ML13263A225

LRA Draft RAI Set 48

ML13263A225
Person / Time
Site:	Grand Gulf
Issue date:	11/21/2013
From:	Daily J License Renewal Projects Branch 1
To:	Kevin Mulligan Entergy Nuclear Operations
Sayoc E, 415-4084
References
TAC ME7493
Download: ML13263A225 (10)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 November 21, 2013 Mr. Kevin Mulligan Vice President, Site Entergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150

SUBJECT:

REQUESTS FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE GRAND GULF NUCLEAR STATION, LICENSE RENEWAL APPLICATION (TAC NO. ME7493)- SET 48

Dear Mr. Perito:

By letter dated October 28, 2011, Entergy Operations, Inc., submitted an application pursuant to Title 10 of the Code of Federal Regulations (CFR) Part 54, to renew the operating license, NPF-29, for Grand Gulf Nuclear Station, Unit 1, for review by the U.S. Nuclear Regulatory Commission staff. The staff is reviewing the information contained in the license renewal application and has identified, in the enclosure, areas where additional information is needed to complete the review.

These requests for additional information, outlined in Enclosure 1, were discussed with Ted Ivy, 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 at (301) 415-3873 or by e-mail at john.daily@ nrc.gov.

Sincerely, JL~

John Daily, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-416

Enclosure:

Requests for Additional Information cc w/encl: Listserv

ML13263A225 *concurred via email OFFICE LA:RPB2:DLR PM:RPB1 :DLR BC:RPB1 :DLR PM: RPB1 :DLR NAME I King E Sayoc Y Diaz-Sanabria J Daily DATE 11/4/2013 9/27/2013 11/21/2013 11/21/2013 Letter to K. Mulligan from J. Daily dated November 21, 2013

SUBJECT:

REQUESTS FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE GRAND GULF NUCLEAR STATION, LICENSE RENEWAL APPLICATION (TAC NO. ME? 493) - SET 48 DISTRIBUTION:

HARD COPY:

DLR RF E-MAIL:

PUBLIC RidsNrrDir Resource RidsNrrDirRpb1 Resource RidsNrrDirRpb2 Resource RidsNrrDirRerb Resource RidsNrrDirRarb Resource RidsNrrDirRasb Resource RidsNrrDirRapb Resource RidsNrrDirRpob Resource john.daily@ nrc.gov emmanuel.sayoc@ nrc.gov david. drucker@ nrc. gov david. wrona@ nrc.gov melanie.wong@ nrc.gov yoira.diaz-sanabria@ nrc.gov dennis.morey@ nrc.gov rich.smith@ nrc.gov blake. rice@ nrc. gov greg.pick@ nrc.gov david.mcintyre@nrc.gov

GRAND GULF NUCLEAR STATION LICENSE RENEWAL APPLICATION REQUESTS FOR ADDITIONAL INFORMATION SET 48 (REVISED)

RAI A.1-1, License Renewal Commitments and the USAR

Background:

By letter dated October 28, 2011, Entergy Operations, Inc. (Entergy), submitted an application pursuant to Title 10 of the Code of Federal Regulations (CFR) Part 54, to renew the operating license, NPF-29, for Grand Gulf Nuclear Station (GGNS), Unit 1, for review by the U.S. Nuclear Regulatory Commission (NRC) staff. The staff of NRC 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." By letter dated January 31, 2013, the NRC provided the "Safety Evaluation Report with Open Items related to the License Renewal of the Grand Gulf Nuclear Station" (SEA), and requested that Entergy review the SEA and provide comments to the NRC staff. By letter dated April2, 2013, Entergy provided its comments.

During the review of the GGNS license renewal application (LRA) by the NRC staff, Entergy made commitments related to aging management programs (AMPs), aging management reviews (AMRs), and time-limited aging analyses, as applicable, related to managing the aging

' effects of structures and components prior to the period of extended operation (PEO). The list of these commitments, as well as the implementation schedules and the sources for each commitment, was included as a Table in Appendix A to the SEA with Open Items.

In Section 1.7, "Summary of Proposed License Conditions," of the SEA with Open Items, the staff stated that following its review of the LRA, including subsequent information and clarifications provided by the applicant, it identified proposed license conditions. The first license condition requires the information in the updated safety analysis report (USAR) supplement, submitted pursuant to 10 CFR 54.21 (d), as revised during the LRA review process, be made a part of the USAR. The second license condition in part states that the new programs and enhancements to existing programs listed in Appendix A of the SEA and the applicant's USAR supplement be implemented no later than 6 months prior to the PEO. This license condition also states, in part, that activities in certain other commitments shall be completed by 6 months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

The NRC plans to revise Appendix A of the SEA to align with this guidance and to reformat the license condition to be as follows:

The USAR supplement submitted pursuant to 10 CFR 54.21 (d), as revised during the license renewal application review process, and as supplemented by Appendix A of NUREG [XXXX], "Safety Evaluation Report Related to the License Renewal of Grand Gulf Nuclear Station" dated [Month Year], describes certain programs to be implemented and activities to be completed prior to the PEO.

a) The licensee shall implement those new programs and enhancements to existing programs no later than 6 months prior to PEO.

