ML091810958
| ML091810958 | |
| Person / Time | |
|---|---|
| Site: | Kewaunee  |
| Issue date: | 07/13/2009 |
| From: | Hernandez-Quinones S License Renewal Projects Branch 1 |
| To: | Heacock D Dominion Energy Kewaunee |
| Hernandez S, NRR/DLR/RPB1, 415-4049 | |
| References | |
| TAC MD9408 | |
| Download: ML091810958 (43) | |
Text
July 13, 2009 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Energy Kewaunee, Inc.
Innsbrook Technical Center - 2SW 5000 Dominion Boulevard Glen Allen, VA 23060-6711
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION - AGING MANAGEMENT PROGRAMS (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 (KPS).
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
July 13, 2009 Mr. David A. Heacock President and Chief Nuclear Officer Dominion Energy Kewaunee, Inc.
Innsbrook Technical Center - 2SW 5000 Dominion Boulevard Glen Allen, VA 23060-6711
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION - AGING MANAGEMENT PROGRAMS (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 (KPS).
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: ML091810958 OFFICE PM:RPB1:DLR LA:DLR BC:RPB1:DLR PM:RPB1:DLR NAME SHernandez SFigueroa DPelton (DAshley for)
SHernandez (Signature)
DATE 07/08/09 07/07/09 07/13/09 07/13/09 OFFICIAL RECORD COPY
Letter to David A. Heacock from Samuel Hernandez dated July 13, 2009
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION - AGING MANAGEMENT PROGRAMS (TAC NO. MD9408)
DISTRIBUTION:
HARD COPY:
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PUBLIC RidsNrrDlr Resource RidsNrrDlrRpb1 Resource RidsNrrDlrRpb2 Resource RidsNrrDlrRerb Resource RidsNrrDlrRpob Resource RidsNrrDlrRer1 Resource RidsNrrDlrRer1 Resource RidsNrrDciCvib Resource RidsNrrDciCpnb Resource RidsNrrDraAfpb Resource RidsNrrDeEmcb Resource RidsNrrDeEeeb Resource RidsNrrDssSrxb Resource RidsNrrDssSbpb Resource RidsNrrDssScvb Resource RidsOgcMailCenter Resource S. Hernandez S. Lopas P. Tam S. Burton K. Barclay M. Kunowski V. Mitlyng I. Couret S. Burton P. Higgins
Kewaunee Power Station cc:
Resident Inspectors Office U.S. Nuclear Regulatory Commission N490 Hwy 42 Kewaunee, WI 54216-9510 Mr. Chris L. Funderburk Director, Nuclear Licensing and Operations Support Dominion Resources Services, Inc.
Innsbrook Technical Center - 2SE 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Mr. Thomas L. Breene Dominon Energy Kewaunee, Inc.
Kewaunee Power Station N490 Highway 42 Kewaunee, WI 54216 Mr. Michael J. Wilson, Director Nuclear Safety & Licensing Dominion Energy Kewaunee, Inc.
Kewaunee Power Station N490 Highway 42 Kewaunee, WI 54216 Mr. William R. Matthews Senior Vice President - Nuclear Operations Innsbrook Technical Center - 2SE 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Mr. Alan J. Price Vice President - Nuclear Engineering Innsbrook Technical Center - 2SE 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Mr. William D. Corbin Director - Nuclear Engineering Innsbrook Technical Center - 3NE 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Mr. Paul C. Aitken Supervisor - License Renewal Project Innsbrook Technical Center - 3NE 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Mr. David A. Sommers Supervisor - Nuclear Engineering Innsbrook Technical Center - 2SE 5000 Dominion Boulevard Glen Allen, VA 23060-6711 Ms. Lillian M. Cuoco, Esq.
Senior Counsel Dominion Resources Services, Inc.
120 Tredegar Street Riverside 2 Richmond, VA 23219 Mr. Stephen E. Scace Site Vice President Dominion Energy Kewaunee, Inc.
Kewaunee Power Station N490 Highway 42 Kewaunee, WI 54216 Mr. David R. Lewis Pillsbury Winthrop Shaw Pittman, LLP 2300 N Street, N.W.
Washington, DC 20037-1122 Mr. Ken Paplham E 4095 Sandy Bay Rd.
Kewaunee, WI 54216 Mr. Jeff Kitsembel, P.E.
Public Service Commission of Wisconsin P. O. Box 7854 Madison, WI 53707-7854
KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION REQUEST FOR ADDITIONAL INFORMATION AGING MANAGEMENT PROGRAMS ENCLOSURE License Renewal Application (LRA) Aging Management Program (AMP) B2.1.2 American Society of Mechanical Engineers (ASME)Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Request for Additional Information (RAI) B2.1.2-1
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Background===
NUREG-1801, Generic Aging Lessons Learned (GALL) Report, recommends a stand-alone program to address aging management of class 1 small bore piping up to NPS 4. The program is specified in GALL Report AMP XI.M35, One-Time Inspection of ASME Code Class 1 Small Bore Piping. The applicant does not have a program consistent with GALL AMP XI.M35, but chooses instead to use AMP B2.1.2, ASME Section XI, Inservice Inspection - IWB, IWC, and IWD to cover small bore piping aging management program.
Issue AMP B2.1.2 does not fully address issues as recommended in GALL Report AMP XI.M35.
Request Please provide program information on aging management of class 1 small bore piping up to NPS 4.
RAI B2.1.2-2
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Background===
GALL Report AMP XI.M35, One-Time Inspection of ASME Code Class 1 Small Bore Piping, recommends one time volumetric inspection of small bore piping.
Issue No specific information was provided regarding examination of small-bore piping socket welds.
During an onsite audit discussion, the applicant indicated that there are 450 class 1 welds up to NPS 4, some of which are sockets welds.
Request Please provide information on the examination of small bore piping socket welds.
LRA AMP B2.1.3 ASME Section XI, Subsection IWE RAI B2.1.3-1
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Background===
Indications of reactor refueling cavity leakage have been documented during Kewaunee Power Station (KPS) refueling outages.
Issue Refueling cavity leakage could contact the containment vessel and cause degradation of inaccessible regions of the vessel, specifically the areas that are surrounded by concrete.
Request Explain how the IWE program is addressing this possible aging effect, or why it is not necessary to evaluate it under the IWE program.
RAI B2.1.3-2
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Background===
ASME Section XI, Subsection IWE-1241 discusses surfaces requiring augmented examinations, including interior and exterior containment surface areas that are subject to accelerated corrosion with no or minimal corrosion allowance. Such areas may include surfaces that are wetted during refueling, concrete-to-steel shell interfaces, embedment zones and sump liners.
Issue KPS may have containment locations that require augmented examinations based on the above description, specifically at concrete-to-steel interfaces and embedment zones.
Request Please provide the minimum required containment vessel design thickness, the nominal containment vessel thickness, and any locations that require augmented examinations based on the requirements of IWE-1241. Provide the results of any required augmented examinations.
RAI B2.1.3-3
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Background===
The GALL Report includes AMP XI.S8, Protective Coating Monitoring and Maintenance to ensure proper maintenance of protective coatings inside containment. In the KPS LRA, the ASME Section XI, Subsection IWE AMP mentions coating degradation under operating experience however, the LRA does not include aging management of coatings.
Issue The failure of coatings could result in aging effects for the steel containment vessel, as well as failure of safety systems to perform their intended functions.
Request Please justify not having an aging management program for coatings, including a discussion of plant-specific operating experience relating to coating inspections and degradation.
LRA AMP B2.1.4 ASME Section XI, Subsection IWF RAI B2.1.4-1
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Background===
ASME Section XI, Subsection IWF-2430 requires additional examinations when conditions are revealed that exceed the acceptance standards of IWF-3400.
Issue During the AMP audit, the staff reviewed KPS surveillance procedure SP-55-085, which states additional examinations for support and hanger visual indications that exceed acceptance standards of ASME Boiler and Pressure Vessel Code will be addressed by the Kewaunee Power Station Augmented Program for Class 1, Class 2, and Class 3 Supports and Hangers.
No discussion is provided on how this program, or the additional ASME examinations, are implemented. In addition, attachments seven and eight of KPS procedure ER-AA-NDE-VT-603 used for documenting the visual examination of supports does not include guidance for initiating additional examinations to comply with IWF-2430.
Request Please explain how the requirements of IWF-2430 are satisfied. If the augmented IWF program is credited for the additional examinations, explain how the augmented program is implemented and how it satisfies the requirements of IWF-2430.
LRA AMP B2.1.5, Bolting Integrity RAI B2.1.5-1
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Background===
In the KPS LRA, the B2.1.5 Bolting Integrity Program Item 4.2 states that the program implements recommendations and guidelines in EPRI NP-5769 section 1 and volume 2, and NUREG-1339 for a comprehensive bolting integrity program, is to include training of plant staff with respect to bolting issues. However, the program does not specify the frequency of training for bolting issues.
