ML24298A117

Cycle 26, 180-Day Steam Generator Tube Inspection Report

ML24298A117
Person / Time
Site:	Sequoyah
Issue date:	10/24/2024
From:	Marshall T Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
Download: ML24298A117 (1)

Text

October 24, 2024 10 CFR 50.4 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Unit 1 Renewed Facility Operating License No. DPR-77 NRC Docket No. 50-327

Subject:

Unit 1 Cycle 26 - 180-Day Steam Generator Tube Inspection Report In accordance with Sequoyah Nuclear Plant (SQN), Unit 1, Technical Specification Section 5.5.7, Steam Generator (SG) Program, and Section 5.6.6, Steam Generator Tube Inspection Report, the Tennessee Valley Authority is submitting the 180-day SG Tube Inspection Report that includes the results of inservice inspections performed on Unit 1 SGs during the Unit 1 Cycle 26 refueling outage. Initial entry into MODE 4 following SQNs Unit 1 Cycle 26 refueling outage was completed on April 27, 2024, therefore; the due date for this report is October 24, 2024.

There are no new regulatory commitments contained in this letter. If you have any questions concerning this report, please contact Mr. Rick Medina, Site Licensing Manager, at (423) 843-8129 or rmedina4@tva.gov.

Respectfully, Thomas Marshall Site Vice President Sequoyah Nuclear Plant

Enclosure:

Unit 1 Cycle 26 180-Day Steam Generator Tube Inspection Report cc: See Page 2

Marshall, Thomas B.

Digitally signed by Marshall, Thomas B.

Date: 2024.10.24 08:10:03 -04'00' Sequoyah Nuclear Plant, Post Office Box 2000, Soddy Daisy, Tennessee 37384

U.S. Nuclear Regulatory Commission Page 2 October 24, 2024 Enclosure cc (Enclosure):

NRC Regional Administrator - Region II NRC Senior Resident Inspector - Sequoyah Nuclear Plant

ENCLOSURE TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT UNIT 1 CYCLE 26 180-DAY STEAM GENERATOR TUBE INSPECTION REPORT

Sequoyah U1R26 180 Day Steam Generator Tube Inspection Report Author:

Virginia Allen SG Program Engineer Verifiers:

Emmett Camp SG Program Engineer Connor Rigsby SG Program Engineer Allen, Virginia Ann Signature/ Date Digitally signed by Allen, Virginia Ann Date: 2024.10.10 13:13:17

-04'00' Digitally signed by Camp, Camp, Emmett D. EmmettD.

Date: 2024.10.15 07:30:14 -04'00' Signature/ Date R *, g S by Conn Or Digitally signed by Rigsby, Connor Date: 2024.10.15 08:21 :48 -04'00' Signature/ Date Digitally signed by Folsom, Daniel P.

Reviewers:

Folsom, Daniel ON: dc=gov, dc=tva, dc=main, ou=Main, ou=Remote Sites, P

ou=Users, ou=SQN, cn=Folsom, Daniel P., email=dpfolsom@tva.gov Reason: I am the author of this document Location:CLS Daniel P. Folsom NOE Eddy Current Level Ill Robert Himmelspach NOE Eddy Current Level II-A Ryan Spencer SG Program Manager Signature/ Date Himmelspach, Robert John Signature/ Date 1/2-~---

Signature/ Date Date: 2024.10.17 10:32:12 --04'00' Digitally signed by Himmelspach, Robert John Date: 2024.10.15 1 0:24:27 -04'00' Digitally signed by Spencer, Ryan S Date: 2024.10.15 12:35:13 -04'00' 1

Table of Contents I.

Introduction.......................................................................................................................................... 4 II.

180-day Report according to EPRI Guidelines and Technical Specifications......................................... 4

1.

Design and operating parameters..................................................................................................... 4

2.

Scope of inspections......................................................................................................................... 5

3.

The nondestructive examination techniques utilized for tubes with increased degradation susceptibility............................................................................................................................................. 6

4.

The nondestructive examination technique utilized for each degradation mechanism found........ 6

5.

The location, orientation (if linear), measured size (if available), and voltage responses of each indication. For tube wear at support structures less than 20% TW, only the total number of indications needs to be reported................................................................................................................................ 7

6.

