ML23221A300
| ML23221A300 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 08/09/2023 |
| From: | Georgeson C South Texas |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| NOC-AE-23003978, 35497201, EPlD L-2023-LRO-0029 | |
| Download: ML23221A300 (1) | |
Text
{{#Wiki_filter:ryfr South Texas Campany Pro/ect Electrb Generating Statrbn I:O. Box 289 Wadsworth, Teras 77483 August 9,2023 NOC-AE-23003978 10 cFR 50.36 STI: 35497201 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 South Texas Project Unit 2 Docket No. STN 50-499 2RE22 I nspection Summary Report for Steam Generator Tubinq Rev 1 (EPlD. L-2023-LRO-0029)
Reference:
Letter; C. Georgeson (STP) to Document Control Desk (NRC);"2RE22 lnspection Summary Report for Steam Generator Tubing;" Aprll24,2Q23; (NOC-AE-23003958) (M1231 1 4A341) STP Nuclear Operating Company is submitting the attached Revision 1 to the referenced letter regarding the summary report of the South Texas Project Unit 2 steam generator tube inspection. The revision reflects clarification in Section 2 and Section 5. 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 (36't) 972-4527 .
/t Christopher on General Manager, Engineering scr RE22lnspection Summary Report for Steam Generator Tubing (Rev. 1) South Texas Project Electric Generating Station Unit 2 cc:
Regional Administrator, Region lV U.S. Nuclear Regulatory Commission 1600 E. Lamar Boulevard Arlington, TX 7601 1-4511
I 3U D z SiTP 2RF,22 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING (Rev. 1) SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 2 p.o. Box 289, WADSWORTH, TEXAS 77483 Commercial Operation: June 19, 1989 Issue Date: Aprll 24th, 2023 USNRC DOCKET NO 50-499 OPERATING LICENSE NO. NPF-80 COMMERCIAL OPERATION DATE June 1gth, 1989 Prepared By: %/fu M. farner-a /t/ zs Date Steam Generator Engineer Approved By C.
/ r a3 Manager, General Engineering
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 6907T I 4
- of tubes per SG / Nominal Tube Dia. / tube 7,585 I II116 in / 0.040 in thickness Support Plate Style / Material Broached Trefoil / 405 Stainless Steel Last Inspection Date April2018 EFPM since the last inspection 51.12 EFPM Total cumulative SG EFPY 17.64 EFPY Mode 4 initial entry Aprtl24th,2018 Observed P/S Leak Rate since the last 0.00 GPD RT-8027 radiation monitor inspection and how it trended with time Nominal indicated value of Thot during Cycle 62I.8 degrees F (This value was taken at X at full power RCTA0430A on July 10th.2022\
Potential pitting mechanism similar the STP Unit I volumetric indication discovered under Degradation mechanism sub population hardened sludge collar during 1RE19 (Fall 20 1 s). Deviations from SGMP guidelines since the None last inspection Steam Generator Schematic Schematic is attached. See next pase
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- 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 newly discovered indication locations were identified during the 2RE22 inspection. There were six (6) small indications being tracked from previous inspections that finally met the threshold to be reported in2RE22; and are listed as newly reported. No expansions were needed.
Bobbin Coil Inspection o 100Yo Full length bobbin coil inspection ofall tubes Rotating Coil Inspection U-Bend o 100Yo +POINT probe inspection of the upper TSP hot leg to upper TSP cold leg of Rows 1 atd2. Rotating Coil Inspection - Straight Section r +Point probe inspection ofouter three tubes ofperiphery and divider lane TTS +6 inches/-3 inches, including hot leg (HL) and cold leg (CL), to aid in foreign objects detection. o 40%o Sample +Point probe inspection of TSH +6 inches/-3 inches. o 100o/o +Point probe inspection of TSH +6 inches/-16 inches in tubes with bulges and over-expansions. r +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 r +Point probe inspection of all previously identified dents and dings > 5 volts, bobbin inspection of all previously identified dents and dings < 5 volts. o +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. r +Point probe inspection ofpossible loose parts (PLPs) in the eddy current database as identified by previous eddy current inspections. r +Point probe inspection of a minimum two tube locations surrounding all observed foreign objects identified during 2RE22 secondary side video inspections. o +Point probe inspection of a minimum two tube locations surrounding any newly identified PLP. o +Point probe inspection of any tube-to-tube wear indications detected by bobbin coil. o +Point probe inspection of all bobbin proximity (PRO) signals >2.5 volts. o +Point probe inspection of all MBM bobbin coil indications that have increased by .0.5 volt for existing bobbin coil MBM indications. o +Point probe inspection of prior cycle MBMs that are tube-to-tube wear (TTW) candidates. o +Point probe inspection of all wear indications left in service. Other Primary Side Inspections o Video inspection of all installed tube plugs from the primary side. o 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 o Rotating Coil inspection of kidney region (hot leg sludge pile area) .uirth2 tube locations surrounding the sludge pile, +6 inches/-3 inches in all four steam generators was performed to identifu any pitting mechanisms similar to STP Unit 1 (lREl9 during the Fall of 2015).
