LR-N04-0108, Steam Generator Condition Monitoring Report

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Steam Generator Condition Monitoring Report
ML040760608
Person / Time
Site: Salem PSEG icon.png
Issue date: 03/09/2004
From: Mannon S
Public Service Enterprise Group
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
LR-N04-0108 S-2-RC-MEE-1800, Rev 0
Download: ML040760608 (26)
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Text

J7 PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236 MAR 0 2004 0 PSEG NuclearLLC LR-N04-01 08 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 STEAM GENERATOR CONDITION MONITORING REPORT SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE DPR-75 DOCKET NO. 50-311 Public Service Electric Gas Nuclear LLC, (PSEG) hereby submits the Steam Generator Condition Monitoring (CM) Report for Salem Unit No. 2 as required by Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines" and PSEG station procedures. This CM report, including results of tube pulls and in situ testing, is required to be submitted within 120 days after the reactor coolant system re-enters Hot Shutdown conditions when steam generator inspection results indicate that greater than 1%of the inspected tubes in any steam generator exceed the repair criteria. During Refueling Outage 13, greater than 1% of the tubes inspected in 23 Steam Generator exceeded the stations repair criteria.

PSEG's CM assessment results demonstrate that all tubes meet the structural integrity and accident induced leakage performance criteria of NEI 97-06 and station procedures for Cycle 13, which ended in October 2003. Further, PSEG recently completed an Operational Assessment, which demonstrates that the performance criteria will be maintained throughout Cycle 14 operations.

The CM work for end of cycle 13 did not require removal of tubes from the steam generators. Nine tubes were in situ pressure tested. All tubes passed without leakage or burst. In situ pressure testing screening criterion and results are described in the body of the CM report.

95-2168 REV. 7/99

MAR 0 9 2004 Document Control Desk 2 LR-N04-0108 Please contact Howard Berrick at 856-339-1862 if there are any questions about this submittal.

Sincerel Steven R. Man on Manager - Nuclear Safety and Licensing

Enclosure:

2R13 Steam Generator Condition Monitoring Evaluation C Mr. H. Miller Regional Administrator - Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Mr. R. Fretz, Project Manager - Salem U.S. Nuclear Regulatory Commission Mail Stop 08B2 Washington, DC 20555-0001 USNRC Senior Resident Inspector - Salem (X24)

Mr. K. Tosch, Manager IV Bureau of Nuclear Engineering P.O. Box 415 Trenton, NJ 08625

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ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 (Rev. No: 0 l ate: 1-12-2004 TiTLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A PERIODICREVIEWREQUIRED: No Sheet: 1 of23 __j 1.0 REVISION

SUMMARY

Original Issue 2.0 PURPOSE The purpose of this Engineering Evaluation is to document that steam generator performance criteria relating to tube integrity have been met for operating cycle 13, cycle previous to outage 2R13 (CM).

The performance criteria are defined in NEI 97-06 and SC.SG-AP.ZZ-0001 (Q), "Steam Generator Management Program'. At the end of each operating cycle, steam generator tube flaws must be reviewed for compliance of the structural integrity criterion and accident induced leakage criterion.

This typc of evaluation is called Condition Monitoring (CM). During outage 2R13, the steam generator tube Non-Destructive Examinations (NDE) inspections were performed by Framatome-ANP (FANP).

Indications were provided from the Framatome Data Management System (FDMS) and reviewed against the performance criteria and appropriate limits.

3.0 SCOPE This Engineering Evaluation affects the Salem Unit 2 Steam Generators, which are Reactor Coolant system components.

4.0 BACKGROUND

Commissioned in October of 1981, Salem Unit Two has four Westinghouse Model 51 series steam generators. Each steam generator contains 3388 NiCrFe alloy (Inconel ASME-SB-163) U-tubes with an outside diameter of 0.875 inches and a nominal wall thickness of 0.050 inches. The tube support structures consist of seven equally-spaced 0.750 inch thick carbon steel support plates which arc drilled with 0.891 inch holes and two sets of anti-vibration bars (AVB) that are located in the U-bend region of the tubes. The AVB bars are made from 0.387 square cross-section straight length bar material (Nickel-Chromium iron Alloy 600, chrome plated subsequent to bending), that is bent to a vee form with a 5.00-inch radius at the apex. The tube sheet is 21 inches thick ASME-SA508 Class 2 steel forging with Inconel cladding on the primary side. The tube ends are rolled into the tube plate and welded to the tube plate cladding. All tubes are explosively expanded into the tube sheet holes (a.k.a. WEXTEX). The expansion includes the entire depth of the tube sheet for both the hot and cold leg sides.

The steam generator primary side serves as part of the Reactor Coolant Pressure Boundary for containing the reactor coolant and/or emergency core cooling flow and for limiting radiation release to the Reactor Containment (by limiting coolant leakage) during all plant operating conditions. In addition, the steam generators serve as part of the Reactor Coolant Pressure boundary to preclude leakage and radiation release and provide separation between the radioactive primary side and the non-

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304.

ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A l PERIODIC REVIEW REQUIRED: No Sheet: 2 of 23 radioactive secondary side/system, Main Steam system, and the outside atmosphere during all plant operating conditions.

Structural Limits (SL) and Condition Monitoring limits (CM) have been established for Salem Unit 2 steam generator tubing, and are documented in S-2-RC-MDC-2002. To document the Condition Monitoring limits (CM) the structural limits (SL) must be reduced to account for material, relational, and NDE uncertainties. The structural limits, after being reduced by the various uncertainties, are termed Condition Monitoring (CM) structural limits. Methods to determine the CM limits are provided in the EPRI Stearn Generator Integrity Assessment Guidelines and EPRI Steam Generator Degradation Specific Management Flaw Handbook. For outage 2R13 the square root of the sum of the squares (SRSS) method, or otherwise known as simplified statistical, was used to combine the various uncertainties. The CM structural limits are then used to evaluate as-found indications to determine if the performance criteria have been met. This approach is consistent with NEI 97-06 and is known as a "bounding deterministic" approach. In addition, the use of In Situ Screening Parameters (FANP document 51-5032554-00, PSEG Vendor Technical Document (VID} 326112) and the EPRI Steam Generator In Situ Pressure Test Guidelines: Rev 2 (EPRI document 1007904), were utilized during outage 2R13 for screening of degradation in determination of structural and leakage integrity.

