ML070650263

Annual Steam Generator Inservice Inspection Summary Report

ML070650263
Person / Time
Site:	Surry
Issue date:	03/01/2007
From:	Funderburk C Dominion, Dominion Resources Services
To:	Document Control Desk, Office of Nuclear Reactor Regulation
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ML070650263	List: ML070650263
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07-0099
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k Dominion Resources Services, Inc.

5000 Dominion Boulevard, Glen Allen, VA 2 i O ( 4 1 Dominion" Wb Address: www.dom.com March 1, 2007 United States Nuclear Regulatory Commission Serial No. 07-0099 Attention: Document Control Desk NLOSIvlh Washington, D. C. 20555-0001 Docket Nos. 50-280 50-281 License Nos. DPR-32 DPR-37 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2 2006 ANNUAL STEAM GENERATOR INSERVICE INSPECTION

SUMMARY

REPORT Pursuant to Technical Specification 4.19.F.b for Surry Power Station Units 1 and 2, Dominion is required to submit an Annual Steam Generator lnservice lnspection Summary Report to the NRC. Enclosures 1 and 2 to this letter provide the 2006 annual steam generator inspection reports for Surry Units 1 and 2, respectively.

This letter does not establish any new commitments. Should you have any questions or require additional information, please contact Mr. Gary D. Miller at (804) 273-2771 .

Very truly yours, C. L. ~underburk,Director Nuclear Licensing and Operations Support Dominion Resources Services, Inc.

for Virginia Electric and Power Company

Enclosures:

1. 2006 Annual Steam Generator lnservice lnspection Report - Surry Unit 1

2. 2006 Annual Steam Generator lnservice lnspection Report - Surry Unit 2

Serial No. 07-0099 Docket Nos. 50-280 and 281 Page 2 of 2 cc: U. S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, S.W.

Suite 23T85 Atlanta, GA 30303-8931 Mr. S. P. Lingarn U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Rockville, MD 20852 Mr. L. N. Olshan U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Rockville, MD 20852 Mr. N. P. Garrett NRC Senior Resident Inspector Surry Power Station

Serial No. 07-0099 Docket No. 50-280 ENCLOSURE 1 2006 Annual Steam Generator Inservice Inspection Report Surry Unit 1 Virginia Electric and Power Company (Dominion)

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Virginia Electric and Power Company (Dominion)

Surry Unit 1 Annual Steam Generator Report Summary Data Station Unit I Outage Date I Generator Examined I Date of Report Surry 1 April, 2006 I A l I C I February 25,2007 SG Design Information I SG Model TSP Type. TSP Mat'l # TSP Baffle Mat'l AVB Mat'l # AVB 5 1F Quatrefoil Type 405 SS 7 Type 405 SS Chrome Plated 2 Alloy-600

1. Tubes Tube Dia. Tube Mat'l Tube Pitch Tube Tks Expansion Heat X-fer Area 3342 0.875" Alloy 600TT 1.281" 0.050" Full Hydraulic 51,500 sq. ft.

Scope of Inspection SG Inspection Program Planned Inspected Inspection Method Extent A 100 % Bobbin 3326 3326 Bobbin TSH- TSC, Except Row 1 U-bends A 100%RowlU-BendRC 88 88 +Point U-Bend RC 7H - 7C A TTS Hot leg" NTE RC 2 2 + Point RC TEH-TSH +3" A I TTS Hot leg RC 669 669 + Point RC TSH +I- 3" 1 A Special Interest RC Exams 230 + Point RC Various A RC Scope Expansion, Hot 669 + Point RC TSH +I- 3" Leg and Cold Leg 669 TSC +I-3" C 100 % Bobbin Bobbin TSH- TSC, Except Row 3325 3325 1 U-bends-C 100% Row 1 U-Bend RC 90 90 +Point U-Bend RC 7H - 7C C TTS Hot leg NTEWTE RC 7 7 + Point RC TEH - TSH +3" C TTS Hot leg RC 669 669 + Point RC TSH +I- 3" C S~ecialInterest RC Exams 145 + Point RC Various 2006 Inspection Tube Plugging Summary SG Reason/Mechanism Tubes Plugged A Foreign Object Wear 6 A Permeability Variation 7 C Point Contact Wear at AVB Apex 1 C Foreign Object Wear 2 Total Tubes Plugged 16 2006 Inspection Plugging Attributions SG Row Column Reason/Mechanism Plugging Method A 10 24 PVN @ 2C-20.57 to -23.15 Mechanical A 3 27 PVN @ 6H-25.99 to 35.48 Mechanical A 36 49 VOL @ TSH-0.01 I Mechanical I A 1 3 6 1 50 VOL @ TSH+O.O Mechanical A 32 51 PVN @ 4H-22.43 to -26.08 Mechanical A 19 55 A 35 68 Page 2

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 A 36 68 VOL @ TSH+0.13 Mechanical A 35 69 VOL @ TSH+O.17 Mechanical A 6 71 PVN @ 2H+22.43 Mechanical A 14 73 PVN @ 3C+15.49 to 25.67 Mechanical A 4 82 PVN @ 3C+12.58 Mechanical A 5 88 VOL @ TSH+O.16 Mechanical C 11 37 VOL @ AV2lAV3 Mechanical C 15 62 VOL @ 3H-0.59 Mechanical C 38 62 VOL @ 1H-0.35" Mechanical Plugging/Repair Record SG Tubes Tubes Repaired Percent Percent Repaired Percent Plugged Average Plugging Plugged (Not Plugged) Plugged (Not Plugged) or Repaired (See Note 1)

A 29 0 0.87 0 0.87 Note 1: As described in the safety evaluation and plant LOCA analyses, steam generators are restricted to an equivalent plugging limit of 15% average and 15% in any one steam generator with no greater than a 5% differential between any two steam generators expressed in number of tubes per generator.

Page 3

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 TUBE INTEGRITY ASSESSMENT

SUMMARY

1.0 Evaluation Summary Overall condition assessments have been delineated in the Steam Generator (SG) Monitoring and lnspection Plan (Reference 1) and are consistent with the requirements of NEI 97-06 (Reference 11). A Pre-Outage Assessment (Reference 2) was performed to identify any relevant condition to be considered for the Surry Unit 1 steam generators that had not been included in Reference 1. The assessment also identified the appropriate eddy current inspection scope, probes to be utilized during the subject inspection, and appropriate detection and sizing information for mechanisms considered relevant for the proposed inspection scope.

As required by NEI 97-06, Performance Criteria are established in three areas:

+ Structural Integrity - Margin of 3.0 against burst under normal steady state power operation and a margin of 1.4 against burst under the most limiting design basis accident. Additional requirements are specified for non-pressure accident loads.

+ Operational Leakage - RCS operational primary-to-secondary leakage through one steam generator shall not exceed 150 gpd.

+ Accident Induced Leakage - Leakage shall not exceed 1 gpm per steam generator during Main Steam Line Break (MSLB).

The inspections performed were consistent with the previously referenced Monitoring and lnspection Plan and Revision 6 of the EPRl SG Examination Guidelines. Two independent analysis paths evaluated the acquired eddy current data: manual primary analysis and computerized data screening (CDS) secondary analysis. A third team of analysts resolved any discrepancies between the two analyst teams. The Dominion Eddy Current Level Ill performed oversight evaluations as the Independent Qualified Data Analyst (IQDA), a role defined within the EPRl SG Examination Guidelines.

The Surry Site Specific Guidelines (Reference 4) served as the primary guidance document for data evaluation. As with past practice, Surry-specific examination technique summary sheets (ETSS) were used in conjunction with Reference 4 to summarize instructions relative to acquisition and analysis setups and analysis screening parameters.

A condition monitoring evaluation of the steam generator tube bundles was performed to verify that the condition of the tubes, as reflected in the inspection results, is in compliance with the plant licensing basis and meets the stated performance criteria. Structurally significant indications were evaluated to confirm that the safety margins against leakage and burst were not exceeded at the end of this operating cycle. The results of the condition monitoring evaluation were used as a basis for the operational assessment which demonstrates prospectively that the anticipated performance of the steam generators will likewise not exceed the performance criteria margins against leakage and tube burst during the ensuing operating period.

An operational assessment evaluation was performed to determine if tube structural or leakage integrity would be challenged prior to the next scheduled inspection of the subject steam generator. In addition, an assessment was made to verify the structural and leakage integrity of Page 4

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 the un-inspected steam generators until their next planned inspection based on current inspection findings. This report summarizes the condition monitoring and operational assessment of the tube inspection results from the Surry Unit 1 "A" and "C" steam generators. It conforms to the March 2000 EPRl Steam Generator Integrity Assessment Guidelines (Reference 6) and the requirements of NEI 97-06.

2.0 Condition Monitoring Assessment This condition monitoring assessment evaluated structural and leakage integrity based on current inspection results. The condition of the Surry Unit 1 steam generators, as indicated by the results of the inspections performed on the "A" and "C" steam generators, satisfy required structural and leakage integrity criteria. A discussion of the inspection results and the evaluations performed is provided in the following sections.

