ML25120A433

RE25 Inspection Summary Report for Steam Generator Tubing

ML25120A433
Person / Time
Site:	South Texas
Issue date:	04/30/2025
From:	Georgeson C South Texas
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
NOC-AE-25004106, STI: 35733294
Download: ML25120A433 (1)

Text

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Nuclear Operating Company A TIN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 South Texas Project Unit 1 April 30, 2025 NOC-AE-25004106 10 CFR 50.36 STI: 35733294 Docket No. STN 50-498 1 RE25 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 1 RE25. 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 me at (361) 972-8352, or Stephanie Rodgers at (361) 972-4527.

il~

General Manager, Strategic Projects &

Design Engineering

Enclosure:

1 RE25 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

1RE25 INSPECTION

SUMMARY

REPORT FOR STEAM GENERATOR TUBING (Rev 0) of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 1 P.O. BOX 289 WADSWORTH, TEXAS 77483 Commercial Operation:

August 25, 1988

1 RE25 INSPECTION

SUMMARY

REPORT FOR STEAM GENERA TOR TUBING (Rev. 0) of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 1 USNRC DOCKET NO.:

50-498 OPERATING LICENSE NO.:

NPF-76 COMMERCIAL OPERATION DATE:

August 25, 1988 Prepared By:

M. Garner Date Steam Generator Program Engineer Approved By:

C. Georgeson Date General Manager, Strategic Projects and Design Engineering Pagell

P a g e l 2 180-Day Steam Generator Tube Inspection Report South Texas Project Unit 1 Cycle 25

1.

DESIGN AND OPERATING PARAMETERS Steam Generator Design and Operating Parameters SG Model / Tube Material / # SGs per unit Delta 94 Replacement SG / Alloy 690TT / 4

1. of tubes per SG / Nominal Tube Dia. / tube thickness 7,585 / 11/16 in / 0.040 in Support Plate Style / Material Broached Trefoil / 405 Stainless Steel Last Inspection Date April 2020 EFPM since the last inspection 50.316 EFPM Total cumulative SG EFPY 22.102 EFPY Mode 4 initial entry April 14th, 2020 Observed P/S Leak Rate since the last inspection and how it trended with time 0.00 GPD RT-8027 radiation monitor Nominal indicated value of Thot during Cycle X at full power 622.5 degrees F (This value was taken at RCTA0430A on April 22nd, 2025)

Degradation mechanism sub population Potential pitting mechanism, STP Unit 1 volumetric indication discovered under hardened sludge collar during 1RE19 (Fall 2015).

Deviations from SGMP guidelines since the last inspection None Steam Generator Schematic Schematic is attached. See next page.

P a g e l 3 South Texas Delta 94 Replacement Steam Generator (RSG) Fabricated by Equipos Nucleares, S.A. (ENSA)

P a g e l 4

2.

SCOPE OF INSPECTIONS PERFORMED ON EACH STEAM GENERATOR The primary side inspection consisted of 100% full length bobbin of all tubes in all four SGs, and additional inspections of dents/dings, portions of the cold leg tubesheet (TSH),

and special interest.

No new indications were identified, or expansions needed.

Bobbin Coil Inspection 100% Full length bobbin coil inspection of all tubes.

Rotating Coil Inspection U-Bend 100% +POINT probe inspection of the upper tube support plate (TSP) hot leg to upper TSP cold leg of Rows 1 and 2.

Rotating Coil Inspection - Straight Section

+Point probe inspection of outer three tubes of periphery and divider lane TTS +6 inches/-3 inches, including hot leg (HL) and cold leg (CL), to aid in foreign objects detection.

40% Sample +Point probe inspection of TSH +6 inches/-3 inches.

100% +Point probe inspection of TSH +6 inches/-16 inches in tubes with bulges and over-expansions.

+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, bobbin 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 possible loose parts (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 foreign objects identified during 1RE22 secondary side video inspections.

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

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

+Point probe inspection of all bobbin proximity (PRO) signals >2.5 volts.

+Point probe inspection of all MBM bobbin coil indications that have increased by 0.5 volt for existing bobbin coil MBM indications.

+Point probe inspection of prior cycle MBMs that are tube-to-tube wear (TTW) candidates.

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

Other Primary Side Inspections Video inspection of all installed tube plugs from the primary side.

Video inspection of hot and cold leg bowl looking for thinning or missing cladding and associated wastage

P a g e l 5

3.

