effects. e) Ensure that the LRA, including the FSAR supplement, is consistent with the response.

Callaway Response a) Examinations of the indications are included as part of the VT-3 examinations of the interior of the reactor vessel when the lower internals are removed. These examinations are performed consistent with ASME Section XI, Table IW8-2500-1, Examination Category 8-N-1. Although these indications were presented as operating experience in LRA Section 82.1.5, inservice inspections are required by ASME Section XI and are addressed in LRA Appendix 82.1.1, ASME Section XI lnservice Inspection, Subsections IW8, IWC, and IWD. Therefore, an enhancement to GALL Report AMP XI.M11 8 is not required.

b) VT-3 examinations will be used to monitor the indications in the reactor vessel. ASME Section XI, Table IW8-2500-1, Examination Category 8-N-1, requires a VT-3 examination of the reactor vessel interior.

The acceptance standard for this examination is IW8-3520.2, which allows a reduction of nominal section thickness of up to 5% due to corrosion or erosion. The indications in the Callaway reactor vessel currently meet this acceptance standard.

If a future VT-3 examination finds that an indication has degraded, the Callaway corrective action program would determine any additional inspections required to characterize the indication, which may include an ultrasonic examination.

In addition to the VT-3 examinations, profile measurements of both the 2004 and 2007 indications are planned for the refueling outage in the spring of 2013. Results of the profile measurements will be evaluated to determine if additional examinations such as ultrasonic thickness measurements are required.

c) The indications in the reactor vessel will be examined as part of the ASME Code required VT -3 examination of the reactor vessel interior.

Consistent with ASME Code requirements, the indications in the reactor vessel are accessible when the lower internals are removed, ULNRC-05928 November 8, 2012 Enclosure 1 Page 9 of 11 which is currently required by the ASME Code every 10 years. Thus, the indications will be inspected consistent with ASME Code requirements that are in effect. The corrosion rate for low alloy steel, which is the base metal of the reactor vessel, is very slow in an environment of borated primary water with low oxygen levels and where the temperature pH is kept very close to neutral. A Callaway calculation, using the methodology from EPRI 1000975, Boric Acid Corrosion Guidebook, determined that the total corrosion over a 40 year period (which would include the period of extended operation) is only 0.119 inches. This is within the 5% of nominal section thickness allowed by the ASME Code, and provides justification for performing an inspection every 10 years. The examination frequency is described as opportunistic because the examinations are performed whenever the lower internals are removed. If the lower internals are removed more often than required by the ASME Code, then the inspections will occur more frequently.

The indication discovered in 2004 has been inspected twice. There was no change in the indication.

The indication discovered in 2007 has been inspected only once. As discussed in b) above, the next inspection for both indications is planned for the refueling outage in the spring of 2013. d) (1) The value for the width of the 2004 indication used in the corrective action document, FSAR-SP Section 5.3.3.1, and the LRA is 0.75 inches. Calculation BB-183, Rev. 1, used a value of 0.625 inches for the width of the indication.

In 2011, the discrepancy was discovered and a corrective action document was generated.

The resolution of the corrective action document was that the calculation should have stated the width of the indication as 0. 75 inches, but that the results and conclusion of the calculation remained valid. An addendum to the calculation was issued to correct the error. The width of 0.625 inches reported in the response to RAI 82.1.5-4 was part of a quotation from Calculation BB-183, Rev. 1. The correct width is 0.75 inches. (2) The indication found in 2004 is described as an area 1.5 in. x 0.75 in. located between penetrations

1. 54 and #58 and approximately six inches above the penetrations.

It appears that grinding was most likely performed during vessel fabrication around the 2004 indication that reduced the clad thickness to 0.14 in. at the edge of the indication.

Although the nominal thickness of the clad in the reactor vessel is 0.22 inches, the NDE vendor estimated that the cladding thickness is only about 0.14 inches in the vicinity of the indication.

Thus, the assumption that the base metal depth is reduced by 0.14 inches in addition to the 0.14 inch cladding thickness results in a conservative depth of 0.28 inches. The calculation that verified the acceptability of the indications assumed the vessel wall thickness of 5.38 inches also included the thickness of the clad. This assumption was conservative since the minimum wall thickness of the low alloy steel of the reactor vessel is 5.38 inches, and does not include the clad. The clad thickness was assumed to be 0.14 inches at the location of the indications.

The actual depth of the indications was 0.14 inches for the indication found in 2004, and 0.1 inches for the one found in 2007. A depth of 0.28 inches bounds the measured indications and is used in the calculation.

A sketch of the 2004 indication (Figure 1) follows this RAI response.

The sketch was developed from several sources, including inspection reports, engineering evaluations, photographs and verbal descriptions.

e) No changes are required in the LRA.

ULNRC-05928 November 8, 2012 Enclosure 1 Corresponding Amendment Changes Page 10 of 11 No changes to the License Renewal Application (LRA) are needed as a result of this response ULNRC-05928 November 8 , 2012 Enclosure 1 .22 in nominal cladding Lhickness

(.125 in minimwu Lhickness)

Variable dimens i ons i n transition area Figure I 20 0 4 R PV l ndir ation Sketch showing cladding area of concern 1.5 in .07 in r-Area of _____, no cladding Cross sectional view of A-A All dimensions are approximate Page 11 of 11 Low alloy steel 5.38 in minimum