ML100110061

Response to Request for Additional Information for the Review of the License Renewal Application

ML100110061
Person / Time
Site:	Kewaunee
Issue date:	12/28/2009
From:	Price J Dominion Energy Kewaunee
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
09-760, FOIA/PA-2010-0209
Download: ML100110061 (44)

Text

Dominion Energy Kewaunee, Inc.

5000 Dominion Boulevard, Glen Allen, VA 23060 J Dominion December 28, 2009 United States Nuclear Regulatory Commission Serial No.: 09-760 Attention: Document Control Desk LR/MWH RO Washington, DC 20555-0001 Docket No.: 50-305 License No.: DPR-43 DOMINION ENERGY KEWAUNEE, INC.

KEWAUNEE POWER STATION RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE KEWAUNEE POWER STATION LICENSE RENEWAL APPLICATION By letter dated November 20, 2009 (Reference 1), the NRC requested additional information regarding the aging management review results included in the license renewal application (LRA) for Kewaunee Power Station (KPS) (Reference 2). The NRC staff indicated that a response to each request for additional information (RAI) is needed to complete the review of the KPS LRA. Attachment 1 to this letter provides the Dominion Energy Kewaunee, Inc. (DEK) responses to each of the RAIs submitted by the NRC staff in Reference 1. to this letter provides supplemental information related to the DEK response to RAI B2.1.21-1. The original DEK response was provided to NRC in a letter dated August 17, 2009 (Reference 3). This response is being supplemented as requested by the NRC staff during a telephone conference with DEK on November 19, 2009 (Reference 4).

In Reference 5, the NRC staff provided a correction to the numbering for two RAIs transmitted in Reference 1. The corrected numbering is reflected in Attachment 1.

AiB

Serial No.09-760 Docket -No. 50-305 Page 2 of 5 Should you have any questions regarding this submittal, please contact Mr. Paul C.

Aitken at (804) 273-2818.

Very truly yours, J.

Vie).resident - Nuclear Engineering STATE OF CONNECTICUT COUNTY OF NEW LONDON The foregoing document was acknowledged before me, in and for the County and State aforesaid, today by J. Alan Price, who is Vice President - Nuclear Engineering of Dominion Energy Kewaunee, Inc. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this 479 day of " ae*c'. 2009.

My Commission Expires:

Notary Public I22~~f4 DIANE MPHILUPO NOTARY PUBUC 3r*

MY COMMISION EXPIRES 1213112010

Serial No.09-760 Docket No. 50-305 Page 3 of 5

References:

1. Letter from Samuel Hernandez (NRC) to David A. Heacock (DEK), "Request for Additional Information for the Review of the Kewaunee Power Station License Renewal Application (TAC No. MD9408)," dated November 20, 2009. [ADAMS Accession No. ML091890836]

2. Letter from D. A. Christian (DEK) to NRC, "Kewaunee Power Station Application for Renewed Operating License,"dated August 12, 2008. [ADAMS Accession No.

ML082341020]

3. Letter from S. E. Scace (DEK) to NRC, "Response to Request for Additional Information for the Review of the Kewaunee Power Station License Renewal Application - Aging Management Programs," dated August 17, 2009. [ADAMS Accession No. ML092320093]

4. Notes of Teleconference from Samuel Hernandez (NRC) to Dominion Energy Kewaunee, Inc., "Summary of Telephone Conference Call Between Dominion Energy Kewaunee, Inc. and U.S. Nuclear Regulatory Commission to Discuss the (XI.E3) Electrical Aging Management Program (TAC No. MD9408)," dated November 27, 2009. [ADAMS Accession No. ML093240038]

5. Notes of Teleconference from Samuel Hernandez (NRC) to Dominion Energy Kewaunee, Inc., "Summary of Telephone Conference Call on December 14, 2009, Between Dominion Energy Kewaunee, Inc. and U. S. Nuclear Regulatory Commission to Discuss Tables Referenced in the Work Control Process Amendment Letter (TAC No. MD9408)," dated December 16, 2009. [ADAMS Accession No. ML093431339]

Attachments:

1. Response to Request for Additional Information Regarding the Kewaunee Power Station License Renewal Application

2. Supplemental Response to RAI B2.1.21-1

Serial No.09-760 Docket No. 50-305 Page 4 of 5 Commitments made in this letter:

1. The Structures Monitoring Program description in LRA Appendix A, USAR Supplement, Section A2.1.31, will be revised consistent with the response to RAI B2.1.31-1a. The revised program description is proposed to support approval of the renewed operating license, and may change during the NRC review period.

2. License Renewal Commitment 33 will be added to LRA Table A6.0-1, consistent with the response to RAI B2.1.31-4a. The new commitment is proposed to support approval of the renewed operating license, and may change during the NRC review period.

3. License Renewal Commitments 34, 35, and 36 will be added to LRA Table A6.0-1, consistent with the response to RAI B2.1.31-5a. The new commitments are proposed to support approval of the renewed operating license, and may change during the NRC review period.

4. The Non-EQ Inaccessible Medium-Voltage Cables program description in LRA Appendix A, USAR Supplement, Section A2.1.21, will be revised consistent with the supplemental response toRAI B2.1.21-1. The revised program description is proposed to support approval of the renewed operating license, and may change during the NRC review period.

Serial No.09-760 Docket No. 50-305 Page 5 of 5 cc: U.S. Nuclear Regulatory Commission Regional Administrator, Region III 2443 Warrenville Road Suite 210 Lisle, IL 60532-4532 Mr. P. S. Tam, Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint, Mail Stop 08-H4A 11555 Rockville Pike Rockville, MD 20852-2738 Ms. V. Perin Environmental Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-11 F1 Washington, DC 20555-0001 Mr. Q. S. Hernandez License Renewal Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-11F1 Washington, DC 20555-0001 NRC Senior Resident Inspector Kewaunee Power Station N490 Highway 42 Kewaunee, WI 54216 Public Service Commission of Wisconsin Electric Division P.O. Box 7854 Madison, WI 53707 David Hardtke Chairman - Town of Carlton E2334 Lakeshore Road Kewaunee, WI 54216

Serial No.09-760 Docket No. 50-305 ATTACHMENT 1 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING THE KEWAUNEE POWER STAION LICENSE RENEWAL APPLICATION KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 1 of 36 RAI B2.1.31-1a - Updated Safety Analysis Report (USAR) Supplement, Section A2.1.31 Background/Issue The applicant responded to RAI B2.1.31-1 in a letter dated August 17, 2009. The applicant'sresponse has covered only the Structures Monitoring Program. Descriptions for masonry wall and water-controlstructures are not included in the response.

