ML23114A341

RE22 Inspection Summary Report for Steam Generator Tubing

ML23114A341
Person / Time
Site:	South Texas  (NPF-080)
Issue date:	04/24/2023
From:	Georgeson C South Texas
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
NOC-AE-23003958, STI: 35463459
Download: ML23114A341 (1)

Text

Campcny Y:T South Texas Pro/ect Electric Generatint Station 20. &ox 289 Wadsworth, Tees 77483 April24,2023 NOC-AE-23003958 10 cFR 50.36 STI: 35463459 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 South Texas Project Unit 2 Docket No. STN 50-499 2RE22 lnspection Summarv Report for Steam Generator Tubing Enclosed is the summary report describing the results of the South Texas Project Unit 2 steam generator tube inspection performed during refueling outage 2RE22. 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.

lf there are any questions regarding this report, please contact me at (361) 972-7806, or Stephanie Rodgers at (361) 972-4527.

(/

Christopher n

General M'anager, Engineering

Enclosure:

2RE22lnspection Summary Report for Steam Generator Tubing (Rev. 0) of the South Texas Project Electric Generating Station Unit 2 Regional Administrator, Region lV U.S. Nuclear Regulatory Commission 1600 E. Lamar Boulevard Arlington, TX 76Q1 1-4511 scr cc

Prepared By:

Approved By:

2RE22 INSPECTION

SUMMARY

REPORT FOR STEAM GENERATOR TUBING (Rev. 0)

SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 2 P.O. BOX289, WADSWORTH, TEXAS 77483 Commercial Operation: June 19, 1989 Issue Date: April 24th, 2023 USNRC DOCKET NO.:

OPERATING LICENSE NO.:

COMMERCIAL OPERATION DATE:

M. Gamer Steam Generator Engineer C.Georg~ JI, /!~-,,.

Manager, General Engineering 50-499 NPF-80 June 19th, 1989 Date 1

2 180-Day Steam Generator Tube Inspection Report South Texas Project Unit 2 Cycle 22

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 2018 EFPM since the last inspection 51.12 EFPM Total cumulative SG EFPY 17.64 EFPY Mode 4 initial entry April 24th, 2018 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 621.8 degrees F (This value was taken at RCTA0430A on July 10th, 2022)

Degradation mechanism sub population Potential pitting mechanism similar the 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.

3 South Texas Delta 94 RSGs Fabricated by Equipos Nucleares, S.A. (ENSA)

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, and special interest. No 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 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 (Appendix B).

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 2RE22 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 2RE22 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

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 mechanisms similar to STP Unit 1 (1RE19 during the Fall of 2015).

5

• 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 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 PERCENT THROUGH-WALL, ONLY THE TOTAL NUMBER OF INDICATIONS NEEDS TO BE REPORTED The 2RE22 inspection includes a bobbin noise threshold of 0.5-volt in all regions of interest.

This threshold is lower than the value required by the must-detect flaws, and a common threshold for similar 690TT plants. Therefore, it is established that any indications greater than or equal to the must detect depth will be reported.

During the STP Unit 2 steam generator inspections conducted during 2RE22, ten locations were found to have TSP wear. There was one new indication reported in SG 2A: R1C79 08C; three new indications reported in SG 2C: R1C121 07C, R4C82 07C, R4C124 06C; two new indications reported in SG 2D: R6C118 05C, R6C118 08C. There were no new indications reported in SG 2B. A historic data re-analysis was performed on these new indications and these indications were able to be seen in previous outages. See Table 2-2 for additional information.

7 The following table evaluates the ten locations as PCT and 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 2 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 2 SG operating interval.

The condition monitoring results are summarized in Table 3-1.

8

7.

DISCUSS ANY DEGRADATION THAT WAS NOT BOUNDED BY THE 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 2RE22 that was not bounded by the prior Operational Assessment (2RE19). 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.

