RC-10-0074, Special Report 2010-001, Steam Generator Tube Report for RF18
| ML101540064 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 06/01/2010 |
| From: | Gatlin T D SCANA Corp, South Carolina Electric & Gas Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| RC-10-0074, SPR 2010-001 | |
| Download: ML101540064 (20) | |
Text
Thomas D. Gatlin Vice President, Nuclear Operations 803.345.4342 A SCANA COMPANY June 1,2010 RC- 10-0074 Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555
Dear Sir / Madam:
Subject:
VIRGIL C. SUMMER NUCLEAR STATION (VCSNS) UNIT 1 DOCKET NO. 50/395 OPERATING LICENSE NO. NPF-12 SPECIAL REPORT (SPR) 2010-001, STEAM GENERATOR TUBE REPORT FOR RF18 South Carolina Electric & Gas Company (SCE&G) hereby submits the Steam Generator Tube Report pursuant to the requirements of Technical Specifications 6.9.1.12.
This report summarizes the examination conducted during the 2009 Fall Refueling (RF18) and the state of the three steam generators installed at V. C. Summer Nuclear Station (VCSNS), Unit 1.Adverse conditions have been entered into the VCSNS Corrective Action Program. Should you have any questions, please call Bruce Thompson at (803) 931-5042 at your convenience.
Thomas D. Gatlin JMG/TDG/jw Attachment 1, Steam Generator Inspection Report c: K. B. Marsh W. M. Cherry K. M. Sutton S. A. Byrne L. A. Reyes NSRC J. B. Archie R. E. Martin RTS N. S. Cams NRC Resident Inspector File (818.08)J. H. Hamilton INPO Records Center PRSF (RC-10-0074)
R. J. White A400i Virgil C. Summer Station
- Post Office Box 88. Jenkinsville, SC. 29065. T (803) 345-5209 A it Document Control Desk Attachment 1 RC-1 0-0074 Page 1 of 19 Steam Generator Tube Inspection Report VC Summer Nuclear Station Jenkinsville SC 29065 RF18 December 2009 1.0 Background Commissioned in January 1984, VCSNS originally had three Westinghouse Model D3 steam generators.
The original steam generators were replaced with Westinghouse Delta-75 steam generators in the fall of 1994.Each of the replacement steam generators (SG) contains 6,307 thermally treated INCONEL Alloy 690 tubes with an outside diameter of 0.6875 inches and a nominal wall thickness of 0.040 inches. Stress relief was performed during fabrication on the U-bends of the first 17 rows of tubing. The straight sections of the tubing are supported by nine tube support plates made of 1.125 inch thick, SA-240, Type 405 Stainless Steel.The tube support plates have trifoil shaped broached holes which reduce dryout and the collection of impurities at the tube-to-support plate intersections.
The U-bend sections of the tubing are supported by four sets of anti-vibration bars (AVB) made of SA-240, Type 405 stainless steel. Each AVB assembly consists of a "V" shaped bar with two end caps made of thermally treated INCONEL Alloy 690.A flow distribution baffle plate made of ASME-SA-240, Type 405 Stainless Steel is located between the tubesheet and the lowest support plate. The flow distribution baffle increases the secondary side flow velocity near the tubesheet, thus reducing the accumulation of sludge at the top of the tubesheet.
The D-75 steam generators contain a passive sludge collector above each primary separator which is designed to reduce the accumulation of sludge at the tubesheet.
The sludge collector is designed to collect suspended particles in the bulk water as it recirculates through the steam generator.
The tubes are welded to the tubesheet at the primary face and are hydraulically expanded into the tubesheet.
Document Control Desk Attachment 1 RC- 10-0074 Page 2 of 19 2.0 SG Examination and Repair History Table 1 provides the inspection history for the three VCSNS steam generators.