5.0 PERFORMANCE CRITERIA The performance criteria, provided from NEI 97-06, and documented in SC.SG-AP.ZZ-0001(Q) is as follows:

  • StructuralIntegrityPerformanceCriterion: Steam generatortubingshall retainstructural integrity over thefiull range of normal operatingconditions (includingstartup, operationin the power range, hot standby, and cooldown and allanticipatedtransients Includedin the design specyifcation) and design basis accidents. This includes retaininga safetyfactor of 3.0 againstburst under normalsteady statefull power operationand a safetyfactor of.1.4 againstburst under the limiting design basisaccident. Any additionalloadingcombinations shall be included as requiredby exisitingdesign and licensing basis.
  • Accident Induced Leakage Performance CrIterion; The primary to secondaryaccident induced leakage ratefor the limitingdesign basisaccident, other than asteam generator tube rupture, shall not exceed the leakage rate assumedIn the accidentanalysis In terms of total leakage ratefor all steam generatorsand leakage ratefor an individualsteam generator. Forall types of degradation,leakage is not to exceed I gpm per steam generator.
  • OperatIonalLeakagePerformanceCriterion:TheRCSoperationalprimary-to-secondary leakage through any one steam generatorshall be limited to 150 gallonsper day.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304 i ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 l ate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACIlON REQUEST: N/A l PERIODIC REVIEW REQUIRED: No l Sheet: 3of23 Performance of the Structural Integrity Performance Criterion and the Accident Induced Leakage Performance Criterion will be determined via this evaluation, IAW SC.SG-AP.ZZ-0001. Performance of the Operational Leakage Performance Criterion is determined by the primary-to-secondary leakage-monitoring program, as described in SC.SG-AP.ZZ-000l. There was no detectable primary-to-secondary operational leakage during cycle 13.

6.0 Salem Unit 2 Outage 2R13 CM Evaluation The CM evaluations in this document utilize, in addition to other documentation, the 2R1 3 Degradation Assessment (DA), 2R13 Structural and Condition Monitoring Limits Calculation (SL & CM limits).

The 2R13 DA provided the estimated Salem Unit 2 performance and cycle 14 expected EFPD. The actual end of cycle 13 operation in calendar days, EFPD, EFPY, and cumulative EFPY are: 510.6, 495.6, 1.36, and 13.46. The estimated cycle 14, on a reactor fuels basis, operation in calendar days, EFPD, EFPY, and cumulative EFPY are: 495, 482.5, 1.32, and 14.78; respectively (-97.5 Capacity Factor).

The Degradation Assessment also provides the details of the EPRI Examination Technique Specification Sheets (ETSS) used during outage 2R13. All flaws detected, that do not have a qualified sizing technique, have their respective tube plugged on detection. Those flaws that do have a qualified sizing technique can be evaluated against the Tech Spec plugging limit of 40% TW.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304_

ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 Date: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation

.ACTION REQUEST: N/A PERIODIC REVIEW REQUIRED: No Sheet: 4 of 23 6.1 Tube Plugs Visual Examinations of all hot and cold leg installed tube plugs was performed during 2R13 in accordance with procedure SC.SG-TLRCE-0002 (Q), "Steam Generator Tube Plug Visual Examination". As a result of the visual inspections the following Westinghouse alloy 600 plugs with Plug-In-Plug (PIPs) and Plug-A-Plug (PAPs) installed, were identified as requiring additional review and evaluation:

SG Row Column Leg Description PSEG Order 21 1 43 HLI FANP PAP 70034496 21 1 58 HL Westinghouse PIP 70034496 21 61 H1L Westinghouse PIP 70034496 21 1 63 HL Westinghouse PIP 70034496 22 1 86 HL Westinghouse PIP 70034497 23 1 21 HL Westinghouse PIP 70034498 23 1 65 HL Westinghouse PIP 70034498 23 1 71 HL FANP PAP 70034498 1 In accordance with the evaluations and inspections performed by PSEG with support from Westinghouse (VTD 326355), the conditions identified during the plug visual inspections for the Westinghouse PIPs are acceptable and not considered a condition adverse to quality. The minor boron and wetness was determined to be typical for these mechanical plugs with a Westinghouse PIP installed.

The OE (Original Equipment) vendor for the PAPs was also requested to supply PSEG an evaluation of the FANP PAP locations. In accordance with the FANP evaluation (FANP CR 6029365), FANP conservatively recommended utilization of weld plug repair on these two PAP locations. FANP performed the PAP removal and weld plug installation (SG21 RI C43, SG23 Rl C71). It was visually noted during the PAP removal and weld plug preparation processes that the integrity of the parent tube plug appeared to be structurally sound. NDE inspection of these tube plugs was not performed after PAP removal since NDE is not possible for the Westinghouse ribbed I-600 plug design.

In addition, volumetric examinations (utilizing Eddy Current probe technology) were performed on four (4) FANP mechanical tube plugs, in two tubes. During outage 2R9 two locations R2 C45 in 21-steam generator and R2 C3 in 24-steam generator were plugged due to stuck eddy current probes in the U-bend region. Evaluations documented within Framatome NCR 96-00037 and PSEG PIRS 960202211 and 960203082 required the tubes to be plugged and periodically reviewed. Future inspection requirements were documented in confirmation numbers 1125911 of order 80006642 operation 620 and 1230739 of order 80006642 operation 660. During 2R10 eddy current volumetric examinations and visual inspections were performed on the tube plugs, with no indications of degradation detected. During 2R1 1 and 2R12, performance of volumetric inspections was based on the visual inspection results. No plug abnormalities identified.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304:

ENGINEERINGEVAL.NO.: S-2-RC-MEE-1800 Rev. No: 0 Date: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: NIA l PERIODIC REVIEW REQUIRED: No Sheet: 5 of 23 During 2Rl3, volumetric eddy current inspections of the tube plugs located in both the hot and cold legs of locations R2 C45 in 21-steam generator and R2 C3 in 24-steam generator were performed. In addition, the secondary side visual inspection plans included a secondary side top of tubesheet visual of the two tubes in question, both hot and cold leg side. Visual inspections on the primary side of the tube plug are performed every outage IAW procedure SC.SG-TI.RCE-0002. Therefore, these three (3) inspections provided a complete review of the tube locations R2 C45 in 21-steam generator and R2 C3 in 24-steam. No abnormalities or conditions adverse to quality were identified.

Following the completion of outage 2R13, a total of 110 additional tubes were removed from service from all four steam generators. This resulted in a total of 1022 tubes, or 7.54%, removed from service from all four steam generators.

SG SG SG SG' Total

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 21 22 23 24 TUBES PLUGGED Prior to 2R1 1 166 183 144 260 753 TUBES PLUGGED During 2R11 31 33 17 37 118 TUBES PLUGGED During 2R12 (April 2002) 14 8 10 9 41 TUBES PLUGGED During 2R13 (Oct 2003) 13 11 62 24 110 TOTAL TUBES PLUGGED CUMULATIVE 224 235 233 330 1022 CUMULATIVE TUBE PLUGGING % 6.61 6.94 6.88 9.74 7.54 Tube plugging, including details of specific tubes plugged, is documented in workorders 50052913, 50052966, 50056208, and 50052982.

Salem Unit 2 utilized various types of tube plugs over the course of the previous outages. These include rolled, ribbed, PIPs, PAPs, and welded plugs. In addition; two different vendors, Westinghouse and Framatome, were contracted during different outages to install their version of tube plug. Salem Unit 2 has some alloy 600 mechanical tube plugs in service, all of which were supplemented (repaired) with either a Westinghouse PIP or Frarnatome PAP. The PIP or PAP essentially limits leakage of the alloy 600 tube plug and prevents the plug top from being rapidly propelled through the tube in the event of a plug top release event.