Issue In order to assure proper training of bolting procedures it is important to not only have a training program, but one of structured frequency to assure that all staff personnel pertinent to the program receive proper training in acceptable intervals and frequency.
Request Please state the various bolting integrity training programs and the frequency of this training for applicable staff personnel.
RAI B2.1.5-2
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Background===
In the KPS LRA, the B2.1.5 Bolting Integrity Program Item 4.6 states that ASME pressure retaining bolting and nuclear steam supply system (NSSS) component support bolting indications are evaluated in accordance with Section XI of the ASME Code. The section goes on to state that particular subsections pertinent are IWB, IWC, and IWD.
Issue Subsections IWB, IWC, and IWD are still too vague and need specific section numbers that are relevant so they can be referenced and verified properly and quickly.
Request Please provide the relative section numbers.
RAI B2.1.5-3
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Background===
Section 5.1 of the LRAs AMP: Enhancement I: Bolting Program Improvements states that the Bolting Integrity Program will be enhanced to further incorporate applicable electric power research institute (EPRI) documents and industry bolting guidance pertinent to joint assembly, torque, values, gasket types, lubricants, and other bolting fundamentals. However, the section does not state which EPRI documents covers these items.
Issue Specific EPRI documents needs to be stated.
Request Provide the specific applicable EPRI documents credited in this AMP. For instance, EPRI 1015336, and EPRI 1015337.
RAI B2.1.5-4
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Background===
In the KPS LRA, the B2.1.5 Bolting Integrity AMP is stated to be consistent, with enhancement, with the GALL report XI.M18, Bolting Integrity AMP. However, the LRA is not clear in how it satisfies the GALL report program element, parameters monitored/inspected regarding the monitoring of high strength bolts for cracking. In addition, LRA Section 3.3.2.2.4.4 states that stress corrosion cracking does not apply since high strength bolts do not exist in the specific system.
Issue KPS LRA Section 3.3.2.2.4.4, states that the bolting associated with the high-pressure charging pump pressure head are not fabricated from high-strength steel, and concludes that therefore, this item is not applicable. However, the staff found in accordance to documentation provided by the applicant on-site, which contains the system specific to the NSSS, there exists high strength bolts (yield strength >150 ksi) that are being used in the NSSS supports associated with the reactor coolant pumps and the steam generators. The applicants basis document states that a detailed review of the application and installation of high strength bolting has led to the assessment that stress-corrosion cracking (SCC) is an aging effect that does not require specific aging management. The applicant then concludes that this bolting unique to the NSSS support stand will be managed only for the loss of material aging effect, and not for cracking.
The staff noted that if these steel bolts specific to the NSSS supports are fabricated from high strength bolting materials, then the applicant must justify why they have assessed that the SCC aging effect does not require specific aging management beyond the loss of material aging effect and also identify this as an exception to the GALL report XI.M18 Bolting Integrity AMP.
Request Please provide further justification and analyses on the applicability of cracking in high strength bolts as it relates to LRA section 3.3.2.2.4.4.
Furthermore, please identify why this item is not an exception to the GALL report XI.M18 Bolting Integrity AMP, even though cracking is not identified as an aging effect for high strength bolts by KPS, contrary to the recommendations in GALL report program element, parameters monitored/inspected LRA AMP B2.1.7, Buried Piping and Tanks Inspection RAI B2.1.7-1
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Background===
The applicant states that its proposed aging management program Buried Piping and Tanks Inspection (B2.1.7) (LRA AMP) is consistent with the aging management program Buried Piping and Tanks Inspection (XI.M34) contained in the GALL Report (GALL AMP). Section 1 (Scope of Program) of the GALL AMP includes buried steel piping and tanks. The LRA AMP includes steel and stainless steel piping and tanks. According to chapter IX.C of Volume 2 of the GALL Report, stainless steel is not included in the definition of steel.
Issue The LRA AMP includes stainless steel piping while the GALL AMP does not. The proposed AMP also indicates that the stainless steel piping is coated and/or wrapped. Wrapping stainless steel piping could be harmful to its corrosion resistance.
Request Please revise the LRA AMP to reflect that the inclusion of stainless steel is an exception to the GALL AMP. Please clarify whether the stainless steel piping is coated.
RAI B2.1.7-2
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Background===
The applicant states that its proposed aging management program Buried Piping and Tanks Inspection (B2.1.7) (LRA AMP) is consistent with the aging management program Buried Piping and Tanks Inspection (XI.M34) contained in the GALL Report (GALL AMP). Section 3 (Parameters Monitored/Inspected) of the LRA AMP states that uncoated buried steel is included. The GALL AMP includes only coated steel.
Issue The inclusion of uncoated steel in the LRA AMP is considered an exception to the GALL AMP.
Request Please rewrite the LRA AMP showing the inclusion of uncoated steel as an exception. Please demonstrate that the procedures specified in the LRA AMP will adequately manage corrosion of buried uncoated steel piping.
LRA AMP B2.1.8, Closed-Cycle Cooling Water System RAI B2.1.8-1
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Background===
LRA AMP B2.1.8, Closed-Cycle Cooling Water System, manages the aging effects of cracking, loss of material, and reduction of heat transfer for the steel, stainless steel, and copper alloy piping, heat exchangers, and other components in the Component Cooling System, Emergency Diesel Generator cooling water subsystems, and Control Room Air Conditioning System. The program consists of water chemistry guidelines, including the use of inhibitors, in accordance with the EPRI Report 1007820, Revision 1, and performance monitoring to verify the effectiveness of the chemistry control program. The applicant claims that AMP B2.1.8 is consistent with GALL AMP XI.M21.
Issue The AMP takes an exception (Exception 2) to the preventive action program element in that the program is implemented using the guidance of EPRI 1007820, Revision 1 (2004), instead of EPRI 107396 (1997), recommended by the GALL Report. The applicant stated that the new revision provides more prescriptive guidance and has a more conservative monitoring approach. The applicant further stated that implementation of EPRI 1007820 results in specific chemistry action levels that are more restrictive than those allowed in EPRI 107396.
Request If the chemistry action levels are more restrictive, the exception should also affect acceptance criteria program element. Revise the AMP B2.1.8, Exception 2, to indicate that program elements affected include preventive actions and acceptance criteria.
RAI B2.1.8-2
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Background===
LRA AMP B2.1.8, Closed-Cycle Cooling Water System, manages the aging effects of cracking, loss of material, and reduction of heat transfer for the steel, stainless steel, and copper alloy piping, heat exchangers, and other components in the Component Cooling System, Emergency Diesel Generator cooling water subsystems, and Control Room Air Conditioning System. The program consists of water chemistry guidelines, including the use of inhibitors, in accordance with the EPRI Report 1007820, Revision 1, and performance monitoring to verify the effectiveness of the chemistry control program. The applicant claims that AMP B2.1.8 is consistent with GALL AMP XI.M21.
Issue The AMP takes an exception (Exception 4) to the parameters monitored or inspected program element in that thermal performance testing is not performed for the heat exchangers included in the Component Cooling System cooling loop that are part of other systems or the Emergency Diesel Generator (EDG) cooling water subsystem heat exchangers and lube oil coolers. The applicant stated that in lieu of thermal performance testing, the heat exchangers are periodically inspected and flushed. In addition, the tubes of the EDG cooling water heat exchangers are periodically eddy current tested.
Request Indicate the frequency for the periodic inspection and flushing of the above-referenced heat exchangers and lube oil coolers and provide a basis for specifying this frequency. In addition, please provide information on operating experience to verify the effectiveness of this program.
RAI B2.1.8-3
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Background===
LRA AMP B2.1.8, Closed-Cycle Cooling Water System, manages the aging effects of cracking, loss of material, and reduction of heat transfer for the steel, stainless steel, and copper alloy piping, heat exchangers, and other components in the Component Cooling System, Emergency Diesel Generator cooling water subsystems, and Control Room Air Conditioning System. The program consists of water chemistry guidelines, including the use of inhibitors, in accordance with the EPRI Report 1007820, Revision 1, and performance monitoring to verify the effectiveness of the chemistry control program. The applicant claims that AMP B2.1.8 is consistent with GALL AMP XI.M21.
Issue The applicants AMP does not specify a monitoring frequency for nitrate levels in the component cooling water system, which utilizes a nitrite/molybdenate corrosion control program. However, EPRI Report 1007820, Revision 1 specifies that nitrate levels for such systems be monitored on a monthly basis for both Tier 1 and Tier 2 systems (EPRI Table 5-3).
Request Provide a justification for not performing monthly monitoring of the nitrate levels in the closed cooling water system.
LRA AMP B2.1.9, Compressed Air Monitoring RAI B.2.1.9-1
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Background===
In LRA Appendix B, Section B.2.1.9, the applicant stated that the Compressed Air Monitoring Program is consistent with the program in the GALL Report except for the exception regarding lack of leak testing and the enhancement to implement ASME OM-S/G-1998, Part 17, and EPRI TR-108147. In the LRA, the applicants program with the enhancement referred to the following technical basis references: ISA-S7.0.01-1996, U.S. Nuclear Regulatory Commission (NRC)
Generic Letter (GL) 88-14, ASME OM-S/G-1998, Part 17, and EPRI TR-108147. The applicant also stated that EPRI TR-108147, which the applicant committed to implement, is the latest revision of EPRI NP-7079.
