NOC-AE-20003764, 1 RE22 Inspection Summary Report for Steam Generator Tubing

1 RE22 Inspection Summary Report for Steam Generator Tubing

ML20281A854
Person / Time
Site:	South Texas
Issue date:	10/07/2020
From:	Georgeson C South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-20003764
Download: ML20281A854 (13)

Text

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Nuc ear Operating Company South kx:i.< f'rtftxl Electric Cener.1/ing S/Jtion P.O. &J.r :!S'l i1!Jdm11rth, l fa;ir 77*18.l October 07, 2020 NOC-AE-20003764 10 CFR 50.36 STI: 35079185 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington , DC 20555-0001 South Texas Project Unit 1 Docket No. STN 50-498 1RE22 Inspection Summary Report for Steam Generator Tubing Enclosed is the summary report describing the results of the South Texas Project Unit 1 steam generator tube inspection performed during refueling outage 1RE22 . The summary report satisfies the reporting requirements of Section 6.9.1.7 of the South Texas Project Technical Specifications. This report provides the information required by Technical Specification 6.8.3.o for maintaining steam generator tube integrity.

There are no commitments in this letter.

If there are any questions regarding this report, please contact either Zachary Dibbern at (361) 972-4336 or me at (361) 972-7806.

Christopher Ge rgeson General Ma nager, Engineering zd

Enclosure:

1RE22 Inspection Summary Report for Steam Generator Tubing (Rev. 0) of the South Texas Project Electric Generating Station Unit 1 cc:

Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 1600 E. Lamar Boulevard Arlington, TX 76011-4511

1 1RE22 INSPECTION

SUMMARY

REPORT FOR STEAM GENERATOR TUBING (Rev 0) of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNITl P.O. BOX289 WADSWORTH, TEXAS 77483 Commercial Operation: August 25, 1988 Issue Date: September 29, 2020

2 1RE22 INSPECTION

SUMMARY

REPORT FOR STEAM GENERATOR TUBING (Rev. 0) of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNITl USNRC DOCKET NO. : 50-498 OPERATING LICENSE NO. : NPF-76 COMMERCIAL OPERATION DATE: August25, 1988 Prepared By:

M. Gamer Steam Generator Engineer Approved By: 9/29/20 E. Stephens Date Manager, Strategic Engineering

3 SOUTH TEXAS PROJECT UNIT 1 1RE22 INSPECTION

SUMMARY

REPORT FOR STEAM GENERATOR TUBING Introduction This summary report describes the inspection of steam generator tubing at South Texas Project (STP)

Unit I performed during refueling outage IRE22 beginning 03/13/2020 and ending with breaker closure on 04/25/2020. Eddy current inspection, sludge lancing, and Foreign Object Search and Retrieval (FOSAR) were conducted in steam generators (SG) IA, lB, IC and ID.

The eddy current inspection performed during IRE22 completes the second inspection of the Technical Specification Second Interval for all Unit I steam generators. The outage was performed following I 7 .9 I EFPY of cumulative service with the Delta 94 replacement steam generators. This report provides the information required by Technical Specification 6.8.3.o for maintaining steam generator tube integrity and the reporting requirements of Technical Specification 6.9.1.7.

The IRE22 Steam Generator inspection was performed to investigate three preexisting forms of degradation: tube support plate wear, foreign object wear, and sludge pile volumetric degradation. Two potential modes of steam generator degradation were also fully examined: anti-vibration bar (AVB) wear and tube-to-tube wear (TTW). Other potential issues that were considered included manufacturing artifacts: manufacturing burnish marks, dings, laps and the channel head cladding. Secondary side conditions were also investigated: foreign objects, upper steam drum components, and the condition of an upper support plate.

Scope of Examination The Inspection Plan, "Steam Generator In-Service Outage Plan for South Texas Unit- I, Spring 2020" identified the steam generator tube areas to be examined by eddy current testing and the related procedures to be used during the inservice inspection. A Degradation Assessment (DA), written prior to the outage established the following scope of primary and secondary side inspections:

Primary Side Inspection Scope As required by the EPRI Examination Guidelines, the IRE22 outage inspection program addressed the known degradation mechanism(s) as well as those regarded as potential degradation mechanisms. The following outlines the IRE22 outage initial inspection plan, as justified in the Degradation Assessment (DA). It is applicable to South Texas Unit I Steam Generators IA, IB, IC and ID:

Bobbin Coil Inspection

• Full length bobbin coil inspection of 100% of the outer (3) peripheral tubes from tube end to tube end, including I 0 tubes inwards into the no-tube lane from the periphery.