Mechanically installed tube plugs are considered leak limiting. An example of a conservative estimate of potential leakage provided from the installed tube plugs can be shown by review of Framatome document 51-1179145 (PSEG VTD 326072). This report calculates that a conservative estimate of operating temperature primary-to-secondary leakage would be approximately 0.11 gallons per hour (0.0018 gpm) if 20% of the tube plugs in all four steam generators were plugged using the FANP alloy 690 rolled plug. This leakage is negligible, and assumes a through-wall flaw condition in the parent tubing.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304 ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 blate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation

.-ACTION IEQUEST: N/A PERIODICREVIEW REQUIRED: No l Sheet: 6 of 23 There was no detectable primary-to-secondary operational leakage during cycle 13.

6.2 PWSCC in the WEXTEX & TTS Transition Zone A total of 15 PWSCC Axial indications, affecting 15 tubes, were identified in the hot leg WEXTEX region inspections (-8 inches below TTS and +3 inches above TTS) performed in all four steam generators. The results are sumnarized in the table below and in attachment 2. All tubes identified with this degradation were plugged. Structural performance criterion for indications below the TTS are met based on the fact that the tubesheet prevents burst. All indications were located below the TTS IAW eddy current inspections. The axial length for all of the WEXTEX indications ranged approximately between 0.08 and 0.18 inch.

PWSCC Axial indications that are found to be entirely contained below the WEXTEX Transition (BWT) are also conservatively evaluated using the methods found in WCAP-14797, Revision 1, "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions". Per WCAP-14797, accident-induced leakage (MSLB) is a function solely of the contact stress between the WEXTEX-expanded tube and the tubesheet.

These contact stresses vary with the distance from the WEXTX transition, and with the radial location on the tubeshect. The We methodology breaks the tubesheet down into five radial zones (A, BI, B2, B3, and B4). Leakage therefore depends only on the distance of the defect from the WEXTEX transition zone (Bottom of WEXTEX - BWI) and on the zone location in the tubesheet. The BWT and location of the upper crack tip (UCT) is presented in attachment 2 for each indication. The distance the UCT is in relation to the BWT includes uncertainty in measurement (WCAP 14797,Tablc 8.3-1: 0.28"). Figure 8.2-1 of WCAP-14797 was used to determine the W* radial zone and Figure 6.4-3 was used to estimate an accident leakage rate.

Results are provided in attachment 2 using an extremely conservative assumption that all indications that are below the BWT are 100% through-wall. It should be noted that for additional conservatism the maximum %TW, regardless of voltage, in the line-by-line sizing was reported in Table 6.2-1. This can be conservative when considering that the %TW at maximum voltage can be a more accurate indicator for maximum %TW. Consideration of the location in the sizing data for %TW and voltage can also be used for more accurate maximum %TW sizing analysis. Regardless, a conservative estimate of PWSCC WEXTEX accident.leakage was calculated for each steam generator. This resulted in a total theoretical leak rate for all SGs of approximately 0.170 GPM, with SG 2-4 contributing approximately 0.105 GPM of this total, and assuming all indications are 100%TW. Based on the location, NDE sizing data, low voltage flaw amplitudes; the actual total faulted condition leakage for WEXTEX PWSCC indications would be insignificant.

One (1) PWSCC volumetric indication was identified in the WEXTEX region of SG 2-1 (-.0.5 inch below TTS). This volumctric indication was sized at 0.09 inch in axial extent and 54 degrees in circumferential extent with a maximum depth of 21%TW and a Plus-point voltage of 0.85 volts. IAW the EPRI SG In Situ Pressure Test Guidelines: Rev 2, a narrow volumetric

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY i 20040304 i ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 I Rev. No: 0 1Date: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A I PERIODIC REVIEW REQUIRED: No l Sheet: 7 of23 band of degradation, which is predominantly circumferential, may respond like a circumferential crack. Assuming this indication is circumferential is therefore conservative for in situ screening.

Assuming the indication is throughwall, and utilizing the EPRI SO In Situ Pressure Test Guidelines (section 4.4.2.2), a conservative screening limit of 180 degrees demonstrates that this indication is not a structural concern (conservatively assuming tubesheet does not provide resistance to burst). Based on the maximum depth sizing, leakage is not probable, even when conservatively applying extreme uncertainties in depth sizing of 3 or 4 times actual NDE sizing.

Also the indication when conservatively screened as circumferential, and IAW VTD 326112, 2R13 In-Situ Testing Screening Parameters; and the EPRI SG In Situ Pressure Test Guidelines, a voltage-screening limit of 1.25 volts demonstrates that leakage is not probable. This indication is neither a structural or leakage concern at EOC 13 based on its location and geometry.

Axial indications in the tubesheet that are at or above the BWT are not applicable to the W*

leakage models and are evaluated for SLB leakage by utilizing the in-situ screening criteria for leakage, which is 2.5 volts Plus Point (Steam Generator In Situ Pressure Test Guidelines: Rev 2). All axial indications determined to be at or above the BWT are less than 0.60 volts, and therefore leakage criteria are met. In fact, all PWSCC indications in the WEXTEX are less than 1.30 volts and more than half of these are less than 0.5 volts.

Table 6.2-1 Summary of WEXTEX PWSCC Indications SGRw Ct ID LCT UCT BWVT Volts Lon CIrc Max (inch) (Inch) (inch) l() (inch) (Dog) (cMx 21 2 20 SAI -2.29 -2.17 -0.22 0.33 0.12 NA 93 21 6 70 SAI -0.73 -0.64 -0.29 0.46 0.09 NA 31 21 15 27 SAI -9.74 -9.88 -0.49 1.26 0.14 NA 48 21 30 79 SVI -0.68 -0.49 -0.24 0.85 0.09 54 21 22 25 72 SAI -1.53 -1.44 -0.32 0.46 0.09 NA 44 23 25 61 SAI -8.48 -8.3 -0.24 0.63 0.18 NA 38 24 3 51 SAI -0.97 -0.86 -0.22 0.34 0.11 NA 41 24 9 36 SAI -1.37 -1.26 -0.38 0.4 0.12 NA 28 24 14 17 SAI -0.47 -0.31 -0.27 0.53 0.16 NA 79 24 14 41 SAI -1.06 -0.95 -0.42 0.3 0.11 NA 28 24 20 35 SAI -2.02 -1.91 -0.31 0.15 0.11 NA 28 24 24 52 SAI -0.21 -0.13 -0.21 0.68 0.08 NA 55 24 31 52 SAI -0.32 -0.23 -0.39 0.42 0.09 NA 28 24 31 54 SAI -0.41 -0.29 -0.25 0.57 0.12 NA 44 24 31 58 SAI -0.32 -0.21 -0.34 0.47 0.11 NA 55 24 33 44 SAI -0.51 -0.34 -0.47 0.37 0.17 NA 35

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304-ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 bate: 1-12-2004 TITLE: 2R13 Steam Gencrator Condition Monitoring Evaluation ACTION REQUEST: N/A PERIODIC REVIEW REQUIRED: No Sheet: 8 of 23 --j 6.3 PWSCC at the Tube Support Plate C(SP) Intersections A total of 2 axial PWSCC indications and 1 circumferential indication were detected at the hot leg dented TSP intersections, affecting 2 of the steam generators (SG 2-1 and 2-2). The location in SG 2-1 (RI 9C18) had the axial and circumferential indication at the same TSP, 02H TSP.