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

DEK Response The following will be added to LRA Appendix A, USAR Supplement, Section A2.1.31, after the last sentence in the third paragraph:

For masonry walls within the scope of license renewal, the Structures Monitoring Program manages aging effects based on guidance provided in IE Bulletin 80-11, "Masonry Wall Design," and plant-specific monitoring proposed by NRC Information Notice 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to NRC IE Bulletin 80-11." For water-control structures within the scope of license renewal, the Structures Monitoring Program manages aging effects consistent with the guidelines of RG 1.127, "Inspection of Water Control Structures Associated with NuclearPower Plants."

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 2 of 36 RAI B2.1.31-2a - Implementation of Inspection of Water-Control Structures Background/Issue The applicant responded to RAI B2.1.31-2 in a letter dated August 17, 2009. The applicant's response did not address all the elements of AMP XI.S7, "RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants." The applicanthas added RG 1.127 for Element 4 only.

Request

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

" Describe how Element 10 of AMP XI-S7 will be implemented in Structures Monitoring DEK Response The Kewaunee water-control structures within the scope of license renewal include the Intake Structure, the Screenhouse, the Discharge Tunnel and Pipe, and the Discharge Structure. There are no earthen water-control structures within the scope of license renewal.

" The parameters monitored and inspected are (1) cracking, loss of bond, loss of material (spalling, scaling), cracks and distortion, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation for concrete, (2) loss of material for steel, and (3) loss of sealing for elastomers. The Structures Monitoring Program uses periodic visual inspections to monitor and inspect for these parameters.

" Implementation of Element 10, Operating Experience, is described in LRA Appendix B, Section B2.1.31 under the heading Operating Experience. The review of operating experience indicates that the Structures Monitoring Program is effective in identifying structural degradation, evaluating the degradation and implementing corrective actions for in-scope structures, including water-control structures. When degradation has been identified, corrective actions have been implemented to ensure that the intended functions of the affected structure or component support are maintained. Examples of plant-specific operating experience related to the Structures Monitoring Program, including applicable corrective actions, are provided in LRA Section B2.1.31, Operating Experience. An OE example is included in the LRA for the Screen House (a water-control structure) and Tunnel.

Serial No.09-760 Docket No. 50-305 Attachment l/Page 3 of 36 RAI B2.1.31-3a - Ground Water Quality Background/Issue:

In response to RAI B2.1.31-3, the applicant stated that the groundwatersamples taken in June 2007; March, July, August, and October 2008; and March and June 2009 indicate a chloride range from 34 ppm to 1240 ppm. The average chloride readings from the eight wells selected for monitoring for license renewal are varying from 120 ppm to 640 ppm. The applicanthas also stated that use of deicing salt is the most likely contributor to the elevated chloride concentration found in these wells. Use of salt, instead of sand as a deicer for the paved area began sometime between 1992 and 2000. Furthermore, the applicant has stated that 40 mil thick polyvinyl chloride waterproofing membrane was installed to the concrete surface which minimizes direct contact between the concrete structures and the groundwaterenvironment.

Request:

• Show the well locations with reference to the structures on the Plant General Arrangement Plan Drawing and indicate the maximum and average chloride content of the groundwater. This should indentify the safety-related structures that are located in the areaswhere the chloride content has been found to be >500 ppm.

• Demonstrate that the current level of chloride in the groundwateris not causing any degradationto the structures.

• Address the ability of water proofing membrane to resist ingress of water in the concrete.

DEK Response First Bulleted Item Figure 1 identifies the locations of the safety-related structures relative to the eight groundwater monitoring well locations. The maximum, minimum, and average chloride content of samples from these wells is as follows:

Maximum Minimum Average Well Identification Chloride Chloride Chloride Number of Number Content (ppm) Content (ppm) Content (ppm) Readings AB-707 456 111 263 9 AB-708 634 129 250 10 AB-709 213 35 107 9

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 4 of 36 Maximum Minimum Average Well Identification Chloride Chloride Chloride Number of Number Content (ppm) Content (ppm) Content (ppm) Readings AB-710 884 120 597 10 AB-711 758 419 554 10 AB-712 1071 34 336 10 AB-715 1240 302 628 10 AB-717 556 85 176 10 The three groundwater monitoring wells that have average chloride readings exceeding 500 ppm are located adjacent to the Auxiliary Building (AB-710 and AB-711) and the Shield Building (AB-715). Both the Auxiliary Building and Shield Building are safety-related structures. [Note that the average chloride readings have been updated since the response to RAI B.2.1.31-3 was submitted (DEK Letter 09-469 dated August 17, 2009 [ADAMS ML092320093]) to include additional third and fourth quarter, 2009 groundwater readings.]

Second Bulleted Item The current level of chlorides in the groundwater is not causing degradation of the structures based on the following:

1. Grade elevation in the area of the Administration, Auxiliary, Technical Support Center, Turbine, and Shield Buildings is approximately 605.5 ft. The groundwater table near these structures- is approximately elevation 588 ft. USAR Figure 1.2-8, General Arrangement Reactor and Auxiliary Building Cross-Section, shows building elevations below ground. This figure illustrates that only the foundation and a lower portion of the below-grade concrete walls for these structures are located below the groundwater table elevation. In addition, for Kewaunee there is a reduction in groundwater hydraulic head, which is the driving force for the groundwater to penetrate the below-grade concrete, of up to 17 ft. relative to plant-sites with the groundwater table near grade elevation.

2. The average chloride readings have exceeded the threshold value in only three of the eight groundwater monitoring wells. Furthermore, this exceedance is only marginally above the conservative 500 ppm threshold identified in NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," which is used as an indication of aggressive groundwater. Also, the below-grade concrete of the affected structures has not been continuously exposed to chlorides levels exceeding 500 ppm, based on varying groundwater sampling results.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 5 of 36

3. For all Class I (safety-related) structures except the Screenhouse (which is not in an area of elevated groundwater chloride content), a polyvinyl chloride sheet (waterproofing membrane) was put in place to act as a vapor barrier prior to the placement of the foundations and exterior walls below grade. This membrane was provided to prevent the infiltration of groundwater to the below-grade structural concrete. The waterproofing membrane extends up to an elevation of one foot below grade, which is twenty-two feet above high water lake levels. The waterproofing membrane minimizes direct contact between the below-grade concrete and the groundwater.

Plant-specific operating experience has shown that there has been no significant in-leakage of groundwater through the waterproofing membrane below the elevation of the groundwater table. Although minor, two indications of potential groundwater in-leakage were identified and are described below (see Third Bulleted Item). This operating experience is evidence that the waterproofing membrane is intact and still performing its function of minimizing the infiltration of groundwater.

