LR-N10-0365, Salem Nuclear Generating Station Unit 1, Steam Generator Tube Inspection Report- Twentieth Refueling Outage (1 R20)
| ML102980089 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 10/21/2010 |
| From: | Fricker C J Public Service Enterprise Group |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| LR-N10-0365 | |
| Download: ML102980089 (62) | |
Text
PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236 0 PSEG Nuclear LLC OCT 2 12010 Technical Specification 6.9.1.10 LR-N10-0365 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington DC 20555-001 Salem Nuclear Generating Station Unit 1 Facility Operating License Number. DPR-70 NRC Docket Number. 50-272
SUBJECT:
Steam Generator Tube Inspection Report- Twentieth Refueling Outage (1 R20)PSEG Nuclear, LLC (PSEG) hereby submits the Steam Generator Tube Inspection Report consistent with the requirements of Technical Specification (TS) 6.9.1.10.
The report is being submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of the inspection performed in accordance with Technical Specification 6.8.4.i, "Steam Generator (SG) Program." Salem Unit 1 entered HOT SHUTDOWN (Mode 4) on April 24, 2010, following the completion of its twentieth refueling outage.The following attachments are included in this letter: Attachment 1 Attachment 2 Attachment 3 Attachment 4 Attachment 5 Attachment 6 Attachment 7 Attachment 8 Attachment 9 Steam Generator Tube Inspection Report TS 6.9.1.10 Salem Unit 1 Model F SG Tube Support Arrangement and Terminology Summary of Salem 1 R20 Wear Indications (Tubes / Indications)
Repairable Tube Status Report Total Number and Percentage of Tubes Plugged to Date 1 R20 Nondestructive Examination Techniques 1 R20 Service Induced Indications (AVB Wear)1 R20 Service Induced Indications (TSP Wear)1 R20 Service Induced Indications (Foreign Object (FO) Wear)95-2168 REV. 7/99 Document Control Desk Page 2 OCT 2 1 2010 LR-N 10-0365 There are no regulatory commitments contained in this letter. Should you have any questions regarding this submittal, please contact Mr. E. Villar at (856) 339-5456.Sincerel arl F /cker Site Vice President
-Salem Attachments (9)cc Mr. W. Dean, Administrator
-Region I Mr. R. Ennis, Licensing Project Manager -Salem USNRC Senior Resident Inspector
-Salem (X24)Mr. P. Mulligan, Manager IV Mr. H. Berrick, Salem Commitment Tracking Coordinator Mr. L. Marabella, Corporate Commitment Tracking Coordinator Attachment 1 LR-N10-0365 Steam Generator Tube Inspection Report TS 6.9.1.10 Attachment 1 Document Control Desk LR-N 10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 1.0 PURPOSE The purpose of this document is to provide information to support the Salem Unit 1 180 Day Steam Generator (SG) Report. This document provides a summary of the inspection results and findings from the Salem 1R20 SG Inspection.
2.0 INTRODUCTION
In 1998 Salem Unit 1 commenced operating cycle 13 with the newly replaced SG from the canceled Seabrook-2 plant. Salem Unit 1 is a four (4) loop Westinghouse Pressurized Water Reactor (PWR) with Model F SGs that incorporate thermally treated Inconel 600 U-tubes. The tube bundle consists of 5,626 tubes with an outside diameter (OD) of 0.688 inches and a nominal tube wall thickness of 0.040 inches. During SG fabrication, the tubes were hydraulically expanded over the full tubesheet depth and the first ten tube rows were thermally stress relieved after U-bend formation.
The seven (7) tube support plates (TSP) are fabricated from 405 stainless steel (SS) and have broached "quatrefoil" tube holes. A flow distribution baffle (FDB) plate, also 405SS, between the secondary face of the tubesheet and the first tube support plate, provides top-of-tubesheet (TTS) sludge pile control. Tube support within the U-bend region is provided by three V-shaped chrome-plated Inconel 600 antivibration bars (AVB's). Attachment 2 provides a general summary of the Salem Unit 1 Model F SG Tube Support Arrangement and Terminology.