The flaws were -120 to 180 degrees apart on the tube wall (opposite sides of tube) and separated axially within the TSP, thus flaw interaction is not probable and burst capability is not reduced.

All indications were within the TSP, and the voltage of the indications ranged from 0.42 to 0.58 volts. The bounding voltage screening parameters of 0.50 volt for proof testing, and the TSP axial screening limit of 0.565 inch (VTD 326112), demonstrates that these indications are not structurally significant. In addition, the structural limit of a through-wall circumferential flaw is approximately 262 degrees, and the CM limit (when utilizing conservative NDE uncertainty) is

-200 degrees. Leakage is also not probable based on a bounding PWSCC screening of 1.0 volts (SG In Situ Pressure Test Guidelines, Table 4-1), which is conservative for axial and circumferential PWSCC (actual axial PWSCC TSP voltage screening is 2.57 volt). Based on the location, size, and voltage magnitude (VTD 326112, S-2-RC-MDC-2002, SG In Situ Pressure Test Guidelines); structural and leakage integrity are met. The circumferential indication did not require stabilization based on the criteria defined in FANP document 51-1257327-05 (PSEG VTD 326071).

Table 6.3-1 Summary of 2R13 TSP PWSCC Indications l 2R13 Data 1 SO R C IND TSP LEN MD % VOLTS OUTSIDE DENT ITSP VOLTS 21 19 15 SCI 2H 26.5 66 0.42 NO 4.74 21 19 15S SAl 2H 0.22 61 0.45 NO 4.74 22 _ 77 SAI I 10.24 E 3 0.58 NO .2A9 6.4 PWSCC In the U-Bends During outage 2R13, the base scope inspections in the U-bends included 100% of row 2 through row 10, and 20% of row 13 through 17, in all four steam generators. Both a mid-frequency and high-frequency rotating coil were used for inspecting the low row U-bends (rows 2 and 3).

During the inspection, circumferentially oriented indications were detected in SG 2-3 (at or below row 9), which resulted into expansion to the base scope to include 100% inspection of the u-bends up to row 20 in SG 23. It was determined that these indications are attributable to circumferentially oriented PWSCC in the flank area of the tube. The complete evaluation of the NDE data from these indications is presented in FANP document 5 1-5035782-00 (VTD 326318). It was determined through the various studies and NDE inspections that these indications, although not of the same magnitude of the indications detected at Diablo Canyon

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304.

ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 'Bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: NIA PERIODIC REVIEW REQUIRED: No Sheet: 9 of 23 Unit 2, were similar in origin, orientation, and confined at or below row 9. Forty-six tubes were affected by this degradation (SCI), and another nine tubes were plugged preventatively (PTP).

The nine PTP tubes were judged not to be degradation, however these nine locations were also preventively plugged and stabilized along with the forty-six locations that were reported as containing SCIs.

Table 6.4-1 contains a summary of the eddy current data relative to the 46 indications classified as SCI. Arc length and depths along the indications were determined by the eddy current sizing analyst. The average depth was conservatively computed using only the depths of the flaws along their profiles, excluding the zero depth end points and including the high depth end points that are not realistic duo to end effects and phase sizing. The indications are all relatively the same arc length, ranging from 14 to 35 degrees. These lengths are well below the conservatively reduced in-situ screening limit of 180 degrees for a 100%TW flaw (Section 4.4.2.2 of the EPRI SO In-situ Pressure Test Guidelines Rev 2). Therefore if it is assumed that the indications are l 00%/TW for the entire arc length, they are well below the structural limit. The maximum depths ranged from 20 to 97%TW. The largest maximum depths were usually associated with the end points of the flaws and as such were not regarded as either truth or valuable when compared to the associated voltage at the same point of the indication. Phase angle sizing was used to estimate these depths, which is known to provide erroneous depth estimates at the crack tips where the signal sometimes rotates out of the flaw plane. The average depths ranged from 10 to 60%TW, but again, reliance on the accuracy of these depths to determine the impact on SLB leakage was not relied upon. The indication voltage was used as a screening tool for determining which indications should be leak tested. When reviewing the EPRI SQ In-situ Guidelines Revision 2, it was determined that the circumferential indication data was not updated to include the Diablo Canyon Unit 2 data from the spring of 2003. An ADHOC preliminary revision of the data in Table B-16 was performed by Westinghouse, with a revised leakage threshold voltage of -1.68, compared to the published value of 1.83. Irrcspectivc of this value, indications ->1.2 volts were administratively selected for leak testing, as well as the tube with the most indications, during 2R13 (R5C27, R5C38, R5C42, R5C68, R5C71, R5C74 and R9C23). A total of seven locations were proof and leak tested to the 3 APNO and 1.4 LADP (MSLB), respectively, equivalent room temperature pressure with no burst or leakage during any of the test pressures (VTD 326353). Therefore both structural and leakage performance criteria were met for this degradation at EOC 13.

OUTSTANDING onh A n CHANGES MUST BE ATTACHED FOR WORKING COPY LUU4%JOU4 ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 l Rev. No: 0 1bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A I PERIODIC REVIEW REQUIRED: No Sheet: 10 of 23 Table 6.4-1 Summary of U-bend Circumferential PWSCC Indications l Row Cob a7 Loc ZIndH AV depth MaX alpun AKi "n-t3

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-w07r - W73Y r u-T, 5- 40n m1.05 44 3857 -z 97-- Z 25 9 221 -o7n 4T1T,2 -- U.96< -- 4Z- 4 8 -T 44 U C2;1-"W -4ZZ. 1 0.73Y 7 22 o3-T 07r -66r -ME 0.3843- 1 Z3" 287a 0 .4 4 42 b a 1 9 X47F01 30.5Ba 0.55 44 To Z 2 T Z 07F r3.0 T 0 .38 34 7 46 9V -W virs bN.2M44S1 9 -07Fr 0.71 40 4S-2-.BT T3 7T .57: T .1 2 3 _1 93 0H 3.-3 9 .U 31 35 20 T 0.41~ .3a 27 :18 29

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304 ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 ate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A l PERIODIC REVIE:WREQUIRED: No lSheet: 11of 23 6.5 ODSCC in the rTS Transition Zone & TTS One axial ODSCC indication was detected at the TTS region in steam generator 24. This indication was sized as approximately 0.21 inches in axial length and 51% TW at a maximum, and the voltage ofthis indication is -0.15 volts. This ODSCC indication was within the sludge pile region of the TTS, approximately 0.30 inches above the TTS. The bounding voltage screening parameters of 0.50 volt for proof testing and 1.00 volt for leakage (bounding voltage for axial ODSCC) as identified in VTD 326112, 2R13 In-Situ Testing Screening Parameters; and the EPRI SG In Situ Pressure Test Guidelines, demonstrate that this indication meets the structural and leakage performance criterion.

