CP-202300361, (CPNPP) - Unit 2 Refueling Outage 20 (2RF20) Steam Generator 180 Day Report

(CPNPP) - Unit 2 Refueling Outage 20 (2RF20) Steam Generator 180 Day Report

ML23229A598
Person / Time
Site:	Comanche Peak
Issue date:	08/17/2023
From:	Hicks J Luminant, Vistra Operating Co. (VistraOpCo)
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
CP-202300361, TXX-23056
Download: ML23229A598 (1)

Text

m Luminant Jack C. Hicks Manager, Regulatory Affairs Comanche Peak Nuclear Power Plant (Vistra Operations Company LLC)

P.O. Box 1002 6322 North FM 56 Glen Rose, TX 76043 T 254.897 .6725 CP-202300361 TXX-23056 August17, 2023 U.S. Nuclear Regulatory Cmrnnission Ref 10CFR50.55a ATIN: Docmnent Conh*ol Desk TS5.6.9 Washington, DC 20555-0001

Subject:

Comanche Peak Nuclear Power Plant (CPNPP)

Docket No. 50-446 Unit 2 Refueling Outage 20 (2RF20) Steam Generator 180 Day Report

Dear Sir or Madam:

Vish*a Operations Company LLC ("Vish*a OpCo") hereby submits the Comanche Peak Nuclear Power Plant (CPNPP) Unit 2 steam generator tube inspection report for 2RF20 as required by Teclmical Specification 5.6.9.

This conunl.mication contains no new conm1ihnents regarding CPNPP Unit 2.

Should you have any questions, please contact Jim Barnette at (254) 897-5866 or I arnes.barnette@lurninant.com.

Sincerely, Attaclunent: 180 Day Stearn Generator Tube Inspection Report - Comanche Peak Unit 2 Cycle 20 c (email) - Robert Lewis, Region IV [Robert.Lewis@mc.gov]

Dennis Galvin, NRR [Dennis.Galvin@mc.gov]

John Ellegood, Senior Resident Inspector, CPNPP Uolm.Ellegood@mc.gov]

Attachment to TXX-23056 Page 1 of 11 180 Day Steam Generator Tube Inspection Report - Comanche Peak Unit 2 Cycle 20

1. DESIGN AND OPERATING PARAMETERS Steam Generator Design and Operating Parameters SG Model / Tube Material / # SGs per unit W-D5 / Alloy 600TT / 4

1. of tubes per SG / Nominal Tube Dia. / tube 4,570 / 0.750 in. / 0.043 in.

thickness Broached Quatrefoil and Drilled Hole /

Support Plate Style / Material Stainless Steel Last Inspection Date October 2021 (2RF19)

EFPM since the last inspection 17.11 Total cumulative SG EFPY 26.90 Mode 4 initial entry May 22nd, 2023 Observed P/S Leak Rate since the last No leakage observed inspection and how it trended with time 618 Degrees F (This value was the highest Nominal indicated value of Thot during Cycle and will be used as the conservative average 20 at full power of the four loops.)

Degradation mechanism sub-population Potential ODSCC at Dings/Dents Deviations from SGMP guidelines since the None last inspection Steam Generator Schematic Schematic is attached. See next page

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Attachment to TXX-23056 Page 3 of 11

2. SCOPE OF INSPECTIONS PERFORMED ON EACH SG The 2RF20 inspection scope was implemented as-planned, with no scope expansion required.

The inspection scope implemented during 2RF20 was limited based on the requirements of TSTF-577 for inspections following the detection of cracking at the previous inspection. As per TSTF-577, inspections of all dents and dings were required during 2RF20 due to the reporting of an Axial ODSCC indication at a freespan ding in 2RF19. The inspection scope included the items listed below (for all SGs unless otherwise noted):

Primary Side Exam Probe Extent Base Scope Bobbin 100% of 2RF19(1) Dents/Dings in all SGs Bobbin 100% of 2RF20 Dents/Dings 2-5v in all SGs

ŽZ&Ž SGs Special 100% of Dents/Dings in high residual tubes (-2 sigma tubes) in all SGs Interest Two-tube box-in of any newly identified PLPs

+Point One-tube box-in of any PLPs that have been previously identified (Diagnostic)

All I-Codes not resolved after history review (DNI, NQI, etc.)

As needed to support tube integrity evaluations Plug Visual Inspection Camera All plugs inspected Primary Channel Camera Hot leg and cold leg exam per Section 5.3 of NEI TSTF-510 Head Visual (1) All 2RF19 reported Dents/Dings will be measured with bobbin in 2RF20. Due to fluctuation of voltage between inspections, indications will require +Point testing if they exceed the 5v threshold as measured in 2RF20.