The three generators were replaced in the fall of 1994, during RF8 and is the official start of the Effective Full Power Years (EFPY) for the replacement SGs. The latest inspection was conducted during the 2009 Fall Refueling (RF1 8). The next scheduled inspection will be conducted during the 2013 Spring Refueling (RF21) in accordance with VCSNS TS and the SG Program.Table 1: VCSNS Steam Generator Inspection History Refuel Date EFPY Bobbin SGs # Title/Comments (approx) (%) inspected Pre- 1994 NA A, B, C NA Pre-service Inspection No service Report Submitted RF08 9/1 994 0 NA Steam Generator Replaced I _No Report Submitted RF09 4/1996 1.3 20 A, B RC-96-0132 Special Report (SPR 96-004), RC-96-0150 Special Report (SPR 96-004 R1)RF10 10/1997 2.6 30 C RC-97-0226 SPR 97-001 RFll 4/1999 4.0 40 A, B RC-99-0090 Special Report (SPR 1999-003)RF12 10/2000 5.4 100 A, B, C RC-00-0345 Special Report (SPR 2000-005)1_ [ML003769321 No Inservice Inspections RF13 4/2002 6.5 NAPefrd Performed No Inservice Inspections RF14 10/2003 7.9 NAPeord Performed RF1 5 4/2005 9.2 100 A, B, C RC-05-0076 Special Report (SPR 2005-001)No Inservice Inspections RF16 10/2006 10.5 NAPeord Performed No Inservice Inspections RF17 4/2008 12.0 NAPefrd Performed RF18 10/2009 13.3 100 A, B, C RC-10-0074 Special Report (SPR 2010-001)Three tubes were plugged with Westinghouse Alloy 690 welded plugs prior to the steam generators being placed in service (Fall 1994). Five tubes were preventatively plugged during RF12 with AREVA Alloy 690 mechanical plugs due to the lack of tube expansion (NTE) in the tubesheet region. Table 2 shows the tube plugging history when inspected for VCSNS SGs.Table 2: SG Tube Plugging History Outage SG A SG B SG C Pre-service 0 1 2 RF09 0 0 0 RF10 0 0 0 RF1 1 0 0 0 RF12 3 0 2 RF15 0 0 0 RF18 0 0 0 Total 3 1 4 Document Control Desk Attachment 1 RC-1 0-0074 Page 3 of 19 3.0 Scope of Inspections Performed on Each Steam Generator 100% of all operational tubes within the three steam generators were inspected with a bobbin coil probe. A total of 18,913 of 18,921 tubes are operational at VCSNS.A 100% examination was performed of the Hot Leg (HL) and Cold Leg (CL% periphery Top of Tubesheet (TTS) (2 tubes into the bundle) with the rotating +PointT coil. The testing methodology aids in providing enhanced detection of any foreign objects or foreign object wear within this region. The eddy current examination was supplemented by a visual Secondary Side Inspection (SSI) of the top of the tubesheet and the outer periphery of the tube bundle in each SG. Rotating coil examinations were performed in locations where the bobbin probe response was ambiguous, or where bounding examinations for Possible Loose Part (PLP) indications were required.
Table 3 shows a summary of the examination scope performed during RF1 8.Stress Corrosion Cracking (SCC) has not been observed in INCONEL Alloy 690 tubing to date and thus SCC is not a potential damage mechanism in the VCSNS steam generators.
As-a proactive measure and since the VCSNS steam generators are among the earliest using the INCONEL Alloy 690 tubing, sampling was performed in certain areas that have exhibited early detection of SCC in alloy 600 plants. These regions include HL TTS expansion transitions, U-bends, denting (DNT), bulges (BLG) or manufacturing burnish marks (MBMs). In addition to the peripheral examination of the U-S, supplemental tubes were examined to result in a 20% examination in the HL TTS region. No indications of SCC were detected.Table 3: ECT Examination Scope SG A SG B SG C Total Number of Tubes Inservice 6304 6306 6303 18913 Number of Tubes Inspected F/L w/ Bobbin Probe 5569 5639 6092 17300 Number of Tubes Inspected w/ Bobbin Probe Hot Leg 735 667 211 1613 Straights and Cold Leg Candy Canes Number of Examinations w/ Motorized Rotating Pancake Coil 2068 2082 2090 6240 (MRPC) Total* Hot Leg Transitions
(+3 / -3) -Periphery 678 677 676 2031* Hot Leg Transitions
(+3 / -3) -Interior Bundle 584 585 586 1755* Cold Leg Transitions
(+3 /-3) -Periphery 678 677 676 2031" Row 1 and 2 U-Bends 0 30 0 30" Hot Leg Misc. Special Interest -Diagnostic Exams 63 64 106 233 and from Previous History* Cold Leg Misc. Special Interest -Diagnostic Exams 11 28 18 57 and from Previous History* U-bend Special Interest -Diagnostic Exams and from 0 1 4 Previous History I* PLP Bounding Special Interest 51 21 27 99 Document Control Desk Attachment 1 RC-10-0074 Page 4 of 19 4.0 Active Degradation Mechanisms Found 4.1 Anti-Vibration Bar (AVB) Wear There were three AVB wear indications reported in SG A and one reported in SG C.None of which were new AVB indications.
The maximum depth of AVB wear reported during RF1 8 was 9% through wall (TW). The results of the inspection are provided in Table 7 of this report. A growth rate was estimated to be 3% TW or 0.75 TW per Effective Full Power Years (EFPY) when compared to previous inspection conducted in RF1 5. Projection analysis for AVB Wear concludes this degradation mechanism will not exceed the Performance Criteria for SG Tube Integrity or Repair Criteria limit of 40% TW as defined with VCSNS TS 6.8.4.K.2 and 6.8.4.K.3, for operation up to RF21.4.2 Tube Support Plate (TSP) Wear There were 20 TSP wear indications reported in SG A, 41 TSP wear indications reported in B, and 16 reported in SG C. The results of the inspection are provided in Tables 8, 9, and 10. The maximum depth of TSP wear reported during RF18 was in SG A with 28% TW reported at an indication that was historically 21% TW during RF1 5.A growth rate of 2.75% TW per EFPY was bounding and applied to the projection analysis.