2.1 Primary Side Inspection 2.1 .I Bobbin Program Anti-Vibration Bar (AVB) Wear Indications A total of 46 AVB wear indications in 34 tubes were identified in steam generators "A" and "C" (Table 2). None of the flaws included in the table exceeded the Technical Specification plugging limit (40 %TW). The maximum indicated depth (27 %TW) was reported in tube SGC R11 C37, which was preventatively plugged as discussed in Section 3.

The appropriate non-destructive examination (NDE) technique performance data for the bobbin probe for detection and sizing of AVB wear is based on the EPRl NDE technique ETSS 96004.1. Reference 2 summarizes the NDE sizing uncertainty parameters for ETSS 96004.1 and they are repeated in Table 2 for convenience. The total random sizing uncertainty of 10.7 % throughwall (TW) was applied to the adjusted 2006 depth estimates to obtain upper bound estimates of 2006 flaw depth. This value is compared directly with the structural limit for AVB wear (64 %TW for rows 9 to II , 69.4 %TW for rows 12 to 46). As shown in Table 2, the largest 2006 upper limit depth (40 %TW) is well below the minimum structural limit of 64 %TW.

In addition to the pressure loads upon which the above structural limits are based, the CM must also consider the impact of non-pressure accident loads if they could have a significant effect on the burst pressure of the degraded tubes. A review of the screening guidance of Reference 13 provides the basis for concluding that non-pressure accident loads are not limiting for AVB wear. It indicates that non-pressure loads will not significantly affect the burst pressure of U-bend support bar wear. Hence, the structural performance criterion was not exceeded by AVB wear identified during the current inspection.

The average growth rate in the " A and "C" steam generators since the last inspection was 2.39 %TW/Cycle and 0.85 %TW/Cycle, respectively. As with prior growth information, this value is based on the process in which negative values of depth change (i.e., the more recent indication depth is smaller than the previous depth) are set equal to zero in the calculation of average growth. The growth rate continues its decreasing trend as has been historically observed at Surry. The average growth of all historical Unit 1 AVB wear for which growth information is available, including spring 2006 SG " A and "C" data, is 2.31 %TW/Cycle; reduced from 2.44 %TW/Cycle reported following the spring 2003 SG examination.

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Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Eighteen AVB wear indications reported during this inspection were not reported during the previous (2001) inspection of SG " A . However, a review of historical data confirmed that the indications were present; however, none had changed significantly since that inspection. All AVB wear reported in SG "C" had been reported during the previous inspection (2000) except for SGC R11 C37 discussed above. For growth determination purposes, it was assumed that the newly reported wear did not exist at the time of the previous inspection. Table 1 summarizes AVB wear growth rates for each Unit 1 SG and for all Unit 1 SGs combined.

Table 1 - Surry Unit 1 AVB Statistical Summary Updated with 2006 Data a) Steam Generator 'A" Number of Tubes with AVB Wear Indications to Date 35 Average Wear Rate 2.14%TWD I Cycle Number of Data Points 74 Standard Deviation 1.96% TWD I Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 4.64%TWD I Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 5.36% TWD I Cycle Number of Tubes Plugged Due to AVB Wear 4 b) Steam Generator "B" Number of Tubes with AVB Wear Indications to Date I 19 Average Wear Rate 1.66%TWDI Cvcle Number of Data Points 41 Standard Deviation 2.03% TWD I Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 4.26% TWD I Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 5.01% TWD I Cycle Number of Tubes Plueeed Due to AVB Wear 4 C) Steam Generator "C" Number of Tubes with AVB Wear Indications to Date I 17 Average Wear Rate 3.1 1 % TWD I Cvcle Number of Data Points 50 Standard Deviation 2.42% TWD I Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 6.21% TWD I Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 7.1 1% TWD / Cycle I Number of Tubes Plugged Due to AVB Wear 1 10 d) Steam Generators "A", "B", and "C" Combined Number of Tubes with AVB Wear Indications to Date 71 Average Wear Rate 2.31% TWD I Cycle Number

~ of Data

--.-- - ~ ~Points

~- 165 I

I Standard Deviation I 2.19% TWD I Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation I 5.1 1% TWD / Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 5.92% TWD I Cycle

( Number of Tubes Plugged Due to AVR Wear Page 6

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Table 2 -- Surrv I Spring 2006 Inspection Summary - AVB Indications Number of Tubes With AVB Indications Reported in 2006: SGA: 27; SGC: 7 Number of AVB Wear Sites Reported in 2006: SGA: 34; SGC: 12 Number of New Indications Not Present Previously Based on Historical Review: SGA: 0; SGC: 1 SG "A" Average Wear Rate 200 1 to 2006 (%TW / Cycle): 2.39 (34 points)'

SG "A" Historical Average Wear Rate (%TW / Cycle): 2.14 (74 points)

SG "C"Average Wear Rate 2000 to 2006 (%TW / Cycle): 0.85 (12 points)

SG "C"Historical Average Wear Rate (%TW / Cycle): 3.1 1 (50 points) 95/50 Wear Rate Based on Unit 1 Current & Historical Data: 5.92 %TW / Cycle Total Random Sizing Uncertainty at 90% CL: 10.7 %TW Adjusted 2006 %TW: [0.97] x [Field Call] + 13.491 Spring 2009 Projection %TW: [Adjusted 2006 %TW] +

[5.92 %TW/cycle x 2 cycles]+

[10.7 %TW]

r -

Comparison of 2001 and 2006 AVB Wear Depths Surw Unit 1 SG A -

Increased slightly due to relatively large number of previously unreported AVB wear indications in this SG. The calculation assumes those not reported were O%TW which yields a larger apparent growth. In fact, all were present previously.

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Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Table 2 (continued)

I Comparison of 2000 and 2006 AVB Wear Depths - Surw Unit 1 - SG C 1 Bobbin "I-Codes1' During the bobbin coil inspection program, a total of 48 indications (SGA: 32; SGC: 16) of potential degradation (bobbin I-Codes) in 43 tubes (SGA: 29; SGC: 14) were identified which required rotating coil (+Point) diagnosis. These I-Codes are temporary designations whose purpose is to flag potential damage and prompt examination with the +Point probe. Should the

+Point examination not confirm the presence of tube damage, the bobbin "I" is changed to an "S" (e.g., NQI would be changed to NQS). These +Point diagnostic or "special interest" examinations confirmed that a number of the bobbin I-Code indications were the result of volumetric tube damage beyond that of the AVB wear already discussed. This is discussed in section 2.1.2.

Local Geometry Variations (LG-Codes)

Local anomalies are distributed throughout the SG tube bundle and were caused by original manufacturing and insertion of tubes in the support plates. They are indicative of scrapes and indentations on the tubes. These indications are tracked from outage to outage. LGVs are indications with localized diameter reductions accompanied by material conductivity variation, which indicate no evidence of degradation. LGSs represent final analysis results on possible indications of degradation that were in turn inspected with rotating pancake coil (RPC) probes and shown to not be degraded. LGHs represent final analysis results on possible indications of degradation that were shown through a review of historical data to not be degraded. The total count identified by bobbin probe exams during this inspection is summarized below. These Page 8

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 indications were resolved through history review andlor +Point examination. No cracking or other types of degradation were observed to be associated with these indications.

LG-Code Summary (tubeslindications) SG A SG C LGV 0 10 010 LGS 010 1I 2 LGH 38 I57 86 I185 Dent Signals (DNT)

Consistent with the inspection scopes for the Surry steam generators, indications of tube denting (i.e. combination of manufacturing induced, random impact type denting during operation, and point contact type anomalies at tube support plate quatrefoil lands) continue to be monitored for potential degradation. Dent signal analysis protocol has been to assign a DNT call if the signal does not rotate to the flaw plane. DDI calls are used to indicate that a dent produces a distorted indication and requires examination with the +Point probe. DDH calls are used to indicate that a dent signal has been reviewed in history and confirmed to be unchanged from two previous inspections. None of these signals represent the same phenomena as classical corrosion-induced denting observed in older steam generators with carbon steel drilled tube support plates. The process of reporting dents at the 2-volt level for the purpose of more closely monitoring potential future changes was first instituted at Unit 1 during the fall 2001 inspection. As specified in the Surry Site Specific Eddy Current Analysis Guidelines, dents or bulges greater than or equal to 2 volts without a history confirmation, or those which exhibit signal change from historical results, must be re-inspected with a +Point probe to ensure that no degradation has developed.

During the SG " A and "C" bobbin probe inspections a total of 1258 DNT indications measuring

> 2 Volts were reported in 912 tubes. A summary of these dents is provided below. In addition to the bobbin probe examination, more than 20% of dent indications > 2 volts were also tested with +Point probes in each SG (SGA: 121 tubes I160 tests; SGC: 81 tubes I124 tests). No degradation was identified. Recent inspection results from the Unit 1 and 2 "C" steam generators have shown a pattern of dent calls being identified in peripheral tubes at the 6th and 7th tube support plates. The summary below also includes a breakdown of these similar indications observed on Unit 1 at this inspection.