THE NONDESTRUCTIVE EXAMINATION TECHNIQUES UTILIZED FOR TUBES WITH INCREASED DEGRADATION SUSCEPTIBILITY Rotating Coil 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 was performed to identify any pitting mechanism similar to the previous STP Unit 1 single volumetric indication found in 1RE19 during the Fall of 2015 Rotating Coil was utilized for other special interest locations as listed in the inspection scope.

No indications were identified, or expansions needed.

4.

THE NONDESTRUCTIVE EXAMINATION TECHNIQUES UTILIZED FOR EACHDEGRADATION MECHANISM FOUND

P a g e l 6

P a g e l 7

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 PERCENT THROUGH-WALL, ONLY THE TOTAL NUMBER OF INDICATIONS NEEDS TO BE REPORTED During the STP Unit 1 steam generator inspections conducted during 1RE25, three locations were found to have TSP wear. There were zero (0) new indication reported in any of the SGs. All of the historic TSP wear indications were reinspected with bobbin and confirmed on +Pt so that they could be monitored for potential growth. The three (3) historic indications are listed below in Table 2-3; minimal growth was reported on each of the indications.

Table 2-3 below evaluates the three locations as percent through-wall (PCT) and support plate wear (WAR); and includes voltage.

6.

A DESCRIPTION OF THE CONDITION MONITORING ASSESSMENT AND RESULTS, INCLUDING THE MARGIN TO THE TUBE INTEGRITY PERFORMANCE CRITERIA AND COMPARISON WITH THE MARGIN PREDICTED TO EXIST AT THE INSPECTION BY THE PREVIOUS FORWARD-LOOKING TUBE INTEGRITY ASSESSMENT Based on the inspection data and the condition monitoring assessment, no tubes exhibited degradation in excess of the condition monitoring limits. No tubes required in situ pressure testing to demonstrate structural and leakage integrity. There was no reported SG primary-to-secondary leakage prior to the end of the South Texas Unit 1 RSG inspection interval.

Therefore, the SG performance criteria for structural and leakage integrity were satisfied for all degradation mechanisms detected for the preceding South Texas Unit 1 SG operating interval. The condition monitoring results are summarized in Table 3-1.

7.

DISCUSS ANY DEGRADATION THAT WAS NOT BOUNDED BY THE

P a g e l 8 PRIOR OPERATIONAL ASSESSMENT IN TERMS OF PROJECTED MAXIMUM FLAW DIMENSIONS, MINIMUM BURST STRENGTH, AND/OR ACCIDENT INDUCED LEAK RATE. PROVIDE DETAILS OF ANY IN-SITU PRESSURE TEST.

There was no degradation found in 1RE25 that was not bounded by the prior Operational Assessment (1RE22). No tubes required in-situ pressure testing to support the Condition Monitoring (CM) assessment based on the Degradation Assessment (DA) and Electric Power Research Institute (EPRI) In-Situ Pressure Test Guidelines.

8.

THE NUMBER OF TUBES PLUGGED [OR REPAIRED] DURING THE INSPECTION OUTAGE. ALSO, PROVIDE THE TUBE LOCATION AND REASON FOR PLUGGING.

No tubes were plugged during the 1RE25 outage. No tubes have exhibited degradation exceeding the tube integrity criteria given in the Degradation Assessment (DA) for the 1RE25 outage.

9.

THE REPAIR METHODS UTILIZED, AND THE NUMBER OF TUBES REPAIRED BY EACH REPAIR METHOD.

STPNOC does not repair tubes, tubes are plugged if they do not meet acceptance criteria. No tubes were plugged during the 1RE25 outage. Historically, a total of 114 tubes have been plugged in the STP Unit 1 RSGs leading up to 1RE25:

P a g e l 9

10.

AN ANALYSIS

SUMMARY

OF THE TUBE INTEGRITY CONDITIONS PREDICTED TO EXIST AT THE NEXT SCHEDULED INSPECTION (THE 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.

An operational assessment of each existing tube degradation mechanism identified during the 1RE25 inspection along with the foreign objects that remain on the secondary side is provided in the following sections:

Mechanical Wear at Tube Support Plates The operational assessment for TSP wear considers both detected and undetected flaws, as well as conservative growth rates, to ensure structural and leakage integrity for a 5-cycle interval (to End of Cycle (EOC) 30).

