CNL-20-076, Response to Request for Additional Information Re Application to Revise Sequoyah Nuclear Plant (SQN) Unit 1 Technical Specifications for Steam Generator Tube Inspection Frequency (SQN-TS-20-01)

Response to Request for Additional Information Re Application to Revise Sequoyah Nuclear Plant (SQN) Unit 1 Technical Specifications for Steam Generator Tube Inspection Frequency (SQN-TS-20-01)

ML20267A525
Person / Time
Site:	Sequoyah
Issue date:	09/23/2020
From:	Jim Barstow Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNL-20-076, EPID L-2020-LLA-0030, SQN-TS-20-01 SG-SGMP-16-15
Download: ML20267A525 (43)

Text

10 CFR 50.90 Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 CNL-20-076 September 23, 2020 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Sequoyah Nuclear Plant Unit 1 Renewed Facility Operating License No. DPR-77 NRC Docket No. 50-327

Subject:

Response to Request for Additional Information Regarding Application to Revise Sequoyah Nuclear Plant (SQN) Unit 1 Technical Specifications for Steam Generator Tube Inspection Frequency (SQN-TS-20-01)

(EPID L-2020-LLA-0030)

References:

1. TVA Letter to NRC, CNL-20-010, Application to Revise Sequoyah Nuclear Plant (SQN) Unit 1 Technical Specifications for Steam Generator Tube Inspection Frequency (SQN-TS-20-01), dated February 24, 2020 (ML20056C857)

2. NRC Electronic Mail to TVA, Sequoyah Nuclear Plant, Units 1 and 2 -

Request for Additional Information Regarding Request to Revise Steam Generator Inspection Frequency (EPID L-2020-LLA-0030), dated September 2, 2020 (ML20248H509)

In Reference 1, Tennessee Valley Authority (TVA) submitted a request for an amendment to Renewed Facility Operating License No. DPR-77 for the Sequoyah Nuclear Plant (SQN)

Unit 1. The proposed license amendment request (LAR) revises SQN Unit 1 Technical Specifications (TS) 5.5.7, Steam Generator (SG) Program, and SQN Unit 1 TS 5.6.6, Steam Generator Tube Inspection Report, to reflect a proposed change to the required SG tube inspection frequency from every 72 effective full power months (EFPM) to every 96 EFPM.

In Reference 2, the Nuclear Regulatory Commission (NRC) provided a request for additional information (RAI) and requested a response by October 2, 2020. Enclosure 1 to this letter provides the response to the RAI.

U.S. Nuclear Regulatory Commission CNL-20-076 Page 2 September 23, 2020 As requested by the NRC in Question 1 of Enclosure 1, Enclosure 2 to this letter contains Westinghouse Electric Company LLC (Westinghouse) Document, SG-SGMP-16-15, Revision 1, Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment. Additionally, in response to Question 2 of Enclosure 1, Enclosure 3 to this letter contains a revised mark-up to the proposed change to SQN Unit 1 TS 5.5.7.d.2, and to this letter contains the re-typed SQN Unit 1 TS 5.5.7.d.2 to show the proposed change. Enclosures 3 and 4 supersede the corresponding information provided in Attachments 1 and 2 to the enclosure to Reference 1.

This letter does not change the no significant hazard considerations nor the environmental considerations contained in Reference 1. Additionally, in accordance with 10 CFR 50.91(b)(1), TVA is sending a copy of this letter and the enclosures to the Tennessee Department of Environment and Conservation.

There are no new regulatory commitments associated with this submittal. Please address any questions regarding this submittal to Gordon Williams, Senior Manager, Fleet Licensing (Acting), at (423) 751-2687.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 23rd day of September 2020.

Respectfully, James Barstow Vice President, Nuclear Regulatory Affairs & Support Services

Enclosures:

1.

Response to NRC Additional Request for Additional Information 2.

Westinghouse Document, SG-SGMP-16-15, Revision 1, Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment 3.

Revised TS Changes (Mark-Ups) for SQN Unit 1 4.

Revised TS Changes (Final Typed) for SQN Unit 1 cc (Enclosures):

NRC Regional Administrator - Region II NRC Project Manager - Sequoyah Nuclear Plant NRC Senior Resident Inspector - Sequoyah Nuclear Plant Director, Division of Radiological Health - Tennessee State Department of Environment and Conservation CNL-20-076 E1-1 of 2 Response to NRC Additional Request for Additional Information NRC Introduction

1. A review of the entire revised refueling outage 21 (U1R21) operational assessment is an important element of the NRC staff safety determination, as it provides necessary information that is not contained in the submitted license amendment request (LAR). This information includes, but is not limited to, the foreign object tube wear rate analysis referenced in Section 3.2.5 of the LAR and the specific growth rates used in the Monte Carlo analysis referenced in Section 3.2.7. The NRC staff notes that while the maximum and 95th percentile growth rates for the U-bend support structures and advanced tube support grids are discussed in Section 3.2.7 of the LAR, the growth rates used in the Monte Carlo analysis were not provided.

Therefore, the NRC staff requests the revised U1R21 operational assessment.

TVA Response to Question 1 to this submittal contains Westinghouse Document, SG-SGMP-16-15, Revision 1, Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment.

2. Note 3 of Table 1 of the LAR states:

The SQN U1R21 inspection consisted of a 100% combination bobbin and array coil inspection of all tubes full length with the exception of the U-bend sections of tube Rows 1 through 4, which were inspected with a singular bobbin probe due to dimensional constraints. This is the planned scope for all scheduled inspections under the proposed amendment.

Licensees in general, including at Sequoyah Nuclear Plant (Sequoyah), Unit 1, have demonstrated the ability to conservatively manage loose parts once they are detected by eddy current examinations or by secondary-side foreign object search and retrieval inspections. Licensees at Sequoyah, Unit 1, and other plants have also effectively managed tube wear while maintaining tube integrity. This good operational experience, however, was developed within the inspection frequency of the existing technical specifications.

Decreasing steam generator tube inspection frequency will increase the amount of time that loose parts can potentially create tube wear, and increase the uncertainties associated with loose parts and other tube wear mechanisms that are projected assuming consistent secondary side thermal hydraulic conditions. The NRC staff notes that the enhanced detection achieved by inspection with advanced probes could reasonably be expected to provide a mitigating factor to increased operational time between inspections, by providing a more accurate assessment of the current tube condition. The NRC staff believes that such inspections are an important element of an inspection program supporting an increased interval between inspections. Regardless of the specific tubing alloy in a steam generator, detection of existing loose parts is enhanced by using advanced probes, such as the combination bobbin and array coil probe or other equivalent (or better) probes. Also, while Alloy 690 tubing has not experienced corrosion degradation in operation, use of enhanced probes provides earlier detection of pitting or other forms of corrosion, should they occur during future operation. Therefore, the NRC staff supports the widespread use of advanced probes in future inspections.

CNL-20-076 E1-2 of 2 The NRCs regulations at paragraph 50.36(c)(5) of Title 10 of the Code of Federal Regulations require, in part, that licensees have administrative controls in place to assure the safe operation of a facility. In light of the preceding discussion, provide justification for not incorporating enhanced inspections equivalent to or better than array probe technology, such as those described in Note 3, into the Sequoyah, Unit 1, steam generator Technical Specifications (e.g., in Section 5.5.7.d.2). Alternately, provide revisions to the Sequoyah, Unit 1, steam generator Technical Specifications that will ensure enhanced inspections equivalent to or better than array probe technology will be performed during the extended inspection intervals.

TVA Response to Question 2 TVA is proposing to add the following verbiage to the proposed change to SQN Unit 1 Technical Specification (TS) 5.5.7.d.2:

After the first refueling outage following SG installation, inspect each SG at least every 96 effective full power months. Tube inspections shall be performed using equivalent to or better than array probe technology. For regions where a tube inspection with array probe technology is not possible (such as due to dimensional constraints or tube specific conditions), the tube inspection techniques applied shall be capable of detecting all forms of existing and potential degradation in that region. to this letter contains a revised mark-up to the proposed change to SQN Unit 1 TS 5.5.7.d.2 and Enclosure 4 to this letter contains the re-typed SQN Unit 1 TS 5.5.7.d.2 to show the proposed change.

CNL-20-076 Westinghouse Document, SG-SGMP-16-15, Revision 1, Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment

WESTINGHOUSE NON-PROPRIETARY CLASS 3 SG-SGMP-16-15 October 2019 Revision 1 Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 2 of 31 Record of Revisions Revision Date Description 0a December 2016 Preliminary for Tennessee Valley Authority review and comment.

0 December 2016 Incorporated comments received from Tennessee Valley Authority. Issued to the Sequoyah site in support of return to Mode 4 power following U1R21.

1 October 2019 Revised to update the Operational Assessment to allow for extension of the operation interval between required steam generator inspections. Content changes are only made to Section 4 (Operational Assessment) of the report. Minor consistency changes are made as appropriate throughout the rest of the document.

Changes are identified by a bar in the left-hand margin.

List of Trademarks

+POINT is a trademark or registered trademark of Zetec, Inc. Other names may be trademarks of their respective owners.