• 50% Full length bobbin coil inspection of all tubes. Scope included all tubes not inspected full length during IREI9.

Rotating Coil Inspection U-Bend

• 20% +Point probe inspection of the upper TSP hot leg to upper TSP cold leg of Rows I and 2. This inspection was performed using the Zephyr bobbin probe.

4 Rotating Coil Inspection - Straight Section

• +Point probe inspection of outer three tubes of periphery and divider lane TTS

+6 inches/-3 inches, including HL and CL, to aid in foreign objects detection.

• 20% Sample +Point probe inspection of TSH +6 inches/-3 inches.

• 20% Sample +Point probe inspection ofTSH +6 inches/-16 inches in tubes with bulges and over-expans10ns.

• +Point probe inspection of kidney region (hot leg sludge pile area) with 2 tube locations surrounding the sludge pile, +6 inches/-3 inches in all four steam generators.

Rotating Coil Inspection - Special Interest

• +Point probe inspection of all previously identified dents and dings> 5 volts.

• +Point probe inspection of all prior and 1RE22 "I-code" and/or non-quantifiable indications as determined by bobbin coil inspection or any previously reported signal that has changed.

• +Point probe inspection of PLPs in the eddy current database as identified by previous eddy current inspections.

• +Point probe inspection of a minimum two tube locations surrounding all observed Priority 1 or 2 foreign objects as identified during l RE 19 secondary side video inspections and not removed.

• +Point probe inspection of a minimum two tube locations surrounding any newly identified PLP.

• +Point probe inspection of a minimum two tube locations, or as directed otherwise by engineering to support the Operational Assessment, surrounding newly identified foreign objects that are classified as Priority 1 or Priority 2.

• +Point probe inspection of all tube-to-tube wear indications detected by bobbin coil.

• +Point probe inspection of all bobbin proximity (PRO) signals > 1.25 volts.

• +Point probe inspection of all MBM bobbin coil indications that are newly reported or are judged to have changed, based on a history review.

• +Point probe inspection of prior cycle MBMs that are TTW candidates.

• +Point probe inspection of wear indications left in service.

Other Primary-Side Inspections

• Video Inspection of all installed plugs.

• Video Inspection of all hot and cold leg bowl cladding surfaces looking for thinning or missing cladding and associated wastage, if any.

• Conduct stud hole gauging on SG lB.

Inspection Expansion No inspection expansion was performed due to any type of tube degradation.

Primary Side Examination Results No crack-like indications were identified during the 1RE22 inspection. No volumetric indications were identified under the hard sludge region of any steam generator. No new locations with tube support plate wear were identified from the 1RE22 inspection; thus, there remains a total of three locations. Foreign object wear has occurred previously at South Texas Unit 1, but no new foreign object wear was identified during the 1RE22 inspection. These are described below.

5 Eddy Current Indication Results Table 1 presents a summary of the tube NDE indications reported. This summary includes redundant indications that may have been detected by multiple inspection programs.

Table 1: STP Unit 11RE22 Eddy Current Inspection - Final Indication Listing Number of Indications Ind'ication .

D escr 1p onti SG-A SG -B SG - C SG- D Total DNG Ding (From Fabrication or Manufactu.rit12) 466 24 331 185 1006 DNS Dist01ted Ding Indication (Not Confirmed) 15 10 12 32 69 DSS Disto1ted Suppo1t Signal 1 1 2 2 6 INF Indication Not Found -- -- 1 2 3 INR Indication Not Reportable 10 9 9 7 35 MBM Manufacturing Burnish Mark 209 175 201 226 811 NDD No Detectable Degradation 7928 8112 7995 8117 32152 NDF No Degradation Found 151 29 17 7 204 NQS Non-Quantifiable Si~l 35 51 43 27 156 PCT Percent 1 1 -- 1 3 PLP Possible Loose Pait 3 2 5 27 37 PRC Pr~ ious Rotating Probe Call 4 -- -- - 4 PRO Tube-to-Tube Proximity 20 8 4 8 40 PVN Permeability Variation -- -- -- 1 1 RBD Retest - Bad data 3 9 2 -- 14 RIC Retest - Incomplete Test 1 -- 1 2 4 VOL Volumetric -- 1 3 7 11 WAR Wear 1 1 - 1 3 Total 8848 8433 8626 8652 34559 NOTE: Number of indications may in.elude multiple counts in the same regionltube due to multiple tests (bobbin, +Point, :MB Ghent)

6 Existing Degradation Mechanisms The Degradation Assessment categorized sludge pile volumetric degradation, tube support plate (TSP) wear, and foreign object wear as existing degradation mechanisms. The results are as follows:

• Volumetric Indication Under Hard Sludge Deposits There were no volumetric indications found in 1RE22, as was found in 1RE19.

