L-PI-10-051, Revision to Inservice Inspection Summary Report, Interval 4, Period 1, Refueling Outage Dates: 04-28-2006 to 06-06-2006 Fuel Cycle 23: 11-23-2004 to 06-06-2006 and Revision to 2008 Unit 1 180-Day Steam Generator Tube Inspection Report

Revision to Inservice Inspection Summary Report, Interval 4, Period 1, Refueling Outage Dates: 04-28-2006 to 06-06-2006 Fuel Cycle 23: 11-23-2004 to 06-06-2006 and Revision to 2008 Unit 1 180-Day Steam Generator Tube Inspection Report

ML101530111
Person / Time
Site:	Prairie Island
Issue date:	06/01/2010
From:	Schimmel M Northern States Power Co, Xcel Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-PI-10-051
Download: ML101530111 (27)

Text

a Xcel Energya JUN 0 1 2UtO US Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Unit 1 Docket 50-282 License No. DPR-42 Revision to lnservice lnspection Summary Report, Interval 4, Period 1, Refueling Outacre Dates: 04-28-2006 to 06-06-2006 Fuel Cycle 23: 11-23-2004 to 06-06-2006 and Revision to 2008 Unit 1 180-Dav Steam Generator Tube lns~ectionRe~ort

Reference:

1) Letter from Nuclear Management Company, LLC (NMC) to NRC, "Unit Ilnservice lnspection Summary Report, Interval 4, Period 1, Refueling Outage Dates: 04-28-2006 to 06-06-2006, Fuel Cycle 23: 11-23-2004 to 06-06-2006," dated September 01, 2006 (ADAMS Accession Number ML062550530).

2) Letter from NMC to NRC, "2008 Unit 1 180-Day Steam Generator Tube lnspection Report," dated September 08, 2008 (ADAMS Accession Number ML082520615).

In Reference 1, NMC' submitted the lnservice lnspection Summary Report associated with the Prairie Island Nuclear Generating Plant (PINGP) Unit 1 refueling outage 1R24.

In Reference 2, NMC submitted the 180-Day Steam Generator Tube lnspection Report associated with PINGP Unit 1 refueling outage 1R25.

Northern States Power Company, a Minnesota corporation (NSPM), doing business as Xcel Energy, has subsequently determined that due to an error in the Unit 1 steam generator eddy current calibration standard drawing, depth estimates of some service induced indications were incorrectly reported. Tables containing updated information are provided in the enclosures.

' On September 22, 2008, NMC transferred its operating authority to Northern States Power Company, a Minnesota Corporation (NSPM), a wholly owned subsidiary of Xcel Energy. By letter dated September 3, 2008, NSPM assumed responsibility for actions and commitments previously submitted by NMC.

1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1 121

Regional Administrator, Region Ill Page 2 includes a revised Section 7 for the IR24 Inservice Inspection Summary Report (Reference 1). Revisions are found on pages 3 and 4. Enclosure 2 includes a revised 180-Day Steam Generator Tube Inspection Report (Reference 2) for PlNGP Unit 1, refueling outage 1R25. Revisions are found on pages 1, 13, and 15. All revisions to these documents are denoted with side bars.

Summarv of Commitments This letter contains no new commitments and no revisions to existing commitments.

Mark P(. Schimmel Site Vice President, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota Enclosures (2) cc: Administrator, Region Ill, USNRC Project Manager, Prairie Island, USNRC Resident Inspector, Prairie Island, USNRC

ENCLOSURE 1 REVISED STEAM GENERATOR EDDY CURRENT EXAMINATION RESULTS SECTION 7 TO INSERVICE INSPECTION

SUMMARY

REPORT INTERVAL 4, PERIOD I REFUELING OUTAGE DATES: 04-28-2006 TO 06-06-2006 FUEL CYCLE 23: 11-23-2004 TO 06-06-2006 5 pages follow

Section 7. Steam Generator Eddy Current Examination Results Technical Specification 5.6.7.2 requires the results of steam generator tube in-service inspections shall be included with the summary reports of ASME Code Section XI inspections submitted within 90 days of the end of each refueling outage. The report Shall include:

1. number and extent of tubes inspected,

2. location and extent of wall-thickness penetration for each indication of an imperfection, and

3. identification of tubes plugged or sleeved.