In contrast, the technical basis references of the applicants program did not include NRC Information Notices (IN) 81-38, IN 87-28, IN 87-28 Supplement 1 or Institute of Nuclear Power Operations Significant Operating Experience Report (INPO SOER) 88-01. It is noted that the GALL Report recommends GL 88-14 to be augmented by the references that were not included in the applicants program.
It is also noted that IN 87-28 Supplement 1 transmitted to the applicant NUREG-1275, Volume 2 Operating Experience Feedback Report-Air System Problems, which addressed the concerns related to instrument air system failures and recommendations for corrective actions. In addition, INPO SOER 88-01 described the recommendations for operations, training, maintenance and design/analysis to prevent and mitigate instrument air system failures.
Issue It is not clear whether the applicants program is consistent with the Compressed Air Monitoring Program in the GALL Report in terms of applicable references for the technical basis of the program.
Request If any of the IN 81-38, IN 87-28, IN 87-28 Supplement 1, NUREG-1275 Volume 2, and INPO SOER 88-01 is not applicable as a technical basis reference for the applicants program, describe which reference is not applicable. Justify why the applicants approach without the reference is adequate for the aging management or describe the actions for the applicant to take in relation to this potential issue.
RAI B.2.1.9-2
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Background===
In the applicants chemistry procedure for air quality control, CHEM-44.001 Rev. B, Instrument Air and Diesel Air Start Air Quality Specification, dated March 22, 2007, the inspection frequency for dew point is once a year as described in Section 5.3 of the chemistry procedure.
In addition, Section 5.3 of the applicants procedure does not specify any Action Level for hydrocarbon content or particulate size, while the Action Level for the dew point was 22 °F.
Issue The ANSI/ISA-7.0.01-1996, which is one of the applicants technical references, recommends shift monitoring for pressure dew point if a monitored alarm is not available. In addition, the staff found a need to clarify why Action Level was not specified for hydrocarbon content or particulate size.
Request
- Clarify why the applicants inspection frequency for pressure dew point is not consistent with the recommendation of ANSI/ISA-7.0.01-1996 even though the applicant claimed the consistency between the program and the ANSI/ISA-7.0.01-1996.
- Clarify why no Action Level was specified for hydrocarbon content or particulate size in the chemistry procedure.
- If necessary, describe the actions for the applicant to take in relation to the foregoing potential issues.
RAI B.2.1.9-3
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Background===
In element 3 of AMP XI.M24, the GALL Report recommends to confirm the emergency procedures and training. In conjunction with GL 88-14, NUREG-1275, Volume 2 (Part I, Section 9.0) recommends that anticipated transient and system recovery procedures and related training for loss of air systems events should be reviewed for adequacy and revised as necessary. NUREG-1275, Volume 2 also recommends that the plant personnel should be trained in the anticipated transient and system recovery procedures to respond to loss-of-air-systems events.
Issue The staff reviewed the LRA and Attachment 1, Implement Procedures, of applicants Technical Report KLR-1324, Compressed Air Monitoring. The staff did not find a reference that directly describes the emergency procedures or training schedules related to the compressed air monitoring program.
Request Provide relevant references for the emergency procedures on loss-of-air-systems events.
Provide relevant references and schedules for the training on loss-of-air-systems events, anticipated transient and system recovery procedures, and compressed air systems.
RAI B.2.1.9-4
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Background===
In LRA Appendix B, Section B.2.1.9, the applicant 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. In contrast with the program exception, ASME OM-S/G-1998, Part 17 and EPRI TR-108147 recommend leak tests such as:
pressure decay test on the distribution network as one of the recommended tests for the case that compressor loading indicates an increase in system leakage (ASME OM-S/G-1998, Part 17, Section 5.3.3; EPRI TR-108147, Section 8.9.2) air leak test with a soap solution to piping joints and connections (EPRI TR-108147, Section 8.9.2)
The staff noted that one of the major purposes of the leak testing is to identify the location of leaks as described in EPRI TR-108147 Section 8.9.2. In addition, the LRA indicated that only the program element, Detection of Aging Effect, is affected by the exception and enhancement.
Issue The exception regarding lack of leak testing is in apparent conflict with the technical basis references cited for the enhancement of the program. The staff also noted that, based on the applicants technical information and program elements of the GALL Report program, each of the exception and the enhancement is regarded to affect the program elements, Scope of Program, Preventive Actions, Parameters Monitored/Inspected, and Monitoring and Trending, in addition to Detection of Aging Effect. as all foregoing elements involve leak testing.
Request Clarify how the applicants program can identify the locations of air leakage without leak testing for the distribution network.
Clarify whether leak tests for the distribution network will be performed as the technical basis references recommend and the applicant committed to in the program enhancement.
Clarify whether each of the exception and the enhancement applies only to the program element, Detection of Aging Effect.
If necessary, describe the actions for the applicant to take in relation to the foregoing potential issues.
RAI B.2.1.9-5
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Background===
The element, Acceptance Criteria, of the program in the GALL Report recommends that acceptance criteria be established for the system and for individual components that contain specific limits or acceptance ranges based on design basis conditions and/or components vendor specifications. The program element also recommends that the testing results be analyzed to verify that the design and performance of the system in accordance with its intended function.
Issue The staff found that the applicants program documents did not clearly indicate whether the applicants program established acceptance criteria for the following parameters of the compressed air systems.
Minimal operational time for each special service air accumulator and its associated check valves upon loss of the main air system Load and unload times for compressors Inlet and outlet coolant temperatures of the coolant in the compressor intercoolers and aftercoolers Set pressures of compressors and receiver pressure-relief valves Differential pressure through each dryer Request Clarify whether relevant acceptance criteria are established and documented for the foregoing parameters.
If any of the parameters does not have an acceptance criterion, justify why lack of the acceptance criterion for the parameter is acceptable for the aging management.
Otherwise, describe the actions for the applicant to take in relation to the acceptance criteria.
LRA AMP B2.1.10, External Surfaces Monitoring RAI B2.1.10-1
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Background===
LRA Section B2.1.10 describes the existing External Surfaces Monitoring Program as consistent, with GALL AMP XI.M36 External Surfaces Monitoring, with enhancements and no exceptions. The referenced GALL defines this as a condition monitoring program, i.e., the program subscribes to inspection procedures to identify the presence and extent of aging effects.
In the referenced section of the LRA, the applicant professes that its External Surfaces Monitoring Program manages the aging effects of change in material properties, cracking, delamination, loss of material, and hardening and loss of strength by visually inspecting the external surfaces of in-scope components (e.g. piping and its supports) and structural (members and commodities). Materials monitored also include stainless steel, aluminum, copper, and elastomers. The GALL Report AMP XI.M36, however, only applies to materials constructed of steel. NUREG-1801, Vol. 2, Rev 1,Section IX, page IX-12, defines steel to include only carbon steel, alloy steel, cast iron, gray cast iron, malleable iron, and high strength low alloy [(HSLA)]
steel. The applicant has modified their AMP to include other metallics and selected elastomers as part of their external surfaces monitoring program.
Issue The intent of the XI.M36 program is to monitor the aging effects of steel material which can be regularly monitored and easily identified through visual inspections. It does not specify how to monitor the aging effects of the other applicant referenced materials. Rust on carbon steel materials is easily identifiable. It manifests itself as brownish/orange bubbles or layers. Copper and aluminum, exposed to an open air environment, oxidize also, but their oxides could be hard to spot.
Request:
Justify why the inclusion of stainless steel, aluminum, copper, and elastomers to this AMP does not constitute an exception to the GALL Report XI.M36.
Define how corrosion in other metallics such as aluminum or stainless steel will be tracked to avert sudden loss of a system, structure, or (SSC) functionality.
Discuss how the scratch, sniff, and stretch tests identified in the Aging Assessment Field Guide of EPRI (audited reference 9) as potential polymer/elastomer tests to monitor their health could be accomplished strictly via visual observation.
RAI B2.1.10-2
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Background===
In the referenced section of the LRA, the applicant professes that its External Surfaces Monitoring Program manages the aging effects of change in material properties, cracking, delamination, loss of material, and hardening and loss of strength by visually inspecting the external surfaces of in-scope components (e.g. piping and its supports) and structural (members and commodities).
Issue Material properties refer to mechanical, electrical, thermal, magnetic, etc. attributes/capacities of each material to perform specific functions. The staff believes that the monitoring of changes in material properties need monitoring beyond just a visual walkdown inspection.
Request Provide the basis for monitoring the aging effects of change in material properties with visual inspection only.