Regarding expansion of the inspection scope, if cracking is detected scope expansion will be performed in accordance with the EPRI SG Integrity Assessment Guidelines. Since the inspection scope is limited to dents/dings and 100% are planned for inspection at 2RF20, no inspection expansion is expected. If cracking is found in the region below the H* distance, no scope expansion is required; the flaw may remain in service per the H* alternate plugging criteria.

3. THE NONDESTRUCTIVE EXAMINATION TECHNIQUES UTILIZED FOR TUBES WITH INCREASED DEGRADATION SUSCEPTIBILITY

+Point/Rotating probe (RPC) was utilized for all tubes with increased degradation susceptibility as described in the scope of inspections.

Attachment to TXX-23056 Page 4 of 11

4. THE NONDESTRUCTIVE EXAMINATION TECHNIQUES UTILIZED FOR EACH DEGRADATION MECHANISM FOUND Degradation Detection Detection Technique Sizing Probe Sizing Technique Mechanism Probe Type ETSS Type ETSS Quatrefoil TSP Wear Bobbin I96043.1, Rev. 2 +Point 96910.1, Rev. 11 Drilled TSP Wear Bobbin I96042.1, Rev. 4 Pancake 96911.1, Rev. 9 AVB Wear Bobbin I96041.1, Rev. 6 +Point 96004.3, Rev. 13 FO Wear Bobbin 27091.2, Rev. 2 +Point 21998.1, Rev. 4

5. LOCATION, ORIENTATION, MEASURED SIZE, AND VOLTAGE RESPONSES Wear Indications <20% TW at support structures (AVBs, TSPs, and PBPs)

SG1 SG2 SG3 SG4 Total 51 14 12 13 90

Attachment to TXX-23056 Page 5 of 11

% Axial Cir. Cir.

SG Row Col Volts Ind Location Inch Probe TW Length Width Degrees 1 33 103 1.03 WEAR 20 AV1 0.00 Bobbin 1 33 103 1.02 WEAR 20 AV2 0.31 Bobbin 1 34 102 1.24 WEAR 22 AV2 0.31 Bobbin 1 34 102 2.13 WEAR 29 AV4 0.35 Bobbin 1 36 90 1.06 WEAR 20 AV2 0.29 Bobbin 1 38 99 1.03 WEAR 20 AV2 -0.06 Bobbin 1 38 99 1.69 WEAR 26 AV3 0.46 Bobbin 1 39 17 2.09 WEAR 26 AV2 0.09 Bobbin 1 39 89 1.05 WEAR 20 AV2 0.37 Bobbin 1 40 30 1.39 WEAR 20 AV2 0.31 Bobbin 1 40 30 1.34 WEAR 20 AV3 0.17 Bobbin 1 40 30 1.32 WEAR 20 AV4 -0.06 Bobbin 1 42 94 2.89 WEAR 33 AV2 0.03 Bobbin 1 43 87 1.23 WEAR 22 AV3 -0.03 Bobbin 1 43 87 1.8 WEAR 27 AV2 0.06 Bobbin 1 45 79 1.35 WEAR 23 AV2 0.31 Bobbin 1 45 79 2.58 WEAR 31 AV4 0.00 Bobbin 1 45 87 1.13 WEAR 21 AV2 0.00 Bobbin 1 45 87 1.94 WEAR 27 AV1 0.03 Bobbin 1 45 87 2.2 WEAR 29 AV3 0.00 Bobbin 1 46 89 1.44 WEAR 24 AV2 0.03 Bobbin 1 46 89 1.57 WEAR 25 AV4 0.03 Bobbin 2 36 99 3.51 WEAR 34 AV2 0.00 Bobbin 3 24 107 1.14 WEAR 20 AV2 -0.03 Bobbin 3 26 107 1.4 WEAR 22 AV2 0.06 Bobbin 3 30 105 1.76 WEAR 25 AV2 0.00 Bobbin 3 33 103 1.27 WEAR 22 AV4 0.11 Bobbin 3 33 103 1.42 WEAR 23 AV1 0.00 Bobbin 3 33 103 3.52 WEAR 34 AV3 0.00 Bobbin 3 49 59 0.22 VOL 19 H9 -0.79 0.08 0.2 31 +Point 4 27 104 0.13 VOL 17 C1 0.07 0.19 0.28 43 +Point 4 44 43 0.1 VOL 12 C2 2.28 0.14 0.3 46 +Point 4 44 44 0.29 VOL 27 C2 2.02 0.24 0.43 66 +Point 4 44 44 0.39 VOL 34 C2 2.26 0.16 0.45 69 +Point