Projection analysis for TSP Wear concludes this degradation mechanism will not exceed the Performance Criteria for SG Tube Integrity or Repair Criteria limit of 40%TW as defined with VCSNS TS 6.8.4.K.2 and 6.8.4.K.3, for operation up to RF21.4.3 Baffle Plate Wear One indication of baffle plate wear was detected in SG C. This indication in tube SG C row 34, column 91 on the hot leg side of the baffle plate (BPH) +0.47 was sized at 5% TW using Examination Technique Specification Sheets (ETTS) 96910.1. Due to the baffle plate hole design, the circumferential extent was limited to one land of the baffle plate tube hole. It was concluded baffle plate wear will not threaten the Performance Criteria for SG Tube Integrity or Repair Criteria limit of 40% TW, as defined in VCSNS TS 6.8.4.K.2 and 6.8.4.K.3, for operation up to RF21.4.4 Manufacturing Burnish Marks (MBMs)There was one MBM indication reported during RF18 in SG B. This indication was examined with the +PointTM coil to verify that no service degradation is present. MBM is a tubing condition where localized tubing imperfections were removed by buffing and are detectable due to the effects of cold working and localized wall thinning.
No service degradation was detected.
Document Control Desk Attachment 1 RC-1 0-0074 Page 5 of 19 4.5 Bulge Signals (BLGs)There were two BLG signals reported in SG A, three reported in SG B and one reported in SG C. BLG is a tube condition where localized stress indications are generated from the manufacturing process. The concern with a Bulge signal is that it can mask a flaw like signal. Industry operating experience shows SCC has been a challenge to detect within a bulge, specifically with Alloy 600. There have been no known issues with INCONEL Alloy 690 tubin. 1as installed at VCSNS. All indicated bulge signals were examined with the +Point coil to verify that no service degradation is present. No degradation was detected.4.6 Permeability (PRMs)Two tubes in SG C and one tube in SG B showed indication of tube material permeability variation.
All of the permeability locations were re-examined with a magnetic bias probe which provided the necessary saturation for a good examination of the affected tube locations.
No service induced indications were reported.4.7 Dents All hot leg dents with a voltage of 2 Volts or higher were examined with the +PointTM probe. This sample included 55 dents in SG A, 53 dents in SG B and 110 dents in SG C. There was no indication of any degradation within the dent population examined.There were no service induced dents reported during RF18.4.8 Eddy Current Possible Loose Part (PLP) Examinations Previously reported PLP locations in SG A, SG B and SG C were preplanned for+PointTM examination during RF1 8. Some of the previous PLP indications were located within the bundle periphery and were inspected.
SG A had 11 previous PLP indications in 6 groupings.
Therefore, 50 additional tube examinations were required.
SG B had two previous PLP indications that were included within the periphery examination.
SG C had 8 previous PLP indications in 5 groupings.
Therefore, 20 additional tube examinations were required.
Any newly detected PLP locations or Secondary Side Inspection (SSI)reported foreign objects were bound by +PointTM examination.
No foreign object wear was detected in any of these examinations.
SSI and Foreign Object Search and Retrieval (FOSAR) were performed at the secondary face of each SG tubesheet.
The previous PLP indications found in RF1 5 that were repeated in RF1 8 or any new PLP indications were visually inspected to determine the cause. Tables 4, 5 and 6 provide information on the RF15 PLPs, the RF18 PLPs and any FOSAR results. There were two locations where foreign material was confirmed but could not be removed from SG A and SG B.The first was a foreign object fixed in place in SG A between tubes row 69, column 62 and row 70, column 61 which has been present since RF1 5 with no wear. The object was dispositioned in VCSNS Corrective Action Program and evaluated by AREVA Engineering as being firmly in place and presents no threat to tube integrity (Ref. 11.3 and 11.4).
Document Control Desk Attachment 1 RC-1 0-0074 Page 6 of 19 The second was a foreign object located in SG B, resting on the secondary side of the tubesheet.
Attempts to remove the object were not successful.
The object, which appeared to be 1.59 inches long, 0.06 inches wide, and 0.01 inches thick, moved during retrieval attempts, and a small portion of it broke off (see Table 5 for locations).
Both ECT and SSI did not identify any tube with wear in these areas. The objects were dispositioned by VCSNS Corrective Action Program and evaluated by AREVA Engineering (Ref. 11.5 and 11.6). It was concluded that no tube wear damage is expected from the loose parts during the remaining life of the steam generator.