History:

During the Unit l 1RE19 refueling outage, eddy current examination identified a possible volumetric indication in RSG lD Tube R30C78 at approximately 0.2 inch above the hot leg tubesheet and located beneath a I-inch thick hardened sludge collar.

The cause of the indication signal could not be positively determined; however, a direct cause investigation found that two causes were more likely than other possibilities: 1) False Call or 2) Pitting Corrosion.

STPNOC developed a mitigating strategy to address the volumetric indication signal with the conservative assumption that pitting was the cause.

Pitting corrosion was to be assigned as an existing degradation mechanism in future Degradation Assessments for both units following 1RE19. This conservative action requires STP to inspect 100% of the potentially affected tubes over the inspection period until substantive evidence is developed that refutes pitting corrosion as the cause of the indication. This corrective action ensures that STP will identify any corrosion degradation in the sludge pile long before steam generator tube performance criteria are exceeded.

South Texas Unit l will treat pitting as an existing degradation mechanism until both Units l and 2 have two consecutive inspections without any new sludge pile volumetric indications. If the next two inspections at both STP units following l RE 19 (10/ 17/15) reveal no additional similar indications, then pitting corrosion will be removed from the active degradation mechanism list and increased inspection scope will be discontinued.

STP steam generator inspections during 2RE19 (03/24/18) and 1RE22 (03/13/20) found no additional volumetric indication signals. Pitting corrosion will continue to be assigned as an existing degradation mechanism through inspections outages in 2RE22 and 1RE25 (Fall 2022 and Fall 2024, respectively).

• Tube Support Plate Wear The Degradation Assessment categorized tube support plate (TSP) wear as an existing degradation mechanism. During the STP Unit l steam generator inspections conducted during 1RE22, three locations were found to have TSP wear. All three TSP wear indication locations have been monitored since 1RE13 (2006). No discemable growth has occurred since the last inspection outage.

The maximum TSP wear indication reported during 1RE22 was 9%TW, in D-R3C41-08C, as sized by bobbin ETSS 96004.1. This is far below the condition monitoring limit of 57%TW for a 1.125-inch wear scar. These three locations, and their wear depths, are summarized in Table 2.

7 Table 2: TSP Wear Depth Summary for STP Unit 1 lRE.2.2 1REI9 1REI6 lREB #TSP U nit Location f%TIV) (%TW) (%TI¥) (%TI¥) Lauds 'Vear Type 1 A-R126C88-06H 5 5 6 4 Single Pin point 1 B-R3C l 55-06H 7 9 9 4 Single Pin point 1 D-R3C41-08C 9 10 no test 8 Single Tapered Note: TSP wear depths are reported as %TW. Shaded areas were obtained from a data review in a previous outage; the shaded areas were not reportable indications during the applicable outage.

• Foreign Object Wear No new indications of foreign object wear were discovered during the 1RE22 inspection.

Foreign objects have been reported as the cause for tube wear at South Texas Unit 1 during prior inspections. Therefore, wear due to foreign objects is classified as an existing degradation mechanism and has been addressed in the SG inspections for 1RE22.

The instances of foreign object wear from prior cycles listed in Table 3, Wear Indications Left In-Service at STP Unit 1, were all inspected in 1RE22. In each case, the object that caused the wear has been removed. None of the indications have changed since the 1RE19 inspection.

Table 3: Wear Indications Left In-Service at STP Unit 1 lR.El9 Ouitage when. Fir st Depth Ideutffie.d. {%T\\I) Tube Location \¥ear Type 1RE12 23 D-R84C22 TTSHL Stahih:rer wire \Vear <R.emoved) 1RE12 6 D-R84C24 TISHL Stabilizer wire wear <R.emoved) 1RE13 9 ~R2C138 TTSCL Stabilizer wire \.ve:ar <R.emoved) 1RE 13 to D-R99C35 TTSCL Stahilizec \We wear (Removed) 1RE13 21 D-R116C48 TTSCL Stabilizer *wire wear (Removed) 1RE 14 8 D-R70CMO TTSHL Gasket weM !Removed) 1RE16 35 C-R112C48 TTSCL Weld slw wear ffi.emoved) 1RE 16 23 C-Rl 10C48 TTSCL Weld s~ wear (Removed) 1RE16 17 C-R111C47 TTSCL Weld slat?: \¥ear (Removed) 1RE16 5 A-R126C88 06H TSP weM 1RE 16 9 B-R3C155 06H TSP wear 1RE19 to D-R3C41 08C TSP \Vear