Dent Summary (tubeslindications) SG A SG C Dents > 2 Volts 573 1756 339 I502 Dents 2.00 to 4.99 Volts 501 I677 298 I400 Dents 5.00 to 9.99 Volts 55 169 62 I79 Dents > 10 Volts 9/10 20 I23 Dents 2 2 Volts @ 06H 11 I 1 2 79 I123 Dents > 2 Volts @ 07H 42 I 4 9 22 I28 Dents 5 2 Volts @ 06C 111 213 Dents 2 2 Volts @ 07C 161 18 17 I 2 2 Page 9

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 As was the case in the Unit 1 and 2 "C" steam generator previously, the dent calls being reported at these elevations are predominantly located in periphery tubes and tend to be located near tube support wedge locations. Historical data reviews of dents reported during 2006 confirmed that none of the reported indications were new (i.e., all were present previously). A number of dents were flagged for +Point examination to investigate signal distortions (SGA: 4 tubes 14 indications; SGC: 6 tubes 17 indications). No degradation was identified.

Bulge Signals (BLG)

Three bulges were identified during this inspection in SG A. Two were located slightly above 07H and the third was located at an AVB. All of the bulges were examined with +Point probes.

No degradation was reported.

Low Row U-bend Eddy Current Offset During the root cause evaluation performed for the outside diameter stress corrosion cracking (ODSCC) reported in 15 tubes in SG "D" at Seabrook during the Spring 2002 outage, it was noted that the degraded tubes exhibited a unique bobbin signal characteristic. This characteristic was found to be common to all of the flawed tubes, and six additional tubes that were not degraded.

During the steam generator " A and "C" bobbin probe inspections, the U-bend region of all tubes in rows 8 and lower were evaluated for the unique "Seabrook" signature. None of these tubes exhibited the Seabrook signature.

2.1.2 Rotating Probe Examinations Intergranular Stress Corrosion Crackinq The row I U-bend, hot leg top of tubesheet, and other pre-programmed +Point examinations designed to identify intergranular stress corrosion cracking (IGSCC), as well as the various special interest (I-code) and scope expansion exams, revealed no indications of IGSCC.

Hot leg and cold leg tubesheet regions were screened using computerized data sorts (CDS) of bobbin data for the purpose of identifying over-expansions (OXPs within the tubesheet, OVRs above the tubesheet) which may be initiating sites for tube corrosion. The 20 largest hot leg OXPs in each SG, the one OVR identified in SG A hot, and the two OVRs identified in SG "C" cold were included as part of the special interest +Point examinations. Two of the 19 tubes previously identified in SG " A as having potentially high residual stress (see below) contained OXPs and were consequently examined at the affected location. In addition, due to the extensive top-of-tubesheet (TTS) +Point examination scope, additional OXPs were also captured as part of that exam. The total OXP examination count is summarized below. No degradation was identified.

OXP Examination Summary (tubeslindications) SG A SG C Hot Leg 31 138 27 1 32 Cold Leg 5 16 010 Page 10

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Tubes with Potentiallv High Residual Stress A previous evaluation of long row U-bend offset signals (Ref. 12) identified 19 tubes in SG " A and three tubes in SG "C" which may have high residual stress as a result of the thermal treatment process employed during tube fabrication. A sample of the SG " A tubes was tested at areas of interest with the +Point probe: DNTs (17 locations), hot leg transitions (2 locations),

and OXPs (2 locations). The three SG "C" tubes were examined at the hot leg tubesheet location with the +Point probe. No degradation was identified.

Post-Inner Bundle Lance Examinations A trial application of a new secondary side cleaning technique was implemented during this SG inspection, i.e. Inner Bundle Lance (IBL). In order to confirm that the IBL process applied in SG "C" caused no tube damage, tubes in the region of the tubesheet where IBL was applied were

+Point inspected before and after the process. No tube damage was identified as a result of this examination. In addition, the cold leg row 1 bobbin probe examinations were conducted after IBL was completed. No tube damage was detected. These tests confirm that the IBL process did not cause tube damage.

Volumetric Degradation (non-AVB wear)

Rotating probe inspections of top of tubesheet locations on the hot side in conjunction with special interest examinations (flagged by the bobbin probe results) at various locations throughout the tube bundle identified indications of volumetric tube degradation not related to AVB wear. Rotating probe inspection results of these flaws are summarized in Table 3. Three categories of degradation were identified: 1) foreign object wear (11 tubes), 2) tube support plate wear (one tube), and 3) legacy pit-like indications (two tubes).

Of the 11 flaws attributed to foreign object wear, eight had foreign objects adjacent to the affected location as identified by the secondary side inspection group. These objects were removed from the SG. The other three indications attributed to foreign object wear were located within the flow openings of the quatrefoil tube support plates (SGC R38 C62 @1H-0.35 and SGC R15 C62 @3H-0.59) or at the top of the baffle plate (SGA R27 C84). No eddy current indications of foreign objects were observed in the three tubes and no secondary side visual examinations were attempted. Although no foreign objects were identified, foreign objects most likely caused the flaws. Inter-granular attack (IGA) and pitting can produce similar eddy current test (ECT) signals; however, the location of the flaws suggests that these mechanisms were not the cause of the flaws. IGA and pitting are much more likely to occur in crevice and sludge pile locations where more aggressive chemistry environments can develop. These flaws occurred in the open tube support plate flow openings and at the top of the baffle plate, a non supporting structure with large tube holes to allow water flow; regions in which deposit accumulation has not been identified in the Surry SGs. The conditions that make IGA and pitting an unlikely explanation for this damage make foreign object wear the most likely explanation. Water flow within these regions can interact with foreign objects and lead to tube wear. Foreign objects within flow holes and baffle plates are known to have caused tube wear elsewhere within the industry (e.g., Millstone 3).

In general, two sizing techniques were used to determine the dimensions of the flaws. ETSS 21998.1, and its associated flat-bottom hole calibration standard, is appropriate for sizing volumetric indications which are less than 0.25" in length. This technique produces increasingly Page 1I

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 conservative depth estimates as the flaw length increases. For flaws greater than 0.25" long, the depth estimates are overly conservative. Plugging decisions were made on the basis of the more conservative ETSS 21998.1 depth estimate.

Table 3 provides estimates of the maximum depth, as well as the axial and circumferential length for each flaw. For most flaws these values may be used directly to evaluate structural integrity. However, because each flaw's depth varies over its length, it would be very conservative to assume that the maximum depth of wear extends over the full length of the largest reported flaws. To address this issue, axial depth profiles of most of the flaws were measured using the rotating probe. These profiles were evaluated in accordance with the technique described in Reference 9, Section 5.1.5 in order to determine the flaws' structurally significant depths and structurally significant lengths. This calculation is documented in Ref. 13 and the results are provided in Table 3.

Page 12

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Table 3 - Summary of Non-AVB Wear Volumetric Degradation Identified E X S 96910.1 ETSS 21998.1 Max Structural Max Structural Foreign Axial Circ. Depth Depth Structural Depth Depth Structural Present Object In-Situ SG %w Col Location Length (in) Length (in) (%TW) (%TW) Length (in) (%TW) (%TW) Length (in! Comments Previousty Cause remain in^? Tested? Plugged?

A -35 68 BTSH 0.83 0.92 Exceeds CM limit. 96910.1 may Yes.2001; 65 60.4 0.43 na na underestimatethe deDth of this flaw. No. 1997 FO No y% Y ~ s Does not exceed CM limit using A 35 69 96910'1; however, it does BTSH 0.49 0.65 49 44.3 0.35 84 73.1 0.34 No, 2001 CM limit using overly conservative 21998.1.

Does not exceed CM limit with either technique: 98910.1, considered to be the A 16 68 BTSH 0.54 0.52 31 26.3 0.34 54 46.1 0.37 most appropriate sizing technique for Yes, 2001 this flaw. and 21998.1 the most C0nS8~af~e.

A 34 Does not exceed CM limit with the most 67 BTSH 0.26 0.34 na na na 22 20.2 0.20 No, 2001 conservative sizing technique (21998.1).

A 5 Does not exceed CM limit with the most 88 BTSH 0.42 0.53 na na na 40 36.1 0'34 conservative sizing technique (21998.1).

2001 A 6 Does not exceed CM limit with the most 88 BDTSH 0.30 0.40 na na na 17 conservative sizing technique (21998.1).

Historical PIT. Does not exceed CM limit A 8 38 BTSH 0.32 0.37 na na na 20 17.5 0.2 with the most conservative sizing Yes, 2001 technique (21998.1).

A B Top Does not exceed CM limit with the most 27 84 of spH 0.40 0.39 na na na 29 24.6 0.26 Yes, 2001 conservative sizing technique (21998.1 ).