Since the waterproofing membrane is being credited in this RAI response with the intended function of minimizing direct contact between the below-grade concrete and the groundwater, the LRA is supplemented to add the membrane to the scope of license renewal in accordance with 10 CFR 54.4(a)(2). An aging management review has been performed for the polyvinyl chloride sheet membrane, which is exposed to a soil environment. The membrane is sheltered from air, elevated temperatures, and ultraviolet and ionizing radiation in the buried installation. The aging management review concluded that there are no aging effects requiring management for the waterproofing membrane and there is no requirement for an aging management program.

4. The below-grade concrete is constructed to ACI standards- which affords dense, high-quality concrete with low permeability and adequate concrete cover of the reinforcing steel.

Therefore, based on the discussion above, aggressive chemical attack due to marginally elevated groundwater chloride content is not considered an aging mechanism of concern that can cause degradation of safety-related concrete structures.

As an additional measure, periodic monitoring of groundwater chloride levels is performed 'as described in LRA Appendix B, Section B2.1.31, Structures Monitoring Program, to verify that it remains non-conducive to below-grade concrete degradation.

The Structures Monitoring Program also includes the requirement to perform an inspection of the exposed portions of the below-grade concrete when excavated for any reason.

In addition, in order to reduce the amount of chlorides entering the groundwater, the use of sodium chloride-based de-icing products at the site has been discontinued to reduce the mechanism. The current de-icing product is a pelletized calcium chloride material

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 6 of 36 that can be applied at a consistently lower rate. Also, a significant amount of sand has been added to the pelletized calcium chloride application to enhance the de-icing effectiveness* and allow further reduction of salt application near safety-related structures. These actions are expected to reduce the groundwater chloride content in the vicinity of the safety-related structures.

Third Bulleted Item The ability of the waterproofing membrane to resist 'ingress of groundwater is demonstrated by approximately thirty-six years of Kewaunee operating experience indicating the absence of significant groundwater intrusion into areas below the groundwater table. Two minor in-leakage sites were identified in the operating experience review, both in the basement of the Auxiliary Building. One location is in a trench area in the Auxiliary Building basement floor and the other is through a crack in the north wall. The light moisture intrusion in the trench was identified in May of 2009 and was investigated and documented in the Corrective Action Program. An action to seal the leak was scheduled. The in-leakage associated with the crack in the north wall was identified in January of 2008, and was investigated by structural engineering. The crack was found to be tight with no active leak. The condition was documented in the Corrective Action Program and an action was'scheduled to seal the crack and recoat the wall. This operating experience is evidence that the waterproofing membrane is performing its intended function.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 7 of 36 Figure 1 Groundwater Monitoring Well Locations 1K

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Serial No.09-760 Docket No. 50-305 Attachment 1/Page 8 of 36 RAI B2.1.31-4a - Reactor Refueling Cavity Leakage Background/Issue:

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

Reguest:

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

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

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

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

• Plans for permanentremediation of reactorcavity/refueling pool leakage.

DEK Response First Bulleted Item There are three sites within the reactor containment that have been identified as potential indications of leakage from the reactor refueling cavity. These leakage indication sites are identified in Figures 2 and 3, and described below:

0 Leakage Indication Site #1

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 9 of 36 Leakage indication site #1 was identified in April of 2003. As described in LRA Appendix B, Section B2.1.31, Operating Experience, and in the response to RAI B.2.1.31-4 (DEK letter 09-469 dated August 17, 2009 [ADAMS ML092320093]), a crack was identified on the outer surface of the biological shield reinforced concrete wall with indications of dried boric acid residue present. The reactor refueling cavity was filled at the time of this discovery. The boric acid residue was removed from the wall. The wall cracking was evaluated and determined to be a passive condition and acceptable as-is.

The site was re-inspected in October of 2004, during the next refueling outage, with the reactor refueling cavity filled. There was no indication of leakage at that time.

Based on this follow-up inspection, the final evaluation of this leakage indication site determined that the dried boric acid residue identified in April of 2003 was likely due to a small amount of borated water from a leakage source not associated with the reactor refueling cavity pool that flowed down the surface of the wall to the crack on the wall surface, where it dried and formed boric acid residue.

This leakage indication site was inspected in 2006, 2008, and 2009 during refueling outages with the reactor refueling cavity filled, and there has been no change in the cracking condition and no further indications of leakage.

Leakage Indication Site #2 Leakage indication site #2 was identified in October of 2006. Indications of leakage were identified at a construction joint in a wall adjacent to the reactor refueling cavity in the 'A' RCS Vault. The indication consisted of residue streaking and staining on the wall surface below the location of the construction joint, with a small amount of moisture present. There was no observed water flow from the construction joint and no accumulation of dried boric acid crystals. Quantification of leakage volume was not possible due to the minor nature of the observed leakage indications.

This leakage indication site was inspected during the next refueling outage in April of 2008, and indications of leakage were again identified at the 'A' RCS Vault wall construction joint. The indications consisted of wetting / moisture at the joint location. There was minimal accumulation of residue and some amount of wall staining / streaking was noted.

This leakage indication site was inspected again during the refueling outage in 2009, and leakage indications were identified. Multiple inspections were performed during the outage and included an initial 'as-found' inspection, a follow-up inspection prior to filling the reactor refueling cavity pool, inspections after filling the pool, and a final inspection at the end of the outage. Residue was removed from the leakage indication site after the 'as-found' inspection, and no further indications were noted until the final inspection, which was performed 17 days after filling the reactor refueling cavity. Based on this long delay for leakage indications to reappear on the

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 10 of 36 wall surface, potential reactor refueling cavity leakage is considered to be very small.

As a result of the leakage indications at this location, structure monitoring requirements were modified to include inspection of this leakage indication site during each refueling in order to document and trend the observed conditions and assess the integrity of the concrete structure.

Leakage Indication Site #3 Leakage indication site #3 was identified in March of 2008. Indications of leakage were identified on the surface of the biological shield wall in an area located below the reactor refueling cavity. The leakage indications were identified at the junction between the reinforced concrete biological shield wall and the base of the reactor refueling cavity. The indication consisted of residue accumulation, streaking, and staining on the wall surface below the location of the junction, with a small amount of moisture present. There was no observed water flow from the junction.

Quantification of leakage volume was not possible due to the minor nature of the observed leakage indications.

This leakage indication site was inspected again during the refueling outage in 2009, and leakage indications were identified. Multiple inspections were performed during the outage including an initial 'as-found' inspection, a follow-up inspection prior to filling the reactor refueling cavity pool, inspections after filling the pool, and a final inspection at the end of the outage. Residue was removed from the leakage indication site after the 'as-found', inspection, and no further indications were noted until the final inspection, which was performed 17 days after filling the reactor refueling cavity pool. Based on this long delay for leakage indications to reappear on the wall surface, potential reactor refueling cavity pool leakage associated with this leakage indication site is also considered to be very small. As a result of the leakage indications at this location, structure monitoring requirements were modified to also include inspection of this leakage indication site during each refueling in order to document and trend the observed conditions and assess the integrity of the concrete structure.