Consistent with Technical Specification (TS) 6.9.1.10, this report is being submitted within 180 days after the initial entry into HOT SHUTDOWN following completion of inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator Program".This report includes: a. The scope of inspections performed on each SG, b. Active degradation mechanisms found, c. Nondestructive examination techniques (NDE) utilized for each degradation mechanism, d. Location, orientation (if linear), and measured sizes (if available) of service induced indications, e. Number of tubes plugged during the inspection outage for each active degradation mechanism, f. Total number and percentage of tubes plugged to date, and g. The results of condition monitoring, including the results of tube pulls and in-situ testing.Reporting requirements h, i and j are applicable for Refueling Outage 1 R20 through the subsequent operating cycles until the next scheduled SG tube inspection.
- h. The primary to secondary leakage rate observed in each SG (if it is not practical to assign the leakage to an individual SG, the entire primary to secondary leakage should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report, Page 1 of 9 Attachment 1 Document Control Desk LR-N10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 The calculated accident induced leakage rate from the portion of the tubes below 13.1 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 2.16 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, j. The results of monitoring for tube axial displacement (slippage).
If slippage is discovered, the implications of the discovery and corrective action shall be provided.SG inspections were performed in accordance with TS 6.8.4.i, "Steam Generator Program", during Salem Unit 1 Outage 1R20 (April 2010). Each reporting requirement of the U1 TS 6.9.1.10 is addressed in section 4.0 below (items a through j).3.0 EXPLANATION OF TERMS* 1R18: Unit 1 1 8 th Refueling Outage* 1 R20: Unit 1 2 0 th Refueling Outage* AVB: Anti-Vibration Bar (NOTE AV#- designates the Anti-Vibration Bar Number based on the information provided in Attachment 1)* BET: Bottom Expansion Transition
- BHT: Bottom Hydraulic Transition
- BLG: Bulge (Expansion (Per PSEG reporting requirement, these typically occur within the hydraulically expanded tubesheet)
- CL: Cold Leg* CM: Condition Monitoring
- DNG: Ding (Freespan region of the tube per PSEG reporting requirements)
- DNT: Dent (At support structures per PSEG reporting requirements)
- EPRI: Electric Power Research Institute 0 ETL: Expansion Transition Location (considered an under expansion per PSEG reporting requirements)
- ETSS: Examination Technique Specification Sheet* FDB: Flow Distribution Baffle Plate (FBH designates the Flow Distribution Baffle Plate on the Hot leg, FDC designates the Flow Distribution Baffle Plate on the Cold Leg)& FO: Foreign Object* HL: Hot Leg* INR Indication not Reportable
- NDE: Non Destructive Examination
- NDF No Degradation Found* NQI: Non Quantifiable Indication (Bobbin Coil report entry per PSEG requirements)
- OA: Operational Assessment 0 OD: Outside Diameter* ODSCC: Outside Diameter Stress Corrosion Cracking* OEX: Over Expansion (Per PSEG reporting requirement, these occur within the hydraulically expanded tubesheet)
- OXP: Over Expansion (Per PSEG requirements, the hydraulic expansion occurs above the top of tubesheet)
Page 2 of 9 Attachment 1 Document Control Desk LR-N10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 0 0 0 0 0 0 0 0 0 0 0 0 0 PVN: PWR: PWSCC: RTS: SG: SGMP: TS: TSC: TSH: TTS: TSP: TW: Vpp: Permeability Variation Pressurized Water Reactor Primary Water Stress Corrosion Cracking (NOTE: Per PSEG reporting requirements, occurs on the Inside Diameter of the tube)Return to Service Steam Generator Steam Generator Management Program Technical Specification Tubesheet Cold Leg Tubesheet Hot Leg Top of Tubesheet Tube Support Plate (07H would designate the 7 th TSP on the Hot leg, 03C would designate the 3 rd TSP on the Cold Leg, etc)Through-Wall Volts Peak to Peak; is a method of measuring displayed eddy current signals 4.0 TECHNICAL SPECIFICATION 4.1 Tech Spec 6.9.1.10.a The scopes of inspections performed in each SG are summarized below: DEGRADATION ASSESSMENT INSPECTION SCOPES INSPECTION BASIS Active / Potential Damage Mechanisms (AVB A full-length (tube end to tube end) bobbin coil and TSP Wear).probe inspection was performed on 100% of Required per Technical Specifications and the in-service tubes in each steam generator.