Table 4: SG A PLP and Foreign Object Resolution Row Column Leg RF15 RF18 Comments 8 1 HL PLP No RF18 PLP 9 2 HL PLP No RF18 PLP 12 11 HL PLP No RF18 PLP 16 11 HL PLP No RF18 PLP 37 72 HL PLP LPS Sludge- no part found 38 71 HL PLP LPS Sludge- no part found 40 135 HL LPS Sludge- no part found 41 136 H L LPS Sludge- no part found 42 11 HL PLP NO RF18 PLP 58 11 CL LPR Small finishing nail removed 69 62 HL PLP PLP Part not removed -See Ref. 11.3 and 11.4 70 61 HL PLP PLP Part not removed -See Ref. 11.3 and 11.4 75 52 HL PLP LPS Sludge rock 77 52 HL PLP LPS Sludge rock 107 44 HL LPS No part found by FOSAR 108 45 HL LPS No part found by FOSAR 115 62 HL LPS No part found by FOSAR 115 66 HL LPR Small metallic part removed 115 78 HL _ LPS No part found by FOSAR Table 4 shows 10 Loose Part Signals (LPS) and two possible loose part signals. Six of these signals correlated with RR 5. Six indications were attributed to sludge. Two indications between tubes row 69, column 62 and row 70, column 61 were confirmed PLPs though visual inspection and with RR15 PLPs but could not removed. There were two foreign objects that were removed. The final four LPS indications did not result in any part found by FOSAR.
Document Control Desk Attachment 1 RC-1 0-0074 Page 7 of 19 Table 5: SG B PLP and Foreign Object Resolution Row Column Leg RF15 RF18 Comments 9 2 HL LPS FOSAR found tube scale 35 6 HL LPS FOSAR found tube scale 36 5 HL LPS FOSAR found tube scale 51 10 HL LPS FOSAR found tube scale 52 9 HL LPS FOSAR found tube scale 66 127 HL PLP No RF18 PLP 66 128 HL PLP No RF18 PLP 88 91 HL LPR Part moved to R92 C87 and R93 C88 90 90 HL LPR Part moved to R92 C87 and R93 C88 92 87 HL PLP Part not removed -See Ref. 11.5 and 11.6 93 88 HL PLP Part not removed -See Ref. 11.5 and 11.6 111 86 HL LPS No part found by FOSAR Table 5 shows six Loose Part Signals (LPS) that were identified where none of the signals correlated with RF15. The RF15 report reflected the indications had been visually inspected but did not locate any parts found. There were two instances where foreign objects were removed, One LPS did not result with a part found by FOSAR and two indications between tubes row 88, column 91 and row 90, column 90 were confirmed PLPs but could not be removed. Five indications were found to be tube scale.Table 6: SG C PLP and Foreign Object Resolution Row Column Leg RF15 RF18 Comments 1 18 HL PLP No RF18 PLP 10 49 HL PLP No RF18 PLP 10 139 HL PLP No RF18 PLP 12 49 HL PLP No RF18 PLP 18 139 HL PLP No RF18 PLP 20 139 HL PLP No RF18 PLP 54 11 CL LPS Sludge -no part found 62 13 CL LPS Sludge -no part found 63 14 CL LPS Sludge -no part found 59 58 HL PLP No RF18 PLP 60 59 HL PLP No RF18 PLP 99 38 HL LPS FOSAR found tube scale 114 73 HL LPS No part found by FOSAR 115 82 HL LPS No part found by FOSAR Table 6 shows six Loose Part Signals (LPS) that were identified where none of the signals correlated with RF15. The RF15 report reflected the indications had been visually inspected but did not locate any parts found. One indication resulted from tube scale and two locations did not result with a part found by FOSAR. The remaining three were attributed to sludge.
Document Control Desk Attachment 1 RC- 10-0074 Page 8 of 19 5.0 Nondestructive Examination Techniques 5.1 Wear Indications at Support Structures Indications were first detected with the bobbin coil probe. Then all bobbin indications at broached tube support plates (TSPs) and anti-vibration bars (AVBs) were reexamined with a +PointTM coil. The indications were reported as No Degradation Found (NDF) or as wear (WAR). All reported WAR indications were sized from a 300/100 kHz +PointTM process mix channel. A standard amplitude calibration curve on the 300/100 kHz+PointTM process mix channel was used to provide depth estimates on wear at TSPs and AVBs. The amplitude curve was constructed from simulated support wear in the VCSNS wear standard.Indications at TSPs and AVBs that were indicative of wear were assigned %TW depth estimates with the bobbin coil. A standard amplitude calibration curve constructed from the simulated support wear in the VCSNS wear standard was used to report %TW estimates.
The calibration curves were established on a process channel mix that utilized the 630 kHz and 150 kHz differential channels to perform the support suppression mix.5.2 Loose Part Indications Suspected PLP indications were reported with the bobbin probe then examined with the+PointTM coil technique for confirmation.
Additional PLP indications were reported with the +PointTM coil during the planned top-of-tubesheet and supplemental diagnostic examinations.
In general, the +PointTM technique is more sensitive to PLP indications near the top-of-tubesheet expansion and other structures due to the surface riding nature of the rotating probe as well as the coil's inherent electromagnetic properties.
For each PLP that was confirmed with the +PointTM coil, the adjacent tubes were examined to determine if additional PLPs were present therefore bounding the initial indication.