2R13 Data SG C IND LENGTH IMD VOLTS I VOLTS 24 16839 SA 0.21 51 015 NDD lNA 6.6 ODSCC at the Tube Support Plate (ISP) Intersections One OD SVI (Single Volumetric Indication) indication was detected by bobbin in SG 24 at the 01H TSP in tube R35 Cl8. This volumetric indication was rotating coil probe sized with a maximum depth, axial length, circumferential extent, and voltage of approximately 22%TW, 0.16 inch, 51 degrees, and 0.4 volts; respectively. This indication is possibly attributed to intergranular attack corrosion (IGA). IGA is a term that is used to describe a morphology characterized by a uniform or relatively uniform attack of the grain boundaries over the surface of the tubing. Stress is not generally a factor with respect to IGA when the occurrence is over a relatively large extent exhibiting three-dimensional features, in which case, the IGA is referred to as volumetric IGA. If the IGA is three-dimensional and local, the IGA may be referred to as a pocket IGA. The bounding voltage screening parameter of 0.50 volt for proof testing as identified in VTD 326112, 2R13 In-Situ Testing Screening Parameters; and the EPRI SG In Situ Pressure Test Guidelines, demonstrate that this indication is not structurally significant. Based on the maximum depth sizing, leakage is not probable, even when conservatively applying extreme uncertainties in depth sizing of 3 or 4 times actual NDE sizing.

6.7 Thinning at TSP Intersections (Cold Leg Thinning)

During outage 2R13, a total of approximately 114 cold-leg thinning (CLT) indications were detected in all four steam generators. The majority of the indications are in SG 2-2, 2-3, and 24.

Only 6 CLT indications were detected in SG 21; with one low voltage indication (R43 C31, 01C, -0.35 volt) that was judged to be thinning, but was reported as a bobbin DSI due to the low voltage and confounding effects of bobbin sizing. This location, all new 2RI 3 CLT indications

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 2004 304' ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A l PERIODICREVIEWREQUIRED: No Sheet: 12 of 23 and historical in-service cold leg thinning indications not inspected by rotating coil probes during previous outages, were rotating coil probe inspected during 2R13 to ensure that these CLT locations were not crack like. All 114 indications were determined to be volumetric, and not crack like.

The largest detected cold leg thinning indication via bobbin was in SG 22 and was sized at 555%TW. This is well below the CM limit of 66% TW, and all cold leg thinning indications are also well below the leakage screening criteria in the EPRI Steam Generator In Situ Pressure Test Guidelines: Rev 2, therefore the CM structural and leakage performance criteriaare met for EOC 13.

Summary of Cold Leg Thinning Largest Largest SG 2R13 Plug Flaw Tubes BOC Flaw Indications Limit Detected Plugged for Cycle 14 21 6 40 30 1* 30 22 51 40 55 2 38 23 19 40 53 6 34 24 38 40 46 3 37 Totals 114 I IlI l__

  • Low voltage (-0.35 volt) bobbin DS[ that via rotating coil produces a volumetric response typical of cold leg thinning. The %TW depth could not be accurately determined with Bobbin coil technique due to the influence of the tube support plate residual on the signal. The indication was sized with a rotating coil technique using an ASME calibration standard at approximately 19 %TW maximum, and this tube was plugged.

6.8 Wear from Tube Bundle Structural Components (AVB)

Approximately 601 AVB wear indications (272 tubes) were detected in all four steam generators in 2R13. Since each tube has two possible AVB bar contacts, one on each side of the tube, there is a possibility for the tube to have two-sided wear. Normally only one side of the tube develops a wear indication, but occasionally double sided wear is found. The bobbin technique is only capable of detecting double-sided wear when not in the same plane (different axial positions).

Industry data demonstrates that double sided wear in the same plane detected by bobbin provides conservative measurement of depth (over sizes). Indications out of plane are conservatively considered separately.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 2004 ,04 iENGINEERING EVAL. NO.: S-2-RC-MEF-1800 Rev. No: 0 Dlate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A PERIODIC REVIEW REQUIRED: No Sheet: 13 of 23 The largest detected AVB wear indication was in SG 2-4 and was sized at 46%TW. This is well below the CM limit of 67%TW, and therefore the CM structural and leakage performance criteria are met.

Summary of AVB Wear Largest SG 2R13 AVB 2R13 AVB Plug Largest Tubes BOC Flaw Indications Tubes Limit Flaw Plugged for Cycle Detected 14 21 174 79 40 40 1 39.

22 70 36 40 34 0 34.

23 183 94 40 37 0 37 24 174 63 40 46 1 37 Totals 601 272 1 1 1 2 1 6.9 Tube Noise and Probe Stalling Tube noise is a condition that may impede an analyst's ability to identify tube degradation. One example is permeability variations (PVN), which 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 is a potential data quality concern that may impact inspection techniques performance indices (e.g. POD). Permeability variation signals are not considered flaws or degradation, but can possibly mask true indications. In accordance with PSEG's data analysis guidelines, repair of PVN calls is based on final disposition of the PVN call. PSEG has historically demonstrated during 2R11 (32 tubes were removed from service due to data quality concerns; 27 tubes for PVN and 5 tubes for probe skipping or stalling) and 2R12 (1 tube plugged for PVN), that any suspect tubes with tubing noise will not be returned to service. Tubes are removed from service if there is any question of the data quality. During 2R13 the same conservative approach was utilized, resulting in 5 tubes repaired in SG 2-1 for PVN (R13 C44, R19 C47, RIO C56, R28 C57, R27 C80), 1 tube repaired in SG 2-2 for PVN (R21 C15) and 2 tubes (R4 C84, and R5 C73) repaired for the failure of the probe to completely inspect the U-bend area (Probe Stall, Preventatively Tube Plugged - PTP).

6.10 Freespan Anomalies In 2R13 two axially oriented ID indications were detected in SG 2-1 (R14 C90) and SG 2-2 (R19 C71). During the U-bend inspection of SG 2-1, an axial indication in the apex region of the bend was detected with the Plus-point coil that appeared to be axial PWSCC based on phase

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040 304 ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 late. 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A PERIODIC REVIEW REQUIRED: No lSheet: 14 of 23 angle, phase relationship (rotation) between the frequencies and the voltage drop across those frequencies. The indication was very uniform along its length of 1.47 inches, approximately 40% deep from end to end. The bobbin coil data was reviewed for this area in the current outage and previous outages, including the first ISI. It was determined that the indication although present in the 2R1 3 data, could not be expected to be reliably detected with the bobbin coil.

However, the historical review revealed that the indication was present in the first ISI and had not changed significantly in approximately 12 cycles of operation. These facts lead to the conclusion that this indication is not likely to be PWSCC induced, but some sort of manufacturing anomaly in the tube.