Attachment to TXX-23056 Page 6 of 11

6. CONDITION MONITORING ASSESSMENT AND RESULTS, 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 The EPRI PWR SG Examination Guidelines require that the existing degradation mechanisms identified in the DA be subject to appropriate inspection programs to comply with the plant SG Technical Specifications. The existing degradation mechanisms in the CPNPP Unit 2 SGs for 2RF20 are:

• Tube wear at AVBs

• Tube wear at preheater baffle plates

• Tube wear at quatrefoil tube support plates

• Tube wear due to foreign objects

• Circumferential PWSCC at BLG/OXP locations in HL tubesheet (not detected 2RF20)

• Circumferential PWSCC at HL Tubesheet Expansion Transitions (not detected 2RF20)

• Axial ODSCC at Dents/Dings (not detected 2RF20)

The condition monitoring results for 2RF20 are presented in the table below for all detected degradation mechanisms. Any existing degradation mechanisms not found in table were not detected at 2RF20 and meet condition monitoring for structural and leakage integrity. Wear at drilled holes in the PBP and FDB were sized with the Pancake coil (ETSS 96911.1). Wear at broached holes in the TSPs were sized with the

+POINT coil (ETSS 96910.1).

CPNPP 2RF20 Condition Monitoring Summary for Limiting Flaw Mechanism SG Row Col IND Loc 2RF20 Limiting CM Limit Flaw 34% TW, 66.8% TW, 0.5-inch flaw AVB Wear 2 36 99 PCT AV2 0.5-inch 96004.3 (assumed) 12% TW, 0.21- 46.4% TW, 0.75-inch flaw PBP Wear 1 49 56 WAR C5 96911.1 inch 15% TW, 0.24- 54.3% TW, 1.125-inch flaw TSP Wear 1 49 67 WAR C7 96910.1 inch 34% TW, 0.16- 66.2% TW for 0.25-inch flaw FOW 4 44 44 VOL C2 21998.1 inch For volumetric wear flaws with pressure-only loading condition, tube burst and ligament tearing (i.e.,

pop- ŽŽŽŽŽWNO also satisfies the accident induced leakage performance criteria (AILPC) at steam line break differential pressure.

Therefore, for AVB, PBP, TSP and Foreign Object wear, the SG structural and leakage performance criteria are satisfied for condition monitoring.

Attachment to TXX-23056 Page 7 of 11 SG Integrity Assessment Guidelines require condition monitoring results from the current inspection be compared to the OA from the previous inspection. This comparison identifies whether the underlying assumptions, input parameters, or methodology for performing OAs are conservative or require alteration prior to performing the next OA. Failure to meet CM requirements means that the projections of the prior OA were not conservative and that necessary corrective actions are to be identified. Even when CM requirements are met, this comparative review may identify adjustments to the OA inputs or assumptions.

For wear mechanisms, a comparison of the previous OA to the 2RF20 inspection results is presented in the table below.

Comparison of Previous Wear OA Projections to 2RF20 Results Mechanism 2RF20 Projection (% TW) 2RF20 Limiting Flaw (% TW)

AVB Wear - Existing 49.2 34 AVB Wear - New 20.1 17 PBP Wear - Existing 41 12 PBP Wear - New 19.5 N/A TSP Wear - Existing 36.4 15 TSP Wear - New 19.5 13 Based on the inspection data and the condition monitoring assessment, no tubes exhibited degradation exceeding the condition monitoring limits set forth in the 2RF20 DA. No tubes required in situ pressure or leak testing to demonstrate structural and leakage integrity. Therefore, the SG performance criteria for structural and leakage integrity were satisfied for all degradation mechanisms for the preceding CPNPP Unit 2 SG operating interval.

7. TUBES PLUGGED OR REPAIRED DURING THE INSPECTION OUTAGE.

No tubes were required to be plugged as a result of the 2RF20 inspections.