A description of the condition monitoring assessment and results................................................. 7

7.

The number of tubes plugged [or repaired] during the inspection outage...................................... 8

8.

The repair method utilized, and the number of tubes required by each repair method................. 9

9.

An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results. The effective full power months of operation permitted for the current operational assessment................................................................................... 9

10.

The number and percentage of tubes plugged [or repaired] to date, and the effective plugging percentage in each SG............................................................................................................................. 11

11.

The results of any SG secondary-side inspection. The number, type, and location (if available) of loose parts that could damage tubes removed or left in service in each SG......................... ;........... 12

12.

The scope, method, and the results of secondary-side cleaning performed in each SG............ 13

13.

The results of primary side component visual inspection performed in each SG...................... 14

14.

Any plant specific reporting requirements, if applicable............................................................ 14 Ill.

Summary......................................................................................................................................... 14 IV.

References........................................................................................................................................... 14

1.

Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines: Revision 8, EPRI, Palo Alto, CA: 2016. 3002007572.................................................................. 14

2.

Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 5. EPRI, Palo Alto, CA: 2016. 3002007571.................................................................................... 14

3.

Westinghouse Document, SG-CDMP-24-4, Revision 1, "Sequoyah 1R26 Steam Generator Condition Monitoring and Final Operational Assessment," July 2024........................................................................ 14

4.

TVA Document "Sequoyah 1R26 Steam Generator Degradation Assessment", Revision 0, March 2023............................................................................................................................................................ 15 2

5.

Westinghouse Report, SG-SGMP-16-15, Revision 1, "Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment," October 2019.......................................................................... 15 List of Tables Table 1 Steam Generator Design Parameters............................................................................................... 4 Table 2 Degradation Mechanisms and NOE Techniques............................................................................... 6 Table 3 Indications< 20% TW....................................................................................................................... 7 Table 4 Indications>/= 20% TW.................................................................................................................... 7 Table 5 Sequoyah U1R26 Condition Monitoring Summary.......................................................................... 7 Table 6 Plugging Percentage Over Time........................................................................................................ 9 Table 7 Tubes Plugged During U1R26........................................................................................................... 9 Table 8 Tube and Operating Parameter Inputs........................................................................................... 10 Table 9 NOE Measurement Sizing Uncertainty Inputs................................................................................ 10 Table 10 Sffluoyah Unit 1 Operational Assessment Summary................................................................... 11 Table 11 Sffluoyah U1R26 Loose Parts Detected by Tubesheet Visual Inspections................................... 12-13 Table 12 Sludge Weights After Lancing in U1R26........................................................................................ 13 3

I.

Introduction Inspections of the replacement steam generators (SGs) were performed during the Sequoyah Unit 1 (SQNl) spring 2024 refueling outage designated as (U1R26). These inspections included eddy current testing of the SG tubing as well as primary side visual inspections and secondary side cleanings as well as visual inspections. This report documents the "Sequoyah U1R26 180-Day Steam Generator Tube Inspection Report" as required by the SQNl Technical Specifications, TS 5.6.6, "A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.7, 'Steam Generator (SG) Program."'

The original steam generators at SQNl were replaced in 2003 with Westinghouse Model 57AG SGs which have thermally treated Alloy 690 tubing (Alloy 690 TT). The UlR21 inspection was the fifth in-service inspection of the replacement SGs. Prior to the U1R26 inspection, the replacement SGs had operated for 14 fuel cycles since replacement. The replacement SGs had operated for five fuel cycles since the previous inspection at UlR21.

II.

180-day Report according to EPRI Guidelines and Technical Specifications

1.

Design and operating parameters SG Model / Tube Material / # SGs per Unit Westinghouse Model 57AG I Alloy 690TT / 4

1. of tubes per SG / Nominal Tube Diameter / tube 4,983 I 0.75 in. / 0.043 in thickness Support Plate Style / Material Advance Tube Support Grid (ATSG)/ 409 Stainless Steel Last Inspection Date December 2016 EFPM Since Last Inspection 79.5 EFPM Total Cumulative SG EFPM 225.7 Mode 4 Initial Entry 4/27/2024 Observed Primary-to-Secondary Leak Rate No Detectable Leakage Nominal Thot at Full Power Operation 611°F Loose Parts Strainer The Model 57 AG design has spray can nozzles on the main feedwater distribution ring. Each nozzle has small diameter holes acting as strainers to prevent the introduction of foreign material into the steam generators.