Additional inspections were performed during the refueling outage in 2009 to identify any additional indications of potential reactor refueling cavity pool leakage and to verify that there was no potential for moisture contact with the reactor containment vessel.

Areas inspected included reinforced concrete surfaces within the containment basement elevation. In addition, the containment sump 'B' (the sump nearest the containment vessel) was inspected for signs of in-leakage through the concrete walls of the sump.

There were no leakage indications identified during these inspections that would indicate the potential for moisture in contact with the reactor containment vessel. Also, no additional leakage indication sites were identified that could have resulted from reactor refueling cavity pool leakage.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 11 of 36 Second Bulleted Item As described above, the leakage indication observed at leakage indication site #1 in 2003 was determined to be likely due to a small amount of borated water from a leakage source external to the reactor refueling cavity pool that flowed down the surface of the wall to the crack on the wall surface, where it dried and formed boric acid residue.

Leakage indications observed at sites #2 and #3 have been determined to potentially originate from reactor refueling cavity pool liner leakage. Inspections for leakage indications were performed during the refueling outage in 2009, as described above, in order to aid in determining the source and extent of potential leakage from the reactor refueling cavity pool. The results of these inspections will be evaluated as an input to the determination of necessary corrective actions related to potential reactor refueling cavity pool liner leakage.

The following commitment will be added to LRA Appendix A, USAR Supplement, Table A6.0-1:

Item Commitment Source Schedule 33 Develop a plan for identification and Letter 09-760 Prior to the remediation of reactor refueling cavity Response to Period of liner leakage to be implemented during RAI B2.1.3-4a Extended the period of extended operation. Operation Third Bulleted Item As discussed above, the crack identified in the reinforced concrete wall at leakage indication site #1 was evaluated and determined to be a passive condition and acceptable as-is. Additionally, the indications of leakage noted in 2003 were determined likely to be from a leakage source external to the reactor refueling cavity pool that flowed down the surface of the wall such that the concrete and reinforcing steel within the wall are not affected. The results of follow-up inspections performed during the subsequent four refueling outages support this determination. Therefore, structural integrity has been confirmed for the concrete crack at leakage indication site

1. 1.

Leakage indications observed at sites #2 and #3 have been determined to potentially originate from reactor refueling cavity pool liner leakage. The" indications observed at these sites are located at construction joints in the wall and are the result of very small leakage rates, based on the limited moisture and staining / streaking. Additionally, once removed, indications do not re-emerge for a considerable length of time (seventeen

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 12 of 36 days observed during the most recent inspection). Additional inspections within containment have found no other indications of reactor refueling cavity pool leakage and have confirmed absence of a potential for leakage water contact with the reactor containment vessel shell. In addition, based on the results of other nuclear power plant evaluations, the effect of borated water on reinforced concrete structural integrity is considered minimal. As a result, the potential for leakage from the reactor refueling cavity pool to cause significant structural degradation to reinforced concrete or the metal reactor containment vessel is considered to be negligible.

In order to confirm this conclusion, as detailed in response to RAI B2.1.31-5a, a reinforced concrete structural integrity examination will be performed for the concrete slab located below the spent fuel pool in the Auxiliary Building. The results of the examination will provide a representative indication of the condition of the reinforced concrete associated with leakage indication sites #2 and #3, since the concrete and reinforcement, for both locations met the same material specifications and requirements for testing and placement. The environment for potential degradation is the same since the reactor refueling cavity pool and spent fuel pool are in direct communication during refueling outage periods (when the reactor refueling cavity is filled).

Fourth Bulleted Item The results of containment inspections performed during the refueling outage in 2009 will be evaluated in order to determine the source and extent of potential reactor refueling cavity pool leakage. As described in new License Renewal Commitment #33 above, an action plan is being developed to pursue additional methods for identification and remediation of reactor refueling cavity pool liner leakage. Potential methods include weld examinations, and identification and re-sealing of potential leakage sites at liner penetrations.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 13 of 36 Leakage Indication Site #3 Leakage Indication Site #1 Leakage Indication Site #2 Figure 3, Plan View (A-206)

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 14 of 36 RAI B2.1.31-5a - White Substance on Wall and Ceiling of the Waste Drumming Room Background/Issue:

In response to RAI 8.2.1.31-5, the applicant has stated that on December 28, 2007, the white substance was observed on the wall and ceiling of the waste drumming room, below the spent -fuel pool. The area was cleaned and inspected. The applicant concluded that structural integrity of the concrete was not adversely affected and structure was sound on the basis that the concrete did not display visible spalling (which would indicate that the reinforcing is corroding and causing pop outs of the concrete),

deformed surfaces (which would indicate that the reinforcement is in distress), or widening of cracks. Additionally, the applicant stated that the rebar in reinforced concrete is normally protected against corrosion by the alkalinity of the concrete, which is typically in the range of pH 12.5 or more.

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

Request:

• Verify the condition of the concrete and rebar at the crack locations by appropriate nondestructive examination.

" Leakage of boric acid water could change the pH and could be potential cause for the corrosion of the rebar. Staff requests the applicant to clarify the basis for assuming the reinforcing bars will remain protected by concrete even when they.

come in contact with boric acid water for a sustainedperiod.

• Describe the plan for permanent remediation.

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

DEK Response Radioactive contamination of groundwater can occur due to undetected leakage from facility structures, systems, or components that contain or transport radioactive fluids.

In 2007, Kewaunee initiated a groundwater monitoring and sampling program at fourteen outdoor monitoring wells on the plant property. Seven of the wells are near the Auxiliary Building/Spent Fuel Pool (SFP). The groundwater samples are analyzed for gross gamma, tritium, pH, conductivity, fluoride, chloride, and sulfate. To date, no detectable levels of tritium have been recorded 'outside of the Auxiliary Building or in the groundwater.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 15 of 36 Inspections to date indicate that all of the minor leakage from the SFP has been contained within the Auxiliary Building structure or the radioactive waste disposal system. The SFP is actually at an intermediate elevation in the Auxiliary Building. The SFP base is approximately 7 feet thick and fifteen feet above the Auxiliary Building basement floor, facilitating capture and confinement of any potential structural leakage (see Figure 4).

First and Second Bulleted Item As stated in the response to RAI B2.1.31-5 (DEK letter 09-469, dated August 17, 2009

[ADAMS ML092320093]), SFP leakage observed on the ceiling of the waste drumming room has been in the form of white boric acid residue at two specific crack locations (see Figure 1). The leakage sites have indicated minimal leakage, as evidenced by no actual dripping or droplet formation. The leak locations are monitored and trended monthly by visual inspections and photographic documentation. Boric acid residue formation has remained constant since first being observed in December of 2007.