8. THE REPAIR METHODS UTILIZED, AND THE NUMBER OF TUBES REPAIRED BY EACH REPAIR METHOD N/A

Attachment to TXX-23056 Page 8 of 11

9. ANALYSIS

SUMMARY

OF THE TUBE INTEGRITY CONDITIONS PREDICTED TO EXIST AT THE NEXT SCHEDULED INSPECTION The Operational Assessment for tube wear mechanisms was performed using conservative methods to project EOC flaw depths for each active mechanism. For detected wear, this includes burst relation, material property and NDE measurement uncertainties. For undetected wear, this includes burst relation and material property uncertainties. It was concluded that the projected EOC depth of the largest detected and assumed undetected flaw will remain below the calculated structural limits with sufficient margin at 2RF22. For volumetric flaws ligament tearing is coincident to burst. Therefore, since structural

WEKŽeakage integrity is expected to be maintained to at least 2RF22 as well.

The Operational Assessment for SCC mechanisms was performed with assumed undetected flaws for each existing degradation mechanism. Probabilistic methods were used for the OA calculations with an acceptance criterion of 5.0% for POB, POL, minimum burst pressure requirement and the plants accident induced leak rate limit. The evaluations include uncertainties associated with burst relation and tube material properties. Each evaluation assumed undetected flaws at 2RF19 or 2RF20, and the operating interval until the next planned inspection. Accepted industry methods were used to develop the POD functions, undetected flaw populations and growth rates for each SCC mechanism evaluated.

For each SCC mechanism, the POB and POL were calculated to be below the 5.0% criterion which demonstrates structural and leakage integrity until the next planned inspection at 2RF22.

When combining predicted leakages from the OA calculations, and in considering CPNPP Unit 2 requirements associated with the H* alternate repair criteria, it was determined that an administrative leakage limit of 107 gpdRT would be needed for Cycle 21 and Cycle 22.

Two SG channel head cladding anomalies are being tracked at CPNPP Unit 2 and were visually observed during 2RF20. The anomalies did not appear to change from the prior inspection. A corrosion rate evaluation has been performed for the larger of the two flaws. There is significant margin between the estimated flaw depth and the ASME Code allowable; therefore, no repairs are required.

A total of 16 foreign objects remained in the secondary side of the SGs following the last FOSAR at 2RF19.

All of these objects were small parts and demonstrated by bounding calculations through tube wear projections to not adversely affect tube integrity until at least 2RF22. Therefore, FOSAR was not planned or implemented at 2RF20.

The CM and OA for the CPNPP Unit 2 SGs at the 2RF20 outage follows the requirements of the SG Integrity Assessment Guidelines and complies with requirements of NEI-97-06 and the CPNPP Technical Specifications. It has been shown that all existing degradation mechanisms will maintain structural and leakage integrity until the next planned inspection, for each existing degradation mechanism. Potential mechanisms were also considered and are not expected to challenge the structural or leakage integrity performance criteria during the next operating interval, 2RF20-2RF22.

Attachment to TXX-23056 Page 9 of 11

10. NUMBER AND PERCENTAGE OF TUBES PLUGGED OR REPAIRED TO DATE, AND THE EFFECTIVE PLUGGING PERCENTAGE IN EACH SG The tube plugging summary for CPNPP Unit 2 is presented below.

SG # Tubes 2RF20 # Plugged Total # Plugged  % Plugging 1 4,570 0 24 0.53 2 4,570 0 35 0.77 3 4,570 0 24 0.53 4 4,570 0 19 0.42 Total 18,280 0 102 0.56

11. SG SECONDARY-SIDE INSPECTION RESULTS FOSAR inspections were last performed at 2RF19, and the results are detailed in Section 3.7 of the 2RF19 OA. There was no FOSAR planned or completed at 2RF20.

For the objects remaining in the SG secondary side following CPNPP 2RF19, the foreign object evaluation performed following 2RF16 and extended by 2RF18 Deferral OA can be applied. The previous assessment bounds the objects remaining in the SG, which are all Priority 3 items. This assessment finds smaller parts like those remaining after 2RF19 are acceptable for an operating period of greater than 4.5 EFPY by comparison to a bounding evaluation performed in Steam Generator Degradation Assessment Guidelines. Therefore, continued SG operation with the foreign objects known to be present in the secondary side will not adversely affect the SG tube integrity for at least two more cycles after 2RF20 or until the next schedule secondary side inspection at 2RF22.

Upper steam drum visual inspections were last performed in all four SGs during 2RF17. The steam drum inspections did not find any significant signs of progressing erosion, cracking, material loss or other forms of degradation. Small amounts of incipient erosion have been observed in various components.

However, this amount of degradation is judged to be quite small in comparison to the expected structural margin of the component and has been evaluated as acceptable. The steam drum component condition in 2RF17 was similar to the condition at the previous steam drum inspection during 2RF08 with no evidence of progressing degradation.