The other axial signal was detected during the Plus-Point inspection of the historical freespan indications from 2R12. Historical freespan indications are dispositioned based on comparing the current bobbin signal characteristics to the first ISI and determining if change is evident. Based on the recent events at Comanche Peak, all freespan indications that were dispositioned during 2R12 as not meeting the bobbin coil change criterion (i.e. not requiring rotating coil inspections), were conservatively pre-programmed for plus-point inspections during 2RI3.

Location R19 C71 was determined to have an axial indication approximately 8 inches below the 5"' TSP on the cold leg side. The indication was somewhat similar to the indication in the u-bend but was not as consistent in depth across its -1 inch length. As stated previously, since this indication was present in the first ISI and did not change significantly in 12 cycles of operation PSEG concluded that this indication is likely attributed to a manufacturing anomaly.

Based exclusively on the lengths of these indications, it was determined that in-situ pressure testing was prudent. The testing, while demonstrating that tube integrity was met at EOC 13, could also be used to verify that these indications are not actual tube degradation. The length of the indications is such that a pressure test to 3AP would be expected to open up true PWSCC degradation. Post in-situ NDE could then be used to demonstrate whether or not degradation was present by comparing the eddy current signal response to the pre-tested condition. In both cases, these tubes were tested to 5000 psi (RT equivalent to 3AP) and then re-inspected with the Plus-point probe afterwards with no significant changes detected in the NDE characteristics or data. Therefore it was concluded that neither of these indications are likely attributable to service-induced degradation and that the 2R13 inspection program is adequate. These indications were not a structural or leakage concern as established by the in-situ pressure and leakage testing (5000 psi), with no tube burst or leakage.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY I 20G40304' i ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 I Rcv. No: 0 l bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A I PERIODIC REVIEW REQUIRED: No Sheet: 15 of 23 Table 6.10-1 2R13 POST INSITU 2R13 DATA DATA Change SG R C IND TSP/INCH LEN. MD % PT VOLTS BOB IND BOB L

VOLTS LEN.

LE.M%

7MI  % OTS VOLTS LEN. MD% V 21 14 90 SAI 7H+3026 l 1.47 41 2.01 NDD NA 1A5 41 2.01 -0.02 0 0 22 19 71 SAl 5C-8.28 l 0.92 38 1.38 FSH 0.88 0.8 35 1 1.43 .0.12 l3 0.05 As a result of the detection of the axial indications discussed above, the base scope rotating coil probe inspection program was conservatively expanded to include 100% of the current outage (2R13) bobbin coil freespan indications, regardless if change via bobbin wvas apparent or not compared to the first ISI. This resulted in another 156 indications being inspected with rotating coil. The results of this inspection identified 3 locations as SVI (single volumetric indications).

The details are provided in Table 6-10.2. The fact that these indications are present in the first ISI inspection provides the basis that they are not active degradation, but likely manufacturing related. These indications wcre not significant as shown by their Plus-point responses (voltage) and comparison to the screening criteria from VTD 326112 and the EPRI SG In Situ Pressure Test Guidelines.

Table 6.10-2 2R13 Data SG R C IND ID/OD TSP/INCH ARC LEN. MD % VOL+T B IN VOLT 22 40 52 SVI OD TSC+2.02 44 0.29 13 0.22 FSH 0.50 24 3 75 SVI OD (4) 4H 5H 42 0.16 6 0.12 FSH 0.33 24 27 80 IVI OD 2H+24.96 39 0.18 5 0.11 FS1I 0.32

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304 ',

ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 l bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A I PERIODIC REVIEW REQUIRED: No lSheet: 16 of 23 6.11 Upper Steam Generator Secondary Side Evaluation During outage 2R13, SG 21 upper secondary side feedring was remotely inspected through the feedwater nozzle inspection port (Gamma Port). The focus of the inspections was the feedwater backing rings located near the feedwater tee (highest flow rate region). Inspectibns indicated that although typical minor erosion and wear was occurring at the backing rings, there was no significant changes identified compared to previous inspection data and all backing rings inspected were found to be structurally intact.

6.12 Lower Steam Generator Secondary Side Evaluation 6.12.1 Tube Support Plates (Ligament Cracking)

During outage 2R13 approximately 40 tube support plate ligament (TSP) indications were detected. All previously identified indications, and any new potential bobbin suspect TSP ligament indications detected during 2R13, were Plus-point inspected. Data for ligament cracking is presented in attachment 3. Only I new indication of ligament cracking was identified, which was detected via bobbin. As with the previously detected ligament indications, this indication is not necessarily new, but most likely a result of POD. However, the TSP locations that have been visually verified and are in fact missing a piece of ligament (gap), have been demonstrated as readily detectable via the bobbin technique. In addition no significant growth or change could be inferred in the data considering analyst variability and technique utilized. One indication from 2R12 was determined as NDD by Plus-point in 2R13, and is likely a result of a conservative analyst call in 2R12. All indications were returned to service since the criteria of ligament cracking below 145° threshold gap (PIRS 980327073) was not exceeded.

Visual inspections of historical ligament gap locations was performed following chemical cleaning in 2R10 and it was determined that the flow hole and tube holes intersected as a result of misdrilling during manufacture. No indication of true service induced TSP degradation has been detected or visually verified in the Salem 2 SGs.

6.12.2 Loose Parts During outage 2R13, 100% of the bobbin and rotating coil data was reviewed for possible loose part indications, Secondary Side Inspections (SSI) and Foreign Object Search and Retrieval (FOSAR) activities were also performed following sludge lancing activities in all four steam generators (SG). In accordance with the 2R1 3 Degradation Assessment (S RC-MEE-1790) and Framatomc-ANP (FANP), PSEG approved, inspection plan (FANP document 6027524A), previous (2R12) possible loose part eddy current indications identified in SG 21, 22, and 24 were planned for SSI and FOSAR. Many of the previous PLP indications from 2R12 did not confirm during 2R13 visual and/or eddy current inspections. In addition, newly identified foreign objects via FOSAR or eddy current

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040 304' ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 lRev. No: 0 l I)ate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A PERIODIC REVIEW REQUIRED: No Sheet: 17 of 23 testing were either removed (if possible) or evaluated. All SGs received post sludge lancing inner bundle SSI to determine sludge lancing effectiveness.

lAW the PSEG approved FANP QA program, condition reports are created to document the conditions found and evaluations, these FANP CRs and the associated PSEG notifications are as follows:

FANP CR#6029502, PSEG Notification 20064951, Order 70034701 FANP CR#6029474, PSEG Notification 20163949, Order 70034565 FANP CR#6029473, PSEG Notification 20163947, Order 70034564 FANP CR#6029503, PSEG Notification 20164821, Notification references order 70034564 SG 24 tube locations R39 C52 (21%TW wear, 43 degree arc, 0.14 inch axial extent), R40 C51 (30%TW wear, 64 degree arc, 0.37 inch axial extent), and R41 C50 (21%TW wear, 56 degree are, 0.26 inch axial extent); had indications of wear (PLI) and were plugged and stabilized. The wear indications on these tubes are well below the 360 degree uniform thinning CM limit of approximately 63 %TW (at a conservative axial length of 0.5 inch), in addition it was noted that these wear indications are also well below the conservative tube wall uniformly thinned limit of 49.6 %TW (S-2-RC-MDC-2002).