The impact of the presence of an aqueous solution of boric acid on reinforced concrete at the concentrations found at pressurized water reactors has been previously studied and assessed. In 2002, spent fuel pool liner leakage in the Fuel Handling Building at Salem was reported and investigated, including the aging effects on reinforced concrete. Liner leakage of the reactor cavity and SFP was also addressed in the Indian Point License Renewal Safety Evaluation Report (NUREG-1930, "Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3," November 2009). The most recent example of aging effect studies, tests, and investigations have occurred at Prairie Island ("Safety Evaluation Report Related to the License Renewal of Prairie Island Nuclear Generating Plant, Units 1 and 2," October 2009 [ADAMS ML092890209]).

Based on the investigative work to date, reinforced concrete exposed to boric acid does not experience significant degradation. The effects of boric acid on concrete start at the wetted surface and proceed inward. These effects occur at a pace so as not to affect the ability of the structural member to perform its intended function during the period of extended operation. The embedded steel rebar is protected from corrosion by the high alkalinity (pH) of the concrete. Industry data indicate that, even in the presence of borated water, the conditions at the rebar remain sufficiently alkaline to passivate the surface resulting in negligible corrosion.

In order to confirm that potential SFP liner leakage is not causing significant degradation of SFP reinforced concrete, a concrete core sample will be obtained and a strength test and petrographic examination will be performed. Specifically, at least one concrete core sample will be taken from the waste drumming room reinforced concrete ceiling below the spent fuel pool prior to the period of extended operation. The location of the core sample will be as close to the site of the greatest apparent leak as possible. Core depth will be sufficient to validate the strength of the concrete and the extent of any

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 16 of 36 degradation. The core sample will be tested for compressive' strength and will be subject to petrographic examination. In addition, reinforcing steel in the core sample area will be exposed and inspected for materiel condition. Inspection and test results will be entered into the Corrective Action Program and evaluated for impact on SFP structural integrity. The Corrective Action program will also facilitate the identification and disposition of any additional actions that may be warranted.

The following commitment will be added to LRA Appendix A, USAR Supplement, Table A6.0-1:

Item Commitment Source Schedule 34 At least one core bore sample will be Letter 09-760 Prior to the taken from the waste drumming room Response to Period of reinforced concrete ceiling below the RAI B2.1.31-5a Extended spent fuel pool. The core sample Operation location and depth will be sufficient to validate the strength of the concrete and the extent of any degradation. The core sample will be tested for compressive strength and will be subject to petrographic examination. Reinforcing steel in the core sample area will be exposed and inspected for material condition.

Third Bulleted Item An action plan will be developed based on observed leakage and in consideration of available techniques to inspect for leaks, including leak testing of the accessible SFP liner pressure boundary weld seams. The presence of spent fuel in the storage pools makes inspection of a large percentage of the storage pool liners impractical due to access restrictions.

The following commitment will be added to LRA Appendix A, USAR Supplement, Table A6.0-1:

Item Commitment Source Schedule 35 Develop an action plan for identification Letter 09-760 Prior to the and remediation of spent fuel pool liner. Response to Period of leakage to be implemented during the RAI B2.1.31-5a Extended period of extended operation. Operation If repair efforts to eliminate the SFP leakage in the waste 'drumming room are not successful, an additional concrete core sample will be taken prior to the end of the first

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 17 of 36 ten years of extended operation and will be subjected to the same tests and examinations as described above. Reinforcing steel in the core sample area will also be exposed and inspected for material condition. Inspection and test results will be entered into the Corrective Action Program and evaluated for impact on SFP structural integrity and the identification of additional actions that may be warranted.

The following commitment will be added to LRA Appendix A, USAR Supplement, Table A6.0-1:

Item Commitment Source Schedule 36 If SFP liner leakage persists during the Letter 09-760 Prior to the period of extended operation, an Response to end of the~first additional concrete core sample will be RAI B2.1.31-5a ten years of taken from the waste drumming room extended reinforced concrete ceiling below the operation spent fuel pool. The core sample location and depth will be sufficient to validate the strength of the concrete and the extent of any degradation. The core sample will be tested for compressive strength and will be subject to petrographic examination. Reinforcing steel in the core sample area will be exposed and inspected for material condition.

Fourth Bulleted Item The KPS SFP is divided into three storage compartments and a fuel transfer canal. The three storage compartments include a large south pool, a smaller north pool, and a canal pool. The south pool connects to the fuel transfer canal by means of a SFP gate.

In addition, the three spent fuel pools are connected with one another via SFP gates.

The SFPs and fuel transfer canal liners are divided into 10 leak detection zones, five for the pools and five for the transfer canal. Each zone is piped to a telltale, terminating at a collection box, that receives any leakage from the seam leak detection channels for.

that zone. Presently there are three zones, Zones 1, 4 and 5, indicating leakage of approximately 6, 3 and 9 ounces per day respectively. This equates to a total leakage of slightly more than one gallon per week.

The SFP water level is monitored and recorded each shift by the plant Auxiliary Operator during rounds. The operating crew reviews all logs for any abnormal readings or trends. A SFP high/low level alarm is provided in the control room. The SFP level is maintained between the high and low level alarm setpoints in accordance with the normal operating procedure.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 18 of 36 Figure 4 SFP Leakage Indication - Auxiliary Building Elevation f ,- ~ ~i

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 19 of 36 RAI 3.6.2.2.3-1

Background

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

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

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

DEK Response Switchyard bus terminations were evaluated as part of the aging management review for cables and connections component types and the results of the evaluation are provided in LRA Table 3.6.2-1 for the commodity group/component type "Transmission Conductors and Connections." The aging management review concluded that there are no aging effects requiring management for the switchyard bus terminations and no aging management program is required. The basis for this conclusion, as described in LRA Section 3.6.2.2.3, is that; 1) oxidation and loss of pre-load for these connections are minimized through the use of compatible aluminum bolting hardware; 2) lock washers are used in bolted connections, and; 3) no-oxide compounds are used at connection surfaces in all termination types, such that increased resistance of aluminum conductor connections due to oxidation or loss of pre-load is not a credible aging mechanism.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 20 of 36 RAI 3.6.2.2.3-2

Background

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

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

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

DEK Response Stainless steel Belleville washers are installed in switchyard bus aluminum conductor connections. Therefore, embrittlement and stress cracking due to the use of plated washers is not applicable.