Degradation Mechanism Sub-Population There are no sets of tubing currently designated as degradation mechanism sub-populations in the UIR26 operational assessment (OA).

SG program guideline deviations since last Inspection None Table 1 Steam Generator Design Parameters 4

I!Ui C 7 BU{,

~

(')

lltl!i t *o,

[]04

'I' t " *'

Hf!.:!:__.

~

1*02 lfll T5 Figure 1 Tube Support Arrangement for Sequoyah Unit 1 Model 57AG Replacement Steam Generators

2.

Scope of inspections The scope of the inspections performed on all 4 Ul steam generators included 100% of the in-service tubes. All plugs were visually inspected. A visual inspection of the inlet and outlet bowl cladding was performed.

100% bobbin coil inspection of all open tubes in all four SGs full length. This was accomplished with either a standard bobbin probe or a combination bobbin and array coil probe.

Array for all tubes identified in SG-CECO-21-002 Rev. 2 within the high fluid velocity or transition fluid velocity zones, plus a minimum of three periphery tubes deep.

o HL up to the first support 5

o CL up to the first support 100% array probe to inspect previously reported DNG/DNT/DDS > 2 volts plus any newly reported DNG/DNT/DDS > 2 volts in all SGs.

100% array probe of BLGs, GEOs, MBMs, and ADls is in all SGs.

Array probe Special Interest inspection of new and previous wear indications detected with the bobbin coil.

Array probe Special Interest inspections of tube locations with non-resolved bobbin probe signals from the base scope inspection to characterize the underlying condition.

Array probe Special Interest inspections of tube locations with non-resolved PLP signals from the base scope inspection program or if a foreign object is identified during secondary side inspection with identified tube wear. Inspect tubes surrounding all PLP signals to ensure tubes with possible wear have been fully discovered.

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

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

Bobbin and array probe data was collected in SG1 to support scale profiling.

A 100% bobbin coil probe full length inspection program and a minimum 3-tube deep array probe peripheral inspection was performed on the hot leg and cold leg of all four SGs at 1R26 with a focus on foreign object {FO) and FO wear detection. The array program extended beyond three tubes deep to ensure that the transition and high flow fluid velocity regions were inspected. Additionally, any metallic foreign object that was found during foreign object search and retrieval {FOSAR) was inspected and bounded with array probe special interest testing.

There was no eddy current nondestructive examination {NOE) scope expansion of the base inspection programs as required in the 1R26 DA. Targeted diagnostic inspections were performed as part of the special interest programs.

3.

The nondestructive examination techniques utilized for tubes with increased degradation susceptibility Tubes with increased degradation susceptibility are those in the high flow region. Those were inspected using the array program.

4.

The nondestructive examination technique utilized for each degradation mechanism found The NOE technique utilized for each degradation mechanism is listed in Table 2, below.

Degradation Mechanism Detection Technique EPRI ETSS Wear at U-bend Support Structures Bobbin or Bobbin w/ Array B: 96004.1, Revision 14 B: 96044.3, Revision 0 A: 17908.2, Revision 1 Wear at Horizontal A TS Gs Bobbin or Bobbin w/ Array B: 96004.1, Revision 14 B: 96041.1, Revision 8 A: 17908.2, Revision 1 Note: (B: ) indicates bobbin coil ETSSs and (A: ) indicates array probes ETSSs Table 2 Degradation Mechanisms and NOE Techniques 6

5.

The location, orientation (if linear), measured size (if available), and voltage responses of each indication. For tube wear at support structures less than 20% TW, only the total number of indications needs to be reported.

SG 1

4 In Table 3, below is a listing of the number of indications that are <20% through-wall (TW):

Total Total SG U-Bend ATSG Indications Tubes 1

140 15 155 4983 2

80 17 97 4983 3

83 4

87 4983 4

43 10 53 4983 Table 3 Indications< 20% TW There were only two indications >/=20% TW. The first is 22% TW in SGl and the second, 21% TW in SG 4, shown in Table 4, below.