Therefore the structural and leakage performance criteria are met. SG 24 tube locations R40 C52, R39 C51, and R40 C50 were also preventatively plugged and stabilized 1AW evaluations referenced above.

During 2R9 two tubes in 22 SG, R45 C53 and R46 C53, exhibited indications of wear (less than 25%vTW) associated with loose part just above the CL TTS. During 2R13, these locations were preventatively plugged even though there was no change in the wear reported since 2R9.

I OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 200-40304 ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 Date: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A I PERIODIC REVIEW REQUIRED: No I Sheet: 18 of 23

7.0 CONCLUSION

S I RECOMMENDATIONS The Salem Unit 2 Steam Generators met applicable performance criteria for Operating Cycle 13 using a bounding deterministic methodology. An extremely conservative calculation of potential accident leakage was performed for axial Wextex indications, that resulted in a total worst case potential primary-to-secondary leakage of -0.170 gpm. This is well below the 1 gpm per SG limit. An estimate of potential primary-to-secondary leakage for tube plugs was found to be approximately 0.00183 gpm -

negligible -zero (assuming worst case conditions and a through-wall indication existed in the tubing).

There was no detectable primary-to-sceondary operational leakage during cycle 13, and none of the detected or estimated indications challenged the structural and leakage performance criteria.

8.0 EFFECTS ON OTHER TECHNICAL DOCUMENTS The evaluations performed in this document will be utilized for preparation of 2R1 4 Degradation Assessment.

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304.

ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rev. No: 0 bate: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A i PERIODIC REVIEW REQUIRED: No FSheet: 19 of 23 3

9.0 REFERENCES

1. NEI 97-06, Steam Generator Program Guidelines, Rev 1.
2. SC.SG-AP.ZZ-0001(Q), Steam Generator Management Program.
3. EPRI Report TR-1003138, PWR Steam Generator Examination Guidelines: Rev 6.
4. EPRI Report TR-107621-RI, Steam Generator Integrity Assessment Guidelines: Rev 1.
5. EPRI Report 1007904, Steam Generator In Situ Pressure Test Guidelines: Rev 2.
6. WCAP-14797, Revision 1, Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions
7. SC.SG-TI.RCE-O0O2 (Q), Steam Generator Tube Plug Visual Examination.
8. S-2-RC-MEE-1 673, 2R12 Steam Generator Condition Monitoring & Operational Assessment Evaluation
9. S-2-RC-MEE-1790, 2R13 Steam Generator Degradation Assessment
10. S-2-RC-MDC-2002, Steam Generator Tube Structural & Condition Monitoring Limits For Salem 2R13
11. VTD 324511, E-Mech-0710-SR-1 Report
12. VTD 326071, Steam Generator Tube Stabilization Criteria (Salem Unit 2)
13. VTD 326072, 0.875 Roll Plug Design Verification Report - Alloy 690. Framatome-ANP, Document 51-1179145-00
14. VTD 326112, 2R13 In-Situ Testing Screening Parameters. Frarnatome-ANP, Doc 51-5032554-00
15. VTD 326318, Evaluation of U-Bend Indications From Salem Unit 2 Outage 2R13
16. VTD 326355, Disposition of Boron Crusted PIPs. Westinghouse, November 2003
17. VTD 326353, In-Situ Test Summary Report for Salem Unit 2. Framatome-ANP, October 2003 10.0 Attachments
1. Summary of All 2R13 Indications Removed From Service
2. WEXTEX PWSCC Axial Indications (WCAP-14797)
3. Summary of Ligament Crack Indications

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 1 20040304 I ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 l Rev. No: e Date: 1-12-2004 TITLE: 2R13 Steam Generator C&ndltionMonitoring Evaluationl ACTION REQUEST: NI&A _ PEPIODIC REVIEW PX~tEUIRD: NoT Sheeft 20 of 23 11.0 SIGNATURES M DATE Patrick Fablan Z Preparer, PSEZ Structural Ewnglnr Vince Zaroiolsl A h k1 2-Z0 Review Checker i bAliga rinicaft1n, P= Supervisor & Structural Engineer.

Michael Ambrosino 4/

Approval, PSEG SG Supervisor

Oc o0-ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 I Rev. No: 0 l Date: 1-12-2004 w >

0 z TITLE: 2R13 Steam Generator Condition Monitoring Evaluation oz C)

ACIION REQUEST: N/A PERIODIC REVIEW REQUIRED: No Sbeet: 21 of 23 Hr

-41 C) w SALEM 2R13 Summary of Tube Degradation mr Degradation SG 2-1 SG 2-2 SG 2-3 SG 2-4 D Axial PWSCC @TSH 3 1 10 Volumetric OD Indication ©TSC 0 2 0 0 (Historical Loose Part Wear)

Loose Part w/ Tube Wea 0 0 0 3 Loose Part Preventive 0 0 0 3 K Volumetric PWSCC @TSH 1 0 0 0 IrP Circumferential PWSCC @TSH 0 0 0 0 0 LA Axial ODSCC @TSH 0 0 0 1 Volumetric OD (SVI) in TSPlFreespan 0 1 0 6 Axial ODSCC @ TSP 0 0 0 0O 0 Axial PWSCC _ TSP ° 1 0 0 A and C0rc PWSCC @ TSP T 0al -n Axial PWSCC (Low Rad Bend) 0 0 0 0 C)

Circ PWSCC (Low Rad Bend) 0 0 0 0 Axial PWSCC (High Rad Bend) 0 0 0 0 Circ PWSCC (High Rad Bend) 0 0 59 0 Preventive Plug (Ubend Stall or Ubend 0 2 9 0 Signal)

Tube Permeability Signals 5 1 0 0 Freespan Axial Anomaly 1 1 0 0

[ Total Repairable ITotal Repairable Total Repairable Total Repairable AVB Wear[ 174 _ 1 70 O 183 0 137 Cold Leg Thinning 6 1 51 2 19 6 38 TOTAL REPAIRABLE INDICATIONS 13 11 75 28 TOTALREPAIRABLETUBES 13 . - 11 62 _ _ _24 _110_l Attachment 1 Summary of AU 2R13 Indications Removed From Service

0-N0-4 CC=>

ENGINEERING EVAL. NO.: S-2-RC-MEE-1800 Rcv. No: 0 l Date: 1-12-2004 CW()

TITLE: 2R13 Steam Generator Condition Monitoring Evaluation 0-ACTION REQUEST: N/A I PERIODIC REVIEW REQUIRED: No Sheet: 22 of 23 z K:

C')

LAD rr a,

oZ cU7)

U)

SG Row Col Volts LCr UCI c LUflvh m

belo TB ON Lnt uc Wr Uwr ur W*?