EPRI Pressurized Water Reactor Steam Generator Examination Guidelines Rotating coil (+ Point) inspection of the first 3 outer periphery tubes on both HL and CL; and Potential Damage Mechanism the first 3 rows of no-tube lane on the HL and CL for Possible Foreign Object Wear.100% rotating coil (+ Point) inspection of in- Proactive Inspection service HL and CL 1 R18 history hydraulic over expansions (OXP).100% rotating coil (+ Point) inspection of in- Proactive Inspection service HL and CL 1R18 history hydraulic under expansions (ETL)Page 3 of 9 Attachment 1 Document Control Desk LR-N 10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 INSPECTION SCOPES DEGRADATION ASSESSMENT INSPECTION BASIS 100% rotating coil (+ Point) inspection of in-service HL and CL tubesheet Bottom of Hydraulic Expansion transition (BHT) on locations relative to the TTS of BHT => 0 or BHT =< -0.40 inches.NOTE: BHT is the same as BET (bottom of the tube expansion transition), which is the terminology used in Amendment No. 294 to Facility Operating License No. DPR-70 for the Salem Nuclear Generating Station, Unit 1 100% rotating coil (+ Point) inspection of in-service HL BLG (=> 18 volt) and OEX (>0.25 inch) from +3" above TTS to -13.1" below TTS, Proactive Inspection including those OEX that partially extend within this region (e.g. OEX that go from -14" to -12", etc).100% rotating coil (+ Point) of:* Historical FO locations" Current Outage Bobbin Coil Possible FO Potential Damage Mechanism and Suspected FO Wear Calls* Bounding of Current Outage FO and Suspected FO Wear Calls 20% rotating coil (+ Point) inspection of all in-service HL TTS Expansion Transitions.
NOTE: Credited towards this scope was the Proactive Inspection population of tubes inspected for BLG, OEX, ETL, OXP, BHT, and historical FO at the TTS.20% rotating coil (+ Point) inspection of the in-service =>2 volt dented HL TSP locations Proactive Inspection (FBH to 07H) as reported from 1 R18 20% rotating coil (+ Point) inspection of the in-service =>2 volt HL Dings (TSH to 07H) as Proactive Inspection reported from 1 R18 20% rotating coil (+ Point) inspection of the in-service => 2 volt dented AVB locations and 20% of the =>2 volt dings in the U-bend (07H to 07C) in each SG, as reported from 1R18.20% rotating coil (+ Point) inspection of the in-service Row 1 and 2 tubes in each SG, 07H to Proactive Inspection 07C, from the population of tubes NOT inspected in 1 R15 or 1 R16 All previously installed tube plugs, and plugs N/A installed during 1 R1 8, were visually inspected Page 4 of 9 Attachment 1 Document Control Desk LR-N10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 NOTE: As defined in EPRI Report 1019038, Steam Generator Management Program (SGMP): Steam Generator Integrity Assessment Guidelines PROACTIVE INSPECTIONS are supplemental inspections that are not required (by Technical Specification or the SGMP Pressurized Water Reactor Steam Generator Examination Guidelines) which are performed for informational purposes and are not expected to result in findings.
These exams differ from those exams performed for Existing or Potential Degradation in that they do not fall within the periodicity sample. Proactive inspections can provide useful information to both the utility and the industry.
They are typically performed to challenge engineering assumptions.
4.2 Tech Spec 6.9.1.10.b Active degradation mechanisms found: The active degradation mechanisms found during outage 1 R20 were AVB wear, TSP wear, and FO wear (synonymous with Loose Part Wear). A summary table of the wear indications found during the inspection outage is provided in Attachment
- 3. A list of the AVB wear indications are provided in Attachment 7, the TSP wear indications in Attachment 8 and the FO wear indications in Attachment 9.4.3 Tech Spec 6.9.1.10.c Nondestructive examination techniques utilized for each degradation mechanism:
In accordance with Revision 7 of the EPRI PWR Steam Generator Examination Guidelines, a documented review of EPRI Qualified techniques was performed to ensure application of these techniques is pertinent to site-specific SG conditions.
Attachment 6 provides the NDE techniques utilized for each degradation mechanism.
4.4 Tech Spec 6.9.1.10.d Location, orientation (if linear), and measured sizes (if available) of service induced indications:
The only service induced indications detected during outage 1 R20 were due to AVB wear, TSP wear, and FO wear. Attachments 7, 8, and 9 provide information for the AVB, TSP, and FO wear found during 1 R20 inspection outage. The TW sizing in Attachment 7 for AVB wear and Attachment 8 for TSP wear is based on EPRI ETSS 96004.1 (bobbin coil).Four tubes had FO wear indications.