ENCLOSURE

b) The licensee shall complete those inspection and testing activities, as noted in Commitment Nos. x through xx of Appendix A of NUREG XXXX, by the 6 month date prior to PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

The licensee shall notify the NRC in writing within 30 days after having accomplished item (a) above and include the status of those activities that have been or remain to be completed in item (b) above.

The staff also notes that in the course of its evaluating multiple commitments to be implemented in the future in order to arrive at a conclusion of reasonable assurance that requirements of 10 CFR 54.29(a) have been met, these license renewal commitments must be incorporated either into a license condition or into a mandated licensing basis document, such as the USAR.

Those commitments that are incorporated into the USAR are typically done so by incorporating each one verbatim (or by a summary and a commitment reference number) into the respective USAR summaries in the applicant's LRA Appendix A Issue:

As proposed by the applicant and as reflected in the SER Appendix A, the implementation schedule for some commitments may conflict with the implementation schedule intended by the generic license condition. In addition, these licensing commitments need to be incorporated either into a license condition or into the applicant's USAR summary in such a manner as discussed above.

Request:

1. Identify those commitments to implement new programs and enhancements to existing programs. Indicate the expected date for completing the implementation of each of these programs and enhancements.

2. Identify those commitments to complete inspection or testing activities prior to the PEO.

Indicate the expected dates for the completion of each of these inspection and testing activities.

3. For each commitment in the SER Appendix A, identify where and how Entergy proposes that it be incorporated: into either a license condition or into the GGNS USAR.

RAI B.1.41-3c, Service Water Integrity Program Follow-up (revised RAI)

Background:

GGNS LRA Sections A.1.41 and 8.1.41 state that the Service Water Integrity program "manages loss of material and fouling in open-cycle cooling water systems as described in the GGNS response to NRC Generic Letter (GL) 89-13." The GGNS response to GL 89-13, Action Ill, Item 7, "Erosion Monitoring and Control," states that the standby service water system

(SSW) does not meet the selection criteria for erosion monitoring. Based on this, the Service Water Integrity program as described in the LRA does not manage erosion. (Note: The request for additional information (RAI) as presented here supersedes the previous version of RAI B.1.41-3c originally issued by letter dated March 12, 2013.)

In contrast, GGNS EP-08-LRD02, "Operating Experience Review Report- AERM," identifies more than 20 condition reports (CRs) that address erosion. The associated evaluations in the report state that loss of material due to erosion is an identified aging effect for carbon steel components in raw water or treated water environments. The report evaluates erosion found in valve 1P41 F299A through CR-GGN-2007-00370 by noting that this operating experience requires special consideration to specific components in the SSW system. In addition, the NRC independently identified several CRs (e.g., CR-GGN-2003-02331 and CR-GGN-201 0-01344) addressing erosion that appear to indicate that MS 46 is the procedure that monitors the associated components for erosion. During the AMP audit, the staff requested and GGNS provided a copy of GGNS MS 46, "Program Plan for Monitoring Internal Erosion/Corrosion in Moderate Energy Piping Components (Safety-Related)."

GGNS identified erosion in its operating experience reviews, but did not reference MS-46 in GGNS EP-08-LRD06, "Aging Management Program Evaluation Report Non-Class I Mechanical," which was used as the basis for LRA Appendix B. Consequently, the NRC submitted an initial RAI (RAI B.1.41-3) concerning the applicability of MS-46 to GGNS' AMPs.

GGNS initially stated that the GGNS-MS-46 procedure is not an AMP that is necessary or credited to manage the effects of aging for components in the Service Water Integrity program.

However, this statement appeared to be inconsistent with information in another RAI response, so the staff submitted a second RAI, B.1.41-3a, requesting further clarification for the applicability of MS-46. In its response to the second RAI, GGNS stated that MS-46 provides instructions for implementing inspections of components subject to an AMR and that these inspections are ongoing monitoring activities that are credited by the Fire Water System, Water Chemistry Control- Closed Treated Water Systems, and the Service Water Integrity AMPs.