Conservative growth rates are calculated by comparing the current and historic depths of a wear indication. The depth of a given wear indication at the previous inspection is subtracted from its current wear depth and then the difference is divided by the EFPY. Any negative growth is due to sizing uncertainty and is conservatively assumed to be 0%TW/EFPY. When the population of wear is large enough, a 95th percentile growth rate can be determined from a cumulative distribution function (CDF) of the wear for a given population.

In the case of the wear found at STP Unit 1, however, there are not enough instances of wear to calculate a 95th percentile growth rate. In this case, the maximum growth rate observed can be used as bounding and applied to all wear.

For STP unit 1, the maximum growth rate observed is very small, therefore, as recommended by the SG Integrity Assessment Guidelines, a conservative growth rate of 5 %TW/EFPY will be applied to both the largest Return to Service (RTS)

TSP flaw reported during the 1RE25 SG ECT inspection as well as the largest undetected flaw determined from the bounding noise measurement.

From Table 4-1, the largest projected TSP wear flaw size is 58.0% TW for a five-cycle operating interval between inspections. These values satisfy the 3PNO structural integrity performance criteria. For pressure-only loading of volumetric flaws, satisfaction of the structural integrity performance criteria implies satisfaction of leakage integrity performance criteria at accident conditions. Therefore, it is projected that both detected and assumed undetected indications of TSP wear will not violate the SG tube integrity performance criteria during five cycle operating interval between inspections.

P a g e l 10 Assessment of Mechanical Wear at Anti-Vibration Bars (AVB)

The operational assessment for AVB wear considers undetected flaws and conservative growth rates, to ensure structural and leakage integrity for a 5-cycle interval (to EOC 30).

Since there has been no reported AVB wear at South Texas Unit 1 to date, the maximum undetected AVB wear indication assumed to remain in the SGs is estimated to be 14% TW. Table 4-2 shows the resulting projected flaw depth which is then compared to the EOC Structural Lim.it of 66.3% TW for a conservatively assumed flat 0.61-inch wear scar.

Assessment of Foreign Object Wear There have been eleven (11) instances of foreign object wear in three SGs at STP Unit 1; these foreign object wear indications are shown in Table 2-2 and are denoted at Volumetric (VOL) indications with the majority being reported at the Top of Tubesheet (TTS). There is one VOL indication present at the 8th TSP (Row 10 Col 50 08C); this indication is also considered to be wear due to a foreign object.

As shown in Table 2-2, none of the Volumetric indications due to FO wear have grown in the time since they were initially reported. Due to the nature of a wear scar due to a foreign object, these indications have no mechanism by which to grow further. The deepest indication of FO wear is 32% TW and the longest flaw is 0.28-inch, which is less than the structural limit of 67.9% TW for a 0.5-inch flaw. Therefore, it is projected that there will be no challenge to the South Texas Unit 1 SG structural and leakage integrity performance criteria due to foreign object wear.

P a g e l 11 Table 2-6 documents the foreign objects identified during the top of tubesheet inspections. There were 11 objects removed from the steam generators, and 19 objects remaining within the steam generators after the IRE25 inspection. None of these objects are detrimental to the safe operation of the SGs. These remaining objects also have wear times that would not wear a tube to the structural limit as noted in the Degradation Assessment (DA) greater than 7.5 EFPY. These are all summarized in Table 2-6.

Therefore, it is projected that there will be no challenge to the South Texas Unit 1 SG structural and leakage integrity performance criteria relative to these foreign objects that still reside in the SGs over an operating interval of 7.5 EFPY before the next planned inspection at EOC 30.

P a g e l 12

11.

THE NUMBER AND PERCENTAGE OF TUBES PLUGGED [OR REPAIRED] TO DATE, AND THE EFFECTIVE PLUGGING PERCENTAGE IN EACH SG No tubes were plugged during the 1RE25 outage. Historically, a total of 114 tubes have been plugged in the STP Unit 1 RSGs leading up to 1RE25:

12.

THE RESULTS OF ANY SG SECONDARY-SIDE INSPECTIONS. THE NUMBER, TYPE, AND LOCATION (IF AVAILABLE) OF LOOSE PARTS THAT COULD DAMAGE TUBES REMOVED OR LEFT IN SERVICE IN EACH SG During the 1RE25 inspections, six (6) possible loose part (PLP) calls were reported in SG1B and twenty-three (23) PLP calls were reported in SG1D. There were no PLP indications reported in SG1A or SG1C. Two of the 6 PLPs in SG1B were bounded by two tube locations as they were newly reported at 1RE25. No degradation was detected at any of the PLP locations.