8 Potential Degradation Mechanisms The Degradation Assessment categorized AVB wear, and tube-to-tube wear as potential degradation mechanisms. The results are as follows:

• Mechanical Wear Indications at Anti-Vibration Bars There were no tubes in the South Texas Unit l steam generators with indications of wear at the anti-vibration bars.

• Mechanical Wear Indications due to Tube-to-Tube Contact There were no tubes in the South Texas Unit 1 steam generators with indications of wear due to tube-to-tube contact. A review of MBM and PRO indications did not indicate the presence of wear.

• Non-Relevant Degradation Mechanisms Indications first reported with potential flaw-like characteristics in the South Texas Unit 1 SGs may include indications initially reported as distortions or pre-existing signals such as manufacturing burnish marks or dents and dings (MBI, MBM, DNI, and DNS), benign indications (DFI, DFS, DSI, DSS), anomalous signals at the tubesheet or elsewhere (DTI, DTS), nonquantifiable signals in the sludge pile region (NQI, NQS) and permeability indications (PVN).

The character ofl-code signals, when observed, is determined by history review, Lead Analyst Review, or by +Point probe examination. The three support plate indications noted in Table 2 were initially reported as DSI indications and were finally characterized as wear indications of support structure wear. All other I-code indications were dispositioned as non-flaw conditions. There were no unresolved I-codes at 1RE22.

PVNs are technically not I-code signals but rather interferences that can compromise detection of flaw signals. There were no flaws associated with PVN indications.

Ding (DNG) is a baseline indication where the tubing inside diameter is less than normal. The Degradation Assessment specified that all dings greater than 5 volts that were reported in the baseline examination would be inspected with a +Point probe coil. There were 85 dings in the South Texas Unit 1 SGs greater than 5 volts; these were inspected with a +Point probe. No degradation was found.

The use of the Dent (DNT) indication code was discontinued. Prior cycle DNT indications are now associated with the DNG three-letter code.

Bulge (BLG) is a condition where the tubing outside diameter is greater than normal. An overexpansion (OXP) is a similar condition associated with anomalies in the tubesheet. There were no new BLG/OXP locations identified in 1RE22. Existing BLG/OXP locations were inspected with a +Point probe. The results of the tests were that no defects were found (NDF).

9 Other Primary Side Inspection Results Tube Plug Visual Inspections A I 00% visual inspection of all tube plugs in all four SGs was performed from the primary side during South Texas Unit I 2RE22. There were no anomalous conditions, such as a degraded tube plug or excessive surrounding boron deposits reported during performance of the visual inspections.

NSAL-I2-I SG Channel Head Primary Side Bowl Inspection A visual inspection of the bottom of the SG channel head bowl was performed in both legs of all SGs during South Texas Unit I IRE22, necessitated by the industry operating experience discussed in the Degradation Assessment. Visual inspections of the SG hot leg and cold leg divider plate base, and with particular attention to the bottom 36-inch radius of the bowl, were performed in accordance with Westinghouse Nuclear Safety Advisory Letter NSAL- I 2- I recommendations using the SG manway channel head bowl cameras. Satisfactory inspection results were observed in all SGs.

Stud Hole Gauging All stud holes of the SG lB hot and cold leg primary manways were inspected with go/no-go gauges and confirmed that these stud holes were in good condition and without any visible damage.

Tube Repair Summary No crack-like indications were reported, and no tubes were repaired as a result of the IRE22 steam generator eddy current inspection.

Summary of Secondary Side Inspection and Maintenance Plan

• TTS FOSAR in all four steam generators including annulus and no-tube lane.

• TTS In-bundle FOSAR as follows:

o SG lA inspect every 4th column (HL & CL) beginning with Column 3 (between Col 3-4).

o SG lB inspect every 4th column (HL & CL) beginning with Colmnn 4 (between Col 4-5).

o SG 1C inspect every 4th column (HL & CL) beginning with Colmnn 1 (between Col 1-2).

o SG lD inspect every 2nd column (HL & CL) beginning with Column 1 (between Col 1-2).