The PLP location was also screened for any evidence of degradation associated with the PLP. Foreign Object Search and Retrieval (FOSAR) was performed in all three generators during RF1 8 to identify and remove any possible loose parts.The results of PLP examinations and FOSAR are detailed with section 4.8 with comparisons to the previous inspection conducted in RF1 5.5.3 Foreign Obiect Wear The examination techniques applied for detection of foreign object wear included the bobbin coil, the top of tubesheet peripheral examination with +Pointm, the top of tubesheet interior bundle sample, and the SSI examinations of the annulus, bundle periphery and the inner bundle passes. There was no foreign object wear reported during RF1 8. The results of PLP examinations and FOSAR are detailed with section 4.8 with comparisons to the previous inspection conducted in RF15.5.4 Freespan Indications All freespan indications were initially reported with the bobbin technique by production analysts.
Indications could be reported as a Differential Freespan Indication (DFI), Non-Document Control Desk Attachment 1'RC-1 0-0074 Page 9 of 19 Quantifiable Indication (NQI), Absolute Drift Indication (ADI), or Distorted Dent Indication (DDI if associated with a ding). The final disposition was made by the resolution analysts according to the methodology established in the "Free Span Flow Chart" or "Dent Flow Chart." Indications indicative of MBMs were reported using historical tracking codes such as MBM, Differential Freespan History (DFH), or Absolute Drift History (ADH). The MBM, DFH, and ADH "tracking" codes do not require tube repair or removal from service.Indications that were new or that showed a change from baseline data (pre-service examination in 1994) were examined with the +PointTM coil technique for characterization.
5.5 Dent/Ding Indications All dent/ding indications are initially reported with the bobbin technique by production analysts as DNT or DDI (DDI if associated with a ding). The final disposition being made by the resolution analysts according to the methodology established in the "Dent Flow Chart." Dents traceable to the baseline (pre-service examination in 1994) were dispositioned as dings (DNG) by the resolution analyst. All new dents (not traceable to baseline) and dings in the hot leg were examined with the +PointTM coil technique for any degradation.
No service degradation was reported.6.0 Location, and Measured Sizes of Service Induced Indications
/The only service induced indications at VCSNS are AVB wear, TSP wear, and Baffle Plate wear. No new degradation mechanisms or a flow that was more severe than expected was observed in the VCSNS steam generators.
The following sections provide the details for indications identified from RF18.6.1 AVB Wear Table 7: AVB Wear Sizing by ETTS 96004.1 SG Row Column Indication Location Distance Depth From (in.) (%TW)A 19 140 TWD AV7 0.43 9 A 26 139 TWD AV2 -0.81 5 A 26 139 TWD AV7 0.85 7 C 26 3 TWD AV2 -0.75 7 As discussed in section 4.1 there were four indications of AVB wear identified.
The largest indication of through wall depth (TWD) was 9% TW located in SG A row 19 column 140 and 0.43 from the center of location AV7.
Document Control Desk Attachment 1 RC-1 0-0074 Page 10 of 19 6.2 TSP Wear There were 20 TSP wear indications reported in SG A, 41 TSP wear indications reported in B and 16 reported in SG C. The maximum depth of TSP wear reported during RF1 8 was 28% TW reported at an indication that was 21% TW during RF1 5.During RF1 5, four indications were reported in SG A and three were reported in SG C.The maximum growth estimated for the effective full power years between RF15 and RF1 8 was 7% TW per 4 EFPY or 1.75% TW per EFPY. The average growth rate for the seven previously reported indications was established as 1.07% TW per EFPY.All of the new indications were reviewed in the RF1 5 bobbin coil history and all showed indication of wear in the RF1 5 data. Since the wear standard was not available for exact sizing of all previous (RF15) wear signals, a best effort sizing was applied to the previous bobbin coil data to establish a reasonable estimate of the RF1 5 wear depth using ETSS 96004.1. To evaluate the growth of the newly detected indications, the new bobbin coil depth estimate was compared to the look back bobbin coil best estimate wear depth. The average growth (NDE growth rate) of these newly reported indications was 0.15% TW per EFPY and the maximum growth rate for the greatest historical change was 1.75% TW per EFPY reported for RF1 8. Therefore, the growth rate data shows that the evaluated rate reported during RF1 5 and RF1 8 is bounding for the newly reported TSP wear indications.
It is likely that slight growth and improved eddy current signal quality were responsible for the detection of the newly reported wear indications.
None of the indications of TSP wear degradation detected during RF1 8 exceeded the Performance Criteria for SG Tube Integrity or Repair Criteria limit of 40% TW as defined with VCSNS TS 6.8.4.K.2 and 6.8.4.K.3, for operation up to RF21.