m ow Uto MT' CAind Kit Stisfiedi Rate Tot Leak ITS Rate 21 2 20 033 -229 -2.17 0.12 Yes B4 7.12 -0.22 1.67 No Yes Yes -9.38 Yes 0.007

-_4 21 6 70 0.46 -0.73 -0.64 0.09 Yes B3 7.12 -0.29 0.07 No Yes Yes -9.44 Yes 0.043 21 15 27 1.26 -9.88 -9.74 0.14 Yes B3 7.12 -0.49 8.97 Yes Yes Yes -10.15 Yes 0.000 m TOT . _ _ _ . _ 0.050 22 25 72 0.46 -1.53 -1.44 0.09 Yes A 5.32 .0.32 0.84 No Yes Yes -8.57 Yes 0.015 0.015 z m

23 25 61 0.63 -8.4 -83 0.18 Yes 134 7.12 -0.24 7.78 Yes Yes Yes -10.44 Yes 0.000 0.000 rn 091 24 3 51 034 -0.97 -0.86 0.11 Yes RI 7.12 -0.22 0.36 No Yes Yes -9.43 Yes 0.031 9

24 9 36 0.4 -1.37 -1.25 0.12 Yes BR 7.12 -0.38 0.59 No Yes Yes -10.00 Yes 0.025 C) 0I 24 14 17 0.53 -0.47 -0.31 0.16 Yes A 5.32 -0.27 -0.24 No No No -9.56 Yes 0.000 C-)

0~

24 14 41 03 -1.06 -0.95 0.11 Yes B2 7.12 -0.42 0.25 No Yes Yes -9.96 Yes 0.035 0a 24 20 35 0.15 -2.02 -1.91 0.11 Yes B3 7.12 -0.31 1.32 No YEs Yes -933 Yes 0.014 O 24 24 52 08 -0.21 -0.13 0.08 Yes B3 7.12 -0.21 .0.36 No l No No -9.10 Yes 0.000 24 31 52 0.42 -0.32 -0.23 0.09 Yes A 532 -0.39 -0.44 No No No -933 Yes 0.000 l 24 31 54 0.57 -0A.1 -0.29 0.12 Yes A 5.32 -0.25 -0.24 No No No -9.24 Yes 0.000 24 31 58 0.47 -032 -0.21 0.11 Yes A 5.32 -0.34 l0.41 No No No -9.13 Yes 0.000 24 33 44 0.37 -0.51 -0.34 0.17 Yes A 5.32 -0.47 -0.41 No No No -. 84 Yes 0.0001 TOT I I I _ _ _ __l_0.105 Attachment 2 PWSCC in the VEXTEX

OUTSTANDJNG CHANGES MUST BE ATTACHED FOR WORKING COPY Inr)ArVAAn

{w ----- -

ENGINE ERING EVAL. NO.: S-2-RC-MEE-1800 _l Rev. No: 0 l Date: 1-12-2004 TITLE: 2R13 Steam Generator Condition Monitoring Evaluation ACTION REQUEST: N/A l PERIODIC REVIEW REQUIRED: No I Sheet: 23 of23 S RO O N V 2R12 2R13 Cmet ROGO I D T P SIZING SIZING C m et 21 14 6 SLC 0BH SINGLE New 21 20 53 SLC 05H SINGLE SINGLE 21 31 79 SLC 06H SINGLE SINGLE 21 35 54 SLC 03H SINGLE NA NDD 21 36 40 SLC 06H SINGLE SINGLE 21 37 40 SLC 05H SINGLE SINGLE 21 37 40 SLC 06H SINGLE SINGLE 21 42 34 SLC 06H SINGLE SINGLE 21 42 36 SLC OBH SINGLE SINGLE 21 43 40 SLC 06H SINGLE SINGLE 21 45 41 SLC 06H DOUBLE SINGLE_

22 37 54 SLC 03H SINGLE SINGLE 22 41 54 SLC 03H SINGLE SINGLE 23 3 56 SLC 060 46 DEG 55 DEG 23 6 27 SLC 04H 46 DEG 47 DEG 23 9 40 SLC 060 47 DEG 46 DEG SLC 02H 51 DEG 56 DEG 23 9 65 SLO 03H 82 DEG 116 DEG 23 14 37 SLC 04H 37 DEG 32 DEG 23 14 38 SLC 04H 54 DEG 56 DEG 23 14 57 SLC 05C BI DEG 58 DEG 23 17 27 SLC 04H 64 DEG 70 DEG SLC 01H 51 DEG 43 DEG 23 22 7 SLC 07H 111 DEG 104 DEG 23 25 87 SLC 07C SINGLE SINGLE 3 SLC 01C 40 DEG 50 DEG 23 29 81 SLC 07C 71 DEG 64 DEG 23 39 56 SLC 07H SINGLE SINGLE 23 42 59 SLC 04H SINGLE SINGLE 23 45 54 SLC 07H SINGLE SINGLE 23 46 54 SLC 07H SINGLE SINGLE 24 20 29 SLC 07C SINGLE SINGLE 24 26 9 SLC 05C 31 DEG SINGLE 24 34 46 SLC 02C SINGLE SINGLE 24 41 39 SLC 02C SINGLE SINGLE 24 45 41 SLC 07H SINGLE SINGLE 24 45 57 SLC 011H 32DEG 32DEG 24 46 41 SLC 01H 29DEG SINGLE SLC 07H SINGLE SINGLE 24 46 54 SLC 07H DOUBLE DOUBLE Attachment 3 Summary of Ligament Crack Indications

OUTSTANDING CHANGES MUST BE ATTACHED FOR WORKING COPY 20040304' NC.CC-AP.ZZ-001 0(Q)

FORM-1 (Page 2 of 3)

CERTIFICATION FOR DESIGN VERIFICATION (SAP Standard Text Key "NRICDVI")

Reference No. R& ioSeaAd o rtd L -

SUMMARY

STATEMENT

SUMMARY

STATEMENT The referenced evaluation was reviewed line-by-line by the peer reviewer/independent design reviewer. The methodologies were examined and found to be In accordance the standards required by the EPRI Steam Generator Degradation Specific Management Flaw Handbook, (EPRI Report 1001191) and the Steam Generator Integrity Assessment Guidelines, Rev I (EPRI Report TR-107621-RI). Calculations were checked for mathematical accuracy and found to be correct. No comments were Provided.

The individual named below in the right column hereby certifies that the design verification for the subject document has been completed, the questions from the generic checklist have been reviewed and addressed as appropriate, and all comments have been adequately incorporated. SAP Order/Operation final confirmations are the legal equivalent of signatures. - ^ I Design Verifier Assigned By Nam~of pesIgn Verifier / Date (print name of Manager/Director)

Design Verifier Assigned By Name of Design Verifier I Date (print name of Manager/DIrector)

Design Verifier Assigned By Name of Design Verifier I Date (print name of Manager/Director)

Design Verifier Assigned By Name of Design Verifier / Date (print name of Manager/Director)

VIf the Manager/Supervisor acts as the Design Verifier, the name of the next higher level of technical management Is required hI the left column.

Nuclear Common Page 23 of 27 Rev. I

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