Row Col Location lnchl Volts

%TW Length Degradation Probe 87 73 VS3 1.04 1.34 22 0.47 U-bend Wear Bobbin 29 61 VS3

-0.05 1.13 21 0.2 U-bend Wear Bobbin Table 4 Indications>/= 20% TW The indication in SG 1 was plugged. The indication in SG 4 was plugged and stabilized.

6.

A description of the condition monitoring assessment and results Based on the inspection data and t he CM assessment, no tubes exhibited degradation exceeding the CM limits. Table 5 provides a summary of the inspection results for the limiting flaw for each degradation mechanism as compared to the applicable CM limit. The SG performance criteria for operating leakage and structural integrity were satisfied for the preceding Sequoyah Unit 1 SG operating interval encompassing Cycle 22 through Cycle 26, thus meeting CM requirements.

Degradation Sizing Sizing Limiting Limiting Flaw Condition Margin to Flaw Depth Length

Limit, Mechanism Technique Probe (3/4TW)

(in)

Monitoring Limit (3/4TW)(l)

U-Bend Wear Depth:

Bobbin 22 1.55 48.9% TW at 1.55" 26.9 96004.1 ATSGWear Length:

17908.2 Bobbin 17 0.38 58.3% TW at 0.38" 41.3 Note:

(1) Margin to CM limit conservatively considers the maximum flaw depth and length, even though these did not occur at the same flaw Table 5 Sequoyah U1R26 Condinon Monitoring Summary 7

For the existing degradation mechanisms at Sequoyah Unit 1, U-Bend and ATSG wear, a comparison of the previous OA projections performed at 1R21 were compared to the 1R26 inspection results.

The OA methods of the 1R21 CMOA were used to project the 1R21 tube wear to 1R26. The 1R21 OA utilized three methods for projecting to 1R26: simplified arithmetic, Monte Carlo, and volume-based. The volume-based method was found to be the least conservative as it allowed the longest operating interval between inspections. This is typical for these OA methods and the expected result. Since the volume-based method was the least conservative, these results will be used in the comparative review against the 1R26 results.

For U-Bend wear, the 1R21 volume-based results show the maximum returned to service (RTS) flaws for each SG and the largest 7.5 EFPY projection:

SGl Max RTS of 28% TVV with largest projection of 54.4% TW SG2 Max RTS of 21% TVV with largest projection of 47.6% TW SG3 Max RTS of 24% TVV with largest projection of 46.4% TW SG4 Max RTS of 23% TVV with largest projection of 54.4% TW The 1R26 results showed that very little growth was observed from 1R21 to 1R26, with the maximum RTS U-Bend flaw measured at 22% TW. TVA had a new wear scar standard manufactured for 1R26 with an updated voltage-to-depth sizing correlation. For that reason, the 1R21 projections are not directly comparable to the 1R26 results. However, it is clear from the 1R26 results, that the previous volume-based projections are conservative. As a bounding approximation, the 7.5 EFPY projections were converted to a %TW/EFPY growth rate, with a maximum of 4.19%TW/EFPY observed in SG4. The maximum RTS U-Bend flaw measured at 1R21, resized with the new wear scar standard, was 19% TVV. A projection of this flaw at the approximated growth rate of 4.19%

TW/EFPY for the actual time of 6.626 EFPY from 1R21-1R26 is 46.7% TW at 1R26.

For ATSG wear, the 1R21 volume-based results show the maximum RTS flaws for all SG was 22%

TW and the 9 EFPY projection was 53.9% TW. The 1R26 results showed that very little growth was observed from 1R21 to 1R26, with the maximum RTS ATSG flaw measured at 17% TW. It is clear from the 1R26 results that the previous volume-based projections are conservative. As an approximation, the 9 EFPY projection was converted to a %TV\\/ /EFPY growth rate of 3.54%TW /EFPY.