Does not exceed CM limit with the most A 36 49 BDTSH 0.32 0.45 na na na 41 27.8 0.23 conservative sizing technique (21998.1). No, 2001 Not detectable w/bobbin 2006.

Does not exceed CM limit with the most A 3 50 BTSH 0.40 0.48 na na na 43 37.1 0.34 conservative sizing technique (21998.1 ). No. 2001 Not detectable w/bobbin 2006.

TSP A Does not exceed CM limit 96910.1 TSP 2 57 Wear 0.14 0.37 14 12.3 0.09 na na No, 2001 No No No (mix) is appropriate sizing technique. Wear B6C BDTSC

+2. Historical PIT (back to 1997 on lookup).

A ?d 30 0.31 0.42 na na na 17 15.9 0.25 Does not exceed CM limit with the most Yes. 2001 Pit No No No conservative sizing technique (21998.1).

C 5 Does not exceed CM limit with the most 62 B3H 0.32 0.42 na na na 27 na FO No No Yes conservative sizing technique (21998.1 ).

C ?d Does not exceed CM limit with the most 62 01H 0.34 0.37 na na na 32 na conservative sizing technique (21998.1).

2000 FO No No vu Page 13

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 The condition monitoring (CM) assessment must compare the as-found degradation dimensions with the appropriate CM limit which, includes the effects of material strength variability, burst equation uncertainties, and NDE sizing uncertainties. Development of the CM limit must also include the effects of non-pressure accident loads if they could have a significant effect on the burst pressure of the degraded tubes.

A review of the screening guidance of Reference 14 provides the basis for concluding that non-pressure accident loads are not limiting for degradation of the type identified. From Reference 14 it is clear that circumferential degradation and the circumferential component of volumetric degradation is limiting with respect to non-pressure loads. Reference 14 advises that non-pressure loads are not significant contributors to burst for tubes with flaws that are below the top tube support and which are less than 270" in circumferential extent. All flaws listed in Table 3 are below the top tube support, and the maximum circumferential extent reported was 0.92" or 128". Based on this discussion, it is appropriate to use the EPRl Flaw Handbook (Ref. 9) approach, which considers pressure loading only, to establish the CM limit for all of the flaws listed in Table 3.

For the flaws in Table 3, the appropriate Flaw Handbook model is that of volumetric wall loss with limited axial and circumferential extent (see Reference 9, Section 5.3.3). This model was used to establish the CM limit curves, provided in Figures 1 and 2, based upon both of the sizing techniques employed. A CM curve defines the limiting values of field-measured wear depth and length that still meet the structural integrity performance criteria at a 90150 probabilitylconfidence level. If flaws lie on or below the curve, it can be concluded that the flaws did not exceed the CM limit. The dimensions of each flaw identified in Table 3 are also included on Figures 1 and 2. In most cases, the plotted dimensions are the structurally significant depth and axial length based on a flaw profiling evaluation. Profiling was not performed on two of the flaws (i.e. it was not needed in order to demonstrate structural integrity); therefore, the maximum depth and maximum length of those flaws is shown instead.

Based upon the eddy current examination results and CM evaluation, which requires conservative consideration of all significant sources of uncertainty, Figure 1 indicates that the flaw in tube SGA R35 C68 exceeds the CM limit curve. To determine if the CM limit was actually exceeded, this tube was in-situ pressure tested. Tube SGA R35 C69 does not exceed the ETSS 96910.1 CM limit curve (Figure 1); however, it does exceed the very conservative ETSS 21998.1 CM limit curve (Figure 2). ETSS 96910.1 is considered to be a reasonable method for estimating the throughwall depth of this flaw. However, since in-situ testing was required on tube SGA R35 C68, it was judged prudent to also test tube SGA R35 C69. No other tubes failed to meet the ECT based CM limit curves using either of the two sizing techniques employed, and therefore no other tubes were in-situ pressure tested.

The two tubes indicated as CM failures were subjected to in-situ pressure testing in accordance with the EPRl SG In-Situ Pressure Test Guidelines (Ref. 15) and the vendor in-situ test plan (Ref. 16). Both tubes were tested by pressurizing the entire tube length. Neither tube leaked at the MSLB pressure hold point, demonstrating that both tubes met the accident leakage performance criteria. SGA R35 C69 sustained the 3XPnop (3 X normal operating pressure differential) pressure hold point without leakage or burst. Tube SGA R35 C68 developed a small leak at 4650 psia; however, the planned progression of pressure increases continued through the final hold point (3XPnop) without the need for a bladder to seal the leakage. The tube successfully sustained the 3XPnop pressure level without bursting. The maximum measured leak rate during the five minute 3XPnop hold time was 0.98 gpm. In summary, neither tube Page 14

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 leaked at the MSLB pressure hold point nor burst at the 3XPnop pressure hold point. Hence, the testing demonstrated that neither tube failed either the accident leakage performance criteria or the structural performance criteria.

Page 15

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Figure 1 - Condition Monitoring Assessment for Non-AVB Wear Volumetric Degradation ETSS 96810.1

-W50 CM Limit rn SGAR35C68

+ SGAR35C69 SGAR36C68 SGAFt2C57 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 .O Structurally Significant Length (in)

Page 16

Serial No. 07-0099 Docket No.50-280 Enclosure 1 Figure 2 - Condition Monttoting lSPsegsmnt for Non-AVB Wesr Volurnabic bgradatlon ET$S 21888.1

- 90150 CM Limit SGAR35C69 SGAR36C68 SGAR34C67 SGAR5C88 SGAR8C38 SGAR27C84 SGAR36C49 SGA R36C5O SGAR6C88 SGAR38C30 SGCR15C62 SGCR38C62 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.O 1.1 1.2 Structurally Significant Length (In)

Page 17

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 2.1.3 Data Quality The EPRl NDE Guidelines, Revision 6, provided initial guidance on the methodology to be applied to verify data quality. Subsequent interim guidance (Reference 3) responded to technical concerns raised by the industry regarding the effect of noise on tube integrity parameters (probability of detection, sizing uncertainties). For each active, relevant or potential damage mechanism identified, it must be demonstrated that, under the conditions encountered during the inspection, no impairment of the site-qualified techniques' expected capabilities to detect and size tube degradation has occurred.

The quality parameters were verified in accordance with Revision 6 and its associated Data Quality Verification-related interim guidance. The data analysis team performed manual verification for each tube andlor each calibration set as required. Based on the manual verification, as discussed earlier the data for seven tubes did not meet the established parameters due to interference from permeability variations and were consequently plugged.

2.2 Operational Leakage Routine primary-to-secondary leakage monitoring is performed. During the past operating cycle no measurable leakage (i.e. > 1 gpd) was observed. Consequently, the 150 gpd operational leakage limit was met.

2.3 Projected Accident Leakage Based on the fact that no through wall indications or indications exceeding the structural limit have been reported in the Surry Unit 1 steam generators, no primary-to-secondary leakage would be expected under accident induced loadings. In-situ pressure testing performed during this outage confirmed that the tube with the most significant degradation would not have leaked during a MSLB event.

2.4 Condition Monitoring Conclusion Based on the evaluations of this report, the degradation identified during the April 2006 inspection satisfy condition monitoring requirements for SG tube structural and leakage integrity.

Page 18

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 3.0 Operational Assessment 3.1 Discussion NEI 97-06 requires that an operational assessment (OA) be performed to assess if the steam generator tubing will continue to meet the structural and leakage integrity requirements at the end of the upcoming cycle based upon the degradation mechanisms observed in the plant. This assessment includes site-specific degradation growth rates and NDE uncertainties for the largest flaw kept in service. The following sections summarize the growth rate evaluation and the NDE sizing uncertainty evaluations performed for the observed degradation mechanisms of AVB wear and foreign object wear to support the OA.

3.2 AVB Wear The guidance provided in Reference 6 states that structural integrity should be demonstrated at the next inspection by showing that the tube meets the performance criteria with an overall uncertainty based on a probability of 90%, evaluated at 50% confidence (90150). The guideline also indicates that growth rates should be based on 95/50 statistical criteria. This evaluation addresses AVB wear relative to tube integrity requirements with an OA performed to accommodate an operating interval of up to two cycles for the "A" and "C" steam generators. The AVB indications identified during the current inspection were included in the statistical analysis of AVB growth summarized in Table 2. The AVB growth rate used for the operational assessment projection was based on the estimated upper 95/50 combined wear rate for all three Unit 1 steam generators including data obtained during this inspection. That value is 5.92 %TW/Cycle.

The effect of NDE probability of detection (POD) must also be considered in the OA. The beginning of cycle AVB wear depth must be an upper bound estimate of the depth of wear left in service immediately following the SG tube inspection. This value must account for the fact that NDE processes have imperfect PODS, and must account for known flaws left in service following the tube inspection. Consistent with Reference 6, Table 9-1, the beginning of cycle AVB bar wear depth used in this analysis must be the larger of: 1) the largest flaw left in service, or 2) the flaw depth at a fraction detected of ~ 0 . 9 5based on the technique qualification program. In the Surry 1 SGs, the largest AVB wear flaw left in service was 25 %TW. In the technique qualification program for ETSS 96004.1, wear flaws ranging in depth from 4 %TW to 90 %TW were detected. Therefore, the most limiting of these values is 25 %TW. This confirms that it is appropriate to use the reported depths of AVB wear flaws left in service, adjusted to account for NDE uncertainty, to perform the OA.