RAI B2.1.10-3
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Background===
The LRA states, the External Surfaces Monitoring program takes a sampling approach for detecting aging effects and monitoring the condition of plant system, structure, and components (SSCs) in extended operation. It samples the SSCs by segregating the plant into areas containing the SSCs or structural commodities being evaluated. Areas range from portion of rooms, to entire rooms, floors of buildings, or entire buildings. The personnel performing the XI.M36 task, inspect only a representative sample of the materials/environment combinations.
Issue AMP XI.M36 is a monitoring program, not a sampling program. Sampling, however, is allowed (NUREG 1800, Rev. 1) provided the samples (size, population) are adequate to characterize the effects of aging on the structures or components (SCs). There is no elaboration on the size or population of the samples other than a general statement on the materials and SCs defined in the scope. Provisions should also be included on expanding the sample size when degradation is detected in the initial sample.
Request If the applicant intends to sample then provide additional details regarding the sampling methodology such as:
The areas and sample sizes.
What is the basis for selecting these areas/samples?
Did the applicant include previous failure histories in defining the samples? If so, did the applicant biased his samples?
Are the samples biased toward locations most susceptible to corrosion in the period of extended operations?
What are the provisions to modify or expand the samples sizes? How will the applicant do this?
LRA AMP B2.1.11, Fire Protection RAI B.2.1.11-1
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Background===
In its LRA, KPS proposed an exception to XI.M26 on the Halon and CO2 fire suppression systems testing frequencies. The GALL Report recommends a 6-month inspection and testing frequency for both the Halon and CO2 systems. To minimize interruption to the plant operation, KPS proposes to test the relay room CO2 subsystem and the turbine bearing CO2 subsystem every 18 months during the refueling outage. All other CO2 fire suppression systems are functionally tested on a semi-annual basis. The Halon systems are functionally tested on an annual basis.
Issues The testing frequency of the Halon and two of the CO2 sub-systems exceeds the GALL recommended frequency.
Request Please provide reason(s) based on the plant operating experience and other relevant factors to justify the extended functional testing cycle for the Halon and CO2 fire suppression systems.
RAI B.2.1.11-2
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Background===
In its LRA, KPS proposed an enhancement to XI.M26 on the Reactor Coolant Pumps Oil Collection System Inspections. The GALL Report recommends the XI.M39 Lubricating Oil Analysis, and XI.M32, One-Time Inspection AMPs (Ref: VII-G-26 and VII-G-27 on p. VII G-8 of the GALL Report, volume 2) for the material (steel) and environment (lubricating oil) combination. The LRA only credited a one-time inspection of the internal surfaces of the reactor coolant pump oil collection tank before the extended period of operation. The applicant stated that the one-time inspection was not the XI.M32 One-Time Inspection AMP. The lubricating oil analysis AMP was not specifically credited in this enhancement.
Issues It is not clear to the reviewer as to why the XI.M32, One-Time Inspection and the XI.M39, Lubricating Oil Analysis AMPs are not credited to support this enhancement.
Request Please provide the basis for not being consistent with the GALL Report recommendation for this material and environment combination to support this enhancement.
LRA AMP B2.1.13, Flux Thimble Tube inspection RAI B.2.1.13-1
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Background===
In the LRA, the applicant stated that the flux thimble inspection program is consistent with the GALL Report with no exception or enhancement. The element, Monitoring and Trending, of the GALL Report AMP recommends that the wall thickness measurements should be trended and wear rates should be calculated.
Issue The LRA and related on-site program documentation do not clearly address how the program manages discrepancies between projected wear rates and measured wear rates.
Request Explain how the AMP manages discrepancies between projected wear rates and measured wear rates, especially for cases where the discrepancies are big and unexpected.
RAI B.2.1.13-2
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Background===
The operating experience of this program in LRA Appendix B, Section B2.1.13 indicated that inspections were performed in 2000 and 2004.
Issue The LRA did not clearly indicate that the results of the inspections performed in 2000 and 2004 demonstrate the adequacy of the program-defined inspection frequency and wear projection methodology.
Request Provide relevant inspection results, including the actual wear of the two inspection periods which ended in 2000 and 2004, respectively, and demonstrate that the applicants inspection frequency and wear rate projection methodology are adequate to manage the aging effect of the thimble tubes.
RAI B.2.1.13-3
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Background===
In the LRA, the applicant stated that the flux thimble inspection program is consistent with the GALL Report with no exception or enhancement. The element, Acceptance Criteria, of the GALL Report AMP recommends that acceptance criteria such as percent through-wall wear should be established and technically justified to provide an adequate margin of safety to maintain the integrity of the reactor coolant system pressure boundary.
The program element also recommends that acceptance criteria different from those previously documented in NRC acceptance letters for the applicants response to Bulletin 88-09 and amendments thereto should be justified.
Issue The section for the program element, Acceptance Criteria, in the on-site technical report, KLR-1335, Revision 1 stated that the acceptance criterion of 80% through-wall wear requires the repositioning and isolation of the thimble tube. The report also stated that the 80% criterion was first used in 2004 and differs from the 60% limit discussed in the applicants response to GL 88-09.
Request In the applicants program description, GL 88-09 should be corrected to Bulletin 88-09.
Clarify this issue.
As the GALL Report recommends, justify why the current acceptance criteria provide an adequate margin of safety to ensure that the integrity of the reactor coolant system pressure boundary is maintained in consideration of the uncertainties of wall thickness measurements and projections.
RAI B.2.1.13-4
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Background===
The work order instructions of the applicant for thimble tube eddy current inspection, WO# 03-011955 / PM50-032, indicated that WCAP#12866 shall be used to predict future tube degradation.
The staff noted that Section XIII, Conclusions, of WCAP-12866, Bottom Mounted Instrumentation Flux Thimble Wear, states that the best approach to calculating future wall loss is to use the exponential equation, with an exponent value calculated using two previous cycle inspection results for a specific plant. The report also states that for plants which do not have two prior inspection points, a conservative exponent value of 0.67 may be used.
The applicants report, Thimble Tube Inspection Evaluation Report, under KNPP WO# 03-11955 dated October 29, 2003, and attached information on the thimble tube degradation forecast suggest that the applicants wear projection methodology might use an exponent of 0.67 rather than an exponent based on the previous two inspection results.
In addition, the WCAP report states that the changes in thimble or reactor hardware and changes in reactor coolant flow rate can change the thimble wear rate in a given plant and theses changes must be assessed when assessing future thimble wear.
Issue In the applicants response to NRC Bulletin 88-09, dated November 7, 1988, the applicant stated that the examination frequency after 1998 will be dependent on the results of the previous two tests. However, it is not clear whether the applicants approach to define the exponent considers plant-specific inspection results.
The staff also found a need to clarify whether the program adequately manages the potential effect of hardware and flow rate changes on the thimble tube wear rates.
Request Clarify what exponent is used for the wear projections. If the previous inspection results are not used to determine the exponent, demonstrate why the applicants methodology on the exponent determination is in agreement with or conservative than the exponent determination based on the actual plant-specific inspection results.
Describe how the applicants program considers and manages the potential effect of changes in flow rates and thimble or reactor hardware on the wear rates.
RAI B.2.1.13-5 Background and Issue The applicants Updated Final Safety Analysis Report (USAR) summary description in LRA Section A2.1.13 does not include NRC Bulletin 88-09 as a reference in contrast with the summary in SRP-LR Table 3.1-2.
Request In the USAR summary description, include NRC Bulletin 88-09 as a technical reference and clarify whether the program implements the recommendations of NRC Bulletin 88-09.
LRA AMP B2.1.14, Fuel Oil Chemistry RAI B2.1.14-1
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Background===
In Exception #1 of LRA Section B2.1.14, the applicant states that KPS has not adopted the Standard Technical Specification as described in NUREG-1431 and the plant fuel oil specifications and procedures invoke requirements that are similar to the Standard Technical Specifications for fuel oil purity and fuel oil testing.
Issue The staff noted that the meaning of the term requirements that are similar is not clear. The staff noted that the use of this term may also be subjective.
Request Please provide a direct comparison between the Standard Technical Specifications and the KPS fuel oil specifications along with a justification for any difference in fuel oil purity and testing parameters.
RAI B2.1.14-2
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Background===
In Exception #2 of LRA Section B2.1.14, the applicant states that KPS does not add fuel stabilizers to the diesel fuel oil. The applicant continues to state that the diesel generators are operated on a frequent basis which allows for the mixing of incoming new fuel oil and the day tanks are small in size so they experience a high turnover rate of fuel oil.
Issue The LRA was not clear about whether this statement is in reference to the EDGs and/or the TSC DG and how often they are operated. The LRA was also not clear about size of the tanks and how much fuel is consumed in order to be considered as undergoing a high turnover rate.