Document Control Desk Attachment 1 RC-10-0074 Page 11 of 19 Table 8: SG A TSP Wear Sizing by ETTS 96910.1 Row Col Location Inch Indication Depth (%TW)1 10 04C -0.51 WAR 12 1 10 04C 0.47 WAR 13 1 10 05C -0.5 WAR 9 1 10 05C 0.27 WAR 11 1 10 05C 0.47 WAR 18 1 10 06C -0.54 WAR 18 1 10 06C 0.44 WAR 7 1 60 03C -0.53 WAR 6 1 60 03C 0.53 WAR 12 1 60 03C 0.56 WAR 4 2 77 07C -0.52 WAR 22 2 77 07C 0.38 WAR 9 2 77 07C 0.44 WAR 16 2 77 08H -0.46 WAR 28 2 77 08H 0.52 WAR 12 4 103 05C -0.52 WAR 10 4 103 05C 0.49 WAR 11 17 2 05C 0.42 WAR 16 67 24 07C 0.42 WAR 9 115 62 09H 0.39 WAR 12 RF18 inspections identified 20 TSP indications as reflected in Table 8 and Section 4.2.The maximum through wall depth identified and greatest historical change was at row 2, column 77, and location 08H with 28% TW. The historical change between RF18 and RF1 5 resulted in an estimated growth rate of 1.75% TW per EFPY that is bounding for all three SGs. Projection analysis for TSP Wear concludes this degradation mechanism will not exceed the Performance Criteria for SG Tube Integrity or Repair Criteria limit of 40% TW as defined with VCSNS TS 6.8.4.K.2 and 6.8.4.K.3, for operation up to RF21.
Document Control Desk Attachment 1 RC-10-0074 Page 12 of 19 Table 9: SG B TSP Wear Sizing by ETTS 96910.1 Row Col Location Inch Indication Depth (%TW)1 2 05C -0.51 WAR 4 1 2 05C 0.41 WAR 16 1 2 06C -0.56 WAR 11 1 2 06C 0.43 WAR 12 1 28 07H -0.55 WAR 8 1 28 07H 0.48 WAR 9 1 140 06C -0.6 WAR 6 1 .140 06C 0.43 WAR 5 1 140 06C 0.44 WAR 6 2 17 07H 0.44 WAR 9 2 31 05C -0.42 WAR 9 2 31 05C 0.44 WAR 19 2 61 04C -0.57 WAR 5 2 61 04C -0.55 WAR 8 3 46 07C -0.48 WAR 20 3 46 07C -0.45 WAR 10 3 46 08C -0.53 WAR 6 3 46 08C -0.52 WAR 13 3 54 06C 0.55 WAR 8 3 54 06C 0.57 WAR 6 5 84 07C 0.48 WAR 12 5 84 07C 0.54 WAR 8 5 88 07C -0.47 WAR 18 5 88 07C 0.51 WAR 12 5 90 07C -0.47 WAR 9 5 90 07C 0.57 WAR 15 5 90 08C -0.46 WAR 10 5 90 08C 0.5 WAR 11 5 90 08C 0.54 WAR 2 9 6 75 07C -0.51 WAR 12 10 121 08C -0.44 WAR 7 10 121 08C 0.6 WAR 5 20 139 03H -0.56 WAR 9 39 120 08C 0.51 WAR 5 39 120 08C 0.52 WAR 5 94 45 09C 0.44 WAR 7 99 44 090 0.39 WAR 8 108 47 07H -0.49 WAR 5 108 47 07H 0.46 WAR 8 114 75 04H 0.5 WAR 6 115 74 06H 0.42 WAR 9 Table 9 reflects that SG B had 41 indications of TSP wear with a maximum 20% TW at row 3, column 46 and location 07C. Degradation found in SG B remains bounded by SG A TSP analysis and projections.
Document Control Desk Attachment 1 RC-1 0-0074 Page 13 of 19 Table 10: SG C TSP Wear Sizing by ETTS 96910.1 Row Col Location Inch Indication Depth (%TW)1 4 06C 0.53 WAR 6 1 8 07C 0.42 WAR 13 1 82 08H 0.48 WAR 9 1 94 06H 0.5 WAR 16 1 94 06H 0.55 WAR 4 1 112 06C -0.45 WAR 16 1 112 06C 0.5 WAR 6 1 112 06C 0.53 WAR 8 5 52 06C -0.51 WAR 8 5 52 06C -0.49 WAR 14 7 54 06C -0.48 WAR 11 7 54 06C -0.47 WAR 4 7 54 06C 0.54 WAR 7 83 116 07C -0.57 WAR 13 104 55 08C -0.58 WAR 4 104 55 08C 0.37 WAR 17 Table 10 reflects that SG C identified 16 TSP wear indications with the greatest through wall indication was 17% at row 104, column 55, and location 08C. Degradation found in SG C remains bounded by SG A TSP analysis and projections.
6.3 Baffle
Plate Wear One indication of baffle plate wear was detected in SG C. This indication in tube SG C row 34, column 91 on the hot leg side of the baffle plate (BPH) +0.47 was sized at 5%TW using ETSS 96910.1.7.0 Number of Tubes Plugged No tube plugging was required during RF18.8.0 Total Number and Percentage of Tubes Plugged to Date A total of eight tubes have been removed from service by plugging in the three VCSNS SGs as shown in Table 2. The percentage of tubes plugged to date is less than 0.05%for each SG. During RF 8, all plugs were remotely visually examined.