The maximum RTS ATSG flaw measured at 1R21, resized with the new wear scar standard, was 16%

TW. A projection of this flaw at the approximated growth rate of 3.54% TW/EFPY for the actual time of 6.626 EFPY from 1R21-1R26 is 39.5% TW at 1R26.

Based on these results, the 1R21 OA assumptions, inputs, and methodologies for U-Bend and ATSG wear projections were conservative relative to the results observed at 1R26.

7.

The number of tubes plugged [or repaired] during the inspection outage 8

SQN has a plugging limit of 10%. With the plugging done in UlR26, plugging is well within the limit.

Plugging Prior to Plugging During Total U1R26 U1R26 Cumulative Plugging SG Tubes Count Percent Count Percent Count Percent 1

4983 16 0.32%

5 0.10%

21 0.42%

2 4983 6

0.12%

0 0.00%

6 0.12%

3 4983 7

0.14%

0 0.00%

7 0.14%

4 4983 5

0.10%

1 0.02%

6 0.12%

Total 19932 34 0.68%

6 0.12%

40 0.80%

Table 6 Plugging Percentage Over Time SG Row Col Ind Per Locn Plugging Basis Stabilization 1

87 73 PCT 22 VS3 No - no accelerated wear 1

98 66 PCT 19 VS5 No - no accelerated wear 1

75 73 PCT 19 VS3 Preventative No - no accelerated wear 1

76 102 PCT 19 VS2 No - no accelerated wear 1

30 54 PCT 18 VS3 No - no accelerated wear 4

29 61 PCT 21 VS3 Yes - U-Bend Table 7 Tubes Plugged During U1R26

8.

The repair method utilized, and the number of tubes required by each repair method.

No sleeving or other repairs were made to the Ul SGs.

9.

An analysis summary of the tube integrity conditions predicted to exist at the next scheduled inspection (forward-looking tube integrity assessment) relative to the applicable performance criteria, including the analysis methodology, inputs, and results. The effective full power months of operation permitted for the current operational assessment.

Current operational assessment demonstrates that the tube structural and leakage integrity performance criteria will be satisfied for at least 7.5 EFPY, 90 EFPM The existing degradation mechanisms which require OA are:

Mechanical wear from U-bend support structures Mechanical wear from ATSG support structures Inputs are as listed in Tables 8 and 9, below. End of Cycle (EOC) Structural Limit is based on an assumed maximum length of 2.5 inches for U-Bend wear flaws and 0.37 inches for ATSG wear flaws.

9

Parameter Value Tube OD (inches) 0.75 Tube Wall Thickness (inches) 0.043 Bounding Secondary Side Bundle Pressure (psig) 851.7 Primary Side Pressure (psig) 2235

~PNoP (psid) (tube bundle) 1383.33 3~PNoP (psid) 4150

~PsLs (psid) 2560 1.4* ~PsLB (psid) 3584 Sy+Su (ksi) at 650°F 121.29 Standard Deviation of Sy+Su (ksi) at 650°F 2.217 Leakage Limit under accident conditions (gpm) 1.0 Cycles 22-26, Prior Operating Interval (EFPY) 6.626 Cycle 27 (EFPY), 1 cycle 1.5 Cycles 27-31, Future Operating Interval (EFPY), 5 cycle 7.5 Table 8 Tube and Operating Parameter Inputs Degradation EPRIETSS Probe Parameter Linear Regression Standard Mechanism Type Y-Intercept Error Sy.x 96004.1 R14 Bobbin Max Depth Y = 0.99x + 2.93%

4.18%

U-bend Wear 96041.1 R8 Bobbin Max Depth Y = 0.94x + 5.43%

3.41%

and 96044.3 RO Bobbin Max Depth Y = 0.95x + 2.18%

2.38%

ATSG Wear 17908.2 RO Array Length Y = 0.30x + 0.32" 0.09" Note: 17908.2 Rl is listed in the 1R26 DA for sizing of U-Bend and ATSG wear. The Appendix H (17908.2 RO) sizing uncertainties for length are included here. The Appendix I and H techniques have the same setups and analysis sizing guidelines Table 9 NOE Measurement Sizing Uncertainty Inputs When considering the growth rates experienced from 1R18-1R21, it was found that a deterministic method did not satisfy the performance criteria. Additionally, the deterministic method for this degradation mechanism may not be adequate to account for the combined effects of flaw population, returned-to-service size distribution, and growth rate distributions. A fully probabilistic QA is required.