Table I provides the number (as a percentage) and extent of tubes inspected.

Table II provides the location and extent of wall-thickness penetration for each indication of an imperfection.

Table Ill provides the identification of tubes plugged or sleeved.

TABLE l Number and Extent of Tubes Inspected SCOPE PROBE TYPE SIG 11 SIG 12 Full Length Bobbin 100% 100%

I SupplementalO MRPC 100% 100%

O Supplemental MRPC testing was based on both baseline and current results: Inspected all I

baseline GMD, PVN, SVI, and percent calls. Inspect all current BLG 2 1.O, CUD, DEP, DNG 2 1.O, DNI, DSI, DTI, INR > 1.5 V @ TSP's, MBM, NQI, OXP, PDS, PLP, and percent calls.

Section 7. Steam Generator Eddy Current Examination Results

TABLE II Location and Extent of Wall-thickness Penetration for Each Indication of an Imperfection Section 7. Steam Generator Eddy Current Examination Results Page 2

Section 7. Steam Generator Eddy Current Examination Results Page 3 i '4s7i.:

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TABLE Ill Identification of Tubes Plugged or Sleeved Section 7. Steam Generator Eddy Current Examination Results Page 4

LEGEND OF FIELDS AND CODES

-

FIELD NO.

EXPLANATION Cumulative number per table per SIG SIG Steam Generator Number (I Ior 12)

LEG Channel head tested from (H = inlet & C = outlet)

ROW Row number of tube location COL Column number of tube location PERCENT Measured percent or through wall LOCATION Physical Location of lndication - see below ELEV FROM Measurement in inches from the LOCATION to the indication STATUS Repair status - see below

-

CODE EXPLANATION PERCENT BLG Bulge CUD Copper Deposit DEP Deposit DNG Ding DNI Ding with lndication DSI Distorted Support Signal with lndication DTI Distorted Tube Sheet Signal with lndication GMD Geometric Distortion INR lndication Not Reportable MBM Manufacturing Burnish Mark NQI Non Quantifiable lndication OXP Over-Expansion PDS Pilger Drift Signal PLP Possible Loose Part PVN Possible Support lndication SVI Single Volumetric lndication 0-100 As measured percent through wall LOCATION TEH Tube end hot (primary face)

TS H Tube sheet hot (secondary face)

O?H  ? = First through Eigth tube support plate on hot leg side AV?  ? = First through Ninth antivibration bar O?C  ? = First through Eigth tube support plate on cold leg side TSC Tube sheet cold (secondary face)

TEC Tube end cold (primary face)

STATUS <TS Less Than the Technical Specification repair limit PLG Tube Plugged Section 7. Steam Generator Eddy Current Examination Results Page 5

ENCLOSURE 2 Prairie Island Nuclear Generating Plant - Unit 1 2008 Steam Generator Tube Inspection Report Revised-Northern States Power Company, a Minnesota corporation (NSPM), doing business as Xcel Energy submits this corrected report of steam generator tube inspections performed during the 2008 refueling and maintenance outage on Unit 1 (1R25).

PlNGP Unit 1 has two Framatome Model 56/19 Replacement Steam Generators (RSGs) with approximately 5,600 square meters of heat transfer area utilizing tubes with 19 millimeter outside diameter. Each RSG has 4,868 thermally-treated Alloy 690 u-tubes manufactured by Sandvik which have an outside diameter of 0.750 inch and a nominal wall thickness of 0.043 inch. The tubes are configured in a square pitch of 1.0425 inches with 55 rows and 114 columns. The tube u-bends vary in radius from 2.7000 inches for a row 1 tube to 58.9950 inches for a row 55 tube. The tubes vary in length from 738.16 inches for row 1 tubes to 923.94 inches for row 55 tubes. Row 1 through row 9 tubes were subject to stress relieving following the bending process using the thermal treatment process for an additional 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> minimum soak time. The tubes were hydraulically expanded at each end for the full depth of the tubesheet with the expansion transition being between 0.08 inches and 0.24 inches below the secondary tubesheet face.