The upper bound estimates of depth in 2006 previously shown in Table 2 already account for NDE sizing uncertainty; therefore, they need only be adjusted to account for future wear in order to determine upper bound projected 2009 depth estimates. It is anticipated that SGs " A and "C" will be operated for up to two fuel cycles before the next inspection; therefore, the growth adder is 2 X 5.92 or 11.84 %TW. This value was used to generate the 2009 depth estimates provided in Table 2. The maximum projected 2009 depth is 50 %TW2which is well below the 64 %TW structural limit identified for AVB wear in Reference 2.

Note that this evaluation also bounds the scenario in which additional flaws such as that of SGC R11 C37 develop. The planned operating interval for the SGs prior to the next inspection is a shorter time period (i.e., no more than two cycles) than that which caused the flaw in SGC R11 C37 to develop 2

Note that tube SGC R11 C37 was plugged during this outage.

Page 19

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 (four cycles). Since this flaw met the condition monitoring limit after four fuel cycles of growth, there is reasonable assurance that a similar flaw will meet the condition monitoring limit after a shorter operating period. Hence, AVB wear is not expected to challenge the structural integrity performance criteria in any of the three SGs prior to the next inspection. Further, the AVB wear findings during 2006 reinforce previous OA conclusions for SG "B." Specifically, AVB wear is not expected to exceed the structural performance criteria prior to the fall 2007 inspection of SG "B."

3.3 Tube Support Plate (TSP) Wear The tube support plate wear in tube SGA R2 C57 was detected with the bobbin probe and was sized with ETSS 96910.1 as 14 %TW x 0.14" axial x 0.37" circumferentially (see Table 3). Detection of support wear with the bobbin probe is very reliable. The earlier discussion relative to consideration of the maximum flaw depth left in service with consideration for NDE POD applies to this flaw as well. It is appropriate to assume that the maximum depth of tube support plate wear flaws left in service during the current outage is that of the flaw in tube SGA R2 C57: 14 %TW. Applicable NDE sizing uncertainty with respect to this flaw is that associated with ETSS 96910.1, provided in Reference 2 and summarized below:

Total Random Sizing Uncertainty at 90% CL: 13 %TW Adjusted 2006 %TW: [ I .05] x [Field Call] + [2.16]

Compensating for this uncertainty yields an upper bound estimate of the 2006 depth (UB2006):

This flaw most likely developed slowly over the 25+ years since the steam generators were replaced.

However, for conservatism it is assumed that the flaw developed over the three cycles since SG "A" was last inspected. This yields a growth estimate of 30 %TW/(3 Cycles), or 10 %TW/Cycle. Applying this growth rate over the maximum two cycle period prior to the next inspection in SG " A yields an upper bound estimate by end of cycle 22 of 50 %W. This compares favorably with the structural limit of 56.6 %TW provided in Reference 7 for tube support plate wear, and provides the basis for concluding that tube support plate wear will not exceed the structural performance criteria prior to the next inspection in SG " A . it also supports previous OA conclusions relative to the other two SGs.

3.4 Foreign Object Wear The foreign object wear identified is described in detail in section 2.1.2. Volumetric degradation (non-AVB wear) indications were scrutinized using bobbin and +Point probe techniques. All of the indications except the three flaws at the baffle plate and TSP were examined visually to determine if foreign objects were still present. Eddy current testing confirmed that no object remains adjacent to these three flaws. No objects remain adjacent to any volumetric flaws left in service following this inspection, and identified objects which could conceivably cause tube damage were removed from the SGs during this outage. The remaining flaws have no capacity to continue progressing during future operation and pose no future threat to the structural integrity of the affected tubes.

The potential for undetected foreign object wear and the development of new foreign object wear during the ensuing operating intervals in each SG must be considered. It is difficult to predict if and when foreign object wear - a random and inherently unpredictable phenomenon - will occur.

However, by examining the aggregate operating history of the Surry Unit 1 SGs with respect to foreign object wear, a judgment of the risk can be developed. The EOC20 (REOC15) inspections revealed Page 20

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 significant foreign object wear flaws in SG " A ; however, none exceeded the structural integrity performance criteria despite the fact that the SG had operated for three cycles since its last inspection. More broadly, for many years the SGs have operated for three cycles between inspections, yet no foreign object wear exceeding the performance criteria has been detected. Future operating intervals will be limited to two fuel cycles, further reducing the risk of exceeding SG performance criteria. Robust secondary side visual examinations were performed in all three SGs during this outage, and all identified objects of significance were removed from the SGs.

SG "B" was not examined with ECT techniques during this outage; however historically, few foreign objects have been identified in SG "B" despite extensive in-bundle visual examinations. Prior to this outage, SG " A had not been subjected to extensive in-bundle examinations. Consequently, the detected inventory of foreign objects resulting from the in-bundle visual exams is now obviously greater when compared to that of the other two SG's. The historical experience relative to foreign objects in SG "C" is similar to that of SG "B." The tube examinations performed in SG "C" during this outage revealed no structurally significant foreign object wear despite operating for four cycles since its last inspection. No structurally significant foreign object wear is expected in SG "B" after its planned operating interval in fall 2007.

Based on these observations, there is reasonable assurance that foreign object wear will not result in damage that exceeds the structural performance criteria prior to the next inspection of any of the three SGs.

3.5 Operational Leakage Although there are no findings indicative of a concern, sensitivity to primary-to-secondary leakage events will continue with conservatively based monitoring procedures. Incorporation of industry recommended values as indicated in Revision 2 to the EPRl Primary-to-Secondary Leakage Guideline have been implemented.

3.6 Projected Accident Leakage Since none of the identified degradation mechanisms are projected to exceed the structural performance criteria prior to the next inspection, and since there is no evidence of tube corrosion, there is reasonable assurance that the accident leakage performance criteria will not be exceeded prior to the next inspection of these tubes.

3.7 Operational Assessment Conclusion Based on the results of the current and past eddy current inspections and related secondary side inspections, SGs " A and "C" meet the performance criteria to operate two cycles before the next planned tubing inspection. If other issues are identified on other Surry steam generators in ensuing inspections or other relevant industry findings are noted during the inspection of similar model steam generators, review of planned inspection intervals will be conducted per SG Program requirements.

The results of the spring 2006 inspection of SG's " A and "C" indicate that the existing Operational Assessment for the Unit 1 "B" steam generator is valid. No change to the currently anticipated tube inspection of SG "B" in fall 2007 is necessary.

Results of secondary side inspections continue to demonstrate reliable operation. Continuing diligence on chemistry and FME control will support long term petformance. Evaluation and monitoring will continue as planned and is further detailed in the SG Program. Continuing awareness of any related industry issues will be considered when planning future inspections.

Page 2 1

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 Similar chemistry controls are expected to be maintained throughout the next cycle. Chemistry excursions or significant changes to treatment programs will be evaluated on a case by case basis relative to impact on planned inspection cycles and scopes. Sludge lance frequency and the need for enhanced cleaning will be evaluated on the basis of laboratory sludge analyses, corrosion product transport levels, chemistry control, and tube deposit profiling analyses. Appropriate discussions with station management will continue.

Page 22

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 4.0 References Surry Power Station Units 1 and 2 Steam Generator Monitoring and Inspection Plan, SPS-SGMIP-001, Revision 0, dated October 2003.

Steam Generator Monitoring Program Pre-Outage Assessment, Surry Unit 1 - Spring 2006, dated April 20, 2006.

EPRI Interim Guidance Letter, Revision 6, "Examination Guideline Implementation, Tube Noise Criteria," L. Womack, dated April 30, 2003.

Surry Site Specific Eddy Current Analysis Guidelines (SRY-SGPMS-002), Revision 10, dated April 1, 2006.

"Capabilities of Eddy Current Data Analysts to Detect and Characterize Defects in SG Tubes," D. H. Harris, 15th Steam Generator NDE Workshop, Long Beach, CA, July 1996, updated 1999.

EPRI, "Steam Generator lntegrity Assessment Guidelines: Revision 1," TR-107621-R1, dated March 2000.

Westinghouse Electric Company, WCAP-16095-P, "R.G. 1. I 21 Analysis," Revision 0, dated January 2005.

FANP, "MathCad Implementation of SG Flaw Handbook Equations for lntegrity Assessment," 32-5033045-00, dated December 17, 2003.

EPRI, "Steam Generator Degradation Specific Management Flaw Handbook," 1001191, dated January 2001.

VPAP-0820, "Steam Generator Program Administrative Procedure."