The final QA was performed using both deterministic and fully probabilistic calculation methods and the results indicate that the tube structural and leakage integrity performance criteria will be maintained for at least five cycles of operation.

The largest U-bend support wear flaw left in service after 1R26 is 17% TW. The length of the largest indication left in service is assumed to be 2.5 inches~ This significantly bounds the largest U-bend support wear indication axial length of 1.55 inches measured by array at 1R26. The 5-cycle 10

probabilistic worst-case degraded tube OA projection for the largest U-bend support wear flaw returned to service using the average growth rate of 2.01% TW/EFPY and the 95th percentile growth rate of 1.15% TW/EFPY from the bounding distribution of the previous three inspection intervals (1R18-1R21).

The largest assumed undetected flaw size (18% TW) due to U-bend support wear is based on the depth at the Appendix I technique 96044.3 95th percentile probability of detection (POD).

The largest ATSG support wear flaw left in service after 1R26 is 17% TW. The length of the largest indication left in service is assumed to be the maximum contact length of 0.37 inches between the support and tube. The 5-cycle deterministic worst-case degraded tube OA projection for the largest ATSG support wear flaw returned to service using the average growth rate of 1.22% TW/EFPY the 95th percentile growth rate from 1R15 and 1R18 to 1R21 of 4.31% TW /EFPY. The largest assumed undetected flaw size (14% TW) due to ATSG support wear is based on the depth at the Appendix I technique 96041.1 95th percentile POD.

5 Cycle Material EOC OAMargin to Degradation 7.5 EFPY Structural Material Structural Mechanism OA Technique Projection (3/4TW)

Limit Limit (3/4TW)

(3/4TW)

ATSG Wear Deterministic 59.0 64.5 5.5 RTS Flaws ATSG Wear Deterministic 46.3 64.5 18.2 Undetected Flaws Degradation POB POL Mechanism OA Technique

(%)

(%)

Burst Pressure (psi)

Leak Rate (gpm)

U-Bend Wear Fully Probabilistic 3.14 0.000 4233 0.0 RTS and Undetected Flaws Acceptance Criterion

S 5.0

S 5.0 2:: 4150

S 1.0 Acceptable for S Yes Yes Yes Yes Cycles {7.5 EFPY)?

Table 10 Sequoyah Unit 1 Operational Assessment Summary

10. The number and percentage of tubes plugged [or repaired] to date, and the effective plugging percentage in each SG.

Total number and percentage of tubes plugged are available in Table 6, Section 7, above. No tube repairs were performed in this or any Ul outage. No sleeves have been used in SQN Ul so the effective plugging percentage remains the same as the cumulative plugging percentage.

11

11. The results of any SG secondary-side inspection. The number, type, and location (if available) of loose parts that could damage tubes removed or left in service in each SG.

SG 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

2 2

2 2

2 2

2 2

2 2

2 2

A total of 45 FOs in all four SGs were identified through visual FOSAR inspections of the top-of-tubesheet. Table 12 lists the tubesheet FOs found during 1R26 and their status. No tube wear was identified with these objects as determined by array examinations. Twenty five (25} of the objects were retrieved, with 20 remaining in the SGs. The objects not retrieved were small wire bristles, sludge rocks, gasket/weld slag, and scale. Al l of these objects except one are smaller than the respective size limits that justify acceptable operation for 5 cycles per evaluation. The remaining object in SGl (FO 1007) was found to be larger than the allowable screening size. All objects remaining in the SGs have been evaluated for continued operation for at least 5 cycles.

Port Beg.

Beg.

Length Width Height Name ID Desc Elev Col Row Le~

(in.)

(in.)

(in.)