Request Please provide the basis for the statements made in LRA for justifying not using fuel stabilizer additives in the diesel fuel oil. Please be specific and consider the following in your justification:
the diesel generators that are in scope of the program the frequency these diesel generators are operated the operating volume of the fuel oil storage and day tanks the amount of fuel that is consumed in comparison to the size of the respective tanks the parameters that are monitored, which provide indication of fuel oil decomposition or degradation that warrant not using fuel stabilizers RAI B2.1.14-3
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Background===
In Exception #5 of LRA Section B2.1.14, the applicant states that KPS does not perform multi-level sampling of the fuel oil day tanks. Instead a one-gallon sample is taken from the bottom of the tank on a monthly basis to allow for a visual inspection for the presence of water and sediment.
Issue The LRA did not provide the justification and the threshold/criteria that will be used for the visual inspection of the one-gallon samples taken from the day tanks on a monthly basis.
Request Please provide a justification that a visual inspection of this sample is sufficient in-lieu of a laboratory analysis of the sample as described in ASTM D4057. Provide and justify the threshold/criteria that will be used for this visual inspection of the sample, clearly identifying when corrective actions will be taken. Clarify how a visual inspection is capable of quantifying the amount of water/sediment/particulates that is in the one-gallon sample of fuel oil.
Clarify if there is some type of filter or filtration that exists between the respective fuel oil storage tank and fuel oil day tank that would limit the amount of contaminants entering the day tank.
Clarify whether the sample that is taken from the fuel oil day tanks is a true bottom sample or is it taken from another type of configuration. If it is not a true bottom sample please clarify this other type of configuration and justify that there is not a need to remove the accumulated water/sediment/contamination from the tank bottom that is not flushed out during the monthly removal of the one-gallon sample.
RAI B2.1.14-4
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Background===
After the issuance of Revision 1 of the GALL Report, the NRC has issued Information Notice (IN) 2009-02, Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine Performance. This Information Notice discusses potential issues that may occur with the use of B5 blend fuel oil, such as: suspended water particles, biodegradation of B5, material incompatibility, etc.
Issue The LRA did not provide information discussing the concerns of IN 2009-02 and the acceptable or unacceptable use of bio-diesel at KPS.
Request Provide a summary of the actions that were taken to determine the impact of IN 2009-02 and the use of bio-diesel fuel oil at KPS. If actions have not been taken yet, describe the actions that KPS will take to determine the impact of IN 2009-02 and the acceptable or unacceptable use of bio-diesel.
If bio-diesel is currently being used at KPS, please describe any problems that KPS encountered with the use of bio-diesel and the associated corrective actions to prevent reoccurrence in the future.
If bio-diesel has been determined to be not acceptable for use at KPS, please describe the actions taken and/or will be taken to prevent its addition into fuel oil supply. Please also describe actions that will be taken if it is determined that bio-diesel has been added into the fuel oil supply.
LRA AMP B2.1.15, Fuel Oil Tanks Inspections RAI B2.1.15-1
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Background===
In the program description of LRA Section B2.1.15, it describes that the Emergency Diesel Generator (EDG) Storage Tanks and the Technical Support Center (TSC) Diesel Generator (DG) Storage Tank will be periodically drained, cleaned and inspected and the bottom plate will receive an ultrasonic test to determine the minimum wall thickness. The LRA further describes that this program manages aging for underground diesel generator fuel oil storage tanks.
Issue LRA Section B2.1.15 does not describe the activities that will be performed for the EDG Day Tanks and the TSC DG Day Tank. It is not clear to the staff if the Work Control Process program, which has been credited aging management of the respective day tanks, will perform the activities of draining, cleaning and inspections of the internal surfaces of these day tanks, consistent with the recommendations of GALL Report AMP XI.M30.
Request Please clarify if the Work Control Process program will periodically drain, clean and visually inspect the interior of the tank and perform an ultrasonic test of the bottom plate to determine minimum wall thickness for the EDG Day Tanks and the TSC DG Day Tank, consistent with the recommendations of GALL Report AMP XI.M30.
If yes, clarify and justify the frequency that these activities will be performed.
If not, please clarify the activities that will be performed as part of the Work Control Process program and justify the ability of these activities to provide aging management of the EDG Day Tanks and the TSC DG Day Tank. Please consider the recommendations of GALL AMP XI.M30 to periodically drain, clean and visually inspect the interior of the tank and perform an ultrasonic test of the bottom plate in the justification.
Also, please clarify how there is assurance that the internal surfaces of the day tanks is adequate if some type of inspection is not performed to asses the condition of the tank interior. Including the tank bottom where contamination, water and particulates are likely to settle and accumulate that can lead to loss of material.
LRA AMP B2.1.18, Metal Enclosed Bus RAI B2.1.18-1
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Background===
In the LRA Sections B2.1.18 and A2.1.18, the applicant implies to inspect only sections of in-scope metal enclosed bus (MEBs) using visual inspection. The GALL Report AMP XI.E4 under program description states that, The purpose of the aging management program is to provide an inspection of MEBs. In this aging management program, bolted connections at sample sections of the buses in the MEBs will be checked for loose connections.
Issue GALL Report AMP XI.E4 recommends inspecting all MEBs and a sample of bus connections.
The applicant AMP implies inspection of only a sample of MEBs.
Request Please clarify that LRA AMP B2.1.18 inspection of MEBs includes all MEB and a sample of MEB bus connections consistent with GALL Report AMP XI.E4.
RAI B2.1.18-2
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Background===
In LRA Section B2.1.18, under the program description, the applicant states that the metal enclosed bus program is supported by the structures monitoring program which performs visual inspection of portions of the MEB enclosure assemblies.
Issue The staff reviewed the applicants structural monitoring program and noted that it does not address the visual inspection of MEB.
Request Describe acceptance criteria of how the structure monitoring program will be used to visually inspect the exterior portions of the MEB consistent with GALL Report Table VI, Item VI.A-12 and VI.A-13.
RAI B2.1.18-3
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Background===
In LRA Section B2.1.18, the applicant states that the existing inspection program is designed to maintain the tightness of metal-enclosed bus joints and joints were torque checked for proper tightness. Re-torque is not recommended in EPRI document TR-104213 (See Sections 7.2.1 and Section 8.2) for electrical bolted connection maintenance. The EPRI document states that the bolts should not be re-torqued unless the joint requires service or the bolts are clearly loose.
Issue Verifying the torque is not recommended in EPRI TR-104213. The torque required to turn the fastener in the tightening direction (restart torque) is not a good indicator of the preload once the fastener is in service. Due to relaxation of the parts of the joint, the final loads are likely to be lower than the installed loads.
Request Provide technical justification of how re-torque procedures at KPS are consistent with industry recommendations.
LRA AMP B2.1.19, Non-EQ Electrical Cables and Connections RAI B2.1.19-1
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Background===
In LRA Section B2.1.19, the applicant states that an adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for electrical cables and connections. The applicant also states that should an adverse localized environment be observed, a representation sample of electrical cables and connections installed within that environment will be visually inspected for aging.
Issue The applicant has not established the criteria of how an adverse localized environment is identified. As defined in NUREG 1801, an adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified and analyzed service environment for cables (power, control, and instrumentation) and connections. An adverse variation in environment is significant if it could appreciably increase the rate of aging of a component or have an immediate adverse effect on operability.
Request Please describe how adverse localized environments will be established and incorporated into the above AMP.
LRA AMP B2.1.20, Non-EQ Electrical Cable Connections RAI B2.1.20-1
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Background===
Section B2.1.20 states that AMP B2.1.20 is consistent with the recommendations of NUREG-1801,Section XI.E6, Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Revised).
Issue LRA Section B2.1.20 and the associated USAR supplement (A2.1.20) are not consistent with the GALL Report AMP XI.E6 or NUREG -1801, Vol. 2 Revision 1. However, LRA Section B2.1.20 is representative of the summary description and program elements of staff ISG (ISG-LR-ISG-2007-02) issued for public comment by letter dated August 29, 2007 (ADAMS ML072420437). Justification has not been provided as to the acceptability of the changes with respect to GALL AMP XI.E6.
Request Provide justification that demonstrates that the incorporation of ISG-LR-ISG-2007 into LRA AMP B2.1.20 is consistent with GALL Report AMP XI.E6 program elements and should not be considered an exception or a plant-specific program to GALL Report AMP XI.E6.
LRA AMP B2.1.21, Non-EQ Inaccessible Medium-Voltage Cables RAI-B2.1.21-1
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Background===
For LRA AMP B2.1.21, Program Element 4 the applicant states that inspection for water collection should be performed prior to the period of extended operation and every two years thereafter.
Issue GALL Report AMP XI.E3 states that the inspection for water collection should be based on actual plant experience with water accumulation in the manhole with an inspection frequency of at least every two years. The staff is concerned that the applicant did not provide plant-specific operating experience to justify the fixed two year inspection frequency. In addition, the staff is concerned that the applicants program does not provide for adjustment of the two year inspection frequency based on the possibility of subsequent significant water accumulation resulting in cable submergence.
Request Provide justification for the fixed two-year inspection interval and lack of inspection frequency adjustment should cable submergence occur.