After reviewing the second response, the staff had the following concerns: 1) the site documentation appeared to be incomplete because MS 46 was not included as a reference for three cited AMPs, 2) the LRA states the cited AMPs are consistent with the corresponding GALL Report AMP; however, none of these Generic Aging Lessons Learned (GALL) Report AMPs manage loss of material due to erosion, and 3) the LRA tables corresponding to the cited AMPs do not contain any AMR items that address loss of material due to erosion. Based on these concerns the staff issued a third RAI, B.1.41-3b, asking for additional clarification.

In its third response, dated December 18, 2012, GGNS stated that it had revised the appropriate sections of GGNS EP-08-LRD06, "Aging Management Program Evaluation Report Non-Class I Mechanical," to identify MS-46 as an implementing procedure for monitoring microbiologically-influenced corrosion (MIC) for the three cited AMPs. GGNS also stated that 1) MS-46 is not credited with managing loss of material due to erosion on components within the scope of license renewal, 2) MS-46 does not reflect the systems and components that are addressed by this procedure and requires revision to update its purpose and scope, 3) MS-46 does not describe components that are subject to loss of material due to erosion, and 4) there are no recent monitoring activities performed through MS-46. GGNS noted that the required revision to

MS-46 to update its purpose and scope for managing MIC had been entered into its corrective action program.

As a result of NRC questions during a predecisional enforcement conference, GGNS subsequently stated in letter dated August 8, 2013, that it had provided conflicting information in its third response. GGNS stated that it had incorrectly stated that it does not credit MS-46 for managing loss of material due to erosion. The letter states "[p]rocedure GGNS-MS-46 is applicable for monitoring erosion in raw water systems susceptible to microbiologically-influenced corrosion." The staff understood this to mean that MS 46 does manage loss of material due to erosion.

Issue:

Based on the program description in the LRA in conjunction with its response to GL 89-13, the GGNS Service Water Integrity program does not appear to manage loss of material due to erosion. In addition, based on the response to RAI B.1.41-3b, it is not clear to the staff how GGNS manages loss of material due to erosion that is documented and evaluated in EP-08-LRD02, "Operating Experience Review Report- AERM." While it may be true, as stated in EP-08-LRD02, that "loss of material due to erosion is an aging effect identified in mechanical tools for carbon steel," the mechanical tools document (EPRI-1 01 0639) also states that there is no corresponding GALL Report item and there is not a match between the tool and the GALL Report for components in either raw water or treated water environments. As such, if loss of material due to erosion is being managed, then an AMR item citing generic note H, designating that the aging effect is not in the GALL Report for this component, material, and environment combination, would be appropriate for components in each affected system.

Although GGNS apparently monitored erosion/corrosion in certain systems through MS-46 in the past, this appears to no longer be the case. The response to RAI B.1.41-3a states that MS 46 performs inspections of components subject to an AMR, and that these inspections are ongoing monitoring activities that are credited by several AMPs; however, the response to RAI B.1.41-3b states that no recent monitoring activities have been performed through MS-46. In addition, MS-46 apparently needs to be revised to update its purpose and scope because it does not reflect the systems and components that it addresses. Although the required revision to MS-46 is in the corrective action program, this enhancement to an aging management implementing procedure is not captured in GGNS' license renewal List of Regulatory Commitments.

Request:

1. Either update LRA Section A.1.41 and the program description in Section 8.1.41 to reflect current aging management activities with respect to managing erosion, or provide justification that the program described in GGNS' response to GL 89-13, which indicates that erosion monitoring is not part of the program, adequately describes current GGNS aging management activities.

2. Describe the aging management activities at GGNS that are credited to address the operating experience evaluated in EP-08-LRD02 for loss of material due to erosion and include the AMR items in system tables where components are monitored for erosion.

If it is determined that no new AMR items need to be added to any system tables, provide the bases to show that existing AMR items include loss of material due to erosion. For the erosion found in valve 1P41 F299A through CR-GGN-2007 00370, provide details regarding what "special consideration to specific components in the SSW system" have been taken, and delineate where the special consideration has been included in the implementing procedure(s) of an AMP.

3. For any components previously monitored for erosion through MS-46 (i.e., components from the database that was developed and maintained in accordance with MS-46, step 5.1.1 ), discuss whether these components are currently being monitored for erosion or provide information to demonstrate that the component no longer needs to be monitored.

For any components that are currently being monitored for erosion, provide the most recent inspection information (such as the date of last inspection, wall thickness data (i.e., nominal, minimum found, and minimum required), calculated wear rate, and the next scheduled inspection) or other objective evidence to show that the associated effects of aging will be adequately managed.