• Sludge lancing on all four steam generators.

• SG lB and SG IC sludge collectors.

• Steam Drum inspections in SG IB and SG IC.

• Upper Steam Drum inspection in SG lB.

• Video probe inspection of 9th support plate on SG IA.

• FOSAR of Priority I and 2 foreign objects.

• FOSAR of all possible loose parts (PLP) identified by eddy current inspection.

10 Secondary Side Inspection and Maintenance Results Sludge Lancing The post-lance inspection revealed that generally the top of tubesheet of all four SGs were clean with essentially all sludge removed. No anomalies were noted on any tubesheet location. The center region of the hot leg of each SG had a pile of hardened sludge.

Sludge Collector Cleaning The sludge collectors in SG IB and SG IC were cleaned in IRE22.

Cleaning was accomplished with the internal jet and suction port system that is integral to the steam generator. In addition, a hand-held spray wand was used to help move deposits from the center of the sludge collector, out to the periphery where the suction ports are located. The hand wand method was attempted for the first time in IRE22.

Sludge removal amounts in IRE22 were: 31.46 lbs. from SG IB and 25.67 lbs. from SG IC. This is in comparison to the 10.6 lbs. removed from SG ID in IRE13; and 13.SI lbs. removed from the Unit 2 SG 2A in 2REI6, each without using the hand wand.

The hand wand was effective at moving the loose sludge from the center of the collector. The post-cleaning inspection of the sludge collector showed bare metal surfaces near the center of the collector after use of the hand-held spray wand.

Steam Drums Visual observations were made of the steam drums of SG I B and SG IC to assess the condition of the steam drum in each SG and to ensure reliable operations until the next inspection period. The steam drums were inspected for erosion, mechanical damage, cracked welds, corrosion, foreign material and any unusual conditions.

The inspection revealed no abnormal conditions. All components were in good condition with no cracking, erosion, or deformation. The inspection of the steam drums showed that all surfaces were gray in color, similar to the last inspection during I RE I 9.

In-Bundle Inspection of the Ninth Tube Support Plate In order to obtain visual information on the deposit loading in the upper region of the tube bundle, an in-bundle inspection of the 9th tube support plate of SG I A was performed.

The inspection showed a thin layer of magnetite covering the TSP top surface, along with some loose deposits that were present in somewhat greater quantity than in IREI9, but still not to any significant extent. Scale provided a continuous cover of all the tube surfaces with the exception of the tubes nearest the no-tube lane. The tubes near the no-tube lane are minimally fouled. No deposit bridging across the trefoil to tube OD surface was observed; no blockages. No departures from the expected appearance of the TSP ligaments were observed. No negative impact on steam generator operation is expected.

11 Foreign Object Mapping and Retrieval Foreign object search and retrieval was performed at the top of the tubesheet, the tube bundle-shell annulus and the no-tube lane in all four SGs. A total of 35 foreign objects were identified during the top of tubesheet video probe inspections.

During the eddy current program, 28 PLP calls were reported; 11 at the top of the tubesheet and 17 at the SG D flow distribution baffle. As required by EPRI guidelines, coordination between the eddy current and secondary visual inspection results was maintained. Top of the tubesheet tube locations showing PLP signals by eddy current were visually inspected to identify the source of the signal. In addition, all top of the tubesheet tube locations where foreign objects were identified during visual inspections were included in the top of tubesheet +Point probe inspection program.

Based on existing wear analyses and top of the tubesheet velocity maps, prioritization criteria were developed and used to assign priorities to each of the identified foreign objects. Foreign objects were assigned priorities based on the characteristics of the object and its location on the tubesheet:

• Priority 1 foreign objects are those which cannot be left in the steam generators and justify a 3-cycle operational assessment without further evaluation or additional remedial measures.

• Priority 2 foreign objects can be left in and operate for three cycles, but still have the potential for wear and will need to be addressed in future inspection outages.

• Priority 3 foreign objects cannot cause wear of any significance and may be left in the steam generator indefinitely.

There were thirty (30) objects that could not be removed from the steam generators. These are summarized in Table 4. This includes fifteen (15) Priority 3 objects, fifteen (15) Priority 2 objects and zero (0) Priority 1 objects. Each identified foreign object, not removed from the respective steam generator, was subjected to a foreign object wear analysis to support the planned operating period through Cycle 25.

12 Table 4: Unretrieved 1RE22 TTS Foreign Objects Foreign Object Begin End Begin End Length Width Height Dia.

n. n.