STMax is a trademark of Westinghouse Electric Company LLC, its affiliates and/or its subsidiaries in the United States of America and may be registered in other countries throughout the world. All rights reserved. Unauthorized use is strictly prohibited. Other names may be trademarks of their respective owners.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 3 of 31 Table of Contents Executive Summary.......................................................................................................................................... 5 1.0 Introduction................................................................................................................................... 6 2.0 Sequoyah U1R21 Primary Side Inspection Program.................................................................... 6 2.1 Base Scope Inspection Plan.......................................................................................................... 6 2.2 Inspection Expansion.................................................................................................................... 7 2.3 Inspection Results......................................................................................................................... 7 2.4 Tube Plugging and Stabilization................................................................................................... 7 3.0 Condition Monitoring................................................................................................................... 8 3.1 Existing Degradation Mechanisms............................................................................................... 8 3.1.1 Mechanical Wear at U-bend Support Structures........................................................................... 8 3.1.2 Mechanical Wear at Horizontal ATSGs....................................................................................... 9 3.2 Potential Degradation Mechanisms............................................................................................... 9 3.2.1 Mechanical Wear Due to Foreign Objects.................................................................................... 9 3.3 Resolution for Classification of Indications................................................................................ 10 3.4 SG Channel Head Primary Side Bowl and Tube Plug Visual Inspections................................. 10 3.5 Secondary Side Activities........................................................................................................... 11 3.5.1 Top of Tubesheet Cleaning......................................................................................................... 11 3.5.2 Top of Tubesheet FOSAR........................................................................................................... 11 3.6 Condition Monitoring Conclusions............................................................................................. 11 4.0 Operational Assessment.............................................................................................................. 12 4.1 Mechanical Wear at U-bend Support Structures......................................................................... 12 4.1.1 Use of Volume-Based Wear Approach to Extend Inspection Interval....................................... 13 4.2 Mechanical Wear at Horizontal ATSGs..................................................................................... 14 4.2.1 Use of Volume-Based Wear Approach to Extend Inspection Interval....................................... 15 4.3 SG Secondary Side Foreign Objects........................................................................................... 15 4.4 Operational Assessment Conclusions......................................................................................... 16 5.0 References................................................................................................................................... 17 List of Tables Table 2-1: Sequoyah U1R21 SG Eddy Current Inspection - Final Indication Summary..................................... 7 Table 2-2: Sequoyah U1R21 SG Eddy Current Inspection - Final Indication Summary..................................... 7 Table 3-1: Sequoyah U1R21 Possible Loose Part Indications (PLP)................................................................. 10 Table 3-2: Sequoyah U1R21 Resolution for Classification of Indications......................................................... 10 Table 3-3: Sequoyah U1R21 SG Deposit Removal............................................................................................ 11 Table 3-4: Sequoyah U1R21 SG FOSAR Summary.......................................................................................... 11 Table 4-1: Sequoyah U1R21 U-bend Support Structure Wear Growth Comparison......................................... 12 Table 4-2: 95/50 Burst Pressures from WVOL Cases for U-Bend Structural Support Wear............................ 14 Table 4-3: 95/50 Burst Pressures from WVOL Cases for ATSG Tube Wear................................................... 15 Table A3-1: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG1.......................................... 21 Table A3-2: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG2.......................................... 23 Table A3-3: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG3.......................................... 24 Table A3-4: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG4.......................................... 25 Table A4-1: Sequoyah U1R21 ATSG Wear Indications - All SGs................................................................... 29

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-10-16 October 2019 Revision 1 Page 4 of 31 List of Attachments

- Sequoyah U1R21 As-Implemented SG Inspection Scope........................................................ 18 - Sequoyah U1R21 SG Tube Structural and Condition Monitoring Limits................................ 20 - Sequoyah U1R21 U-bend Support Structure Wear Indications............................................... 21 - Sequoyah U1R21 ATSG Wear Indications.............................................................................. 29

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 5 of 31 Executive Summary The Sequoyah U1R21 outage was conducted after cumulative Replacement Steam Generators (RSG) service equivalent to approximately 12.4 effective full power years (EFPY) while the service from previous RSG eddy current inspections during U1R18 was 4.08 EFPY. No tube leakage was reported during this operating interval.

At Sequoyah U1R21, approximately 133.2 effective full power months (EFPM) of the 144 EFPM in the first sequential period have been accrued and U1R21 is the last inspection in this sequential period. Based on the U1R21 steam generator (SG) eddy current and visual inspection data, there are two existing degradation mechanisms in the Sequoyah Unit 1 RSGs. The existing degradation mechanisms are:

Mechanical Wear at U-bend Support Structures Mechanical Wear at Horizontal Advanced Tube Support Grids (ATSGs)

No tubes have exhibited degradation exceeding the tube integrity criteria given in the Degradation Assessment (DA) for the U1R21 outage (Reference 3). No tubes required in situ pressure testing to support the Condition Monitoring (CM) assessment based on the DA and Electric Power Research Institute (EPRI) In Situ Pressure Test Guidelines (Reference 6). A summary of the number of plugged tubes in the Sequoyah Unit 1 RSGs following U1R21 is provided below.

SG

1. Tubes

1. Plugged

% Plugging 1

4,983 16 0.32%

2 4,983 6

0.12%

3 4,983 7

0.14%

4 4,983 5

0.10%

Total 19,932 34 0.17%

A final operational assessment (OA) has been performed considering the indications detected and degradation growth rates observed. Table 3-4 is a summary of results from the foreign object search and retrieval (FOSAR) inspections. Analysis of the remaining foreign objects shows that they are acceptable to remain inside the SGs for a period of greater than five operating cycles.

Development of degradation growth rates for U-bend support structure and advanced tube support grid (ATSG) tube wear indications has been based on historical eddy current data comparisons made by the lead analyst.

These growth rates were then used to project worst-case degradation that could be encountered at the U1R24 inspection. The Revision 0 final OA concludes that structural and leakage integrity will be maintained through Cycles 22, 23 and 24 for all degradation mechanisms observed in the Sequoyah Unit 1 RSGs.

Revision 1 of the report performed a study to determine if the steam generators could be operated for additional cycles between inspections beyond the 3-cycle OA performed in Revision 0 of this report without violation of the performance criteria. Additional calculations were performed on the growth projection of the flaws observed during U1R21 and it was determined that the SGs could be operated for 5 cycles (7.5 EFPY) before the SG performance criteria for burst was not met at 95% probability and 50% confidence levels. The Reference 7 foreign object evaluation conclusion supports SG operation for 5 cycles without adverse impact on tube integrity. The current plant Technical Specifications do not allow for inspection intervals greater than 3 cycles for plants with SG tubes composed of Alloy 690 material and an approved license amendment would be required to operate longer than 3 cycles before inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 6 of 31 1.0 Introduction This condition monitoring and operational assessment (CMOA) has been developed for the Tennessee Valley Authority (TVA) following the Sequoyah Unit 1 21st Refueling Outage (U1R21) RSG tube in-service inspection and assessment conducted in December of 2016. The assessments have been performed to meet the requirements and intent of NEI 97-06 Revision 3 (Reference 2). In preparation for the inspection, and to assure that the inspection adequately supports the CM and final OA evaluations required by NEI 97-06, the licensee documented the inspection scope together with the qualification of the applied nondestructive examination (NDE) techniques (References 3 and 9). This process provides assurance that the NDE techniques are appropriate for detection and measurement and to support development of degradation growth rates, repair criteria, and integrity limits for the degradation mechanisms assessed.

Based on the results obtained from the Sequoyah U1R21 inspections, a condition monitoring assessment was performed on a defect-specific basis, by demonstrating compliance with integrity criteria through comparison of reported NDE measurements with calculated pressure or leakage integrity limits. The indication sizing by NDE was compared to the defect-specific condition monitoring criteria specified in the degradation assessment which are repeated in Attachment 2. All indications detected in this inspection were below the integrity limits and therefore met the condition monitoring requirements provided. A final OA has been performed considering the indications detected during U1R21 and degradation growth rates. The Revision 1 final OA concludes that steam generator tube structural and leakage integrity will be maintained until the end of the upcoming five-cycle inspection interval.

The industry has developed guidelines for SG assessment and TVA has developed a long-term strategic plan to meet or exceed the industry guidelines. The Sequoyah U1R21 SG inspections have been led by the following industry guidelines and SG integrity programs:

EPRI Steam Generator Integrity Assessment Guidelines (Reference 5)

EPRI PWR Steam Generator Examination Guidelines (Reference 1)

EPRI Steam Generator In Situ Pressure Test Guidelines (Reference 6) 0-SI-SXI-068-114.4 TVA Surveillance Instruction for Steam Generator Tubing In-service Inspection and Augmented Inspections (Reference 8)

This document was prepared in accordance with the Westinghouse Quality Management System (QMS).

2.0 Sequoyah U1R21 Primary Side Inspection Program 2.1 Base Scope Inspection Plan The inspection program, as required by the EPRI PWR SG Examination Guidelines (Reference 1), addressed the existing and potential degradation mechanisms for the Sequoyah Unit 1 RSGs. The defined scope implemented during U1R21 included the following:

• 100% combination bobbin and Array probe inspection of all open tubes in all four SGs full length and tube Rows 1 through 4 to the first support from the hot leg (HL) and the cold leg (CL). The remainder of the tubes in Rows 1 through 4 were to be inspected with either a singular bobbin, Array or

+POINT' probe where necessary due to dimensional clearance restrictions.