4. Regarding the revision to be made to MS-46 (that was previously entered into the correction action program), either include this enhancement to the program as a license renewal commitment, or delineate why the required changes to this aging management implementing procedure does not need to be verified as part of NRC Inspection Procedure 71003, "Post-Approval Site Inspection for License Renewal." In addition, clarify whether the revision to MS 46 is limited to updating the purpose and scope for managing MIC (as initially stated in letter dated December 18, 2012), or whether the update will include the erosion mechanism as well.

RAI 8.1.22-1 c, Flow-Accelerated Corrosion follow-up

Background:

The GGNS response to RAI 8.1.22-1 b, dated December 18, 2012, provides additional bases to justify the exception to the Flow-Accelerated Corrosion (FAC) program for managing wall thinning caused by non-FAC mechanisms. For the "detection of aging effects" program element, GGNS stated that the "FAC program includes a quarterly review of plant conditions to identify conditions outside of design conditions that could affect plant piping and equipment due to FAC or erosion," and that the "corrective action process performs extent of condition reviews for component degradation that would be the result of loss of material due to erosion." For the "monitoring and trending" program element, GGNS stated that monitoring for erosion mechanisms is currently performed through a review of plant-specific and industry operating experience. For the "corrective action" program element, GGNS stated that the "corrective action program evaluation of the condition will determine the appropriate corrective action," and "if degradation is due to erosion, it is not acceptable to only replace with FAC or erosion resistant material: monitoring the replaced component at an appropriate frequency is warranted."

The staff noted that, although the implementing procedure, EN-DC-315, "Flow Accelerated Corrosion Program," states that it can be used as a guide for evaluating systems and components that are not included in the FAC program, there did not appear to be any other distinctions in the procedure relative to managing non-FAC wall-thinning mechanisms. In addition, the staff noted in its response to RAI 8.1.22-1 a, dated October 2, 2012, GGNS stated that FAC location 662, which was being managed for non-FAC wall thinning mechanisms, "was replaced in 2004 with FAG-resistant material (stainless steel) and is no longer monitored for FAC."

In the response dated August 8, 2013, to follow-up actions from a teleconference on August 1, 2013, GGNS stated that the implementing procedure EN-DC-315, with sub-tier procedures SEP-FAC-GGN-001, CEP-FAC-001, and GGNS MS-41, provide the details for performing inspections to monitor wall thinning due to FAC and non-FAC mechanisms. The response also adds a commitment to continue periodic monitoring of components that are subject to wall-thinning mechanisms other than FAC, which are replaced with alternate materials, at a frequency commensurate with their post-replacement wear rates and post-replacement cumulative run hours.

Issue:

Although the staff had preliminarily accepted GGNS' October 2, 2012, and December 18, 2012, responses, after additional considerations several aspects are not clear to the staff with respect to how the current FAC program manages components that are being monitored for non-FAC wall-thinning mechanisms. Specifically, the program apparently relies exclusively on the corrective action process/program to provide extent of condition reviews and corrective actions, and the implementing procedures do not appear to provide any guidance in either aspect.

As noted in response to RAI 8.1.22-1 a, FAC location 662 was replaced with stainless steel and is no longer being monitored by the FAC program. Although the commitment provided in the August 8, 2013, letter will now require periodic monitoring of this component, the implementing procedure provided during the NRC's AMP audit for the FAC program did not distinguish between components that are being monitored for FAC and those being monitored for non-FAC mechanisms. Unless the procedure differentiates between components that being managed for FAC and non-FAC mechanisms, it is not clear that post-replacement activities to determine new wear rates and to track cumulative run hours will be performed.

From the "detection of aging effects" perspective, although the current implementing procedure includes a reference to EPRI-1 011231, "Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant System," the procedure does not address any considerations for extent of condition reviews. It is not clear how extent of condition reviews performed through the corrective action process will appropriately consider recommendations for controlling erosion mechanisms without giving guidance through the implementing procedure. In addition, the staff could not identify where the FAC program includes a quarterly review of plant conditions to identify conditions that could affect piping and equipment due to FAC or erosion, as stated in the December 18, 2012 response to RAI 8.1.22-1 b.

Request:

1. Provide additional bases to justify the current exception for using the FAC program to manage components susceptible to non-FAC mechanism. Either include details from the existing implementing procedure(s) to demonstrate that the effects of aging will be adequately managed with respect to a) performing extent of condition reviews, b) replacing components susceptible to wall-thinning mechanisms other than FAC with FAC-resistant material, and c) tracking cumulative run hours for components affected by non-FAC wall thinning, or provide a commitment to enhance the implementing procedures to accomplish these activities. Also include any other aspects of the ten program elements that should be addressed.

2. Explain how the existing FAC program described in LRA 8.1.22 provides "a quarterly review of plant conditions to identify conditions outside of design conditions that could affect plant piping and equipment due to FAC or erosion."