The proper tube number, plug type, and plug position were verified with no signs of degradation.
Document Control Desk Attachment 1 RC-1 0-0074 Page 14 of 19 9.0 Condition Monitoring (CM), Tube Pulls and In-Situ Testing Results 9.1 Anti-Vibration Bar Wear AVB Wear Acceptance Limits for OD Axial Thinning w/Limited Circumferential Extent 100 90 80--4 -- ---- -. ................
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-- ------ ----i ; 1 i ....i .....j i I I 0.0 0.5 1.0 1.5 Degradation Length (in.)2.0 2.5 3.0 Figure 1 : AV13 Wear CM Limit Curves Figure 1 provides the 95/50 CM Limit Curve, which is applicable to the AVB wear indications reported at VCSNS during RF1 8 and reflected in Table 7 of section 6. 1. The CM curve accounts for material property uncertainties, model uncertainties, and NDE depth sizing uncertainties.
The curves shown on the plot are the best estimate of the burst pressure (BE), the structural limit (SL) and the condition monitoring limit (CM)..The maximum depth of AVB wear observed during RF1 8 was 9% TW. On Figure 1, the depth of the measured AVB wear was plotted with the conservative assumption that the axial extent of the wear was 1.0 inch. Since the AVB wear depths are below the CM Limit Curve for AVB Wear, the Condition Monitoring limits were not exceeded.
Document Control Desk Attachment 1 RC-1 0-0074 Page 15 of 19 9.2 TSP Wear Acceptance Limits for OD Axial Thinning w/Limited Circumferential Extent 100 90 80---- 2 ... .------ ----- ---.. ....... ...- ........... .7 ... .... .... ..... .... .I -....T ... .............
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Tube 00: 0.687 inch ....:Tube Wal: 0,040 inch Sy+Su: 135.80 ksl Std Dev: 3.530Oksi Probability:
95.09/6 Confidence:
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- ::: : :: :: ::: :::: :: : : ::: ::: : ::: : 0 0.0 0.5 1.0 1.5 Degradation Length (In.)2.0 2.5 3.0 Figure 2- TSP Wear Limit Curve Figure 2 provides the 95/50 CM Limit Curve, which is applicable to the Tube Sheet Plate (TSP) wear indications reported at VCSNS during RR 8 and reflected in Table 8, 9 and 10 of section 6.2. The CM curve accounts for material property uncertainties, model uncertainties, and NDE depth sizing uncertainties.
The CM Limit Curves are shown below with the RR 8 TSP wear depth data plotted at a 1.2 inch extent.The maximum depth of TSP wear observed during RR 8 was 28% TW. On Figure 2, the depth of all TSP wear was plotted with the assumption that the axial extent of the wear was 1.2 inch. This is a conservative assumption for the physical wear caused by contact between the tubes and the support plate land regions. Since this depth is below the CM Limit Curve for AVB Wear, the Condition Monitoring limits were not exceeded.
Document Control Desk Attachment 1 RC-1 0-0074 Page 16 of 19 9.3 Baffle Plate Wear A single indication of baffle plate wear was detected during RF1 8. Tube row 34 column 91 in SG C had a reported depth of 5% TW sized with ETSS 96910.1. Terrain plot data for this indication shows that the wear is associated with one land of the baffle plate hole and thus has limited circumferential extent. The baffle plate wear indication was evaluated for CM using the same curve as for TSP wear (Figure 2). The baffle plate wear did not exceed the Condition Monitoring limit.9.4 Leakage Performance Criteria Primary to secondary SG leakage was not detected during operation prior to RF1 8.Therefore, the operational leakage performance criteria established in NEI 97-06, VCSNS Station Administrative Procedure SAP-1 58, "Steam Generator Management Program," and VCSNS Technical Specifications were not exceeded during this operating period.Accident induced leakage could result from plant conditions that exacerbate existing degradation or that enhance potential leakage flow paths. The first would apply to tubing with degradation located outside the tubesheet such that an increased primary-to-secondary differential pressure could cause a tube failure or pop through during an accident.
A uniform depth axial wear with an initial depth of approximately 68% TW and a length of 1.00 inch could pop through and leak under a steam line break pressure differential of 1.4 x 2870 psi. No degradation detected during RF1 8 had depths larger than 28% TW and thus there was no degradation close to a pop through condition.
Additionally, because none of the identified degradation presents a threat of rupture at 4800 psi (3 times Normal Operating Pressure Differential (NDP)), pop-through at the lower Main Steam Line Break (MSLB) pressure 2870 psi would be unlikely to occur.None of the degradation detected during RF1 8 exceeded the screening criteria for non-pressure accident loads.9.5 Condition Monitoring Conclusions The structural integrity, accident induced leakage, and operational leakage performance criteria were not exceeded during the operating interval preceding RF1 8. Additionally, there is reasonable assurance that structural integrity, accident induced leakage, and operational leakage performance criteria will not be exceeded prior to the next planned inspection in any of the VCSNS SGs. With respect to AVB wear, TSP wear and baffle plate wear, an inspection interval of three fuel cycles is justified.