• 100% Array or +Point probe examination of dents 2 volts in the straight lengths and U-bends of all SGs. This included all dents previously identified as new in cycle 15 or 18 and any additional identified during these inspections.

• +Point Special Interest inspections of tube locations with non-resolved bobbin and/or Array probe signals and any non-resolved possible loose parts (PLPs) from the base scope inspection program in both the HL and CL to characterize the underlying condition.

• 100% visual inspection of all installed tube plugs from the primary side on both the HL and CL.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 7 of 31

• Visual inspection in all SGs of channel head primary side HL and CL in accordance with Westinghouse letter NSAL-12-1 inclusive of the entire divider plate-to-channel head weld and all visible clad surfaces.

The Sequoyah U1R21 SG inspection plan met or exceeded the requirements of the Reference 1 EPRI examination guidelines and was aligned with the Reference 8 TVA SG Surveillance Instruction. The Sequoyah U1R21 eddy current inspection scope as implemented during the outage is shown in Attachment 1.

2.2 Inspection Expansion There was no NDE inspection scope expansion required during Sequoyah U1R21 (Reference 1).

2.3 Inspection Results Table 2-1 presents a filtered summary of the tube NDE indication results based on data relevant to evaluating tube integrity. The files listed below the table were generated by the Westinghouse STMax' eddy current results data management system and used to create the table.

Table 2-1: Sequoyah U1R21 SG Eddy Current Inspection - Final Indication Summary Indications Condition SG 1 SG 2 SG 3 SG 4 ADS Absolute Drift Signal 44 25 127 22 BLG Tubesheet Bulge 1

4 2

3 DNG Freespan Ding or Dent at Support 15 11 67 16 DSS Distorted Support Signal 1

0 0

0 DFS Distorted Freespan Signal 1

4 2

0 DTS Distorted Tubesheet Signal 0

0 2

1 MBM Manufacturing Burnish Mark 3

0 2

11 PCT Volumetric % Through-wall 79 32 47 28 PLP Possible Loose Part 1

0 2

0 WAR Wear Array Probe 77 30 45 24 SG 1: SG 1 - 12_11_AM_Final.xls SG 2: SG2_Engineering_dump.xlsx SG 3: SG 3 - 12_10_PM_Final.xls SG 4: SG 4 - 12_10_PM_Rev 1.xls 2.4 Tube Plugging and Stabilization There was one tube plugged during the Sequoyah U1R21 RSG in-service inspection. The relevant information regarding this tube is provided in Table 2-2 below.

Table 2-2: Sequoyah U1R21 SG Eddy Current Inspection - Final Indication Summary SG Row Col Year Outage Location Call Plugging Basis Stabilized?

1 90 70 2016 U1R21 U-bend 36%TW Preventive No This tube was preventively plugged in order to provide both confidence and margin in the result of the operational assessment. Given the rigid structure of the Sequoyah Unit 1 RSG upper tube bundle supports, post-plugging growth is not anticipated to create a severed tube condition. Further, monitoring of the adjacent active tubes for degradation with eddy current as part of normally scheduled in-service inspections is an inherent measure for monitoring. Therefore, it was not considered necessary to install a stabilizer into this tube prior to plugging.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 8 of 31 3.0 Condition Monitoring Condition monitoring is the assessment performed on observed indications of tube degradation to confirm that the SG Integrity Performance Criteria embodied in the CM limits have not been violated. It is essentially a backward-looking evaluation. This is contrasted with the OA, which seeks to determine whether the tube integrity performance criteria will be exceeded during subsequent operation of the SGs until the next inspection. The CM limits, derived from the structural limits in accordance with the EPRI SG Integrity Assessment Guidelines (Reference 5) and the SG Degradation Specific Management Flaw Handbook (Reference 4), are provided in the outage DA (Reference 3) and echoed in Attachment 2. Discussion of the indications in relation to CM requirements is provided in the following subsections.

3.1 Existing Degradation Mechanisms The EPRI PWR SG Examination Guidelines (Reference 1) requires that the existing degradation mechanisms identified in the DA be subject to appropriate inspection programs to comply with the plant technical specifications. This section addresses the existing SG degradation mechanisms for Sequoyah U1R21 and the indications identified.

3.1.1 Mechanical Wear at U-bend Support Structures Wear at U-bend support structures is an existing degradation mechanism in the Sequoyah Unit 1 RSGs. This mechanism occurs due to tube interaction with the U-bend support structures resulting from flow-induced vibration (FIV) in the upper tube bundle. The mechanical wear process is related to the tightness of the upper bundle assembly as expressed in the distribution of tube to U-bend support structure gaps. In general, at plants with similar support structures, U-bend support structure wear indications do not represent a challenge to structural or leakage integrity standards between inspections. Indications of U-bend support structure wear may require plugging should observed indication depths exceed the plant SG Technical Specification plugging criterion of 40% through-wall (TW). Plugging may also be required in order to support extended operating intervals between inspections.

provides the full listing of tube locations and eddy current signal character for U-bend support structure wear indications detected during Sequoyah U1R21. The tables display the eddy current signal parameters for the U1R21 bobbin inspection and the corresponding percent through-wall (%TW) degradation as compared to the U1R18 or U1R15 result. A graphical display of both the numerical and spatial distribution of the U-bend support structure wear indications is also provided in Attachment 3 Figure A3-1 and Figure A3-

2. The bobbin probe sizing of the largest U-bend support structure wear indications observed during U1R21 was measured at 36% TW. This indication in SG1 tube R90C70 is considerably less than the worst-case projected U-bend support structure wear indication of 50.7%TW from the U1R18 OA (Reference 12). A modest average change of 2.01%TW/EFPY and standard deviation of 1.15%TW/EFPY is observed in the limiting SG for growth with a normally distributed population of growth rate data points. Therefore, a reasonable and conservative growth rate projection for U-bend support structure wear can be developed in support of the OA.

Tube R90C70 in SG 1 was preventively plugged due to the observable growth of two separate indications of U-bend support structure wear at the VS4 support location. One wear indication grew from 16%TW at U1C18 to 36%TW at U1R21. A separate but adjacent wear indication changed from no degradation detected (NDD) in U1C18 to 25%TW in U1R21. For this reason, it was elected to administratively plug the tube in order to provide both confidence and margin in the OA process. Although the growths of these particular wear indications are outliers, they will be conservatively included in the overall growth rate distributions used in the OA. An eddy current data graphic of this tube wear indication is included in Attachment 3 Figure A3-3 for the U1R21 Array probe data and Figure A3-4 for the U1R18 +Point data.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 9 of 31 Based on the inspection data for this mechanism in comparison to the limits identified in Attachment 2, structural integrity requirements have been met at the U1R21 inspection. Regarding U-bend support structure wear locations, satisfaction of structural integrity implies satisfaction of leakage integrity at accident conditions since steam line break accident condition pressure differential for pop-through is much smaller than 3PNO for pressure-only loading of volumetric flaws. Therefore, CM has been satisfied for degradation associated with U-bend support structure wear indications at the Sequoyah U1R21 inspection.

3.1.2 Mechanical Wear at Horizontal ATSGs Wear at horizontal advanced tube support grits (ATSGs) is an existing degradation mechanism in the Sequoyah Unit 1 RSGs. Flow-induced vibration leading to wear at the ATSGs is governed primarily by thermal hydraulic characteristics and the sizes of the tube-to-support gaps. This suggests that wear rates are subject to steam generator specific conditions and will vary between plants and between steam generators at a specific plant.

There have been a limited number of low-level observations of wear at horizontal ATSGs in the Sequoyah Unit 1 RSGs leading up to the U1R21 inspection. Industry operating experience reviews indicate that plants with similar horizontal tube support designs have also identified ongoing wear at relatively low levels.

provides the full listing tube locations and eddy current signal character for ATSG wear indications detected during Sequoyah U1R21. The tables also display the eddy current signal parameters for the U1R21 bobbin inspection and the corresponding %TW degradation as compared to the U1R18 or U1R15 result. A graphical display of the distribution of the ATSG wear indications is also provided in Attachment 4 Figure A4-1. The bobbin probe sizing of the largest ATSG wear indication observed during U1R21 was measured at 22%TW. This is considerably less than the worst-case projected ATSG wear indication of 50.7%

TW made in Reference 12. A modest average change of 2.48%TW/EFPY and standard deviation of 0.95%TW/EFPY is observed for the indications across all four SGs. Therefore, a reasonable and conservative growth rate projection for ATSG wear can be developed in support of the OA.

Based on the inspection data for this mechanism in comparison to the limits identified in Attachment 2, structural integrity requirements have been met at the U1R21 inspection. Regarding ATSG wear locations, satisfaction of structural integrity implies satisfaction of leakage integrity at accident conditions since steam line break accident condition pressure differential for pop-through is much smaller than 3PNO for pressure-only loading of volumetric flaws. Therefore, CM has been satisfied for degradation associated with horizontal ATSG wear indications at the Sequoyah U1R21 inspection.