Thermography of switchyard bolted connections is performed at least annually to identify any increased resistance condition in switchyard bus connections. Additionally, after any switchyard maintenance that could create a high resistance condition, all re-worked connections have micro-ohm resistance measurements taken to ensure that no high resistance conditions have been created during the maintenance activities.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 21 of 36 RAI 3.6.2.1.2-1

Background

GALL Report, Vol. 2, Rev. 1, Item VI.A-8, ,"Fuse Holders (Not Part of a Larger Assembly; Metallic Clamp," identifies the aging/effect mechanism as fatigue,/ohmic heating, thermal cycling, electrical transients,frequent manipulation, vibration, chemical contamination, corrosion and oxidation. The associated AMP XI.E5, "Fuse Holders,"

states that fuse holders within the scope of license renewal should be tested to provide an indication of the condition of the metallic clamps of fuse holders. In LRA, Section 3.6.2.1.2, "Fuse Holders," the applicant states that there are no aging management programs required for fuse holders based on a review of the environment of the fuse holders. Table 3.6.1, Item 3.6.1-06 of the LRA concludes that only fuse holders located in two enclosed cabinets in the Relay Room ,required evaluation and concludes that these fuse holders are in a controlled environment, and are not subject to the aging effect/mechanisms as identified in Item VI.A-8 of GALL Report, Vol. 2, Rev. 1.

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

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

DEK Response As noted in the RAI above, the fuse holders subject to aging management, review are those located in enclosed cabinets in the Relay Room. As further noted above, the Relay Room is in a temperature and humidity controlled environment. The following provides a basis for the conclusion that the fuse holders are not subject to the aging effects/mechanisms identified in NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," Item VI.A-8.

Fatigue NUREG-1760, "Aging Assessment of Safety-Related Fuses Used in Low- and Medium-Voltage Applications in Nuclear Power Plants," states that fatigue of fuse holders can typically occur due to elevated temperature, mechanical stress, and repeated insertion and removal of fuses. NUREG-1760 further states that fuse failures resulting from thermal cycling are associated with the fuse element,- and not the fuse holder. The fuse

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 22 of 36 holders subject to aging management review are located indoors and in a controlled air environment. There are no significant sources of heat in close proximity to the fuse holders such that elevated temperatures are not expected. Therefore, fatigue due to elevated temperature is not an applicable aging effect. Fatigue related to mechanical.

stress and/or repeated insertion and removal is evaluated under Mechanical Stress below.

Mechanical Stress The fuse holders subject to aging management review are located in enclosed cabinets and the fuses are not routinely removed and reinserted into the metallic clamps. The fuses are only removed during fuse replacement with circuit isolation performed by other devices in the circuit. Therefore, the fuse holder metallic clamps are not subject to repeated manipulation, which could lead to mechanical fatigue. Mechanical stress resulting from electrical faults and transients is not considered a credible aging

,mechanism since electrical faults are infrequent and random in nature. Stresses resulting from electrical faults and transients are mitigated by fast acting circuit protective devices. Therefore, no aging management is required for mechanical stress.

Vibration These fuse panels are wall mounted, not mounted on rotating equipment, and are not in close proximity to rotating equipment such that they could be affected by vibration.

Therefore, vibration is not an applicable aging mechanism for the fuse holders in these panels.

Chemical Contamination/ Corrosion These fuse holders are located in enclosed cabinets that are located indoors in a controlled air environment and not subject to exposure to fluid system leakage. The fuse holders are not subject to moisture or chemicals inside the panel enclosures and do not experience a corrosive environment. Therefore, chemical contamination and corrosion do not require management for the fuse holders.

Ohmic Heating/Thermal Cycling These fuses are used in a low voltage/low current application such that there is no significant ohmic heating. The power is continuous such that thermal cycling does not occur. Therefore, ohmic heating/thermal cycling is not an applicable aging mechanism for these fuse holders.

Oxidation The Relay Room is a controlled air environment. The room is served by the Control Room Air Conditioning System. The environment is maintained at approximately 80°F and 35% RH. Oxidation in this environment is not considered an applicable aging mechanism.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 23 of 36 In addition, a 'review of industry and plant-specific operating experience has indicated no aging concerns for copper alloy fuse holders in similar environments. Therefore, no aging management is required for these fuse holders.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 24 of 36 RAI 3.6.2.3-1

Background

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

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

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

DEK Response As indicated in LRA Table 3.6.2-1, for Commodity Group/Component Type "Fuse Holders insulation," Note 1 states that the fuse holders are not located in an adverse localized environment. The fuse holders subject to aging management review are located in enclosed cabinets in the Relay Room, which has a temperature and humidity controlled environment. Since the fuse holders are not located in an adverse localized environment, the aging effects identified in NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," Item VI.A-6 for fuse holder insulation materials are not applicable.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 25 of 36 RAI B2.1.5 Bolting Integrity Program

Background

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

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

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

DEK Response Material Vascomax 300 (CVM) maraging steel was used as the high strength bolt material to provide the connection between the top of the reactor coolant pump support columns and the support brackets. The architect-engineer for Kewaunee, Pioneer Service &

Engineering Company, recognized the potential for stress corrosion cracking of Vascomax 300 (CVM) when selecting the material for use and specified heat treatment that would promote good resistance to stress-corrosion cracking (SCC) and protective surface treatments intended to reduce the potentially harmful effects of hydrogen. A specification was developed for the protective coating procedure and subsequent handling of this Vascomax material. The procedure called for baking and coating the metal surfaces to drive out the hydrogen and protect the surface after manufacture and during its operation life.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 26 of 36 Manufacturing Process (from heat treating to machining)

Welding and Steel Fabrication Company, Inc. (W&SFC, Inc.) was the vendor that provided the Vascomax 300 high strength bolts. The steel used for fabricating the bolts was purchased from Vanadium Alloys Steel Company (VASC). VASC was required to provide test pieces that were aged at 900°F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> (the standard aging treatment for this particular class of maraging steel) and to provide the following for each heat of steel:

1. Tensile Test

2. Charpy Test

3. Each bar produced to be ultra-sonic tested longitudinally and by angle beam method.

4. Certified mill test reports Review of the testing results shows that none of the ultimate tensile strengths exceeded 295 ksi and none of the yield strengths were higher than 290 ksi. It is known that the propensity for SCC of this material is related to higher strengths, especially above 300ksi; therefore, these results suggest a reduced susceptibility. Also, the Charpy impact testing yielded acceptable results with average values in the range of 13.6 ft-lb to 18.3 ft-lb.

Once W&SFC, Inc. received the material and completed machining the steel rods and nuts, the parts were placed in a furnace and heated to 900°F over a 2-hour period, held at 900 OF for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, removed from the furnace, and air cooled. It should be noted that this aging treatment, that leads to precipitation of the fine inter-metallic compounds (mainly Ni3Mo and Ni3 Ti), would also relieve stress associated with prior forming and machining operations. Time-temperature charts were required on 900'F heat treating.