"SG Program Guidelines," NEI 97-06, Rev. 2, dated May 2005.

AREVA, "Residual Stress Screening of Long Row SG Tubes in Surry Units 1 and 2," 51-5054387-00, dated December 6,2004.

AREVA, "Structural Evaluation of Surry Unit 1 Volumetric Tube Damage," 32-9020613-000, dated April 10, 2006.

EPRI, "Interim Guidelines on Revised Structural lntegrity Performance Criterion," SGMP-IG-05-01, dated January 17, 2005.

EPRI, "SG In Situ Pressure Test Guidelines, Rev. 2," 1007904, dated August 2003.

AREVA, "Test Plan for In-Situ Pressure Testing, Revision 0," dated May 2006.

Page 23

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 ATTACHMENT 1 Three Letter Codes GENERAL CODES ANF - ANOMALY NOT FOUND -Indicates that a previously reported anomaly cannot be found within .50" of the location where the anomaly was previously called.

ANR ANOMALY NOT REPORTABLE - lndicates that a previously reported anomaly does not meet the present reporting criteria.

BDA BAD DATA (retest) - lndicates that the data for the specified tube is not acceptable for analysis due to poor signal quality. The tube will be re-tested to the required extent.

INF - INDICATION NOT FOUND - lndicates that a previously reported INDICATION has not been found in the data being analyzed or that a tubelsignal is being re-tested for positive identification (PID) and no signal is present in the retest data.

INR - INDICATION NOT REPORTABLE - Indication called in previous inspections that are still detectable but fall below current reporting criteria.

LAR Lead Analysts Review - Condition not directly covered by the guidelines, ETSS, or other documentation that the data analyst feels should be brought to the attention of the resolution andlor job lead analyst. Diagnostic testing or PID verifications that the analyst believes are not the correct tube number andlor the correct tube location shall be identified as LAR.

NDD NO DETECTABLE DISCONTINUITY -The recorded data has no signal responses meeting the criteria established in the Site Specific Analysis Guidelines for degradation, damage precursors or anomalies.

NDF No Degradation Found - Used to address a special interest location where no signal meeting the RC criteria (MBM, DNT, etc) is present. Location of rotating coil data verses the bobbin coil shall be verified to ensure correct location was inspected.

NT NO TEST (re-test) lndicates that the tube ROW, COLUMN was encoded on the tape; however, no inspection data was recorded for analysis.

OBS - OBSTRUCTED - Blockage of a tube that prevents passage of a defined minimum size probe through the tube.

PID POSITIVE IDENTIFICATION - Verification of a signal at the same reported ROWICOL and at the same reported tube location.

PLG - PLUG - lndicates that the tube at the specified location has been plugged.

PVN PERMEABILITY VARIATION - Condition where the test coil impedance changes due to a change in the tubing materials inherent tendency to conduct magnetic flux lines.

PLP - POSSIBLE LOOSE PART - lndicates the possible presence of a loose part in the generator.

RST - RESTRICTED - Blockage of a tube that prevents passage of a probe beyond a specified location within the tube.

TIU TUBE I.D. UNCERTAIN (re-test) - lndicates that the ROW and/or COL identifier for a given tube is in doubt.

Page 1

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 ATTACHMENT 1 (Continued)

BOBBIN CODES BLG - BULGE - An area along the tube where the diameter of the tube has been abruptly deformed in an outward direction as compared to the nominal tube diameter.

CUD - COPPER DEPOSIT - The presence of copper deposits on the outside of the tube.

DNT DENT - A n area along the tube where the diameter of the tube has been abruptly reduced compared to the nominal tube diameter.

LGV - LOCAL GEOMETRIC VARIATION - A local reduction in tube diameter usually associated with a localized change in conductivity of the tube. LGV signals are caused by dings introduced during manufacturinglinstallation process and do not represent a discernible wall loss. The signals must be verified by history review to be called with bobbin (See rotating probe DNG code).

MBM MANUFACTURING BURNISH MARK - A tubing condition where localized tubing imperfections were removed by buffing and are detectable due to the effects of cold working and minor localized wall thinning. The signal must be verified by history review to be called with bobbin.

MMB MULTIPLE MANUFACTURING BUFF MARK - Multiple MBM signals in close proximity over a length of tube. The signals must be verified by history review to be called with bobbin.

NQI - NON-QUANTIFIABLE INDICATION - A bobbin signal requiring rotating coil examination for disposition.

NQN - NON-QUANTIFIABLE NONDEGRADED - A bobbin signal which was formally classified as NQI but has been determined to be anomalous or of a type which does not represent degradation.

PDS - POSTIVE DRIFT SIGNAL - Long (several inches to several feet) drift signals evident on absolute channels caused by variations in tube concentricity associated with the pilgring process. The signals may be located at random elevations and are generally only in one leg of the tube.

PTE - PARTIAL TUBE EXPANSION - Code used when only some portion of parent tube has been expanded into the carbon steel tube sheet. PTE shall be reported at the axial location(s) where nominal tube expansion ends and the partial begins, from the 4001100 mix channel. Bobbin andlor rotating coil data shall be carefully analyzed in the non-expanded crevice region.

NTE - NO TUBE EXPANSION - Code used when the parent tube has NOT been expanded into the carbon steel tube sheet from the top of the tube sheet to approximately 2.5" from the tube end. NTE shall be reported from the 4001100 mix channel, location as TSH +0.00. Bobbin andlor rotating coil data shall be carefully analyzed in the non-expanded crevice region.

ROTATING PROBE CODES DNG DING - A localized inward displacement of the tube caused by a mechanical impact on the OD surface.

MAA - MULTIPLE AXIAL ANOMALY - Multiple axially oriented signals located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

Page 2

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 ATTACHMENT 1 (Continued)

MCA MULTIPLE CIRCUMFERENTIALLY ORIENTED ANOMALY - Multiple circumferentially oriented signals located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

MA1 - MULTIPLE AXIAL INDICATION - Multiple axially oriented signals that the rotating coil data shows to result from flaws in the tube.

MBM - MANUFACTURING BURNISH MARK - A tubing condition where localized tubing imperfections were removed by buffing and are detectable due to the effects of cold working and minor localized wall thinning.

MCI MULTIPLE CIRCUMFERENTIALLY ORIENTED INDICATION - Multiple circumferentially oriented signals reported from rotating probe data that the rotating coil data shows to result from flaws in the tube.

MMB - MULTIPLE MANUFACTURING BUFF MARK - Multiple MBM signals in close proximity over a length of tube.

NQN NON-QUANTIFIABLE NONDEGRADED - A bobbin NQI signal which is determined to be anomalous or not to represent degradation.

PIT PIT - Localized attack on tubing resulting from non-uniform corrosion rates caused by the formation of local corrosion cells. At Surry, the condition produces small volumetric indications with approximately the same axial and circumferential extent.

SAA SINGLE AXIAL ANOMALY - A single axially oriented signal located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

SCA SINGLE CIRCUMFERENTIALLY ORIENTED ANOMALY - A single circumferentially oriented signal located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

SAI - SINGLE AXIAL INDICATION - A single axially oriented signal that the rotating coil data shows to result from a flaw in the tube.

SCI - SINGLE CIRCUMFERENTIALLY ORIENTED INDICATION - A single circumferentially oriented signal that the rotating coil data shows to result from a flaw in the tube.

VOL VOLUMETRIC - lndications of volumetric wall loss indicative of general localized thinning, wear or impingement.

SVllMVl - SINGLE VOLUMETRIC INDlCATlONlMULTlPLE VOLUMETRIC INDICATIONS - lndications of volumetric wall loss indicative of general local inter-granular attack (IGA or IGAISCC).

Page 3

Serial No. 07-0099 Docket No. 50-280 Enclosure 1 ATTACHMENT 2 Surry Steam Generator Sketches Page 1

Serial No. 07-0099 Docket No, 50-280 Enclosure t

.. ---- !Page 30 of Record)

[REDACTED]

Medel 51F

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 ENCLOSURE 2 2006 Annual Steam Generator Inservice Inspection Report Surry Unit 2 Virginia Electric and Power Company (Dominion)

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 Virginia Electric and Power Company (Dominion)

Surry Unit 2 Annual Steam Generator Report Summarv Data Station Unit I Outage Date I Generator Examined I Date of Report Surry 2 April, 2006 I A l February 26,2007 SG Design Information SG Model TSP Type. TSP Mat'l # TSP Baflle Mat'l AVB Mat'l # AVB 51F Quatrefoil Type 405 SS 7 Type 405 SS Chrome Plated 2 Alloy-600

1. Tubes I Tube Dia. I Tube Mat'l 1 Tube Pitch 1 Tube Tks 1 Expansion Heat X-fer Area 3342 1 0.875" 1 Alloy600TT 1 1.281" 1 0.050" I Full Hydraulic 1 51,500 sq. ft.