3.2 Potential Degradation Mechanisms The EPRI Pressurized Water Reactor (PWR) SG Examination Guidelines (Reference 1) require that the potential degradation mechanisms identified in the DA be subject to appropriate inspection programs to comply with the plant technical specifications. This section addresses the potential degradation mechanisms listed in the Reference 3 degradation assessment for Sequoyah U1R21.

3.2.1 Mechanical Wear Due to Foreign Objects Although foreign objects have been observed in the Sequoyah Unit 1 RSGs at previous inspections, no tube degradation associated with the presence of these objects has been identified to date. The Array probe was utilized to aid in the detection of foreign objects and foreign object wear during U1R21. During the Sequoyah U1R21 eddy current inspections there were three signals corresponding to a new possible loose part (PLP). As shown in Table 3-1, there were PLP indications reported at the top of the tubesheet in SG1 and SG3. There was no tube wall degradation detected by eddy current coincident with these PLP indications. All PLP indications were visually inspected from the secondary side and any associated foreign objects or loose parts were retrieved or evaluated for continued operation.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 10 of 31 Table 3-1: Sequoyah U1R21 Possible Loose Part Indications (PLP)

SG Row Col Volts Deg Ind Chn Locn Inch1 BegT EndT PDia PType Cal 1

78 86 5.56 116 PLP 60 CTS 0.11 VS3 CTE 0.61 ZYAXT 12 3

90 54 1.73 93 PLP 132 CTS 0.06 VS3 CTE 0.61 ZYAXT 34 3

32 62 2.54 92 PLP 8

HTS 0.09 VS3 HTE 0.61 ZYAXT 43 Visual inspections performed from the SG secondary side did identify a variety of small foreign objects, many of which were removed from the SGs. During the FOSAR, there were no visible signs that any of the objects had caused tube wear on adjacent tubes. The tube wear potential of the objects known to remain resident on the SG secondary side is evaluated as part of the OA.

3.3 Resolution for Classification of Indications Indications reported with flaw-like characteristics in the Sequoyah Unit 1 RSGs may include those initially reported as distortions of pre-existing signals such as absolute drift indications (ADI/ADS), tube support indications (DSI/DSS), distorted tubesheet signals (DTI/DTS) and manufacturing burnish marks (MBI, MBM). The character of I-code signals is further determined by data history review, lead analyst review, or by follow-up examination with alternate NDE techniques. Those indications with a three letter code ending with an I are compared to historical data and are changed to an S if they have not changed within a small variation. The resolution of indications from Sequoyah U1R21 is summarized in Table 3-2 below.

Table 3-2: Sequoyah U1R21 Resolution for Classification of Indications SG Absolute Drift Signals (ADI/ADS)

Distorted Support Signals (DSI/DSS)

Distorted Tubesheet Signals (DTI/DTS)

Mfg. Burnish Marks (MBI/MBM) 1 0 / 44 0 / 1 0 / 0 0 / 3 2

0 / 25 0 / 0 0 / 0 0 / 0 3

0 / 127 0 / 0 0 / 2 0 / 2 4

0 / 22 0 / 0 0 / 1 0 / 11 A number of the ADS indications in the Sequoyah RSGs are residual effects from the RSG tube thermal treatment process. The distorted support and tubesheet bobbin signals from the U1R21 inspection have all been cleared by either review of the corresponding Array probe data or data history review. Finally, an MBM is most typically a burnishing relic created by the tube manufacturer to buff out surface blemishes. All of these eddy current indications have been cleared through the NDE analysis process as being free from tube degradation.

3.4 SG Channel Head Primary Side Bowl and Tube Plug Visual Inspections Visual inspections have been performed of the SG channel head bowl in the vicinity of the drain line in all SGs during Sequoyah U1R21. These inspections are performed based on industry operating experience and guideline requirements discussed in the Reference 3 degradation assessment. Visual inspections of the SG hot leg and cold leg divider plate and drain line, inclusive of the entire divider plate to channel head weld and all visible clad surfaces, were performed in accordance with Westinghouse NSAL-12-1. This inspection was performed using the SG manway channel head bowl cameras. Satisfactory inspection results were observed in all SGs with no indications of cladding surface degradation (Reference 11).

All previously installed tube plugs were also inspected from the primary side in all four of the Sequoyah Unit 1 RSGs using the cameras mounted to the eddy current robots. The inspection results were satisfactory and showed no indication of tube plug leakage or failure. Inspection of the channel head bowl and all installed tube plugs is planned to be performed again in all SGs at the subsequent inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 11 of 31 3.5 Secondary Side Activities 3.5.1 Top of Tubesheet Cleaning A top of tubesheet deposit cleaning process was performed in all four SGs during Sequoyah U1R21. There are two main purposes of the cleaning process. The first is to remove hardened deposits that tend to form at the top of the tubesheet and the second is to force and filter out any loose parts or foreign objects that have migrated to the SG secondary side during operation. The mass of deposit material and debris removed by the top of tubesheet cleaning process is summarized in Table 3-3 below.

Table 3-3: Sequoyah U1R21 SG Deposit Removal SG 1 24.0 lbs SG 2 36.5 lbs SG 3 24.5 lbs SG 4 32.5 lbs All SGs 117.5 lbs Periodic views of the in-line grit tank screen were also performed throughout the tubesheet cleaning process.

These confirmed that the process was successful at removing foreign objects and material from the RSG secondary side in addition to the hardened sludge deposits.

3.5.2 Top of Tubesheet FOSAR A secondary side tubesheet FOSAR has been performed in all four SGs during Sequoyah U1R21 following a tubesheet cleaning. Sludge, scale, foreign objects, and other deposit accumulations at the top of the tubesheet may have been removed as part of the tubesheet sludge lancing process prior to FOSAR inspection of each SG. The FOSAR inspections included visual examination of tube bundle periphery tubes from both the annulus and tubelane on both the hot and cold legs and through the no tube lane. A limited top of tubesheet in-bundle visual inspection was also performed in each SG for the purpose of assessing the level of hardened deposit buildup in the kidney region. Table 3-4 is a summary of the final results from the FOSAR inspections.

Table 3-4: Sequoyah U1R21 SG FOSAR Summary SG Identified Retrieved Remaining 1

5 1

4 2

9 7

2 3

13 2

11 4

11 5

6 All SGs 38 15 23 During Sequoyah U1R21, a total of 15 foreign objects were removed from the top of the tubesheet. The majority of the foreign objects retrieved were small pieces of metal gasket, wires and bristles. Any foreign objects not able to be retrieved were mapped and an engineering evaluation performed in Reference 7 to justify continued operation with the objects present on the SG secondary side.

3.6 Condition Monitoring Conclusions Based on the inspection data, no tubes exhibited degradation that required in situ pressure testing to demonstrate structural and leakage integrity. There was no reported primary-to-secondary leakage prior to the end of the Sequoyah Unit 1 RSG inspection interval. No secondary side tube degradation attributable to foreign objects has been identified from the FOSAR and visual inspections. No indications of U-bend support structure or horizontal ATSG wear were found to be in excess of the CM limits. The SG performance criteria for operating leakage and structural integrity were satisfied for the preceding Sequoyah Unit 1 RSG inspection interval.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 12 of 31 4.0 Operational Assessment NEI 97-06 (Reference 2) requires that an operational assessment be performed to assess if existing degradation mechanisms observed in a steam generator will continue to meet tube structural and leakage integrity performance criteria until the next inspection. An operational assessment of each existing tube degradation mechanism identified during Sequoyah U1R21 along with the foreign objects that remain on the secondary side is provided in the following sections.

4.1 Mechanical Wear at U-bend Support Structures Based on application of conservative U-bend support structure wear growth rates, the condition of the Sequoyah Unit 1 RSG tubes has been analyzed with respect to continued operability without exceeding the limits for structural and leakage integrity. Upon completion of the combination bobbin and Array probe data program, the growth rates have been determined by comparative analysis of the U-bend support structure wear sites. The growth rates are determined given an operating duration of 3.97 EFPY from U1C15 to U1C18 and 4.08 EFPY from U1C18 to U1C21 and normalizing to a %TW/EFPY basis. A conservative assumption is made that the U-bend support structure wear indications showing no detectable degradation at U1R15 grew from 0% TW at U1C18 to their measurement at U1R21. The results of the comparative analysis for the purpose of developing a representative growth rate are shown in Attachment 3 Tables A3-1 through A3-4. A summary of growth rates for the U-bend support structure wear indications in all four SGs is summarized in Table 4-1.

Table 4-1: Sequoyah U1R21 U-bend Support Structure Wear Growth Comparison Outage SG Number of Indications Max Indication

(%TW)

Max Remaining In-Service

(%TW)

Average Growth

(%TW/EFPY)

Standard Deviation

(%TW/EFPY)

U1R21 1

75 361 28 1.43 0.84 U1R21 2

29 21 21 1.66 0.70 U1R21 3

46 24 24 1.67 0.67 U1R21 4

27 23 23 2.01 1.15 Note 1: The tube in SG1 with a 36%TW indication was plugged during U1R21.