In SG 12, tube 3-3 had a possible FO wear indication reported in the freespan region above the cold leg top of tubesheet detected during the peripheral rotating coil examination.
The maximum depth was 25% TW using EPRI ETSS 27903.1. Visual inspections did not confirm a FO at this location.
It is possible that the object was removed by sludge lancing. This tube was returned to service. The surrounding tubes were rotating coil examined in the same area (Cold leg top of tubesheet) with no anomalies or degradation reported.Page 5 of 9 Attachment 1 Document Control Desk LR-N10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10* In SG13, tube 36-15, a possible FO wear indication was detected with bobbin located just below the bottom surfaces of the cold leg flow baffle. The maximum depth was determined to be 7% TW with EPRI ETSS 96004.1 (bobbin) and 15% TW with EPRI ETSS 96910.1 (+ Point). Visual inspection of the area was performed from the top surface of the baffle plate. The presence or absence of a FO could not be confirmed from the top surface. This tube was preventatively plugged and stabilized.
The surrounding tubes were rotating coil examined in the same area (cold leg flow distribution baffle) with no anomalies or degradation reported.* SG 14 had two tubes identified by eddy current with FO wear. During the bobbin coil examination, a NQI was reported 0.42 inches above the FBH in tube 34-109.Subsequent Rotating coil inspection of this location and the surrounding tubes in this region (FBH) of the tube identified three tubes with FO signals on the top of the hot leg flow baffle (Tubes33-108, 33-109 and 34-109) with associated wear signals on two of the tubes (33-109 and 34-109). Visual inspection revealed a FO wedged between the tubes that was subsequently removed. The two tubes with wear indications were sized (+Point) with EPRI ETSS 27903.1. Tube 34-109 was plugged due to a maximum wear depth of 40%TW. Tube 33-109 was returned to service with a maximum depth of 31%TW. Tube 33-108 remained in service with no associated wear reported.4.5 Tech Spec 6.9.1.10.e Number of tubes plugged during the inspection outage for each active degradation mechanism:
Attachment 4 provides the number of tubes plugged during the inspection outage for each active degradation mechanism (and preventative plugging).
In addition to the Technical Specification criteria for plugging flaws equal to or exceeding 40% of the nominal tube wall thickness, preventative tube plugging was performed for AVB wear, data quality issues (PVN), and FO engineering analysis as described below: " AVB wear that exhibited
>19% TW change (over previous two cycles, 1 R1 8 to 1 R20)or AVB wear with >35% TW degradation was preventatively plugged. Four tubes with AVB wear met these administrative criteria." One AVB wear location (SG1 1, tube R54-C37 at AV6) was also reported with a dent signal and therefore was depth sized with an extended +Point technique (ETSS 96910.1) at 16% TW; and subsequently the tube was plugged.* One tube in SG13 (tube R55-C82) was preventatively plugged due to data quality issues. During the 1R18 inspection outage, tube R55-C82 had a DNG call reported at 07H + 14.41". During the 1 R20 inspection outage, the bobbin coil exam reported an INR at the 07H + 14.41" location.
A sample of 1 R18 DNG indications was inspected with +Point probes during the 1 R20 inspection outage and tube R55-C82 was spun at the 07H + 14.41" location.
The +Point exam reported a NDF at the 07H+ 14.41" location.
However, a PVN was reported at 07H which was outside of the targeted area of interest (07H was examined as part of the inspection as a means for Page 6 of 9 Attachment 1 Document Control Desk LR-N1 0-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 the analyst to validate proper land marking).
PVN is a condition where the test coil impedance changes due to a change in the tubing material's inherent willingness to conduct magnetic flux lines. PVN signals are not considered to be flaws or degradation.
Rather, the signals are considered potential data quality issues that may be masking degradation.
Salem Unit 1 has not reported ODSCC at TSPs.Other plants have detected ODSCC at TSPs in thermally treated alloy 600 tubing that was detected using the bobbin probe in all cases. Nearly all of the TSP ODSCC identified to-date has occurred in tubes with higher than normal residual stress. A bobbin coil screening technique was developed to identify tubes with larger than normal residual stresses.
As part of a preventative evaluation, Salem Unit 1 conducted a residual stress screening of all SG tubes. During the evaluation, tubes with the potential for higher residual stress were identified for further evaluation.