Scope of Inspection SG I Inspection Program I Planned I Inspected I Inspection Method I Extent A I 100% Bobbin 1 3326 1 3326 Bobbin I TEC - TEH, Except Row 1 U-bends-A Row 1 U-Bend RC 92 92 +Point U-Bend RC 7C - 7H A 'ITS Hot leg NTE RC 2 2 + Point RC TEH - TSH +3" A TTS Hot leg RC 2067 2067 + Point RC TSH +I-3" A Special Interest RC 185 185 +Point RC Various Exams Tubes Plugged Foreign Object1Wear 3 Tube end damage 1 4

Note 1: AS described in the safety evaluation and plant LOCA analyses, steam generators are restricted to an equivalent plugging limit of 15% average and 15% in any one steam generator with no greater than a 5 % differential between any two steam generators expressed in number of tubes per generator.

Page 2

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 TUBE INTEGRITY ASSESSMENT

SUMMARY

1.0 Evaluation Summary Overall condition assessments have been delineated in the Steam Generator (SG) Monitoring and lnspection Plan (Reference 1) and are consistent with the requirements of NEI 97-06 (Reference 11). A Pre-Outage Assessment (Reference 2) was performed to identify any relevant condition to be considered for the Surry Unit 2 steam generators that had not been included in Reference 1. The assessment also identified the appropriate eddy current inspection scope, probes to be utilized during the subject inspection, and appropriate detection and sizing information for mechanisms considered relevant for the proposed inspection scope.

As required by NEI 97-06, Performance Criteria are established in three areas:

+ Structural Integrity - Margin of 3.0 against burst under normal steady state power operation and a margin of 1.4 against burst under the most limiting design basis accident. Additional requirements are specified for non-pressure accident loads.

+ Operational Leakage - RCS operational primary-to-secondary leakage through one steam generator shall not exceed 150 gpd.

+ Accident Induced Leakage - Leakage shall not exceed the value assumed in the limiting accident analysis.

The inspections performed were consistent with the previously referenced Monitoring and lnspection Plan and the Pre-Outage Assessment (Reference 2). Two independent analysis paths evaluated the acquired eddy current data: manual primary analysis and computerized data screening (CDS) secondary analysis (bobbin). Rotating pancake coil (RPC) data was analyzed manually by both teams. A third team of analysts resolved any discrepancies between the two analyst teams. The Dominion Eddy Current Level Ill performed oversight evaluations as the Independent Qualified Data Analyst (IQDA), a role defined within the EPRl SG Examination Guidelines.

The Surry Site Specific Guidelines (Reference 4) served as the primary guidance document for data evaluation. As with past practice, Surry-specific examination technique summary sheets (ETSS) were used in conjunction with Reference 4 to summarize instructions relative to acquisition and analysis setups and analysis screening parameters.

A condition monitoring (CM) evaluation of the steam generator tube bundles was performed to verify that the condition of the tubes, as reflected in the inspection results, is in compliance with the plant licensing basis and meets the stated performance criteria. Structurally significant indications, if found, are evaluated to confirm that the safety margins against leakage and burst were not exceeded at the end of this operating cycle. The results of the condition monitoring evaluation are used as a basis for the operational assessment, which demonstrates prospectively that the anticipated performance of the steam generators will likewise not exceed the performance criteria margins against leakage and tube burst during the ensuing operating period.

An operational assessment evaluation was performed to determine if tube structural or leakage integrity would be challenged prior to the next scheduled inspection of the subject steam generator. In addition, an assessment is made to verify the structural and leakage integrity of Page 3

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 the un-inspected steam generators until their next planned inspection based on current inspection findings. This report documents the condition monitoring and operational assessment of the tube inspection results from the Surry Unit 2 " A steam generator. It conforms to the March 2000 EPRl Steam Generator Integrity Assessment Guidelines (Reference 6) and the requirements of NEI 97-06.

2.0 Condition Monitoring Assessment This condition monitoring assessment (CMA) evaluated structural and leakage integrity based on current inspection results. The condition of the Surry Unit 2 steam generators, as indicated by the results of the primary and secondary side inspections performed during this outage, satisfy required structural and leakage integrity criteria. A discussion of the inspection results and the evaluations performed is provided in the following sections.

2.1 Primary Side Inspection 2.1. I Bobbin Program Anti-Vibration Bar (AVB) Wear Indications A total of 13 AVB wear indications in 10 tubes was identified in steam generator "A" (Table 1).

None of the identified flaws exceeded the Technical Specification plugging limit of 40 % throughwall (TW), and therefore none of the tubes were plugged. The maximum indicated depth (29 %TW) was reported in tube SGA R36 C62.

The appropriate bobbin probe technique performance data for detection and sizing of AVB wear is based on the EPRl non-destructive examination (NDE) technique ETSS 96004.1. Reference 2 summarizes the NDE sizing uncertainty parameters for ETSS 96004.1, and they are repeated in Table 2 for convenience. In Table 2, the total random sizing uncertainty of 10.7 %TW was applied to the adjusted 2006 depth estimates to obtain upper bound estimates of 2006 flaw depth. This value is compared directly with the structural limit for AVB wear (64 %TW for rows 9 to II , 69.4 %TW for rows 12 to 46, Reference 2). As shown in Table 2, the largest 2006 upper limit depth (42 %TW) is well below the minimum structural limit of 64 %TW.

In addition to the pressure loads upon which the above structural limits are based, the CM must also consider the impact of non-pressure accident loads if they could have a significant effect on the burst pressure of the degraded tubes. A review of the screening guidance provides the basis for concluding that non-pressure accident loads are not limiting for AVB wear.

The average growth rate in the " A steam generator since the last inspection was 0.64 %TW/Cycle. As with other growth information, this value is based on the process in which negative values of depth change (i.e., the more recent indication depth is smaller than the previous depth) are set equal to zero in the calculation of average growth. The growth rate continues its decreasing trend as has been historically observed at Surry. The average growth of historical Unit 2 AVB wear for which growth information is available, including fall 2006 SG " A data, is 2.1 1 %TW/Cycle; reduced from 2.20 %TW/Cycle reported following the spring 2005 SG examination.

Only one AVB wear indication reported during this inspection was not reported during the previous (2002) inspection of SG " A . That tube, SGA R29 C28, contained an 11%TW AVB Page 4

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 wear indication. A review of historical data confirmed that the flaw was present and had not changed significantly since that inspection. For growth determination purposes it was assumed that the newly reported wear did not exist at the time of the previous inspection. Two previously reported AVB wear indications were not reported during this inspection. One was plugged during the last inspection (SGA R11 C24) and one was not reportable during the current inspection (SGA R31 C13). Table 1 summarizes AVB wear growth rates for each Unit 2 SG and for all Unit 2 SGs combined.

Table 1 - Surry Unit 2 AVB Statistical Summary Updated with 2006 Data a) Steam Generator 'A" Number of Tubes with AVB Wear Indications to Date 12 Average Wear Rate 1.18%TWD / Cycle Number of Data Points 45 Standard Deviation 1.25% TWD / Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 2.78%TWD / Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 3.25% TWD / Cycle Number of Tubes Plugged Due to AVB Wear 1 b) Steam Generator "B" Number of Tubes with AVB Wear Indications to Date I 10 Average Wear Rate 2.97%TWD / Cycle Number of Data Points 17 Standard Deviation 2.13% TWD / Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 5.70% TWD / Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 6.48% TWD / Cycle Number of Tubes Plugged Due to AVB Wear 5 C) Steam Generator "C" Number of Tubes with AVB Wear Indications to Date 45 Average Wear Rate 2.29% TWD / Cvcle Number of Data Points 148 Standard Deviation 1.69% TWD / Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 4.45% TWD / Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 5.08% TWD / Cycle I Number of Tubes Plugged Due to AVB Wear 10 1 d) Steam Generators "A", "B", and "C" Combined Number of Tubes with AVB Wear Indications to Date 67 Average Wear Rate 2.1 1% TWD / Cycle Number of Data Points 210 Standard Deviation 1.720A TWD I Cycle 90150 Wear Rate = Mean + 1.28 x Standard Deviation 4.3 1% TWD / Cycle 95/50 Wear Rate = Mean + 1.65 x Standard Deviation 4.94% TWD / Cycle Number of Tubes Plugged Due to AVB Wear 16 Page 5

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 Table 2 -- Surrv 2 Fall 2006 lns~ectionSummary - AVB Indications Number of Tubes With AVB Indications Reported in 2006: SGA: 10 Number of AVB Wear Sites Reported in 2006: SGA: 13 Number of New Indications Not Present Previously Based on Historical Lookups: SGA: 0 SG "A" Average Wear Rate Prior to This Outage (%TW / Cycle): 1.40 (32 points)

SG "A" Average Wear Rate Including This Outage (%TW / Cycle): 1.18 (45 points) 95/50 Wear Rate Based on Unit 2 Current & Historical Data: 4.94 %TW / Cycle Total Random Sizing Uncertainty at 90% CL: 10.7 %TW Adjusted 2006 %TW: [0.97] x [Field Call] + [3.49]

Fall 2009 Projection %TW: [Adjusted 2006 %TW] +

L4.94 %TW/cycle x 2 cycles]+

[10.7 %TW]

1 -

Comparison of 2002 and 2006 AVB Wear Depths Surry Unit 2 - SG A Depth ( % W )

(inch) Adjusted 2006 Depth Upper Bound 2006 Projected 2009 Depth (ETSS 96004.1)

(%W) Depth (%TW) (for CM) (%TW) (for OA)

SG Row Col AVB No. 2002 1 2006 2002 1 2006 Page 6

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 Bobbin "I-Codes" During the bobbin coil inspection program, a total of 12 indications of potential degradation (bobbin I-Codes) in 12 tubes were identified which required rotating coil (+Point) diagnosis.