The tubesheet is low alloy steel 21.46 inches thick with alloys 82 and 182 cladding 0.375" thick for an overall thickness of 21.835 inches. The tubes are supported by eight tube support plates (TSPs) and five anti-vibration bars (AVBs) intersecting tubes between 1, 3, 5, 7 and 9 times (see Figure 1). There is one straight bar that intersects all rows at the center of each bend, two 57 degree bars that intersect rows 13 through 55 and two 14 degree bars that intersect rows 25 through 55. In addition there are 24 peripheral tubes with nine staples (one at each AVB location) that carry the entire load of the complete AVB assembly. All TSPs are constructed from Type 410 stainless steel. The TSPs have a minimum thickness of 1.I81 inch and have quatrefoil-shaped holes through which the tubes pass. The AVBs are constructed from Type 405 stainless steel and are rectangular in cross section (0.5 inch by 0.3 inch).

Each RSG is equipped with a Loose Parts Trapping Systems (LPTS), which is composed of screens at the top of the downcomer and at the top of the primary (cyclone) separators. These screens (0.14" square mesh formed from 0.031" diameter wire), prevent foreign material from entering the steam generator tube area from the main feedwater and auxiliary feedwater systems (see Figure 1).

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loose Parts Trapping Systems

- , ANTI-VIBRATION

~ BAR Figure 1 The original Westinghouse Model 51 Steam Generators (SGs) were replaced during the 2004 refueling outage after 25.75 EFPY of operation. During the 2006 refueling outage the first inservice inspection (100% full length bobbin) was conducted on the RSGs after accumulating the initial 1.36 EFPY of RSG operation. Based on the lack of a definitive root cause for TSP wear and only a single cycle growth rate trend for both AVB and TSP wear identified during 1R24, the NMC conservatively elected to inspect the RSGs during 1R25 after an additional 1.62 EFPY of RSG operation (2.98 RSG cumulative EFPY).

Italicized text represents technical specification excerpts. Each excerpt is followed by the appropriate information intended to address each specific requirement and also includes additional details based on benchmarking recent submittals and Staff requests for additional information of peer Licensees. A legend of codes and field names is included at the end of the report.

5.6.7 Steam Generator Tube Inspection Report

a. A report shall be submitted within 180 days after initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.8, Steam Generator (SG) Program.

Initial entry into MODE 4 occurred on March 13, 2008, dictating submittal of this report on or before September 9, 2008.

The report shall include:

1. The scope of inspections performed on each SG, Table 1 and the text that follows, provides the scope of inspections performed during 1R25.

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TABLE 1 number of tests parenthetically where practical.

O Supplemental MRPC" testing (including the +point" coil) was based on bobbin results to: 1) inspect all BLG, DNG, DNI, MBM, NQI, OXP and PDS signals for latent tube degradation, and 2) inspect all percent through wall calls to refute/confirm, characterize (axial, circumferential or volumetric) and/or measure the length of wear indications.

Notes:

For clarity, only three digit codes that require supplemental MRPC@testing and

>

utilized during 1R25 are included in O above. BLG is called at 1.0 Volt outside the tubesheets and 1 15.0 Volts inside the tubesheets, DNG is called at 2 1.0 Volt, and all the other codes above (DNI, MBM, NQI, OXP and PDS) do not have a voltage calling criteria. The 1.0 Volt DNG calling criteria was established at half the industry standardized 2 Volt calling criteria because all ding signals greater than 2 Volts were rejected in the tubing mill and we elected to establish a sample of dings to track and detect incipient degradation.

O Inspection of upper internals included the Feed Ring, J-tubes, Feedwater Ring Helix, Moisture Separators, Downcomer, LPTS and other upper bundle components per NRC Generic Letter 97-06 and Prairie Island Unit 1 56/19 Replacement Steam Generator Operation and Maintenance Manual.

O Tube lane and periphery of the tube bundle inspected using Camera Transporter System.

(3 Random fiber-optic inspection of one out of every six columns.

O Locating possible loose part (PLP) indications for investigation and possible removal based on eddy current results (not necessary).