During this evaluation, tube R55-C82 was not identified for further evaluation and was not considered to have higher residual stresses, therefore, considered to be less susceptible to ODSCC at the TSP. For tube R55-C82, the data from the Tech Spec examination (bobbin coil) at 07H was acceptable with no degradation detected.
In the cases of ODSCC at other plants, the bobbin coil inspection detected the ODSCC indication.
Bobbin is a qualified technique to detect ODSCC and since acceptable full length bobbin coil data was obtained for tube R55-C82, the PVN reported at 07H does not present a concern from a condition monitoring perspective.
However, to remove any potential that this area could result in degradation being masked during future inspections, this tube was preventatively plugged.PSEG's response to TS 6.9.1.1 0.d provides discussion of the FO wear indications and tubes plugged. In addition four (4) tubes, 20-42, 20-43, 21-41, and 21-42, in SG12 were preventatively plugged and stabilized for an irretrievable FO wedged between these tubes on the HL TTS. There was no wear detected on the preventatively plugged tubes.4.6 Tech Spec 6.9.1.10.f Total number and percentage of tubes plugged to date: During 1 R20, a total of 14 tubes were removed from service from all four-steam generators.
At the completion of 1 R20, the cumulative tube plugging in all four steam generators is 238 tubes or approximately 1.06% of the tubes removed from service. The limiting steam generator is SG 13 with approximately 1.92% of tubes removed from service. Attachment 5 provides a table of total number and percentage of tubes plugged to date.4.7 Tech Spec 6.9.1.10.g The results of condition monitoring, including the results of tube pulls and in-situ testing: A Condition Monitoring (CM) assessment was performed for the Salem Ul SGs following inspections from outage 1 R20 in accordance with NEI 97-06 and EPRI Guidelines (Including the EPRI Steam Generator Integrity Assessment Guidelines, Revision 2). Condition Page 7 of 9 Attachment 1 Document Control Desk LR-N 10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 monitoring assessment means an evaluation of the 'as found' condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The'as found' condition refers to the condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of the tubes. Condition Monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.The 'as found' condition of the tubing for 1R20 is provided in response to TS 6.9.1.10.d.
The Salem Unit 1 Condition Monitoring Limit (CML) is approximately 62% TW for AVB wear, 52% TW for TSP wear, 46% TW for FO wear when using the applicable EPRI ETSS techniques, and as conservatively calculated using guidance consistent with the EPRI Steam Generator Integrity Assessment Guidelines, Revision 2. All wear measured less than the CML, analytically demonstrates that the structural integrity performance criterion is met. All wear indications detected during 1 R20 were found to be below the NDE analytical CML. The maximum %TW found during 1 R20 for AVB wear was 44% TW, for TSP wear 11% TW, and FO wear was 40% TW. Therefore, the degradation was less than the respective condition monitoring limit, demonstrating that all tubes inspected met the tube integrity performance criteria in TS 6.8.4.i.b.
During the +Point inspection of tube R55-C82 for a freespan ding in the U-bend region (DNG at 07H + 14.71") a PVN was reported at 07H. The PVN at 07H was outside the targeted area of interest of the freespan DNG at 07H + 14.71". No degradation was found at the location of interest during the +Point examination.
During the full length TS bobbin coil examination, the bobbin data for tube R55-C82 was obtained and found acceptable.
However, tube R55-C82 that was preventatively plugged due to the PVN being reported at 07H. Since acceptable full length TS bobbin coil data was obtained, this tube does not present a concern from a condition monitoring perspective No tubes required in-situ pressure testing, and no tube pulls were performed during 1 R20.4.8 Tech Spec 6.9.1.10.h The primary to secondary leakage rate observed in each SG (if it is not practical to assign the leakage to an individual SG, the entire primary to secondary leakage should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report: PSEG did not observe any primary to secondary operational leakage at or greater than the detection threshold of approximately one (1) gallon per day over the cycle preceding the inspection in any of the steam generators at Salem Unit 1.Page 8 of 9 Attachment 1 Document Control Desk LR-N 10-0365 STEAM GENERATOR TUBE INSPECTION REPORT TS 6.9.1.10 4.9 Tech Spec 6.9.1.10.i The calculated accident induced leakage rate from the portion of the tubes below 13.1 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 2.16 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined:
PSEG did not observe any primary to secondary operational leakage at or greater than the detection threshold of approximately one (1) gallon per day over the cycle preceding the inspection in any of the steam generators at Salem Unit 1. Since PSEG did not observe any measurable SG primary to secondary operational leakage, the calculated accident induced leakage rate from the most limiting accident would not be significant.