P a g e l 13 Table 2-6 shows the known remaining objects in the SG secondary side following the 1RE25 inspections. These include non-metallic items such as tube scale and hard sludge deposits.

These non-metallic objects are of no concern for tube integrity as industry operating experience has shown them to be incapable of causing tube wear degradation.

Regarding the metallic objects, the objects remaining in each SG have been examined to ensure excessive degradation will not occur over the operating duration until the next secondary side inspection that will occur in 5-cycles. An engineering evaluation of the remaining foreign objects in each SG (performed with respect to the worst flow conditions and tube vibration) shows that all objects that will still reside in the SGs at South Texas Unit 1 are acceptable for operation for at least 5 cycles or 7.5 EFPY.

No tube wear has been detected by the eddy current test program on tubes adjacent to these objects.

Therefore, it is projected that there will be no challenge to the South Texas Unit 1 SG structural and leakage integrity performance criteria relative to these foreign objects that still reside in the SGs over an operating interval of 7.5 EFPY before the next planned inspection at EOC 30.

P a g e l 14

13.

THE SCOPE, METHOD, AND RESULTS OF SECONDARY SIDE CLEANING PERFORMED IN EACH SG Secondary Side Base Scope Sludge Lancing Top of the tubesheet sludge lancing was performed.

Foreign Object Search and Retrieval (FOSAR)

FOSAR was performed on the top of the tubesheet, viewing every other column.

Steam Drum Inspections Visual inspections of SG1A and SG1D Sludge collector cleaning of SG1A and SG1D 9th TSP Visual inspection Visual inspection of the 9th TSP in SG1A See Table 2-6 for foreign objects remaining on secondary side. Sludge removed from top of tubesheet and sludge collectors is shown in Table 2-5:

14.

THE RESULTS OF VISUAL INSPECTIONS PERFORMED IN EACH SG NSAL-12-1 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 1 1RE25. Visual inspections were performed on the entire inside surface of the SG channel head bowl. Key areas of inspection include the channel head cladding, the divider plate-to-channel head weld and the channel head-to-tubesheet weld. Inspections were performed in accordance with guidance provided by Westinghouse Nuclear Safety Advisory Letter (NSAL)

NSAL-12-1 recommendations using the SG manway channel head bowl cameras.

There was no apparent cladding loss in any of the channel head, and there was also no degradation of any welds within the channel heads. Satisfactory inspection results were observed in all SGs.

P a g e l 15 In-Bundle Inspection of the Ninth Tube Support Plate 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 SG1A was performed.

Video probes were deployed from the tube lane using extensions that permitted visual observation of flow slots, tube surfaces, and trefoil ligaments.

The inspection showed a very low level of magnetite covering the TSP top surface, with no loose deposits noted. No deposit bridging across the trefoil to tube outside diameter (OD) surface was observed. No departures from the expected appearance of the TSP ligaments were observed. No negative impact on steam generator operation is expected.

Steam Drums Steam Drum inspections were conducted in SG1A and SG1D and an Upper Steam Drum Inspection was conducted in SG1D 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. Sludge collectors in SG1A and SG1D were cleaned and post cleanliness inspection showed minor sludge left in collectors, no significant findings of loose parts. The inspection of the steam drums showed that all surfaces were gray in color, similar to last inspection during 1RE22.

15.

ANY PLANT-SPECIFIC REPORTING REQUIREMENTS, IF APPLICABLE Sludge Pile Volumetric (Pitting)

During the STP Unit 1 EOC 19 inspection (1RE19), a volumetric indication was reported at one tube location (SG 1D R30-C78 TTS). This tube location is within the hardpack sludge in the kidney region of SG 1D.

According to the mitigation strategy developed by STP, pitting corrosion was assigned as an existing degradation mechanism until both units 1 and 2 have two consecutive inspections without any new sludge pile volumetric indications. This most recent inspection at STP Unit 1 (1RE25), and the most recent inspection at STP Unit 2 (2RE22) were the second inspections at each plant since the enactment of the mitigation strategy.

During the past two inspections for both units 1 and 2, zero (0) sludge pile volumetric indications were reported. Therefore, Pitting Under Hard Sludge Deposits will become a potential mechanism and will no longer require additional eddy current and visual inspections from this inspection forward at STP Units 1 or 2.