2. Active degradation found, Primaw Side Inspections - TSP wear and AVB wear were found in both SGs during 1R25 and captured within the corrective action process. There was no significant change in either the number of new TSP and AVB indications or in the number of tubes with new TSP and AVB indications. The Operational Assessment of indication growth rates, showed that the percent through-wall per effective full power year

(%TW/EFPY) decreased for both TSP and AVB wear in both steam generators as compared to 1R24 results.

Secondary Side Inspections - The upper bundle inspection found part of the feedwater ring inspection port gasket on the Downcomer LPTS and loose bolts on the inspection ports in the 12 Steam Generator. Also there were areas of a thin layer of debris on I 1 and 12 Steam Generator Downcomer LPTS. However an anticipated missing part from 11 Steam Generator Feedwater Regulating Valve (part of an elastomer ring) was not found. The top of tubesheet and in bundle inspection found no loose parts or degraded components in 11 Steam Generator. All secondary side issues were entered into the corrective action process.

3. Nondestructive examination techniques utilized for each degradation mechanism, Table 2 and the text that follows, provides the Electric Power Research Institute (EPRI) Examination Technique Specification Sheet (ETSS) (techniques) utilized during IR25 for active, potential, non-degradation and unexpected degradation.

TABLE 2 CLASSlFlCATlONO MECHANISM LOCATION TECHNIQUEO Active Wear AVB 96004.1 Rev. 11 Active Wear TSP 96004.1 Rev. 1I Potential Wear Staple 96004.1 Rev. 11 Potential Wear PLP 27091.2 Rev. 0 O Active is synonymous with the term "existing" degradation that is found in the EPRI Steam Generator Integrity Assessment Guidelines. Therefore the classical definition applies (i.e., one indication equates to active).

O In addition: 1) Bobbin ETSS's 96010.1 Rev. 7, 24013.1 Rev. 2, and 96007.1 Rev.

11 were site validated for use on non-degradation (MBMs, DNGs, PDS and cold laps), 2) Bobbin ETSS1s96005.2 Rev. 9, 96001. I Rev. 11 and 96007.1 Rev. 11 were site validated for unexpected pitting, wastage and outside diameter stress corrosion cracking (ODSCC) degradation, 3) +pointB ETSS's 96910.1 Rev. 10 was site validated as an alternate wear sizing technique and 4) +pointB ETSS's 21409.1 Rev. 5, 21410.1 Rev. 6, 20510.1 Rev. 7, 2051 1. I Rev. 8 and 96511.2 Rev. 16 were site validated for unexpected ODSCC and primary water stress corrosion cracking (PWSCC) degradation.

4. Location, orientation (if linear), and measured sizes (if available) of service induced indications, Tables 3, 4, 5 and 6 provide the location, orientation and measured size of each reported TSP wear indication and each reported AVB wear indication in each steam generator respectively for the two active degradation mechanisms found during 1R25. All the tubes in these four tables were returned to service.

Tables 7 and 8 provide the location, orientation and measured sizes of AVB wear indications in each steam generator respectively for tubes plugged during 1R25. The Page 4 of 19

AVB wear plugging criteria for IR25 was lowered to greater than 10% through-wall to establish a 4.54 EFPY inspection cycle.

Within Tables 3 through 8, tubes reported with multiple VOL calls at the same ROW/COL/LOCATION confirm indications of double sided AVB wear or multiple wear location sites on multiple land contact points of Quatrefoil TSPs. Conversely, single VOL calls confirm single sided wear sites at AVB and TSP locations. One tube (R55C57) in Table 4 is reported with two bobbin coil percent through wall indications (one at each TSP edge) which was confirmed as a single TSP contact point wear scar spanning the length of the TSP.

A legend of fields and codes with brief explanations is provided at the end of this enclosure for clarification purposes.