4.10 Tech Spec 6.9.1.10.j The results of monitoring for tube axial displacement (slippage).
If slippage is discovered, the implications of the discovery and corrective action shall be provided: 100% of all in-service tubes within the tubesheet, both HL and CL, were monitored for tube axial displacement (slippage) using Bobbin coil inspections.
No indications of slippage were detected.Page 9 of 9 Attachment 2 LR-N10-0365 Salem Unit 1 Model F SG Tube Support Arrangement and Terminology Attachment 2 Document Control Desk LR-N 10-0365 SALEM UNIT 1 MODEL F SG TUBE SUPPORT ARRANGEMENT AND TERMINOLOGY AV3 ____AV4 (AVB)-,Anti-Vibration Barit Tube Support Plate (TSP)Suppo.rt -Number Top of Tubesheet (TTS)Flow Distribution Baffle Plate (FDB)FBC TSC TEC Page 1 of 1 Attachment 3 LR-N10-0365 Summary of Salem 1 R20 Wear Indications (Tubes / Indications)
Attachment 3 Document Control Desk LR-N 10-0365
SUMMARY
OF SALEM 1R20 WEAR INDICATIONS (TUBES / INDICATIONS)
Location of Wear Location ofcat arnSG 11 SG 12 SG 13 SG 14 Indication Non-Dented AVB 178 364 148 287 218 438 167 306 Dented AVB 1 1 0 0 0 0 0 0 Detected TSP 1 1 0 0 3 3 6 7 Loose Part Los at0 0 0 0 1 1 0 0 (Part Present)LoosePart0 0 0 0 2 2 (Part Not Present)Non-Dented AVB 1 5 2 6 4 12 1 3 Dented AVB 1 1 0 0 0 0 0 0 Plugged TSP 0 0 0 0 ( a 0 0 Loose Part (Part Present) a a 0 a i a 0 Loose Part Los at0 0 0 0 0 0 1 1 (Part Not Present)Non-Dented AVB 177 359 146 281 214 426 166 303 Dented AVB 0 0 0 0 0 0 0 0 Returned to TSP 1 1 0 0 3 3 6 7 Service Loose Parta a a a a a a Los at0 0 0 0 0 0 0 0 (Part Present)Loose Part (Part Not Present) a a I 1 a Page 1 of 1 Attachment 4 LR-N10-0365 Repairable Tube Status Report Attachment 4 Document Control Desk LR-N 10-0365 REPAIRABLE TUBES STATUS REPORT Degradation Steam Generator Total Location Tube 1-1 1-2 1-3 1-4 Loose Part Wear 0 0 1 1 2 All Foreign Object Bounding Without 0 4 0 0 4 Wear ABV Wear>39%TW 1 0 1 0 2 U-Bends ABV Wear 0 2 2 0 4 Preventative ABV Wear @ Dent 1 0 0 0 1 TSP/FBP Wear 0 0 0 0 0 Misc Data Quality / PVN 0 0 1 0 1 Total Tubes to Plug 2 6 5 1 14 Note: AVB Wear Preventative is for those tubes with AVB wear >35% TW or AVB wear that had wear change of >19% TW between the 1 R1 8 inspection and 1 R20 (2 cycles).Page 1 of 1 Attachment 5 LR-N10-0365 Total Number and Percentage of Tubes Plugged to Date Attachment 5 Document Control Desk LR-N 10-0365 TOTAL NUMBER AND PERCENTAGE OF TUBES PLUGGED TO DATE Salem Unit 1 Steam Generator Tube Plugging Status I SG 11 SG 12 SG 13 SG 14 Total Tubes Plugged Prior to 1 R20 44 45 103 32 224 Tubes Plugged During 1R20 2 6 5 1 14 Total Tubes Plugged 1 46 1 51 108 1 33 1 238 Total Percentage 1 0.82 1 0.91 1.92 1 0.59 1 1.06 Page 1 of 1 Attachment 6 LR-N10-0365 1R20 Nondestructive Examination Techniques Attachment 6 Document Control Desk LR-N 10-0365 1R20 NONDESTRUCTIVE EXAMINATION TECHNIQUES Salem Industry Damage Demonstrated Extended Site-Specific Review Technique Qualification Mechanism Applicability Applicability Deemed Acceptable Detection Sizing 96001.1 For CM/OA or 1 Bobbin Revision 11 Thinning TSP and TTS None Yes Information Only 96004.1 2 Bobbin Reison1 Wear TSP and AVB None Yes For Service Revision 12 96005.1 