Magnetic particle testing was performed after 900°F heat treating. After heat treating and testing, parts were cleaned using Bronoco HS 2331 solvent (compound of acetone, naptha, and toluene).

All stock material for the bolts was ultrasonically tested in the axial direction before machine threading occurred. After manufacturing and inspection was completed, all bolts and nuts were stress equalized for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by baking in a pure nitrogen atmosphere at a temperature of 350°F to 375°F. This treatment also assured the material was free of elemental hydrogen which might lead to embrittlement.

Immediately after removal from the baking oven, the first bonded coating was applied at 180 0 F, and then the bolting returned to the baking oven for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 210'F. Two solid lubricants were then applied; the first after removal from the oven, and the second at room temperature. The items were then placed in sealed protective wrappings for shipping. Following erection, all surfaces subjected to possible openings in the coating, were covered again to inhibit re-contamination.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 27 of 36 The above describes the care taken during the fabrication, delivery, and installation process for the Vascomax 300 (CVM) high strength steel bolting material including:

• Specified heat treatment after machining the rods and nuts that, in addition to strengthening the material, lead to the reduction of residual stresses.

" Stress equalizing and nitrogen baking of all bolts and nuts after manufacturing and inspection.

• Application and baking of a first bonded coating.

• Application of the two solid lubricants, one after removal from the oven and the second at room temperature.

" Sealed protective wrapping for shipping.

" Reapplication of coating to all surfaces subjected to possible openings following erection.

Therefore, the potential for residual stress crack initiation has been adequately addressed such that a visual inspection is adequate for management of SCC for these high-strength bolts.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 28 of 36 RAI 3.1.2.2.2.4-2

Background:

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

Issue:

In LRA Table 3.1.2-4, the applicantaddresses the aging effect of loss of materiel due to general, pitting and crevice corrosion by the ASME Section X1 In-service inspection, subsections IWB, IWC, and IWD for the upper, lower and transition cone shells. From the LRA, the new transitionweld from the steam generatorreplacement would have the same conditions as the original upper shell-to-transitioncone girth weld, and therefore, would be susceptible to the same aging effects (even if the shell geometry is less severe for the new weld). From Drawing LRXK-100-10, the new transition weld appears to be located in a "gross structural discontinuity" because the transition cone is by definition a junction between shells of different diameters (as defined is ASME NB-3213.2).

Request:

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

DEK Response The new weld, generated by the cut made in the transition cone at the time of steam generator replacement, received a radiography examination in accordance with the requirements of ASME Code,Section III. There were no unacceptable indications (i.e.,

no indications exceeded the acceptance criteria of ASME Code,Section III).

The new transition cone closure weld is not a gross structural discontinuity in accordance with the definition in ASME Code,Section III, NB-3213.2 (ASME Code, Section Xl, Table IWC-2500-1 and Figure IWC-2500-1 provide applicable examples of gross structural discontinuities) and the closure weld is located a sufficient distance from the structural discontinuity at the transition cone-to-upper shell junction such that resultihg stresses do not affect the weld area (i.e., the closure weld is not in a high-stress region). Thus, the new transition cone weld does not require volumetric examination in accordance with ASME Code, Section Xl Inservice Inspection requirements. However, the new transition cone closure weld receives a VT-2 visual examination as part of the system pressure test in accordance with IWC 2500-1, Category C-H.

f Serial No.09-760 Docket No. 50-305 Attachment 1/Page 29 of 36 The concerns identified in NRC Information Notice 90-04, "Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam Generators," which are further clarified by NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," as being limited to Westinghouse Model 44 and 51 steam generators where a high stress region exists at the shell to transition cone weld, are not a'plicable to the new transition cone closure weld based on:

" The new transition cone closure weld is not located at a structural discontinuity since it is a plate-to-plate weld configuration with 0.02" maximum plate thickness difference, I

• The weld is located away from the locally stressed area associated with the original existing upper shell-to-transition cone weld, and

• The weld is not in a high-stress region.

Therefore, consistent with ASME Code, Section Xl requirements, and since the issues identified in IN 90-04 are not applicable, no inspections other than a system pressure test leakage examination are required for the new transition cone closure weld during the period of extended operation.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 30 of 36 RAI B2.1.30-16

Background

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

The staff reviewed LRA Table 3.1.2-4 against the criteria of SRP-LR Table 3.1.1.

Instead of the two aging effects described in SRP-LR and LRA Tables 3.1.1-72 and 3.1.1-74 (e.g. cracking due to stress corrosion cracking and loss of material due to fretting and wear/crevice corrosion and fretting), the applicant identified the aging effects of cracking and proposed another type of loss of material, due to pitting and crevice corrosion for these seven components. Although the GALL report does not have a correspondingAMR for these seven steam generator components, the staff finds the applicant'sidentification of aging effects acceptable according to the selection criteria of the applicant. However, the applicantstated it would manage the aging effect of loss of material due to pitting and crevice corrosion using the Secondary Water Chemistry program described by the AMP for SRP-LR and LRA item 3.4.1-37 without providing any explanation orjustification for the adequacy of this program.

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

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

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 31 of 36 Request

• Explain why your choice of AMP for the seven steam generator components listed above is appropriatewhen the environment associatedwith LRA item 3.4.1-37 (e.g.,

dry steam) and that to which these components are exposed (e.g., treated water and/or steam-secondary)are different, and this AMP does not provide for any other actions (e.g., in-service inspections)to confirm its effectiveness.

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

DEK Response The dry steam environment is combined with the treated water and/or steam-secondary environment for the purposes of aging management reviews because the potential aging effects are the same. Loss of material due to pitting and crevice corrosion for the nickel-based alloy feedwater inlet ring J nozzles, feedwater nozzle (and nickel alloy cladding), feedwater nozzle thermal sleeve, steam nozzle flow restrictor, tube bundle support hardware, tube plugs, and tube and sleeves is adequately managed by the Secondary Water Chemistry program. The Secondary Water Chemistry program includes specifications for chemical species, sampling and analysis frequencies, and corrective actions for control of the environment to which surfaces of components are exposed. Additionally, the program maintains water quality (pH and conductivity) in accordance with industry chemistry control guidelines as described in LRA Appendix B, Section B2.1.28.

However, in response to NRC staff concerns, the Steam Generator Tube Integrity program will be conservatively credited as an additional aging management program for components listed above, with the exception of the steam nozzle flow restrictor, to provide verification that loss of material due to pitting and crevice corrosion is not occurring. For the steam nozzle flow restrictor, the Secondary Water Chemistry program alone is adequate to manage loss of material due to pitting and crevice corrosion since this component is exposed to a dry steam environment, which is a less corrosive environment than treated water and does not require further augmentation consistent with NUREG-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," Item SP-18.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 32 of 36 Including the Steam Generator Tube Integrity program to manage aging for the specified components results in the addition of the following paragraphs to LRA Table 3.4.1, Line Item 3.4.1-37, Discussion:

"Consistent with NUREG-1 801.