LRA AMP B2.1.23, Open-Cycle Cooling Water System RAI B2.1.23-1
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Background===
The applicant states that its proposed aging management program Open Cycle Cooling Water System (B2.1.23) LRA AMP) is consistent with the aging management program Open Cycle Cooling Water System (XI.M20) (GALL AMP) contained in the GALL Report. Section 2 (Preventive Actions) of the GALL AMP states that all service water piping should be lined. The LRA AMP indicates that much of the service water piping is not lined.
Issue Loss of material due to corrosion can be expected to occur much more rapidly in bare steel and cast iron piping than in lined piping. The absence of linings may require an aging management program which exceeds the requirements established by the GALL AMP.
Request Please demonstrate that the proposed program is sufficiently robust to adequately manage aging in the absence of pipe.
RAI B2.1.23-2
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Background===
The applicant states that its proposed aging management program Open Cycle Cooling Water System (B2.1.23) (LRA AMP) is consistent with the aging management program Open Cycle Cooling Water System (XI.M20) (GALL AMP) contained in the GALL Report. Section 2 (Preventive Actions) of the GALL AMP states that chemical treatment is necessary to control biofouling in the open cycle cooling water system.
Issue Plant operating experience indicates that the biocide injection system is less than fully reliable.
Plant operating experience also indicates that zebra mussels are commonly found in various parts of the open cycle cooling water system. Given these observations, it is not clear to the staff that the proposed program is sufficiently robust to adequately manage biofouling during the period of extended operation.
Request Please either demonstrate the sufficiency of the proposed program to address biofouling (including the reliability of the chemical injection equipment) or propose modifications to the program which will adequately manage aging.
RAI B2.1.23-3
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Background===
The applicant states that its proposed aging management program Open Cycle Cooling Water System (B2.1.23) (LRA AMP) is consistent with the GALL AMP contained in the GALL Report.
During its review of operating experience the staff identified numerous instances in which the LRA AMP failed to prevent loss of function. The subjects of some of these operating experience reports dealt with fouling under low flow conditions. The staff was not able to determine the applicants response to all of these events.
Issue The applicant demonstrates in the LRA AMP that operating experience obtained from a given component is used to modify the inspection of other similar components/environments. The staff independently identified and reviewed operating experience for which it was not obvious that the operating experience from one component had been applied to other similar components. This was particularly true for low flow heat exchangers.
Request Please provide additional examples, particularly associated with low flow heat exchangers, demonstrating that operating experience from one component is used to modify the inspection program for other, similar, components.
LRA AMP B2.1.24, Primary Water Chemistry RAI B2.1.24-1
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Background===
GALL AMP XI.M2 (Water Chemistry) states that it is based on the primary water chemistry guidelines for pressurized water reactors contained in EPRI Report TR-105714 (Pressurized Water Reactor Primary Water Chemistry Guidelines, Rev. 3) published in 1995, or later revisions. The applicants LRA Section B2.1.24 (Primary Water Chemistry) states that its Primary Water Chemistry AMP is based upon EPRI Report 1002884, which it identifies as Pressurized Water Reactor Primary Water Chemistry Guidelines, Vol. 1, Rev. 6.
Issue EPRI Report 1002884 cited by the applicant is actually Revision 5 of Pressurized Water Reactor Primary Water Chemistry Guidelines, Vol. 1, issued in October 2003. Revision 6 of this report, which is the most recent revision (published in December 2007) is EPRI Report 1014986 and is the edition of the report currently in effect.
Request Clarify which revision of the EPRI report Pressurized Water Reactor Primary Water Chemistry Guidelines, Vol. 1 forms the basis for the applicants Primary Water Chemistry AMP B.1.24.
RAI B2.1.24-2
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Background===
EPRI Report 1014986 (Pressurized Water Reactor Primary Water Chemistry Guidelines, Vol.
1, Rev. 6), which forms the most recently updated basis for GALL AMP XI.M2 (Water Chemistry), defines action level limits for dissolved oxygen in the primary water for operation under reactor critical conditions (Table 3-3). These limits are >5 ppb for Action Level 1, >100 ppb for Action Level 2, and >1000 ppb for Action Level 3.
Issue The applicants Primary Water Chemistry Program Directive (NAD-01.44, Rev D) defines action level limits for dissolved oxygen for reactor critical conditions that are identical to those contained in EPRI Report 1014986. However, the applicants Primary Chemistry Sample Specifications Procedure (CY-KW-040-001, Rev. 2) defines the following action levels for the same conditions: Action Level 1: >5 ppb, Action Level 2: (no limit stated), and Action Level 3:
>100 ppb.
Request Resolve this apparent inconsistency between the applicant documents NAD-01.44, Rev D and CY-KW-040-001, Rev. 2.
RAI B2.1.24-3
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Background===
EPRI Report 1014986 (Pressurized Water Reactor Primary Water Chemistry Guidelines, Vol.
1, Rev. 6), which forms the most recently updated basis for GALL AMP XI.M2 (Water Chemistry), states on p. B-13 that the concentration limit for reactive silica in the boric acid storage tanks is 5000 ppb. It further states that this limit is for 4% boric acid, and that the limit can be increased proportionally for higher boric acid concentrations.
Issue The applicants Primary Water Chemistry Program Directive (NAD-01.44, Rev D) states on p. 12 that, for the boric acid storage tank, the limit on reactive silica is 5,000 ppb. However, the applicants Chemistry Procedure (CY-KW-040-001, Rev. 2) states on p. 13 that the limit on reactive silica is 10,000 ppb. In footnote 2 for this latter value, the applicant notes that the EPRI limit of 5,000 ppb has been increased proportionally for the higher boric acid level of approximately 8%, as permitted by the EPRI guidance. The limits on reactive silica in the two applicant documents appear to be inconsistent.
Request Resolve this apparent inconsistency between the applicant documents NAD-01.44, Rev. D and CY-KW-040-001, Rev. 2.
RAI B2.1.24-4
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Background===
The applicants LRA lists a number of structures and components for which the operating environment is primary water and for which aging is managed by the Water Chemistry Program (e.g., IV.B2-2, IV.C2-13, IV.D1-4, etc.). GALL states that no further aging management review is necessary for these and similar components if the applicant provides certain component-specific commitments in the FSAR Supplement.
Issue The applicants USAR Supplement A2.1.24 for the Primary Water Chemistry Program includes no commitments with respect to the components described above.
Request Revise USAR Supplement A2.1.24 to include the appropriate commitments for the component types described above or provide a justification for not including these commitments.
LRA AMP B2.1.30, Steam Generator Tube Integrity RAI B2.1.30-1
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue KPS program document, Technical Report KLR-1319, describes the steam generator tube integrity aging management program. The aging management program has numerous references. Several of the references have been superceded (e.g., references 8.8 and 8.9),
and some are no longer the current versions of the document (e.g., reference 8.12).
Request Please discuss your plans for modifying the document to be consistent with the updated references and provide the list of references.
RAI B2.1.30-2
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue KPS program document, SP-36-084, Steam Generator Tube Inspection, Revision 0, dated August 17, 2006, does not appear to be updated to reflect the latest version of the Electric Power Research Institute (EPRI) Pressurized Water Reactor Steam Generator Examination Guidelines. Nuclear Energy Institute (NEI) initiative NEI 97-06, Steam Generator Program Guidelines, Revision 2, which is referenced as an acceptable aging management program for steam generator tube integrity in the GALL report, requires licensees to modify their Steam Generator Programs upon issuance of updated guidelines during the time frame specified in the letter forwarding the revised guidelines. In addition, Kewaunee procedures appear to require the issuance of a corrective action system entry to ensure that the appropriate procedures have been updated. The staff also notes that a similar issue was previously identified during a Kewaunee self-assessment and an external review visit in 2005.
Request Please confirm whether SP-36-084 has been updated to reflect the latest version of the EPRI guidelines. Provide your plan to ensure that future updates to the guidelines will be incorporated in a timely manner.
RAI B2.1.30-3
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue During the review of KPS program document, SP-36-084, the staff identified several potential discrepancies between the industry guidelines (referenced in NEI 97-06) and the plant procedure.
Request Please address the following issues:
In section 1.3 in the Validation of Inspection Intervals section, there is a note indicating that the first inservice inspection of the steam generators can not occur within six effective full power months of steam generator replacement. This statement appears to be in conflict with the requirements in NEI 97-06 (and the steam generator technical specifications) which do not specify a minimum timeframe limit on when the first inservice inspection shall be (other than during the first refueling outage following replacement).
In section 2 in the Validation of Inspection Intervals section, it appears that the inspection frequencies for the steam generators may exceed the requirements of NEI 97-06 if both steam generators are not inspected every outage. Please confirm that the guidance in this procedure is sufficient to ensure the inspection frequency of NEI 97-06 (and the technical specifications) will not be exceeded. If it isnt sufficient, discuss your plans to modify the procedure.
In the Categorization of Steam Generator Tube Inspection Results section, there are references to the inspection categories and degraded and defective tubes. This terminology appears to have been replaced in the latest version of the EPRI Steam Generator Examination Guidelines. Please discuss.