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 2RE22 outage. No tubes have exhibited degradation exceeding the tube integrity criteria given in the Degradation Assessment (DA) for the 2RE22 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 2RE22 outage. Historically, a total of ten tubes have been plugged in the STP Unit 2 RSGs leading up to 2RE22:

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 2RE22 inspection along with the foreign objects that remain on the secondary side is provided in the following sections:

Mechanical Wear at Tube Support Plates

9 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 EOC 27).

The growth rates are determined given an operating duration between two inspections of the same tube. Seven tubes were inspected previously in 2RE19, and two were inspected previously in 2RE16. The inspection between 2RE19 to 2RE22 is 4.26 EFPY and the inspection interval between 2RE16 to 2RE22 is 8.29 EFPY. Taking the largest difference in growth between the two inspections, for 2RE19 and 2RE22 is 4% TW and 2RE16 to 2RE22 is 4% TW, and divided by the EFPY of the inspection interval, 4.26 EFPY for 2RE19 to 2RE22 and 8.29 EFPY for 2RE16 to 2RE22, a growth rate is determined.

From Table 4-1, the largest projected TSP wear flaw size is 60.8% 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.

Assessment of Mechanical Wear at Anti-Vibration Bars 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 27).

Since there has been no reported AVB wear at South Texas Unit 2 to date, an undetected population flaw depth of 19% TW is assumed to remain in service for 5-operating cycles between inspections with each cycle conservatively assumed to be 1.5 EFPY. Table 4-2 shows the resulting projected flaw depth which is then compared to the EOC Structural Limit of 66%

for a conservatively assumed flat 0.61-inch wear scar.

10 Assessment of Foreign Object Wear There has been no reported foreign object wear reported at South Texas Unit 2 to date.

Therefore, without any foreign object wear, no operational assessment is needed.

Table 2-4 shows the known remaining objects in the SG secondary side following the 2RE22 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 of the objects that will remain in the SGs at South Texas Unit 2 have wear times greater than 10-cycles. Results of this evaluation are shown as Wear Time in Table 2-4. (See next page)

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 2 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 27.

11

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 2RE22 outage. Historically, a total of ten tubes have been plugged in the STP Unit 2 RSGs leading up to 2RE22:

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 2RE22 inspections there were no foreign objects discovered corresponding to new PLPs.

12 Table 2-4 shows the known remaining objects in the SG secondary side following the 2RE22 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 the all objects that will still reside in the SGs at South Texas Unit 2 have wear times greater than 10-cycles. Results of this evaluation are shown as Wear Time in Table 2-4.

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 2 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 27.

Table 2.4:

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.

13 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 SG2A and SG2D

• Sludge collector cleanings of SG2A and SG2D 9th TSP Visual inspection

• Visual inspection of the 9th TSP in SG2A See Table 2.4 (previous page) for foreign objects remaining on secondary side. Sludge removed from top of tubesheet and sludge collectors is as follows:

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 2 2RE22. 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.

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 SG 2A was performed.

Video probes were deployed from the tube lane using extensions that permitted visual

14 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 Visual observations were made of the steam drums of SG 2A and SG 2D 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 SG 2A and 2D 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 2RE19.

15.

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

Pitting is an assumed existing degradation mechanism in South Texas Unit 2. Pitting has not been identified in South Texas Unit 2, but as part of the resolution of the sludge pile volumetric indication that was found in South Texas Unit 1 during the 1RE19 inspection, South Texas Unit 2 will treat pitting as an existing degradation mechanism until both Units 1 and 2 have two consecutive inspections without any new sludge pile volumetric indications.

No sludge pile volumetric indications were identified during the South Texas Unit 2 2RE22 inspection. Since there has been two consecutive inspections at STP Unit 2 with no findings of these indications, the expanded scope for pitting can be removed from the base scope inspection plan and sludge pile volumetric indications will become a potential degradation mechanism for the next Unit 2 inspection.