For the steam generator steam nozzle flow restrictor, loss of material due to pitting and crevice corrosion is managed by the Secondary Water Chemistry program.

For the steam generator feedwater inlet ring J nozzles, feedwater nozzle (and nickel alloy cladding), feedwater nozzle thermal sleeve, tube bundle support hardware, tube plugs, and tube and sleeves, loss of material due to pitting and crevice corrosion is managed by the Secondary Water Chemistry program and the Steam Generator Tube Integrity program since the environment is secondary treated water and not steam."

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 33 of 36 RAI B.2.1.9-6

Background

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

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

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

Request 1, Clarify whether the applicant's program with the program enhancement has acceptance criteria for the load time of the station and instrument air system compressors.

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

DEK Response Establishment of specific acceptance criteria for load and unload time is not practical for the Station and Instrument Air System compressors, since the load/unload times vary based on the varying system air demands.

As stated in the response to RAI B.2.1.9-5, the unload times, for the in-service compressors in the Station and Instrument Air System are monitored each shift in

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 34 of 36 accordance with approved procedures. Additionally, the System Engineer performs monitoring and trending of the system in accordance with the established system monitoring, plan. As part of the system monitoring plan, the System Engineer records the load and unload times during compressor walkdowns performed at least once a month. The System Engineer uses the load and unload times, in conjunction with other system parameters, to monitor the system performance and to evaluate long term issues.

Therefore, although compressor load and unload time acceptance criteria are not practical to establish, system performance monitoring and trending through the System Engineering system monitoring plan, as part of the Compressed Air Monitoring program, adequately manages aging effects such that the Station and Instrument Air System intended functions are maintained.

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 35 of 36 RAI B.2.1.9-7

Background

As addressed in RAI B.2.1.9-4 sent by letter dated June 13, 2009, LRA Section B.2.1.9 described the exception of the applicant's CompressedAir Monitoring Programthat leak testing is not performed for the station and instrument air system distribution network. In comparison, as an enhancement of the program, the applicant committed to incorporate the compressed air system testing and maintenance recommendations from ASME OM-S/G-1998, Part 17 and EPRI TR-108147 and to identify these documents as part of the program basis. However, the staff noted that ASME OM-S/G-1998 and EPRI TR-108147 address the conduct of leak tests as described in Sections 5.3.1(b) and 5.3.2 of the ASME document and Section 8.9.2 of the EPRI report. Therefore, the staff issued RAI B.2.1.9-4 to resolve the potential conflict between the exception and the enhancement that the applicantclaimed regardingleak testing.

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

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

Issue The applicant stated ASME OM-S/G-1998, Part 17 advocates leak testing as part of a troubleshootingprocess. However, the staff noted that Section 5.3. 1(b)(1) and Table I in ASME OM-S/G-1998, Part 17 require that special service air accumulators and the associated check valves should be leak tested using pressure decay test of paragraph 5.2.3(b) every refueling outage, which is consistent with the recommendation of GALL AMP X1. M24 that frequent leak testing be performed for valves, piping and other system components.

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

Serial No.09-760 Docket No. 50-305 Attachment 1/Page 36 of 36 and identify adverse trends or the system and component degradation due to aging effects.

Request

1. Clarify whether the applicant's program with the program enhancement includes the leak tests for special service air accumulators and associated check valves as described in Section 5.3. 1(b)(1) and Table I in ASME OM-S/G-1998, Part 17.

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

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

DEK Response The safety-related special service air accumulators and associated check valves are leak tested each refueling outage consistent with the requirements of ASME OM-S/G-1998, Part 17, to meet design basis requirements. However, this testing is not included in or credited by the Compressed Air Monitoring program, since the testing is not required in order to adequately manage the effects of aging for the Service and Instrument Air System components within the scope of license renewal.

The aging management review for the special service air accumulators and associated check valves, as indicated in LRA Table 3.3.2-8, "Auxiliary Systems - Station and Instrument Air - Aging Management Evaluation," for the Component Types "Accumulators" and "Valves" with an internal environment of "Air-Dried," concludes that there are no aging effects requiring management for these components due to exposure to the dried compressed air environment. These aging management review results are consistent with NUREG-1801, "Generic Aging Lessons Learned (GALL) Report,"

Section VII, Items VII.J-3, VII.J-18, and VII.J-22, which indicate that piping, piping components, and piping elements, fabricated from copper alloys, stainless steel, or steel materials, are not subject to aging effects in a dried air environment. Therefore, there are no aging effects applicable to the special service air accumulators and associated check valves that require management by the Compressed Air Monitoring program.

Serial No.09-760 Docket No. 50-305 ATTACHMENT 2 SUPPLEMENTAL RESPONSE TO RAI B2.1.21-1 KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.

Serial No.09-760 Docket No. 50-305 Attachment 2/Page 1 of 1 NRC Request Need to provide additional updates to LRA Section B2.1.21 and USAR Appendix A, Section A2.1.21 for the Non-EQ Inaccessible Medium-Voltage Cables Program The applicant's RAI [B2.1.21-1] response did not update license renewal application (LRA) Section B2.1.21 and associated Updated Safety Analysis Report (USAR) supplement to specify that inspection for water collection is performed based on actual plant experience with water accumulation in the in-scope manhole of the tertiary auxiliary transformer consistent with Generic Aging Lessons Learned Aging Management ProgramXI.E3 and Standard Review Plan for License Renewal of Nuclear Power Plants Table 3.6.2.

As a result of the discussions, DEK indicatedthat they will supplement their response to RAI B2.1.21-1 to provide additionalinformation to the staff regardingthe update of LRA Section B2.1.21 and USAR Appendix A, Section A2.1.21 of the KPS LRA.

DEK Supplemental Response As a clarification to LRA Appendix B, Section B2.1.21, Non-EQ Inaccessible Medium-Voltage Cables, and the response provided to RAI B2.1.21-1 in DEK letter 09-469 dated August 17, 2009, the inspection of the in-scope manhole east of the tertiary auxiliary transformer for water collection will be performed based on actual plant experience with water accumulation in the manhole. However, the inspection will be performed at least every two years. The first inspection for license renewal will be performed prior to the period of extended operation.

LRA Appendix A, USAR Supplement, Section A2.1.21, "Non-EQ Inaccessible Medium-Voltage Cables," will be revised to replace the fifth paragraph in the Program Description with the following:

"Inspection of the in-scope manhole east of the tertiary auxiliary transformer for water collection will be performed based on actual plant experience with water accumulation in the manhole. However, the inspection will be performed at least every two years. The first inspection for license renewal will be performed prior to the period of extended operation."