Regions susceptible to these degradation mechanisms will be examined during RF21 in accordance with VCSNS TS and the SG Program.
Document Control Desk Attachment 1 RC-10-0074 Page 17 of 19 10.0 Secondary Side Inspections During RF1 8, the VCSNS secondary side inspection included:* Primary and secondary moisture separators
- Steam Drum* Feed rings" Feed ring nozzles" Auxiliary feed pipe and nozzle* Sludge collector* Upper tube bundle region and top of 9th support plate* Support plate trifoil broached openings" Lower tube bundle region" Tube sheet and baffle plate Secondary side visual examinations were performed in the steam drum upper internals area of each SG with concentration on the feed ring, sludge collector, moisture separators and general structural condition.
There were some foreign objects removed from the feed ring and feed ring spray nozzles. The sludge collectors were cleaned on allthree SGs with pre and post lance inspections to evaluate the effectiveness of the lancing process. The sludge removed was quantified as 146 pounds from SG A, 121 pounds from SG B, and 61 pounds from SG C.There were no deficiencies noted in the condition of the upper internal components that could be visualized.
The inlet side of the secondary moisture separator bank perforated holes and chevrons all looked to be in good condition.
The primary moisture separator swirl vanes all appeared to be in good condition.
The vanes had a slight deposit on them but the edges were still sharp showing no indication of erosion. All ladders, drains, supports and associated welds throughout the unit at the steam drum elevation appear to be satisfactory.
The steam drum examination plan initially included inspection of the upper steam drum region above the secondary moisture separators.
However, the access hatches from the steam drum to the region above the secondary separators could not be removed in any of the three steam generators.
The bolts presented some difficulty but even with the bolts removed, the hatches could not be removed due to a -seal weld. VCSNS CR-09-04275 (Ref. 11.8) was created for evaluation.
A video camera probe was inserted through one of the open bolt holes in the SG A hatch cover and was used to provide a remote visual examination of the region above the secondary chevron separators in that SG. No further inspections above the hatch level were attempted for SG B and SG C.Secondary side visual examinations were performed around the tubesheet secondary face annulus and tube bundle periphery to identify and remove any foreign objects.Visualization included looking into the tube bundle several tubes deep. This helped in the detection of foreign objects within this region. Some small objects were detected and removed from each SG annulus.
Document Control Desk Attachment 1 RC- 10-0074 Page 18 of 19 The 9th TSP showed a very slight ridge of sludge at the bottom of the tube support plate. No broaches were found to be blocked.34 Feedwater Spray Nozzles located on the main feed water pipe were internally and externally inspected and found to be in good condition.
Debris was found protruding from the holes of some of the feedwater spray nozzles on each SG. All of the foreign objects were retrieved from the nozzles and captured in VCSNS Corrective Action Program (Reference 11.9, 11.10, and 11.11 for SG A, SG B, and SG C, respectively).
All components, primary separator riser barrels, drains, drain cups, pipe supports, Feedwater
'T's, Aux Feedwater Nozzle, ladders, and deck welds on the lower deck were viewed to be satisfactory.
The Auxiliary Feedwater nozzles were viewed to be in good condition on all three SGs.The visual examination of upper internal components in all three SGs during RF18 revealed no degradation that could threaten the SG. There is no expected degradation mechanism of these components that could threaten tube integrity prior to the next inspection.
Document Control Desk Attachment 1 RC-10-0074 Page 19 of 19 11.0 References 11.1 AREVA Document 51 -9126059 -000, VC Summer Steam Generator Condition Monitoring and Operational Assessment for Refueling Outage 18, November, 2009.11.2 AREVA Document 51 -.9127095 -000, Technical Summary of Steam Generator Eddy Current Examinations at VC Summer Nuclear Power Station, 1 R18, November 2009.11.3 AREVA CR, CR 2009-7552, "Loose Part Discovered in A SG at Location 69-62 and 70-61", November 2009.11.4 SCE&G CR, CR-09-04707, "FM in SG A", October, 2009.11.5 AREVA CR, CR 2009-7543, "VC Summer -Two Irretrievable Metallic Foreign Objects in B SG Secondary Side", November 2009.11.6 SCE&G CR, CR-09-04680, "SG B Foreign Material", October, 2009.11.7 AREVA Document 51-5007713-005, V C Summer EOC18 Steam Generator Degradation Assessment, October, 2009.11.8 SCE&G CR, CR-09-04275, 'While attempting to open the upper hatch for steam drum inspection, one of the nuts sheared off", October, 2009.11.9 SCE&G CR, CR-09-04288, "Alpha SG foreign material in the feedring spray nozzle" 11.10 SCE&G CR, CR-09-04364, "B SG foreign material in the feedring spray nozzle" 11.11 SCE&G CR, CR-09-04436, "Charlie SG foreign material in the feedring spray nozzle"