12. THE SCOPE, METHOD, AND RESULTS OF SECONDARY-SIDE CLEANING PERFORMED IN EACH SG Sludge lancing was not performed for any of the SGs during 2RF20. Sludge lancing was last performed during 2RF19 and has been performed at every outage where SG inspections were performed (with the exception of 2RF17, due to the original intention of that outages being a skipped inspection).

Attachment to TXX-23056 Page 10 of 11

13. THE RESULTS OF PRIMARY SIDE COMPONENT VISUAL INSPECTIONS PERFORMED IN EACH SG The channel heads in all four SGs were inspected per Westinghouse Nuclear Safety Advisory Letter NSAL-12-1, Revision 1. Two SG channel head cladding anomalies are being tracked at CPNPP Unit 2 and were visually observed during 2RF20. The anomalies did not appear to change from the prior inspection.

A corrosion rate evaluation has been performed for the larger of the two flaws. There is significant margin between the estimated flaw depth and the ASME Code allowable; therefore, no repairs are required.

A 100% visual inspection of tube plugs has been performed from the primary side during 2RF20. No anomalous conditions, such as a degraded tube plug or surrounding boron deposits, have been reported during performance of these visual inspections.

14. THE PRIMARY TO SECONDARY LEAKAGE RATE OBSERVED IN EACH SG DURING THE CYCLE PRECEDING THE INSPECTION WHICH IS THE INSPECTION WHICH IS THE SUBJECT OF THE REPORT No leakage rate was observed in any of the SGs.

15. THE CALCULATED ACCIDENT INDUCED LEAKAGE RATE FROM THE PORTION OF THE TUBES BELOW 14.01 INCHES FROM THE TOP OF THE TUBESHEET FOR THE MOST LIMITING ACCIDENT IN THE MOST LIMITING SG. IN ADDITION, IF THE CALCULATED ACCIDENT INDUCED LEAKAGE RATE FROM THE MOST LIMITING ACCIDENT IS LESS THAN 3.16 TIMES THE MAXIMUM OPERATIONAL PRIMARY TO SECONDARY LEAKAGE RATE, THE REPORT SHOULD DESCRIBE HOW IT WAS DETERMINED With predicted accident leakage, an assessment must be made to determine if an administrative operational leakage limit lower than 150 gpd must be applied to ensure the total accident leakage rate remains within the design basis. H* implementation requires that the predicted leak rate be subtracted from the accident induced leakage limit (0.3472 gpmRT) and the result is divided by the H* leak rate factor of 3.16 to determine the amount of leakage that is allowed below the H* region of the tubesheet during normal operation. Following this method, the amount of leakage below H* that is allowed is:

Allowable H* leak rate = (0.3472 gpmRT - 0.113 gpmRT)/3.16 = 0.074 gpmRT or 107 gpdRT The 107 gpdRT calculated leak rate is less than the 150 gpdRT Technical Specification operational leak rate limit. A new administrative limit of 107 gpdRT will not need to be established for allowable primary-to-secondary operational leakage for CPNPP Unit 2 during Cycle 21 and Cycle 22 due to the stations current administrative leakage rate being more conservative at 100 gpd.Currently, the station administrative limits are as follows:

Action Level 1: The plant condition entered when leakage has increased to a condition that requires frequent monitoring by the radiation monitoring system with periodic bench marking by laboratory analyses. Action Level 1 is entered when primary-to-secondary leakage is 30 gpd.

Action Level 2: Plant condition entered when primary-to-secondary leakage is 75 gpd in any steam generator AND is sustained for > 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Be in Mode 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of entering Action Level 2.

Attachment to TXX-23056 Page 11 of 11 Action Level 3: Plant condition entered when primary-to-secondary leakage in any steam generator is 100 gpd. Commence prompt and controlled plant shut down and be at less than or equal to 50% power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and be in Mode 3 within the next 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (total of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />).

16. THE RESULTS OF MONITORING FOR TUBE AXIAL DISPLACEMENT (SLIPPAGE). IF SLIPPAGE IS DISCOVERED, THE IMPLICATIONS OF THE DISCOVERY AND CORRECTIVE ACTION SHALL BE PROVIDED The tube slippage monitoring was conducted as part of the SG tube inspection program. Tube slippage is detected through bobbin coil examination. During 2RF20, as part of the dent/ding inspection program, a subset of the tubes was tested with the bobbin probe. No slippage was detected in any of the tubes inspected.