The examination technique specification sheet (ETSS) 96004.1, Revision 13, is the bobbin technique used to size U-bend support structure wear. As a result, the associated sizing equation (y = 0.98x + 2.89 and Syx =

4.19%) is appropriate for the character of U-bend support structure wear indications that have been detected.

This technique is part of the Appendix H ETSS library in the Reference 1 guidelines and, therefore, a factor of 1.12 will be applied to the technique standard error in order to account for analyst uncertainty for OA purposes.

An arithmetic OA approach is applied first to demonstrate that the SG performance criteria are met. With the largest flaw being returned to service measured at 28% TW, and the largest 95th percentile growth from a single SG being calculated to be 3.9 %TW/EFPY (2.01 + 1.15*1.645), the OA is calculated as follows.

124 28% 0.98 2.89% 1.645 1.12 4.19% 3.9%

4.5 55.6%

The CM limit for mechanical wear at U-bend support structures is 47% TW from Attachment 2. Therefore, a Monte Carlo OA approach is applied.

The Westinghouse configured software Single Flaw Model (SFM) Version 2.2 has been used for the OA projection using the inputs discussed above and material properties from the Reference 3 DA. The associated software runs are attached to this document in the Westinghouse EDMS and the configuration control is documented in Reference 10. With this software, the burst pressure of projected flaws is determined through the Monte Carlo simulation method described in Reference 5 and compared against the structural and leakage

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 13 of 31 integrity performance criteria. The OA projection considers 95/50 contributions from depth, relation, material and growth in the reduction in tube burst pressure.

The largest indication returning to service following Sequoyah U1R21 measures 28% TW in SG 1 R87C73 and R75C73 both at VS3 and will remain in service for an assumed 4.5 EFPY between inspections. The projection uses the limiting statistical mean and standard deviation in growth from SG4, assumes a normal distribution and a 2.5 inch bounding wear indication length. The resulting projected flaw has a burst pressure of 4812 psi (46% TW) which is in excess of the 4200 psi structural integrity performance criterion. When performing a 6.0 EFPY OA using this method and inputs, the EOC 95/50 burst pressure associated with the largest returned to service flaw of 28% TW is 4367 psi, which still exceeds the 4200 psi structural integrity performance criterion. Four cycles (6 EFPY) is the maximum inspection interval that can be demonstrated using the depth-based Monte Carlo approach. Since the largest indication returning to service is greater than the 95th percentile detection threshold for bobbin inspection, this conclusion also applies to the assumed undetected indications of U-bend support structure wear.

For pressure-only loading of volumetric flaws, satisfaction of the structural integrity implies satisfaction of leakage integrity at accident conditions since steam line break accident condition pressure differential for pop-through is much smaller than 3PNO. Therefore, it is projected that both detected and assumed undetected indications of U-bend support structure wear will not violate the SG tube integrity performance criteria during the upcoming three-cycle operating interval until the Sequoyah U1R24 eddy current inspections.

4.1.1 Use of Volume-Based Wear Approach The Westinghouse software W-VOL (Reference 13) was utilized to further evaluate an inspection interval that can be considered by TVA should a Technical Specification amendment permit extension of the inspection intervals beyond the current licensing basis limits for Alloy 690 plants. The W-VOL code applies a volume-based approach towards calculating wear over time. This method can project flaw growth that is conservative, and more realistic, than when calculated using wear depth methods. Ultimately, this method demonstrates an increased operational assessment interval in which the SG performance criteria is maintained for a flaw distribution set.

Benchmark calculations are performed by W-VOL to establish plant-specific growth trends. This is useful when there is a large amount of data from at least three consecutive inspections for a particular degradation mechanism. In cases where the level of data necessary to make this a useful tool is not available, the user is directed to apply typical, but conservative, values for benchmark parameters per the W-VOL Users Documentation (Reference 13). This is the method that was used for OA calculations of U-bend structural support wear at Sequoyah Unit 1.

Data from different flaws were available from the Sequoyah Unit 1 R15 and R18 SG eddy current database.

Given this, two separate cases were run for each SG: Wear projection based on wear incurred from R15 to R21 (7.98 EFPY) and wear projection based on wear incurred from R18 to R21 (4.08 EFPY). For each SG, the resultant 95/50 burst pressure was limiting in the cases of projecting growth from R18 to R21. Therefore, the results from these W-VOL calculations are shown below in Table 4-2.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 14 of 31 Table 4-2: 95/50 Burst Pressures from WVOL Cases for U-Bend Structural Support Wear SG Beginning of Growth Period End of Growth Period Growth EFPY Max R21 Indication Remaining In-Service

(%TW)

Projection EFPY Largest Projected Flaw (including NDE Uncertainty)

(%TW) 95/50 Burst Pressure (psi) 1 R18 R21 4.08 28 7.5 54.4 4314 2

R18 R21 4.08 21 7.5 47.6 4907 3

R18 R21 4.08 24 7.5 46.4 4901 4

R18 R21 4.08 23 7.5 54.4 4376 As evident in Table 4-2, the flaw population in all SGs meet the performance criteria of 4200 psi at 95%

probability and 50% confidence levels for five cycles (7.5 EFPY) of operation. When attempting to calculate a six cycle (9.0 EFPY) OA, the SG1 flaw set failed the SG burst performance criteria with a 95/50 burst pressure of 3985 psi.

4.2 Mechanical Wear at Horizontal ATSGs Based on application of conservative horizontal ATSG wear growth rates, the condition of the Sequoyah Unit 1 RSG tubes has been analyzed with respect to continued operability without exceeding the limits for structural and leakage integrity. Upon completion of the bobbin and Array probe data program, the growth rates have been determined by comparative analysis of the ATSG wear sites. The growth rates are determined given an operating duration of 3.97 EFPY from U1C15 to U1C18 and 4.08 EFPY from U1C18 to U1C21 and normalizing to a %TW/EFPY basis. A conservative growth rate assumption is made that the horizontal wear indications showing no detectable degradation at U1R15 grew from 0%TW at U1C18 to their measurement at U1R21. This is considered a reasonable assumption given the growth history of the horizontal ATSG wear indications. The results of the comparative analysis for the purpose of developing a representative growth rate are shown in Attachment 4 Table A4-1.

The ETSS 96004.1 Revision 13 is the bobbin technique used to size horizontal ATSG wear. As a result, the associated sizing equation (y = 0.98x + 2.89 and Syx = 4.19%) is appropriate for the character of ATSG wear indications that have been detected in the Sequoyah Unit 1 RSGs. This technique is part of the Appendix H ETSS library in the Reference 1 guidelines and, therefore, a factor of 1.12 will be applied to the technique standard error in order to account for analyst uncertainty for OA purposes.

An arithmetic OA approach is applied first to demonstrate that the SG performance criteria are met. With the largest flaw being returned to service measured at 22% TW, and the largest observed growth rate from a single indication of 4.17 %TW/EFPY being applied, the OA is calculated as follows.

124 22% 0.98 2.89% 1.645 1.12 4.19% 4.17%

4.5 51.0%

The CM limit for mechanical wear at horizontal ATSGs is 48% TW from Attachment 2. Therefore, a Monte Carlo OA approach is applied.

The Westinghouse configured software SFM Version 2.2 has been used for the OA projection using the inputs discussed above and material properties from the Reference 3 DA. The associated software runs are attached to this document in EDMS and the configuration control is documented in Reference 10. With this software, the burst pressure of projected flaws is determined through the Monte Carlo simulation method described in

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 15 of 31 Reference 5 and compared against the structural and leakage integrity performance criteria and consider 95/50 contributions from depth, relation, material and growth in the reduction in tube burst pressure.

The largest indication returning to service following Sequoyah U1R21 measures 22% TW in SG2 tube R5C37 at H02 and will be in service for an assumed 4.5 EFPY. The single largest growth rate of 4.17%TW/EFPY in horizontal ATSG wear locations also occurred in SG2 tube R5C37 and will be used for the OA projections.

Using the single largest growth rate data point and a 2.0-inch bounding length for horizontal ATSG wear the projected flaw has a burst pressure of 4802 psi (47% TW). This burst pressure is in excess of the 4200 psi structural integrity performance criterion. When performing a 6.0 EFPY OA using this method and inputs, the EOC 95/50 burst pressure associated with the largest returned to service flaw of 22% TW is 4240 psi, which still exceeds the 4200 psi structural integrity performance criterion. Four cycles (6 EFPY) is the maximum inspection interval that can be demonstrated using the depth-based Monte Carlo approach. Since the largest indication returning to service is greater than the 95th percentile detection threshold for bobbin inspections, this conclusion also applies to the assumed undetected indications of horizontal ATSG wear.

For pressure-only loading of volumetric flaws, satisfaction of the structural integrity implies satisfaction of leakage integrity at accident conditions since steam line break accident condition pressure differential for pop-through is much smaller than 3PNO. Therefore, it is projected that both detected and assumed undetected indications of horizontal ATSG wear will not violate the SG tube integrity performance criteria during the three-cycle operating interval until the Sequoyah U1R24 eddy current inspections.