In the Condition Monitoring Screening section, paragraph 5.2.2, implies that growth rates need to be assessed as part of condition monitoring. The evaluation of growth rates is not relevant for condition monitoring. Please clarify. In addition, the reason for not assessing all indications in condition monitoring (regardless of depth) is not clear.
In the Loose Parts Disposition Flow Chart, there does not appear to be an option that the safety evaluation of a loose part could result in a conclusion that is unacceptable to leave the part/tube in service.
RAI B2.1.30-4
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue The regulatory requirements section (3.1.9) in KPS program document, ER-AP-SGP-101, Steam Generator Program, does not appear to list all of the regulatory requirements identified in NEI 97-06.
Request Please address this inconsistency.
RAI B2.1.30-5
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue
- Section 3.1.3 of ER-AP-SGP-102, Steam Generator Degradation Assessment, requires compliance with the latest revision of the EPRI guidelines; however section 3.1.6 of ER-AP-SGP-101 requires compliance with the latest revision of the EPRI guidelines within the timeframe in the transmittal letter for the new guidelines.
- Section 3.2.1.d of ER-AP-SGP-102 appears to try to ensure tube integrity for the operating interval between inspections; however, it is not clear that this is possible to do such an assessment prior to the inspection (since the actual inspection results are needed for the assessment of tube integrity for the next operating interval).
Request Please resolve these apparent conflicts.
RAI B2.1.30-6
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Section 3.2.5 of ER-AP-SGP-102 on insitu pressure testing only addresses differential pressure loads.
Request Since NEI 97-06 requires the assessment of loads other than that associated with differential pressure, please discuss whether Section 3.2.5 is sufficient for verifying tube integrity. If it is not sufficient, please discuss your plans for modifying this section to reflect all the loads that must be considered per NEI 97-06 (and the technical specifications).
RAI B2.1.30-7
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Section 3.2.2 of ER-AP-SGP-103 implies that growth rates need to be assessed as part of condition monitoring. The evaluation of growth rates is not relevant for condition monitoring.
Section 3.2 of ER-AP-SGP-103 requires an assessment of the accident induced leakage performance criteria; however, this document does not indicate the probability and confidence level for this assessment. The probability and confidence level for the structural integrity assessment is provided in the document, and is consistent with NEI 97-06.
Request Please resolve these discrepancies.
RAI B2.1.30-8
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Section 2.0 of ER-AP-SGP-103, Condition Monitoring and Operational Assessment, indicates that condition monitoring is required whenever steam generators are being inspected.
Request Since NEI 97-06 and the technical specifications require condition monitoring to be performed when inspections are performed or tubes are plugged, please discuss whether this procedure is also applicable when steam generator tubes are plugged (without inspection).
RAI B2.1.30-9
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Section 3.2.5 of ER-AP-SGP-103 appears to only require an assessment of accident induced leakage when operational leakage is observed.
Request Given that there may be accident induced leakage without observing operational leakage, discuss how your program ensures the NEI 97-06 accident induced leakage criteria will be met.
RAI B2.1.30-10
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Section 3.2.11 of ER-AP-SGP-103 provides various conditions when the differential pressure across the steam generator tubes must be assessed and included in the operational assessment.
Request Since there may be other conditions that result in an increase in the differential pressure across the tubes (e.g., fouling), please discuss why only those conditions identified in the procedure as increasing the differential pressure across the tubes are required to be assessed.
RAI B2.1.30-11
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue The Secondary Side Integrity Plan apparently references several outdated references.
Request Please address this discrepancy and specify your plans for updating this document.
RAI B2.1.30-12
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Section 6.3 of the steam generator Secondary Side Integrity Plan makes recommendations on sludge lancing. Since this document is the plan for performing secondary side inspections, it is not clear that these recommendations are consistent with the requirements of section 3.3.6 or ER-AP-SGP-101 which requires a plan.
Request Please address this discrepancy.
RAI B2.1.30-13
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Background===
The applicant stated in Section B2.1.30 of the LRA that its Steam Generator Tube Integrity program is an existing program that is consistent with the recommendations of NUREG-1801,Section XI.M19, Steam Generator Tube Integrity, with exceptions. It further stated that its program meets the intent of NEI 97-06 as recommended by NUREG-1801.
Issue Two documents, ER-AP-SGP-10, Steam Generator Program Description, Revision 1 and Dominion Nuclear Fleet Program Description ER-AP-SGP-101, Steam Generator Program, Revision 2, describe the responsibilities of steam generator program personnel. The staff noted some inconsistencies in the designation and responsibilities defined for Steam Generator Program. For example, in Section 4.2 of ER-AP-SGP-10, Administrative information-Responsibilities, the applicant stated that it is the Manager Corporate Engineering Programs -
Innsbrook who is responsible for designating the Fleet Lead for the SG program. However, in Section 5.2.3 of ER-AP-SGP-101, Administrative information-Responsibilities, the applicant stated that it is the Director Nuclear Engineering - Innsbrook - Programs who is responsible for designating a Fleet Lead for the Steam Generator program. Also, Section 4.2.2 of ER-AP-SGP-10 states that Manager Nuclear Engineering - Site is responsible for implementing the site SG program while Sections 5.2.2 and 5.2.11 of ER-AP-SGP-101 indicate otherwise. These discrepancies could create some misunderstandings about the responsibilities of people in charge of implementing the Steam Generator Tube Integrity AMP.
Request Please review these documents and clarify the responsibilities of each person involved in Steam Generator Program are identified correctly and consistently. Confirm that these updates are performed.
LRA AMP B2.1.31, Structures Monitoring Program RAI B.2.1.31-1
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Background===
LRA Section B2.1.31 states that applicants Structures Monitoring Program is an existing program that corresponds to NUREG-1801,Section XI.S5, Masonry Wall Program, XI.S6, Structures Monitoring Program. and XI.7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants.
Issue LRA Section A does not clearly describe the program summary with all necessary references for implementation as defined in NUREG-1800, Rev. 1.
Request Revise Appendix A, Program Description to summarize AMP B2.1.31 consistent with the level of details provided in NUREG-1800, Rev. 1.
RAI B.2.1.31-2
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Background===
LRA Section B2.1.31 states that the Structures Monitoring Program is an existing program and is consistent with the recommendations of NUREG 1801. Technical Report KLR: 1431 -
Structures Monitoring Program Attachment 5 presents an element by element evaluation of the applicants program with the corresponding GALL Report Program.
Issue The technical report does not clearly describe the program elements with all necessary references for implementation as defined in the GALL Report Program elements.
Request Include all the references for implementation in the element by element comparison to be consistent with the GALL Report or explain why they are not included.
RAI B.2.1.31-3
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Background===
The LRA Section B2.1.31 states that the Structures Monitoring Program will be enhanced to monitor ground water quality and verify that it remains non-aggressive to below-grade concrete.
Issue Evidence of apparent high chloride and sulfate was noted in Section 3.5.2.2.1.1 of the LRA and also in reviewed condition report CR095754.
Requests Describe past and present groundwater monitoring activities at the Kewaunee Power Station, including the results for sulfates, pH and chlorides.
Provide the location(s) where test samples were/are taken relative to the safety-related and important-to-safety embedded concrete foundations.
Indicate seasonal variations.
Explain the technical basis and acceptance criteria.
RAI B.2.1.31-4
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Background===
The LRA Appendix B Operating Experience section states leaching and cracking was observed on the outer concrete surface of the reactor refueling cavity wall. Based on inspection and chemistry sampling, a small amount of borated water found its way down the wall, followed the crack, and deposited boric acid when it was dried.
Issue The last inspection was performed in October 2004. There is no discussion of managing and/or preventing further degradation in the LRA.
Request Provide further information on what has been done to monitor the cracking, leaching, and leakage of boric acid after the last inspection in 2004.
What action will be taken to manage the degradation during the period of extended operation to prevent any loss of intended function?
Address the adequacy of the current inspection interval considering the specific operating experience.
RAI B.2.1.31-5
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Background===
During the audit, while reviewing condition reports, it was found that a white substance was observed on the wall and ceiling of the waste drumming room, below the spent fuel pool. The issue was discovered in December 2007. According to the condition report (CR), it is boric acid related.
Issue The white substance indicates leakage of borated water through the concrete, which may be degrading the concrete and rebar.
Request Provide the information regarding the source of the leakage and any plan to fix the leakage prior to entering the period of extended operation.
If no plan exists to fix the leakage, provide the monitoring plan, inspection methods, and inspection schedule to ensure that aging degradation will be detected and quantified before there is loss of intended functions.
RAI B.2.1.31-6
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Background===
During the LRA audit, a plant walkdown was performed. Various concrete degradation mechanisms were observed on the walls of the Screenhouse Structures. The noted deficiencies/aging effects include cracking, leaching, and patterned cracking. According to the operating experience presented in Section B2.1.31, the last inspection was done in April 2008.