Metallic Retrieved Attempted 1001 MWY Scale TTS 93 81 HL 0.05 0.05 0.05 No No No 1002 MWY Scale TTS 84 90 HL 0.03 0.03 0.03 No No No 1003 MWY Scale TTS 75 100 HL 0.4 0.2 0.1 No No No 1004 MWY Sludge TTS 62 96 HL 0.1 0.1 0.1 No No No Rock 1005 MWY Scale TTS 51 95 HL 0.17 0.17 0.05 No No No 1006 MWY Gasket TTS 44 97 HL 1.0625 0.17 0.5 Yes Yes Yes 1007 MWY Gasket TTS 42 96 HL 0.7 0.17 0.09 Yes No NoC1l

/ Weld Slag 1008 MWY Scale TTS 38 92 HL 0.17 0.02 0.02 No No No 1009 MWY Gasket TTS 24 74 HL 0.75 0.17 0.01 No Yes Yes 1010 MWY Sludge TTS 23 71 HL 0.17 0.17 0.05 No No No Rock 1011 MWY Sludge TTS 1

16 HL 0.05 0.05 0.02 No No No Rock 1012 MWY Sludge TTS 70 100 CL 0.1 0.1 0.15 No No No Rock 1013 MWY Gasket TTS 84 82 HL 0.5 0.25 0.125 Yes Yes Yes 1014 NZL Sludge TTS 39 94 CL 0.17 0.17 0

No No No Rock 1015 NZL Scale TIS 60 94 HL 0.25 0.171 0.125 No No No 2001 MWY Scale TTS 108 63 CL 0.2 0.16 0.05 No No No 20020 MWY Wire TTS 95 82 CL 0.85 0.063 0.063 Yes Yes Yes Bristle (same as FO 2010) 2003 MWY Scale TTS 90 89 CL 0.13 0.1 0.05 No No No 2004 MWY Gasket TTS 57 95 CL 0.7 0.16 0.125 Yes Yes Yes 2005 MWY Scale TTS 1

9 CL 0.75 0.17 0.05 No Yes Yes 2006 NZL Gasket TTS 48 99 HL 1.25 0.125 0.125 Yes Yes Yes 2007 NZL Sludge TTS 66 98 HL 0.15 0.15 0.15 No No No Rock 2008 NZL Gasket TTS 121 2

HL 2

0.15 0.17 Yes Yes Yes 2009 MWY Wire TTS 108 23 CL 1.5 0.063 0.063 Yes Yes Yes Bristle 2010(1 MWY Wire TTS 95 82 CL 0.85 0.063 0.063 Yes Yes Yes Bristle (same asFO 2002) 2011 MWY Wire TTS 89 72 CL 0.45 0.063 0.063 Yes No No Bristle 2012 MWY Wire TTS 89 68 HL 0.5 0.063 0.063 Yes No No Bristle 12

Port Beg.

Beg.

Length Width Height SC Name ID Desc Elev Col Row Leg (in.)

(in.)

(in.)