4.2.1 Use of Volume-Based Wear Approach When applying the constant growth rate of 4.17% TW/EFPY (noted above for wear at horizonal ATSG intersections) for an OA period of 7.5 EFPY, the resultant 95/50 burst pressure is 3700 psi, which is far less than the SG performance criteria. Therefore, an evaluation utilizing W-VOL was also performed for the mechanical wear indications observed at horizontal ATSGs observed during the most recent R21 inspection to gain additional margin.

As with the U-bend structural support wear calculation, typical, but conservative, values were used in lieu of benchmark data per the W-VOL Users Documentation (Reference 13). Table 4-3 below shows the W-VOL output for a six-cycle OA (9 EFPY) for this degradation mechanism. One computer simulation was performed which included projected growth for indications in all four SGs. The projected flaw sizes (including NDE uncertainties) are less than the structural limit of 59% TW and the 95/50 burst pressure exceeds the performance criteria of 4200 psi and therefore is acceptable.

Table 4-3: 95/50 Burst Pressures from WVOL Cases for ATSG Tube Wear SG Beginning of Growth Period End of Growth Period Growth EFPY Maximum R21 Indication Remaining In-Service

(%TW)

Projection EFPY Largest Projected Flaw (including NDE Uncertainty)

(%TW) 95/50 Burst Pressure (psi) 1-4 (Note 1)

R18 R21 4.08 22 9.0 53.9 4519 Note 1: Flaws from all SGs including in same computer simulation with maximum flaw referenced in table above.

4.3 SG Secondary Side Foreign Objects During Sequoyah U1R21 there were three signals corresponding to new PLPs. There were PLP indications reported at the top of the tubesheet in both SG1 and SG3. All PLP indications were visually inspected from the secondary side and any associated foreign objects or loose parts were retrieved or evaluated for continued operation. There was no tube degradation detected by eddy current or visual inspection coincident with these

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 16 of 31 PLP indications. As a result, no degradation is anticipated as a result of these PLP indications in the upcoming operating interval.

For the objects known to be remaining in the SG secondary side following U1R21, the analysis performed in Reference 7 establishes that at least six cycles or 9.0 EFPY of operating time would accrue before the object with the greatest potential to cause tube wear degradation could potentially exceed the tube structural limit.

Furthermore, for tube wear to approach 3P burst dimensions, the depth must exceed the structural limit for the degraded tube length. The axial flaw lengths calculated for the remaining foreign objects are expected to be much less than the 3.0 inch or greater assumed foreign object wear flaw corresponding to the 50% TW structural limit.

For pressure-only loading of volumetric flaws, satisfaction of the structural integrity implies satisfaction of leakage integrity at accident conditions since steam line break accident condition pressure differential for pop-through is much smaller than 3PNO. Therefore, it is projected that there will be no challenge to the Sequoyah Unit 1 SG structural and leakage integrity performance criteria relative to this degradation mechanism before the next scheduled eddy current inspections.

4.4 Operational Assessment Conclusions An operational assessment is performed to assess whether degradation mechanisms observed in a plant will continue to meet the SG tube structural and leakage integrity performance criteria at the end of the upcoming inspection interval. Based on application of conservative U-bend support structure and horizontal ATSG wear growth rates, the condition of the Sequoyah Unit 1 RSG tubes has been analyzed with respect to continued operability of the SGs without exceeding the SG tube integrity performance criteria. The growth rates were determined by comparative analysis of U-bend support structure and horizontal ATSG wear sites for all SGs.

The operational assessment projections for mechanical tube wear mechanisms (U-bend structural support wear and ATSG horizontal support wear), performed using several different methods, show that conditions exceeding the SG integrity performance criteria will not occur in any of the four SGs at Sequoyah Unit 1 during the next inspection interval. The OA performed using the WVOL computer program demonstrated tube integrity is maintained for the next 7.5 EFPY. The assessment of the foreign objects remaining in the SG supports this conclusion as no adverse effects on tube integrity are projected within the next 7.5 EFPY. The results of this evaluation can be used should industry and plant licensing requirements be adjusted to accommodate such an approach towards SG program management.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 17 of 31 5.0 References

1.

Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 8, EPRI, Palo Alto, CA: 2016. 3002007572.

2.

Steam Generator Program Guidelines, NEI 97-06, Revision 3, January 2011.

3.

Westinghouse Document SG-SGMP-16-12, Revision 1, Sequoyah U1R21 Steam Generator Degradation Assessment, December 2016.

4.

Steam Generator Degradation Specific Management: Steam Generator Degradation Specific Management Flaw Handbook, Revision 2. EPRI, Palo Alto, CA: 2015. 3002005426.

5.

Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision

4. EPRI, Palo Alto, CA: 2016. 3002007571.

6.

Steam Generator Management Program: Steam Generator In Situ Pressure Test Guidelines, Revision 4, EPRI, Palo Alto, CA: 2012. 1025132.

7.

Westinghouse Letter LTR-SGMP-16-82, Revision 1, Evaluation of Foreign Objects in the Secondary Side of the Sequoyah Unit 1 Steam Generators - Fall 2016 U1R21 Outage, October 2019.

8.

Sequoyah Nuclear Plant Document 0-SI-SXI-068-114.4, Revision 1, Steam Generator Tubing Inservice Inspection and Augmented Inspections, May 2016.

9.

Tennessee Valley Authority Document EDMS # L18 161110800, Latest Revision, Sequoyah Nuclear Power Plant Unit 1 Use of Appendix H and Appendix I Qualified Techniques U1R21 Outage, December 2016.

10. Westinghouse Letter LTR-SGMP-14-59, Software Release Letter for Single Flaw Model Version 2.2, August 2014.

11. Sequoyah Unit 1 SG Channel Head Primary Examination Reports, December 2016. (Attached in EDMS)

12. Tennessee Valley Authority Document, Degradation Assessment and Operational Assessment Technical Review and Justification for not Performing Primary or Secondary Inspections of the Steam Generators SQN U1R20 Outage, April 2015. Attached to this document in EDMS.

13. Westinghouse Letter RT-LTR-18-45, Rev. 0, Software Release Letter for W-VOL Version 1.0, February 2018.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 18 of 31 - Sequoyah U1R21 As-Implemented SG Inspection Scope

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 19 of 31

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 20 of 31

- Sequoyah U1R21 SG Tube Structural and Condition Monitoring Limits Degradation Mechanism Plugging Structural Limit Condition Monitoring Limit Existing Wear at U-bend Support Structures 40% TW 59% TW for 2.5 inch 47% TW for 2.5" 96004.1 Revision 13 Wear at Horizontal ATSGs 40% TW 59% TW for 2.0 inch 48% TW for 2.0" 96004.1 Revision 13 Potential Wear due to Foreign Objects 40% TW 60% TW for 1.5 inch 40% TW for 1.5" 21998.1 Revision 4 Tube-to-Tube Contact Wear 40% TW 59% TW for 2.0 inch 52% TW for 2.0" 27905.2 Revision 2 Pitting in the Sludge Pile Region Plug on Detection 73% TW for 0.3 inch 53% TW for 0.3" 21998.1 Revision 4 Note: The structural and condition monitoring limits identified in this table are from the Reference 3 degradation assessment.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 21 of 31

- Sequoyah U1R21 U-bend Support Structure Wear Indications Table A3-1: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG1 SG Row Col Locn Inch1 Ind Per