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. 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
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- 5. THE LOCATION, ORIENTATION (IF LINEAR), MEASURED SIZE (IF AVAILABLE), AND VOLTAGE RESPONSES OF EACH INDICATION. FOR TUBE WEARAT SUPPORT STRUCTURES LESS THAN 20 PERCENT THROUGH-WALL, ONLY THE TOTAL NUMBEROF INDICATIONS NEEDS TO BE REPORTED The2RE22 inspection includes a bobbin noise threshold of O.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 Unit2 steam generator inspections conducted during 2RE22, ten locations were found to have TSP wear. There were six (6) small indications being tracked from previous inspections that finally met the threshold to be reported. There was one newly reported indication in SG 24: R1C79 08C; three newly reported indications in SG 2C:RlCl2I07C, R4C82 07C, R4C124 06C; and two newly reported indications in SG 2D: R6C118 05C, R6C1 18 08C. There were no new indications to report in SG 28. A historic data re-analysis was perfonned on these newly reportable indications and these indications were able to be seen in previous outages. See Table 2-2 for additional information.
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- 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 Unit2 RSG inspection interval.
Therefore. the SG performarlce criteria for structural and leakage integrity were satisfied for all degradation mechanisms detected for the preceding South Texas Unit2 SG operating interval. The condition monitoring results are summarizedin Table 3-1.
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- 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 in2RE22 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 REPAIREDI 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 2R822 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 2PtE22 outage. Historically , a total of ten tubes have been plugged in the STP Unit 2 RSGs leading up to 2RE22: sfi # Tuhgr # Flllsxrd fir lrlussilts f f i'!_-\ t $.st:1
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- 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 2P.E22 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 EOC27). 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 2R822 is 4.26 EFPY and the inspection interval between 2RE16 to 2R822 is 8.29 EFPY. Taking the largest difference in growth between the two inspections, for 2RE19 and2RE22 is 4o/o TW and 2RE16 to 2RE22 is 4oATW, and divided by the EFPY of the inspection interval, 4.26EFPY for 2RE19 to2RE22 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 satisff the 3APNO 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. Tuhle 4*Il $*uth Ter** InS33 TSF trtr;**r {}A i* fiO{] 3? Drgr*dxti*x ${xx S,sratian
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!f9.rTlV 5{i"3 :.. {5 I-f ndetrc{*d 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 (toEOC27).
Since there has been no reported AVB wear at South Texas Unit2 to date, an undetected population flaw depth of I9Yo 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 660/o for a conservatively assumed flat 0.61-inch wear scar.
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Alr'B tr?**r: tq?;Tw T"5 tl.fi t 5a;T\\'rEFilY 5#"J fl6T4, TW I ail Und*t*ct*J Assessment of Foreign Object Wear There has been no reported foreign object wear reported at South Texas Unit2 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 the2RE22 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 Unit2 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 Unit2 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 atEOC 27 .
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- 11. THE NUMBER AND PERCENTAGE oF TUBES PLUGGED [oR REPAIREDI TO DATE, AND THE EFFECTIVE PLUGGING PERCENTAGE IN EACH SG No tubes were plugged during the 2R822 outage. Historically, a total of ten tubes have been plugged in the STP Unit 2 RSGs leading up to 2RE22:
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- 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 coffesponding to new PLPs.
t2 Table 2-4 shows the known remaining objects in the SG secondary side following the2RE22 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 Table2-4. 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 Unrt2 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 atEOC 27. Table2.4:
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- 13. THE SCoPEo METHoD, AND RESULTS oF SECoNDARY-SIDE CLEANING PERFORMED IN EACH SG Secondary Side Base Scope Sludge Lancing o Top of the tubesheet sludge lancing was performed.
13 Foreign Object Search and Retrieval (FOSAR) o FOSAR was performed on the top of the tubesheet, viewing every other column. Steam Drum Inspections o Visual inspections of SG2A and SG2D o Sludge collector cleanings of SG2A and SG2D 9th TSP Visual inspection o 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: itr"stbtr* I-F: f,TF Limit ! :ltli}2 ${] Tuh*s}erct il*pa*iZ &*r*av$ l)*prxi{ Amsilnt lt*mrvrd t)*p**i t "Aenaunt Rc m*r,ed ti{; Slu*x* L*nri$s {lhrl Frs,ffi fitr$dse f;rllsetar {}b*}
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- 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 Unit22RE22. 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
I4 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 2Aand 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. A11 components were in good condition with no cracking, erosion, or deformation. Sludge collectors in SG 2A and2D 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. ANYPLANT.SPECIFICREPORTTNGREQUIREMENTS,IFAPPLICABLE Sludge Pile Volumetric (Pitting)
Pitting is an assumed existing degradation mechanism in South Texas Unit2. Pitting has not been identified in South Texas Unit2, but as part of the resolution of the sludge pile volumetric indication that was found in South Texas Unit 1 during the lREl9 inspection, South Texas Unit 2 will treat pitting as an existing degradation mechanism until both Units I and2 have two consecutive inspections without any new sludge pile volumetric indications. No sludge pile volumetric indications were identified during the South Texas Unit 2 2R822 inspection. Since there has been two consecutive inspections at STP Unit2 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 Unit2 inspection.}}