SG FONo. PR! Descrintion Leg Row Row Col Col Leeacii*

""' lln .\ Metallic C.Omments A !A002 2 Fiber CL 110 so New 0.9 0.02 no B !BOO! 2 Gasket Material HL 61 55 56 Legacy 1.5 0.02 0.06 yes Wedgedon tube 61and62. old id B0011from1RE19 B IB002 3 Sludge Rock HL S7 S9 59 59 Legacy 0.1 6 0.1 0. 16 no Old FO 1B004 from IREl6; and B003 from IRE!9 B IB003 3 Sludge Rock CL I 2 21 20 New 0.1 0.1 0.1 no B IB004 3 Grafoil HL 10 10 92 93 New 0.3 15 0.18 0.18 no B !B005 3 \Vire Bristle HL 58 59 92 93 New 0. 163 O.oJ yes c !COO! 2 Gasket Material HL 20 21 76 77 Legacy 0.38 0.07 0.02 yes c !C002 2 \Vire Bristle HL 22 21 76 JJ Legacy 0.25 0.01 0.01 yes c ICOOJ 2 Wire Bristle HL 24 23 76 77 New 0.5 O.ot 0.01 yes c IC004 2 \\irre Bristle HL 24 2l 76 77 New 0.5 0.01 0.01 Y"' fixed in sludge c IC005 2 Wire Bristle HL 25 77 New O.l O.ot 0.01 Y"'

c IC006 3 \Vire Bristle HL 28 78 New 0.38 0.01 0.01 yes fixed in sludge on tube 28 on right of picture c ICOOJ 3 Grafoil HL 26 54 New 0.1 0.05 O.QJ no Touching Tubes C90R44, C89R45, C9QR46. fi."ted in place. \Vill c !COOS 2 Gasket :Material HL 44 46 90 90 New 2.5 0.125 0.03 Y"' notmoYe Touching 117. Seen from TI.. W.u gone when retrieval c !CO!O 3 Fiber CL I 117 New 0.25 0.03 Y"' attemnted. MiEilit have floated awav. Anrv>.ars to be fiber Touching 153. During retrieval attempt, it was determined to be c !COii 3 Fiber lL I 153 New 0.233 0.03 Y"' fiber_ Called off the attemnt when it floated awav Spread of iR&- S. luc :Marks are filsed to tube sheet. After attempted from ffi.90, ran guide tube over and none mo\*ed.

c !C012 2 \Veld Slag HL 79 SI New 1.25 0.5 O.Ol yes Some turned out to be rust spots. but looked different tmder CARTs li!!bts and cam distance Discolored area; c !COil 3 rust soot CL 123 63 64 New 0.4 0.2 0.2 no D ID002 3 Sludge Rock HL 57 59 113 113 Legacy 0.161 0.12 0.12 no D ID003 l Sludge Rock HL 57 113 114 Legacy 0.373 0.15 0.1 5 no D !D004 3 Sludge Rock HL 54 112 113 Legacy 0.3 75 0.2 0.2 no D IDOOl 3 Sludge Rock HL 56 112 Legacy I O.ll O.l l no D ID007 2 Gasket ?\faterial HL 106 96 97 New 0.25 0.125 0.04 yes Gone when attempted to retrieve D ID008 3 \Vue Bristle HL 110 96 97 New 0.25 0.02 yes Gone when attempted to retrieve D 10009 l Sludge Rock HL 77 79 91 92 New 0.3 15 0.25 0.2l no D !DOii 2 \Vue Bristle HL 19 83 84 New 0.12 0.02 Y"'

D !DOl2 2 \Vue Bristle HL 29 SI New 0.25 O.Q2 yes D 10013 2 \Vire Bristle HL 28 so New 0.1 8l 0.02 yes D !DOl4 2 \Vire Bristle HL 30 so New 0.185 0.02 yes D !DOi l 2 \Vire Bristle HL 31 79 New I 0.03 yes Condition Monitoring Conclusions and Operational Assessment Based on the final South Texas Unit 1 1RE22 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 SG inspection interval. The Condition Monitoring limits provided in the DA, and correspondingly, the performance criteria ofNEI 97-06 for operating leakage and structural integrity, were satisfied for the prior South Texas Unit 1 SG operating interval.

A final Operational Assessment was performed and determined that NEI 97-06 performance criteria will be satisfied for three full cycles of operation through at least the end of Cycle 25 The next Unit 1 steam generator inspection is scheduled for refueling outage 1RE25.