and Pitting in the For CM/OA or 3 Bobbin 96005.2 Presence of Freespan None Yes Information Only Revision 9 Copper Within non dented drilled 1-28411 For CM/OA or 4 Bobbin Revision 2 Axial ODSCC TSP and within None Yes Information Only drilled TSP with dents -2.0 Vpp.1-28412 Freespan with or For CM/OA or 5 Bobbin Axial ODSCC without dents < = None Yes formainOAlo Revision 2 2.0 Vpp Information Only Within Freespan, Sludge Pile 6 Bobbin 1-28413 Axial ODSCC region and None Yes For CM/OA or Revision 2 Broached TSP Information Only with or without dents < = 2.0 Vpp 24013.1 Freespan, 7 Bobbin Revision 2 ODSCC including Dings < None Yes N/A= 5.0 Vpp Loose Part 27091.2 Volumetric Wear N/A -Size with 8 Bobbin Revision 0 (Part Not Freespan Part Present YesRC Present)Yes -TSP Wear;AVB; FDB; CM/OA or Info 96910.1 Loose Parts Only Extende 9 +Point Revision 10 Wear Broached TSP Wear (Part Yes Only Extended Present) Applicability Areas Dings, Dents, 10 +ointTubesheet and 20510.1 Circ Expansion Non-dend For CM/OA or Revision 7 PWSCC Transition Non-dented Yes Information Only support structures 96703.1 Non-dented For CM/OA or 11 +Point Revision 17 Axial PWSCC Dent or Ding support structure Yes Information Only and tubesheet Non-dented Il 20511.1 Expansion Non-dente For CM/OA or 12 +Point Revision 8 Axial PWSCC Transition support structure Yes Information Only_____________and tubesheet Freespan, Dings, Dented and Non-21410.1 Circ Expansion dented support For CM/OA or Revision 6 ODSCC Transition structures, Yes Information Only Sludge Pile, Tubesheet and U-bend I I Page 1 of 2 Attachment 6 Document Control Desk LR-N10-0365 1R20 NONDESTRUCTIVE EXAMINATION TECHNIQUES Salem Industry Site-Specific Review Damage Demonstrated Extended Deemed Acceptable Technique Qualification Mechanism Applicability Applicability Detection Sizing Sludge Pile; within non dented drilled Expansion 14 +Point 1-28424 Axial ODSCC TSP and within drilled Transition, > 2.0 Yes N/A Revision 2 TSP with dents Dented TSP and (or Dings) U-bends 5 <2.0 Vpp.Freespan; within non dented broached TSP Expansion 15 +Point 1-28425 Axial ODSCC and within broached Transition, > 2.0 Yes N/A Revision 2 TSP with dents Dented TSP and (or Dings) U-bends_ <2.0 Vpp.21409.1 For CM/OA or 16 +Point Revisio Axial ODSCC Tubesheet Crevice None Yes Form a On Revision 6 Information Only 96511.1 Axial and Circ For CM/OA or 17 +Point Rvso16 wscU-bend None Yes IfrainOl Revision 16 PWSCC Information Only Sludge Pile; non 1-28431 dented drilled TSP Yes -Not For 18 +Point Revision 1 Axial ODSCC and drilled TSP with U-bends No Service dents-< 2.0 Vpp.19 +Point 1-28432 Axial ODSCC Free Span and non U-bends No Yes -Not For Revision 1 dented broached TSP Service 27901.1 27902.1 27903.1 PLP Wear 20 +Point 27904.1 PLP Wear Morphology None Yes For Service 27905.1 Dependent 27906.1 (Part Not Present)27907.1 (All Rev. 0)Page 2 of 2 Attachment 7 LR-N10-0365 1 R20 Service Induced Indications (AVB Wear)
Attachment 7 Document Control Desk LR-N 10-0365 1R20 SERVICE INDUCED INDICATIONS (AVB WEAR)KSG Row I Colýupp ý Inch TI SG11 22 80 AV1i -0.36.........................................
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