(%TW) 20161 Per

(%TW) 20121 Per

(%TW) 20071 Delta

%TW/EFPY 1

74 48 VS3

-0.82 PCT 9

9 0.0 1

83 49 VS2 1.02 PCT 18 11 1.7 1

88 52 VS3 0.94 PCT 21 16 1.2 1

88 52 VS4

-0.97 PCT 16 8

2.0 1

65 53 VS2 0.44 PCT 20 02 4.9 1

30 54 VS3

-0.2 PCT 24 16 2.0 1

75 55 VS2

-0.72 PCT 15 12 0.4 1

69 59 VS3 1.15 PCT 4

6

-0.5 1

87 59 VS4

-0.95 PCT 16 11 0.6 1

97 61 VS4 0.63 PCT 18 10 1.0 1

95 61 VS4 0.8 PCT 19 10 1.1 1

97 63 VS2 0.94 PCT 19 10 1.1 1

95 63 VS3

-0.35 PCT 23 18 1.2 1

95 63 VS4

-1.07 PCT 20 12 2.0 1

84 64 VS4 1.13 PCT 22 15 1.7 1

98 64 VS5 1.29 PCT 21 9

1.5 1

98 64 VS5 0.62 PCT 18 8

1.2 1

98 64 VS5

-0.09 PCT 16 6

1.2 1

93 65 VS2 0.51 PCT 20 13 1.7 1

85 65 VS4 0.72 PCT 21 14 1.7 1

98 66 VS4

-0.68 PCT 15 02 3.7 1

70 66 VS4

-1.31 PCT 22 17 1.2 1

98 66 VS5 1.01 PCT 21 19 0.5 1

85 67 VS4 0.61 PCT 22 18 1.0 1

92 68 VS2 1.25 PCT 18 18 0.0 1

92 68 VS4 0.54 PCT 26 20 1.5 1

92 68 VS4 0

PCT 20 20 0.0 1

99 69 VS3 0.89 PCT 20 8

1.5 1

94 70 VS1

-0.53 PCT 20 9

1.4 1

92 70 VS2

-0.98 PCT 21 16 1.2 1

94 70 VS3

-0.22 PCT 17 9

1.0 1

92 70 VS4 0.95 PCT 22 22 0.0 1

90 70 VS4 0.68 PCT 36 16 4.9 1

90 70 VS4

-0.03 PCT 25 16 2.2 1

90 70 VS4

-1.28 PCT 22 16 1.5 1

88 70 VS4

-1.4 PCT 22 18 1.0 1

97 71 VS1

-1.22 PCT 17 7

1.2 1

92 72 VS2 1.16 PCT 19 8

1.4 1

87 73 VS2 1.11 PCT 23 19 1.0 1

75 73 VS2 0.87 PCT 18 15 0.7 1

87 73 VS3 1.09 PCT 28 19 2.2 1

75 73 VS3 1.01 PCT 28 20 2.0 1

67 73 VS3 0.06 PCT 15 4

1.4 1

88 74 VS2 0.83 PCT 19 7

1.5 1

92 74 VS4 0.78 PCT 17 7

1.2 1

68 76 VS2

-0.23 PCT 15 6

2.2 1

96 76 VS3 1.16 PCT 20 12 2.0 1

83 77 VS2 0.88 PCT 17 11 1.5 1

95 77 VS4

-1.16 PCT 17 11 1.5 1

78 78 VS2 1.11 PCT 21 13 2.0 1

88 78 VS5 1.9 PCT 21 4

2.1

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 22 of 31 1

96 80 VS2 1.05 PCT 19 10 1.1 1

96 80 VS3

-0.95 PCT 22 10 1.5 1

96 80 VS4

-1.2 PCT 16 7

1.1 1

93 81 VS2 0.99 PCT 18 10 1.0 1

85 81 VS2 0.96 PCT 19 9

1.2 1

89 81 VS4 0.6 PCT 21 11 1.2 1

87 81 VS4

-1.19 PCT 21 18 0.7 1

76 82 VS3

-0.8 PCT 21 5

2.0 1

98 82 VS5

-1.41 PCT 19 11 1.0 1

95 83 VS2 1.13 PCT 20 10 1.2 1

90 84 VS4

-1.43 PCT 17 8

1.1 1

61 85 VS2

-1.13 PCT 16 9

1.7 1

92 86 VS4 0.23 PCT 19 8

1.4 1

92 86 VS5 1.18 PCT 25 9

2.0 1

93 87 VS3

-0.74 PCT 19 7

1.5 1

92 88 VS3 0.72 PCT 18 12 1.5 1

92 88 VS4

-1.04 PCT 18 13 1.2 1

70 98 VS2 0.97 PCT 16 5

1.4 1

76 100 VS2

-1.03 PCT 23 18 1.2 1

76 102 VS2

-0.65 PCT 25 18 1.7 1

71 107 VS3

-0.94 PCT 18 7

1.4 1

66 110 VS3 0.51 PCT 16 8

2.0 1

62 112 VS3 0.87 PCT 16 10 1.5 1

55 115 VS3

-1.4 PCT 17 10 1.7 Note 1: Determined either from production data results or lead analyst review of raw eddy current data history. Although certain indications were present in 2007, 2012 and 2016, only the two most recent data points are shown in order for growth rate determination.

Note 2: Indication was NDD at the 2007 inspection, conservatively assume initiation from 0%TW following the 2012 inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 23 of 31 Table A3-2: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG2 SG Row Col Locn Inch1 Ind Per

(%TW) 20161 Per

(%TW) 20121 Per

(%TW) 20071 Delta

%TW/EFPY 2

63 15 VS4 1.03 PCT 18 9

1.1 2

70 18 VS4 1.05 PCT 17 9

1.0 2

68 18 VS4 0.71 PCT 17 9

1.0 2

71 19 VS4 1.05 PCT 18 7

1.4 2

73 21 VS4 0.98 PCT 17 6

1.4 2

75 21 VS4 0.95 PCT 20 9

1.4 2

76 22 VS2 1.03 PCT 20 7

1.6 2

77 23 VS4 0.89 PCT 19 7

1.5 2

78 24 VS2 1.08 PCT 21 8

1.6 2

81 25 VS4 1.18 PCT 16 5

1.4 2

81 27 VS4 0.85 PCT 15 3

1.5 2

83 27 VS4 0.9 PCT 20 10 1.2 2

74 28 VS2 0.88 PCT 18 6

1.5 2

91 37 VS4 0.67 PCT 19 8

1.4 2

89 39 VS4 0.66 PCT 15 6

1.1 2

92 42 VS2

-0.83 PCT 21 11 2.5 2

77 49 VS3

-0.69 PCT 17 7

1.2 2

77 49 VS2 0.92 PCT 19 5

1.7 2

89 51 VS4 0.68 PCT 16 4

1.5 2

94 52 VS1

-0.76 PCT 18 4

1.7 2

94 52 VS2 1.27 PCT 21 4

2.1 2

93 59 VS4

-1.05 PCT 18 7

1.4 2

86 64 VS2 1.2 PCT 16 02 3.9 2

68 68 VS4 0.8 PCT 16 02 3.9 2

97 69 VS3 0.88 PCT 16 5

1.4 2

100 70 VS3

-0.58 PCT 18 6

1.5 2

20 80 VS3 0

PCT 20 12 2.0 2

78 84 VS3 1.28 PCT 17 6

1.4 2

24 84 VS3

-1 PCT 19 4

1.9 Note 1: Determined either from production data results or lead analyst review of raw eddy current data history. Although certain indications were present in 2007, 2012 and 2016, only the two most recent data points are shown in order for growth rate determination.

Note 2: Indication was NDD at the 2007 inspection, conservatively assume initiation from 0%TW following the 2012 inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 24 of 31 Table A3-3: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG3 SG Row Col Locn Inch1 Ind Per

(%TW) 20161 Per

(%TW) 20121 Per

(%TW) 20071 Delta

%TW/EFPY 3

36 50 VS3

-0.15 PCT 18 11 1.7 3

96 52 VS3

-0.12 PCT 17 7

1.2 3

96 52 VS4 1.06 PCT 15 6

1.1 3

47 53 VS2 1.03 PCT 16 16 0.0 3

64 54 VS2

-1.22 PCT 15 4

1.4 3

100 56 VS3 1.04 PCT 16 6

1.2 3

96 56 VS3 0.95 PCT 19 9

1.2 3

98 56 VS4

-1.04 PCT 24 17 1.7 3

101 57 VS3 0.77 PCT 17 6

1.4 3

101 57 VS4 0.77 PCT 16 7

1.1 3

91 61 VS4

-0.95 PCT 15 6

1.1 3

94 62 VS3 1.48 PCT 17 9

1.0 3

87 63 VS2 1.39 PCT 21 13 2.0 3

87 65 VS3 0.89 PCT 23 17 1.5 3

91 69 VS2 0.73 PCT 19 6

1.6 3

89 69 VS4

-0.88 PCT 20 8

1.5 3

85 69 VS4 0.82 PCT 22 14 2.0 3

77 69 VS4 0.84 PCT 17 6

1.4 3

75 69 VS4 0.63 PCT 21 6

1.9 3

97 71 VS3 0.76 PCT 16 7

2.2 3

89 71 VS4 1.04 PCT 17 7

2.5 3

80 72 VS4

-0.86 PCT 19 11 2.0 3

91 73 VS4 0.71 PCT 18 9

1.1 3

67 75 VS2 1.24 PCT 18 7

1.4 3

73 75 VS3 0.84 PCT 17 8

2.2 3

66 76 VS2 1

PCT 16 4

1.5 3

77 77 VS2 0.97 PCT 20 7

1.6 3

79 79 VS2

-0.71 PCT 17 7

2.5 3

79 79 VS3 0.88 PCT 20 11 2.2 3

34 80 VS3

-0.37 PCT 19 8

2.7 3

77 81 VS2 0.81 PCT 19 7

1.5 3

67 81 VS2 0.85 PCT 19 6

1.6 3

67 81 VS3

-0.75 PCT 17 8

1.1 3

76 82 VS2 1.03 PCT 18 5

1.6 3

73 87 VS3

-0.49 PCT 20 9

1.4 3

67 87 VS3

-0.71 PCT 17 4

3.2 3

76 90 VS2 0.79 PCT 19 9

2.5 3

71 91 VS2 1.13 PCT 16 4

1.5 3

78 92 VS3

-0.87 PCT 18 9

1.1 3

76 92 VS3

-0.83 PCT 19 8

1.4 3

70 92 VS3

-0.74 PCT 19 6

1.6 3

68 96 VS3

-0.81 PCT 19 6

1.6 3

73 103 VS2 0.88 PCT 18 02 4.4 3

66 106 VS2

-0.66 PCT 19 5

1.7 3

66 106 VS3 0.73 PCT 19 7

1.5 3

59 113 VS4 1.15 PCT 19 8

1.4 Note 1: Determined either from production data results or lead analyst review of raw eddy current data history. Although certain indications were present in 2007, 2012 and 2016, only the two most recent data points are shown in order for growth rate determination.