Metallic Retrieved Attempted 3

3001 MWY Gasket TTS 92 90 HL 0.36 0.15 0.15 Yes Yes Yes 3

3002 MWY Gasket TTS 85 95 HL 1

0,07 0.07 Yes Yes Yes 3

3003 MWY Gasket TTS 81 97 HL 1.2 0.15 0.15 Yes Yes Yes 3

3004 MWY Gasket TTS 24 72 HL 0.75 0.1 0.1 Yes Yes Yes 3

3005 MWY Wire TTS 14 63 HL 1.5 0.02 0.02 Yes Yes Yes Bristle 3

3006 MWY Sludge TTS 3

21 HL 0.17 0.17 0.17 No No No Rock 3

3007 MWY Gasket TTS 1

15 HL 0.75 0.1 0.1 Yes Yes Yes 3

3008 NZL Gasket TTS 6

16 CL 2

0.1 0.1 Yes Yes Yes 3

3009 NZL Scale TTS 28 73 CL 0.3 0.1 0.1 No No No 3

3010 NZL Gasket TTS 69 101 CL 1.0 0.17 0.17 Yes Yes Yes 3

3011 NZL Gasket TTS 40 87 HL 0.8 0.05 0.05 Yes Yes Yes 3

3012 NZL Wire TTS 28 76 CL 0.3 0.02 0

Yes No No Bristle 3

3013 NZL Wire 29 37 CL 0.5 0.02 0

Yes Yes Yes Bristle 4

4001 NZL Gasket TTS 56 103 CL 1

0.25 0.125 Yes Yes Yes 4

4002 NZL Wire TTS 105 73 CL 1

0.063 0.063 Yes Yes Yes Bristle 4

4003 NZL Wire TTS 109 66 HL 2

0.05 0

Yes Yes Yes Bristle 4

4004 NZL Wire TTS 39 95 HL 0.75 0.01 0.01 Yes Yes Yes Bristle 4

4005 MWY Wire TTS 64 34 HL 0.875 0.025 0.025 Yes No No Bristle 4

4006 MWY Gasket 78 90 HL 0.6 0.1 0.1 Yes Yes Yes Note 1: Retrieval of object 1007 was attempted but object could not be located.

Table 11 Sequoyah U1R26 Loose Parts Detected by Tubesheet Visual Inspections

12. The scope, method, and the results of secondary-side cleaning performed in each SG.

SG secondary side top of tubesheet sludge lancing was performed in each SG during 1R26.

Subsequent post-sludge lance top-of-tubesheet inspections and FOSAR were performed in each SG. The extent of the visual inspections included the tube lane, annulus, and periphery tubes (to at least 3-5 tubes into the tube bundle). No degradation was identified during secondary side inspections. At the completion of sludge lancing in each SG, the sludge lance grit tank screen contents were visually inspected for the presence of foreign objects.

SG Weight 1

34 2

39.8 3

54.3 4

55 Total 183.1 Table 12 Sludge Weights After Lancing in U1R26 In addition to the visual inspections, extensive eddy current programs were conducted focusing on detecting FOs and wear due to FOs. A 100% bobbin coil probe full length inspection program and a minimum 3-tube deep array probe peripheral inspection was performed on the hot leg and cold leg of all four SGs at 1R26 with a focus on FO and FO wear detection. The array program extended 13

beyond three tubes deep to ensure that the transition and high flow fluid velocity regions were inspected. Additionally, any metallic foreign object that was found during FOSAR was inspected and bounded with array probe special interest testing.

SQN 1 ATSGs cause a very free flowing secondary side and to date SQN 1 has not experienced operational performance issues such as water level perturbations or main steam pressure perturbations. A Westinghouse evaluation of Ul SG tube deposit scale profiling using eddy current data gathered during R26 is in progress.

13. The results of primary side component visual inspection performed in each SG.

Each SG primary channel head was visually inspected for signs of cracking and/or breaches in the cladding or divider to channel head weld and for evidence of wastage of the carbon steel channel head. This inspection addresses the experiences in the industry where breaches in the channel cladding and divider plate weld resulted in wastage of the carbon steel channel head pressure boundary. No evidence of cladding or weld cracking and/or breaches or evidence of channel head wastage was identified during 1R26. Satisfactory inspection results were observed in all SGs with no indications of cladding surface degradation.

All previously installed tube plugs were also inspected from the primary side in all four of the SGs 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 next inspection.

14. Any plant specific reporting requirements, if applicable.

There are no plant specific reporting requirements.

Ill.

Summary Based on the inspection data and the CM assessment, no tubes exhibited degradation exceec::ling the CM limits. No tubes required in situ pressure testing to demonstrate structural and leakage integrity. There was no reported SG primary-to-secondary leakage during the preceding inspection interval. The SG performance criteria for operating leakage and structural integrity were satisfied for the preceding Sequoyah Unit 1 SG operating interval encompassing Cycle 22 through Cycle 26, thus meeting CM requirements. The final OA demonstrates that the SG performance criteria will be satisfied until the next planned inspection at 1R31 in the Spring of 2030.

IV.

References

1.

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

2. Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 5. EPRI, Palo Alto, CA: 2021. 3002020909.

3.

Westinghouse Document, SG-CDMP-24-4, Revision 1, ((Sequoyah 1R26 Steam Generator Condition Monitoring and Final Operational Assessment," July 2024.

14

4.

TVA Document "Sequoyah 1R26 Steam Generator Degradation Assessment", Revision 0, March 2023.

5.

Westinghouse Report, SG-SGMP-16-15, Revision 1, "Sequoyah U1R21 Steam Generator Condition Monitoring and Operational Assessment," October 2019.

15