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Page 7 of 19 Page 8 of 19 I 67 1 95 1 44 ( 88 1 0.12 1 VOL ( 04H ( -0.79 1 -0.44 / 0.35 1 TABLE 4 Steam Generator 12 TSP Wear 17 22 55 60 0.15 12 02C 0.56 17 22 55 60 0.23 VOL 02C

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-0.60 0.65 1.25 Page 10 of 19

TABLE 5 Steam Generator 11 AVB Wear 8 12 50 65 0.2 VOL AV6 -0.22 0.31 0.53 8 13 50 65 0.2 6 AV7 -0.03 8 13 50 65 0.3 VOL AV7 -0.27 0.27 0.54 9 14 41 66 0.3 9 AV4 0.13 9 14 41 66 0.3 VOL AV4 -0.24 0.31 0.55 9 15 41 66 0.3 9 AV7 0.00 9 15 41 66 0.4 VOL AV7 -0.27 0.24 0.51 9 16 41 66 0.2 7 AV9 0.00 9 16 41 66 0.3 VOL AV9 -0.24 0.18 0.42 Page 120f 19

Page 13of 19 Page 140f 19 TABLE 6 Steam Generator 12 AVB Wear Page 15 of 19

TABLE 7 Page 16 of 19

Page 17 of 19

5. Number of tubes plugged or repaired during the inspection outage for each active degradation mechanism, Table 9 provides the number of tubes plugged during 1R25.

TABLE 9 I MECHANISM (

AVB Wear SG 11 3

1 SG 12 3

I TSP Wear 0 0

6. Total number and percentage of tubes plugged or repaired to date, Table 10 provides the total number and percentage of tubes plugged to date.

TABLE 10 PLUGGING SG 11 SG 12 TOTAL 3 6 PERCENT 0.06% 0.12%

7. The results of condition monitoring, including the results of tube pulls and in-situ testing, Condition monitoring structural and leakage integrity requirements have been demonstrated for SG tube degradation observed after the second cycle of operation of RSGs at Prairie Island Unit 1 without a need for tube pulls or in-situ testing. The degradation of interest is wear scars at AVB and TSP locations. The progression of wear at the AVB locations is limiting. A conservative operational assessment approach shows that inspection is only required after two cycles of operation without any tube plugging. With the largest wear scar left in service at an AVB location reduced to a maximum NDE depth of 10% through-wall, inspection is only required after three cycles of operation.

8. The effective plugging percentage for all plugging and tube repairs in each SG, There have been no repairs performed on these SGs; therefore the effective plugging percentage is equivalent to that reported in Table 10.

9. Repair method utilized and the number of tubes repaired by each repair method, and There have been no repairs performed on these SGs.

10. The results of inspections performed under Specification 5.5.8.d.3 for all tubes that have flaws below the F* or EF* distance, and were not plugged. The report shall include: a) identification of F* and EF* tubes, and b) location and extent of degradation.

Specification 5.5.8.d.3 is not applicable to Unit 1 Page 18 of 19

LEGEND OF FIELDS AND CODES FIELD EXPLANATION TUBE # Distinct ROWICOL combination within each Table IND # Distinct ROWICOULOCATION combination within each Table ROW Row number of tube location COL Column number of tube location VOLTS Measured Voltage PCT Measured percent or three digit code - see below LOCATION Affected landmark - see below ELEV-FROM Measurement in inches from the centerline of the landmark to the center of the bobbin coil indication or the lower edge of the rotating coil indication ELEV-TO Measurement in inches from the centerline of the landmark to the upper edge of the rotating coil indication LENGTH Calculated Length (ELEV-FROM - ELEV-TO)

FIELD CODE EXPLANATION PERCENT BLG Bulge Signal - Bobbin Coil DNG Ding Signal - Bobbin Coil DNI Ding with an lndication - Bobbin Coil MBM -

Manufacturing Burnish Mark Bobbin Coil NQI Non-Quantifiable lndication - Bobbin Coil OXP Over-Expansion Signal - Bobbin Coil PDS Pilger Drift Signal - Bobbin Coil VOL Volumetric lndication - MRPC@

0-100 As measured percent through wall - Bobbin Coil LOCATION TEH Tube end hot (primary face)

TSH Tube sheet hot (secondary face)

O?H  ? = First through Eighth tube support plate on hot leg side AV?  ? = First through Ninth anti-vibration bar O?C  ? = First through Eighth tube support plate on cold leg side TSC Tube sheet cold (secondary face)

TEC Tube end cold (primary face)

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