Issue Several evidences of leaching were observed. According to the operating experience presented in Appendix B, the last inspection was done in April 2008 and this structure will be included in the long-range rehabilitation plan. Also the applicant stated that this structure was Acceptable with Deficiency.
Request Staff requests an explanation of the long-range rehabilitation plan. What actions will be taken to manage the concrete aging effect and maintain integrity of the structure during the period of extended operation?
LRA TLAA Support Programs TLAA/AMP B3.2, Metal Fatigue of Reactor Coolant Pressure Boundary RAI B3.2-1
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Background===
In LRA Section B3.2, the applicant states that the KPS Metal Fatigue of Reactor Coolant Pressure Boundary program monitors and tracks the critical thermal and pressure transients to ensure that cycle occurrence limits are not exceeded so that the ASME Class 1 vessels and pressurizer surge line fatigue analyses assumptions are maintained.
Issue In the LRA, there was no description or discussion regarding how KPS has been and will be monitoring the severity of pressure and thermal (P-T) activities during plant operations. It is essential that all thermal and pressure activities (transients) are bounded by the design specifications (including P-T excursion ranges and temperature rates) for an effective and valid aging management program.
Request Describe the procedures that KPS uses for tracking thermal transients.
Confirm that all monitored transient events are bounded by the design specifications.
Specify the time (years) over which actual transient monitoring and cycle tracking activities took place. If there have been periods for which transient events were not monitored since the initial plant startup, specify the affected time frame, and provide justification to demonstrate that the estimated cycles for this unmonitored period are conservative.
Provide a histogram of cycles accrued for plant heatup and plant cooldown transients.
RAI B3.2-2
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Background===
LRA Section B3.2 states that the KPS Metal Fatigue of Reactor Coolant Pressure Boundary program utilizes all three modules of EPRI software FatiguePro to perform cycle counting, cycle-based fatigue (CBF) monitoring, and stress-based fatigue (SBF) monitoring.
Issue In its stress-based fatigue monitoring module, FatiguePro does not use all six components of a transient stress tensor (Sxx, Syy, Szz, Sxy, Syz, Szx) to perform fatigue analysis in accordance with the ASME Section III NB-3200 guidance. FatiguePro takes simplified approach by producing only one stress component and uses that single stress component for fatigue usage evaluation. NRC Regulatory Issue Summary (RIS) 2008-30, titled Fatigue Analysis of Nuclear Power Plant Components, dated December 16, 2008 (ML083450727), requests that the license renewal applicants that have used this simplified methodology perform confirmatory analyses to demonstrate that the simplified analyses provide acceptable results. In addition, there are multiple occurrences of terminologies stress-based monitoring and SBF in the body of the LRA. If the plant does not have appropriate stress monitoring capability, use of such terminologies would be misleading.
Request Make appropriate adjustments and corrections regarding the use of the stress-based monitoring and SBF terminologies, and reliance to the SBF methodology for fatigue usage calculations. This action applies to the entire body of the LRA, including License Renewal Commitment 28.
Identify the items whose CUF values were calculated using FatiguePro or simplified methodology, including the results shown in LRA Tables 4.3-2 and the results embedded in the text (not tabulated). The items that are identified must be reevaluated in accordance with the guidelines described in ASME Section III NB-3200, taking all 6 components of stress into consideration.
RAI B3.2-3
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Background===
Under the Operation Experience paragraphs in LRA Section B3.2, the applicant describes a 2001 incident that potentially challenged the charging line and reactor coolant loop piping nozzle fatigue limits. The applicant states that KPS documented the event in the Corrective Action Program and performed a fatigue evaluation for the charging and reactor coolant loop piping as well as for the charging nozzle. In addition, the applicant states that the engineering evaluation determined that no fatigue limits were exceeded based on a review of the USAS B31.1 design code requirements for the charging and reactor coolant loop piping.
Issue Clarification is required.
Request Describe the engineering analysis performed for the incidental transient.
RAI B3.2-4
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Background===
Under the Operation Experience paragraphs in LRA Section B3.2, the applicant describes that unusually high differential temperatures between the pressurizer surge line and RCS hot leg have been mistakenly logged, T.
Issue KPS attributed the unusually high T to the erroneous use of the 'subcooling' data when the pressurizer is in a water solid condition while heating up or cooling down. According to the description shown in LRA Section B3.2, water solid condition will be formed during the heatup and cooldown process under the Modified Steam Bubble method.
Request Describe the Modified Steam Bubble method, which KPS has been using since the plant startup (as indicated in LRA Section 4.3.1.4).
At what stage of the heatup/cooldown process will water-solid condition be established under the Modified Steam Bubble method?
How KPS determines T now since the mistake has been corrected?
LRA TLAA TLAA 4.3, Metal Fatigue RAI 4.3-1
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Background===
In LRA Section 4.3, the applicant states that if the component has a fatigue time-limited aging analysis (TLAA) that remains valid (i) or is projected to cover the period of extended operation (ii), then cracking due to fatigue is not an aging effect requiring management for those components during the period of extended operation.
Issue If cracks developed while the TLAA has concluded that the component is qualified for either 10 CFR 54.21(c)(1)(i) or 10 CFR 54.21(c)(1)(ii), then it is most likely because either the TLAA results have been questionable or the pre-operational inspection results and handling of the inspection results have been questionable. Cracking is a major safety issue for any components. Immediate remedial actions must be taken for cracks that are detected at any time.
Request The statement quoted under the Background above implies that cracking could be ignored as long as the stated conditions are met. Provide the basis to justify this statement and discuss how KPS would handle the situation.
RAI 4.3-2
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Background===
LRA Section 4.3.1.5 describes the environmental fatigue evaluation and the results are presented in LRA Table 4.3-2, including the Fen values determined for each component or location evaluated.
Issue LRA Table 4.3-2 shows three Fen values for all of the components evaluated: 2.455 for all of the locations that use low alloy steel (LAS); 15.35 for all of the locations that use stainless steel (SS) except for the RHR Tee at safety injection accumulator line location. It is known that the Fen value depends on material, strain rates, temperature and the dissolved oxygen (DO) concentration of the reactor water. Here, the SS is not in question because 15.35 is the bounding Fen for SS. Fen value of 2.455 for the LAS involves an assumption that DO is no greater than 0.05 ppm.
Request Summarize KPS' experience in control of DO level in the reactor water since the plant startup. Describe all water chemistry programs KPS has used, including procedures and requirements used for managing DO concentration as well as the inception date of each water chemistry program.
Provide a historic summary of the DO level since the plant startup. Estimate the fraction of time of the KPS operating history, thus far, that the DO level exceeded 0.05 ppm.
Describe how reactor water samples were taken, including the sampling locations. If samples were taken from a single location, justify that the DO data discussed in Part (b) above are applicable to all NUREG/CR-6260 components for the Fen calculations.
RAI 4.3-3
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Background===
LRA Section 4.3.2.1 discusses TLAA for Non-Class 1 piping and states that KPS performed a reevaluation for the reactor coolant hot leg sample line to account for the increased number of thermal expansion cycles.
Issue The information provided in the LRA is insufficient to enable one to perform an independent evaluation.
Request Describe the sampling practice, including number of times sampling activity takes place each day or each week. Estimate total number of thermal cycles projected for 60 years, including those due to the sampling operations and those due to other means.
Provide the maximum stress intensity range induced by those thermal cycles.
Specify the allowable stress range, and the stress range reduction factor used in the reevaluation described in LRA Section 4.3.2.1.
LRA TLAA Support Programs TLAA/AMP B3.1, Environmental Qualification (EQ) of Electrical Components RAI-B3.1-1
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Background===
LRA Section B3.1 and SRP Table 4.4.2 GALL Report AMP X.E1 state that reanalysis for aging evaluation is normally performed to extend the qualification by reducing excess conservatism incorporated in the prior evaluation. Important attributes of a reanalysis include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met).
Issue A staffs review of the LRA Section A3.3 (USAR supplement for B3.1) notes that it does not include reanalysis attributes consistent with the program description of LRA Section B3.1 and SRP Table 4.4.2 (10 CFR 54.21(c)(1)(iii)).
Request Please reconcile LRA Section B3.1 and the LRA Section A3.3 (USAR Supplement descriptions) with SRP LR Table 4.4.2.
RAI-B3.1-2
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Background===
GALL Report AMP X.E1, Parameters Monitored/Inspected, program element states in part that monitoring programs are an acceptable basis to modify a qualified life of electrical components through reanalysis.
Issue In support of AMP B3.1, Technical Report KLR-1301, Section 4.4, Program Element 3, Parameters Monitored/Inspected, Section 4.5 Program Element 4, Detection of Aging Effects, and Program Element 5, Monitoring and Trending specifically references ambient temperature monitoring as being used to modify EQ components qualified life. The AMP description is not clear whether temperature monitoring will be continued into the period of extended operation.
Request Explain how ambient temperature monitoring is or will be performed and controlled under the environmental qualification (EQ) program consistent with GALL Report AMP X.1E and continues to ensure that component qualified life remains bounded with respect to the EQ ambient temperature.