Note 2: Indication was NDD at the 2007 inspection, conservatively assume initiation from 0%TW following the 2012 inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 25 of 31 Table A3-4: Sequoyah U1R21 U-bend Support Structure Wear Indications - SG4 SG Row Col Locn Inch1 Ind Per

(%TW) 20161 Per

(%TW) 20121 Per

(%TW) 20071 Delta

%TW/EFPY 4

92 38 VS2 0.8 PCT 16 8

1.0 4

27 45 VS3 0.07 PCT 18 9

2.2 4

95 47 VS3 1.2 PCT 16 13 0.4 4

95 47 VS3

-0.72 PCT 17 5

1.5 4

96 48 VS3

-0.8 PCT 22 10 1.5 4

97 49 VS3

-0.72 PCT 15 6

1.1 4

56 50 VS3 0.14 PCT 19 02 4.7 4

98 52 VS3

-0.55 PCT 17 11 1.5 4

30 54 VS3

-0.2 PCT 21 14 1.7 4

99 55 VS2

-0.79 PCT 23 6

2.1 4

97 55 VS2

-0.72 PCT 16 10 1.5 4

99 55 VS3

-0.24 PCT 17 6

1.4 4

55 55 VS3 0.11 PCT 17 12 1.2 4

97 55 VS4

-0.45 PCT 15 10 1.2 4

97 55 VS4

-1.01 PCT 17 10 1.7 4

58 56 VS3

-0.47 PCT 22 02 5.4 4

50 60 VS3

-0.21 PCT 17 11 1.5 4

28 62 VS3

-1.07 PCT 19 10 2.2 4

99 63 VS5 0.96 PCT 16 02 3.9 4

70 64 VS2 0.64 PCT 16 5

1.4 4

68 64 VS3

-0.76 PCT 18 11 1.7 4

70 64 VS4 0.73 PCT 16 6

1.2 4

70 66 VS2 0.94 PCT 15 02 3.7 4

62 74 VS2

-0.74 PCT 15 3

1.5 4

45 75 VS3 0.03 PCT 21 12 2.2 4

45 79 VS3

-0.69 PCT 21 11 2.5 4

51 85 VS3 0.06 PCT 21 11 2.5 Note 1: Determined either from production data results or lead analyst review of raw eddy current data history. Although certain indications were present in 2007, 2012 and 2016, only the two most recent data points are shown in order for growth rate determination.

Note 2: Indication was NDD at the 2007 inspection, conservatively assume initiation from 0%TW following the 2012 inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 26 of 31 Figure A3-1: Sequoyah U1R21 U-bend Support Structure Wear Indications in All SGs - Tubesheet Map 0

20 40 60 80 100 0

20 40 60 80 100 120 Tube Row Tube Column SG1 VS SG2 VS SG3 VS SG4 VS Plugged Tubes Note: A small number of tube locations have wear indications in the same tube in multiple SGs. Therefore, some data points are plotted on top of each other on this map.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 27 of 31 Figure A3-2: Sequoyah U1R21 U-bend Wear Growth Distributions - All SGs

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 28 of 31 Figure A3-3: Sequoyah U1R21 Plugged U-bend Support Structure Wear Indication - SG1 R90C70 VS4 Array Graphic 2016 Figure A3-4: Sequoyah U1R21 Plugged U-bend Support Structure Wear Indication - SG1 R90C70 VS4 +Point Graphic 2012

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 29 of 31

- Sequoyah U1R21 ATSG Wear Indications Table A4-1: Sequoyah U1R21 ATSG Wear Indications - All SGs SG Row Col Locn Inch1 Ind Per

(%TW) 2016 Per

(%TW) 2012 Per

(%TW) 20071 Delta

%TW/EFPY 1

98 82 C07 0.67 PCT 17 3

3.43 1

98 72 C07 0.57 PCT 19 8

1.37 1

98 70 C07 0.69 PCT 20 11 1.12 1

4 36 C06

-0.99 PCT 15 6

2.21 2

5 37 H02 0.57 PCT 22 5

4.17 2

5 37 H02

-0.94 PCT 17 8

2.21 2

10 102 C05

-0.86 PCT 17 7

2.45 3

5 33 H06

-0.95 PCT 17 7

2.45 4

11 33 H03

-1.13 PCT 17 5

2.94 Note 1: Based on lead analyst review of raw eddy current data history. No ATSG wear was detected in any tube during the 2007 inspection and these tubes were not tested during the 2012 inspection.

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 30 of 31 Figure A4-1: Sequoyah U1R21 Horizontal ATSG Wear Indications in All SGs - Tubesheet Map 0

20 40 60 80 100 0

20 40 60 80 100 120 Tube Row Tube Column SG1 ATSG SG2 ATSG SG3 ATSG SG4 ATSG Plugged Tubes

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

SG-SGMP-16-15 October 2019 Revision 1 Page 31 of 31 Figure A4-2: Sequoyah U1R21 Horizontal ATSG Wear Indications in All SGs - 3D Map Red = Hot Leg Indication Blue = Cold Leg Indication Figure A4-2: Sequoyah U1R21 Horizontal ATSG Wear Indications in All SGs - 3D Map H/C03 H/C01 H/C02 H/C04 H/C05 H/C06 H/C07 Tubesheet

• • • This record was final approved on 11/7/2019 11:23:16 AM. (This statement was added by the PRIME system upon its validation)

CNL-20-076 Revised TS Changes (Mark-Ups) for SQN Unit 1

Programs and Manuals 5.5 5.5 Programs and Manuals SEQUOYAH - UNIT 1 5.5-6 Amendment 334, XXX 5.5.7 Steam Generator (SG) Program (continued)

2.

Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG.

3.

The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

c.

Provisions for SG tube plugging criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

d.

Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube plugging criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1.

Inspect 100% of the tubes in each SG during the first refueling outage following SG installation.

2.

After the first refueling outage following SG installation, inspect each SG at least every 7296 effective full power months. Tube inspections shall be performed using equivalent to or better than array probe technology. For regions where a tube inspection with array probe technology is not possible (such as due to dimensional constraints or tube specific conditions), the tube inspection techniques applied shall be capable of detecting all forms of existing and potential degradation in that region. or at least every third refueling outage (whichever results in more frequent inspections). In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a and, b, c, and d below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of

Programs and Manuals 5.5 5.5 Programs and Manuals SEQUOYAH - UNIT 1 5.5-7 Amendment 334, XXX degradation at this location and that may satisfy 5.5.7 Steam Generator (SG) Program (continued) the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a)

After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months.

This constitutes the first inspection period; b)

During the next 96120 effective full power months, inspect 100%

of the tubes. This constitutes the second and subsequent inspection periods.

c)b) During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the third inspection period; and d)

During the remaining life of the SGs, inspect 100% of the tubes every 72 effective full power months. This constitutes the fourth and subsequent inspection periods.

3.

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

CNL-20-076 Revised TS Changes (Final Typed) for SQN Unit 1

Programs and Manuals 5.5 5.5 Programs and Manuals SEQUOYAH - UNIT 1 5.5-6 Amendment 334, XXX 5.5.7 Steam Generator (SG) Program (continued)

2.

Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG.

3.

The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

c.

Provisions for SG tube plugging criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

d.

Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube plugging criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. A degradation assessment shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1.

Inspect 100% of the tubes in each SG during the first refueling outage following SG installation.

2.

After the first refueling outage following SG installation, inspect each SG at least every 96 effective full power months. Tube inspections shall be performed using equivalent to or better than array probe technology. For regions where a tube inspection with array probe technology is not possible (such as due to dimensional constraints or tube specific conditions), the tube inspection techniques applied shall be capable of detecting all forms of existing and potential degradation in that region. In addition, the minimum number of tubes inspected at each scheduled inspection shall be the number of tubes in all SGs divided by the number of SG inspection outages scheduled in each inspection period as defined in a and b below. If a degradation assessment indicates the potential for a type of degradation to occur at a location not previously inspected with a technique capable of detecting this type of degradation at this location and that may satisfy

Programs and Manuals 5.5 5.5 Programs and Manuals SEQUOYAH - UNIT 1 5.5-7 Amendment 334, XXX 5.5.7 Steam Generator (SG) Program (continued) the applicable tube plugging criteria, the minimum number of locations inspected with such a capable inspection technique during the remainder of the inspection period may be prorated. The fraction of locations to be inspected for this potential type of degradation at this location at the end of the inspection period shall be no less than the ratio of the number of times the SG is scheduled to be inspected in the inspection period after the determination that a new form of degradation could potentially be occurring at this location divided by the total number of times the SG is scheduled to be inspected in the inspection period. Each inspection period defined below may be extended up to 3 effective full power months to include a SG inspection outage in an inspection period and the subsequent inspection period begins at the conclusion of the included SG inspection outage.

a)

After the first refueling outage following SG installation, inspect 100% of the tubes during the next 144 effective full power months.

This constitutes the first inspection period; b)

During the next 96 effective full power months, inspect 100% of the tubes. This constitutes the second and subsequent inspection periods.

3.

If crack indications are found in any SG tube, then the next inspection for each affected and potentially affected SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever results in more frequent inspections). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.