These I-Codes are temporary designations whose purpose is to flag potential damage and prompt examination with the +Point probe. Should the +Point examination not confirm the presence of tube damage, the bobbin "I" is changed to an "S" (e.g., NQI would be changed to NQS). These +Point diagnostic or "special interest" examinations confirmed that a number of the bobbin I-Code indications were the result of volumetric tube damage beyond that of the AVB wear already discussed. These are discussed in section 2.1.2.

Local Geometrv Variations (LG-Codes)

Local anomalies are distributed throughout the SG tube bundle and were caused by original manufacturing and insertion of tubes in the support plates. They are indicative of scrapes and indentations on the tubes. These indications are tracked from outage to outage. LGVs are indications with localized diameter reductions accompanied by material conductivity variation, which indicate no evidence of degradation. LGSs represent final analysis results on possible indications of degradation that were in turn inspected with RPC probes and shown to not be degraded. LGHs represent final analysis results on possible indications of degradation that were shown through a review of historical data to not be degraded. The total count identified by bobbin probe exams during this inspection is summarized below. These indications were resolved through history review and or +Point examination. No cracking or other types of degradation were observed to be associated with these indications.

LG-Code Summary I (tubeslindications) I SG A LGV 314 LGS 212 LGH 29 1 161 Dent Signals (DNT)

Consistent with the inspection scopes for the Surry steam generators, indications of tube denting (i.e. combination of manufacturing induced, random impact type denting during operation, and point contact type anomalies at tube support plate quatrefoil lands) continue to be monitored for potential degradation. Dent signal analysis protocol has been to assign a DNT call if the signal does not rotate to the flaw plane. DDI calls are used to indicate that a dent produces a distorted indication and requires examination with the +Point probe. DDH calls are used to indicate that dent signals that had a distortion have been reviewed in history and confirmed to be unchanged from two previous inspections. None of these signals represent the same phenomena as classical corrosion-induced denting observed in older steam generators with carbon steel drilled tube support plates. The process of reporting dents at the 2-volt level for the purpose of more closely monitoring potential future changes was first instituted at Unit 2 during the fall 2000 inspection. As specified in the Surry Site Specific Eddy Current Analysis Guidelines, dents or bulges greater than or equal to 2 volts without a history confirmation or those which exhibit signal change from historical results must be re-inspected with a +Point probe to ensure that no degradation has developed.

Page 7

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 During the SG " A bobbin probe inspections a total of 614 DNT indications measuring > 2 Volts were reported in 403 tubes. A detailed tabulation of these dents is provided below. In addition to the bobbin probe examination, more than 20% of dent indications > 2 volts were also tested with

+Point probes (84 tubes I123 tests). No degradation was identified.

The table below provides a breakdown of dent indications reported during this outage:

Dent Summary

( (tubeslindications) SG A Dents > 2 Volts 403 1614 Dents 2.00 to 4.99 Volts 361 1481 Dents 5.00 to 9.99 Volts 69 190 Dents > 10 Volts 30 143 Dents > 2 Volts @ 06H 8 I8 Dents > 2 Volts @ 07H 59 188 Dents 2 2 Volts @ 06C 010 Dents 2 2 Volts @ 07C 76 I126 Historical Surry inspection results have shown a pattern of dent calls at the 6th and 7th tube support plates. The dents reported at these elevations are predominantly located in periphery tubes and tend to be located near tube support wedge locations.

Historical data reviews of all dents reported during 2006 confirmed that none of the reported indications were new (i.e., all were present previously). No dents were flagged for +Point examination, i.e. had not changed, to investigate signal distortions.

Bulge Signals (BLG)

A total of 60 bulges were identified, mostly at the 6'h and 7'h support plates in rows 1 and 2, in 42 tubes during this inspection. Bulges 21 1 volts (1 1 bulges) were examined with +Point probes.

An additional 28 of varying voltages were included as a part of the 100% Row 1 U-bend +Point examination for a total of 39 or 65% of the reported bulges. No degradation was reported.

Low Row U-bend Eddy Current Offset During the root cause evaluation performed for the outside diameter stress corrosion cracking (ODSCC) reported in 15 tubes in SG "Dl' at Seabrook during the Spring 2002 outage, it was noted that the degraded tubes exhibited a unique bobbin signal characteristic. This characteristic was found to be common to all of the flawed tubes, and six additional tubes that were not degraded. During the Surry steam generator "A" bobbin probe inspections, the U-bend region of tubes in rows eight and lower was evaluated for this unique "Seabrook signature.

None of these tubes exhibited the Seabrook signature.

2.1.2 Rotating Probe Examinations Intergranular Stress Corrosion Cracking The Row 1 U-bend, hot leg top of tubesheet, and other pre-programmed +Point examinations designed to identify intergranular stress corrosion cracking (IGSCC), as well as the various special interest (I-code) and scope expansion exams, revealed no indications of IGSCC.

Page 8

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 Tubesheet Overex~ansions Hot leg and cold leg tubesheet regions were screened using computerized data screening (CDS) of bobbin data for the purpose of identifying over-expansions (OXPs within the tubesheet, OVRs above the tubesheet), which may be initiating sites for tube corrosion. A total of 137 hot leg and 101 cold leg OXPs were reported. No OVRs were reported. The 28 largest hot leg OXPs were included as part of the special interest +Point examinations. The largest OXP identified was 39 volts, and it was in the hot leg. In addition, within the top-of-tubesheet

+Point examination scope, one extra OXP was included as a part of that exam. The total OXP examination count is summarized below. In total, 21% of the identified hot leg OXPs were examined with +Point probes. No degradation was identified.

OXP Examination Summary (indications) Reported Examined w/+Point Hot Leg 137 29 (2 1%)

Cold Leg 101 0 (0%)

Tubes with Potentially High Residual Stress A previous evaluation of long row U-bend offset signals (Reference 12) identified tubes in the Surry SGs which may have high residual stress as a result of the thermal treatment process employed during tube fabrication. However, the report identified no such tubes in SG "A."

Tube End Damage / Channel Head Damage During the visual examination of the hot leg tube plugs, a yellow stain was noted in the tube end of tube SGA R41 C27 and on the upper channel head bowl nearby (Figure 1). Additional visual and rotating probe special interest eddy current examinations revealed that the tube appeared to have been drilled off-center, longitudinally from the tube end for a distance of approximately 1.75 inches (Figure 2). The tube wall had been perforated over a circumferential distance of approximately 0.9 inches. During a 1986 outage to fix a tube leak, the hot leg end of SGA R41 C27 was inadvertently plugged. A record search confirmed that the tube had been de-plugged by drilling in 1991 and left in-service. The hydraulic expansion throughout the tubesheet above the tube damage was confirmed via bobbin coil profiling to be normal and the transition was properly positioned at the top of the tubesheet. No other Surry Unit 2 SG tubes have been de-plugged and left in-service.

Page 9

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 Page 10

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 Although the damage to the tube end was substantial, the as-found condition did not violate the steam generator program structural or leakage performance criteria. The tube damage was located deep within the tubesheet more than 19 inches below the expansion transition. Tube rupture at this location is precluded due to the reinforcing effect of the tubesheet. The only failure modes that are relevant in this context are: I ) tube pull out, and 2) primary to secondary leakage under MSLB conditions.

An "H*" evaluation to quantify the ability of the Surry hydraulic expansion to resist pull out and leakage under limiting conditions had been previously performed under the direction of Dominion and a joint Westinghouse Owner's Group study and is documented in Reference 15.

This evaluation concluded that tube defects of any magnitude will have no affect on the tube pull out resistance under bounding loading conditions with appropriate factors of safety (specifically, end cap load produced by 1.4 X MSLB pressure differential) provided the defect is located more than 8.5 inches below the top of the expansion. The evaluation also concluded that, provided the defect is located more than 17 inches below the top of the expansion, the primary-to-secondary leak rate under MSLB conditions will be less than twice the leak rate which occurs during normal operation. Assuming the plant operates with leakage at the normal operating leakage limit (150 GPD), and assuming all leakage originates from within-tubesheet defects located below the 17 inch limit, an MSLB event would result in no more than 300 GPD in the faulted loop. Since this value is less than the 500 GPD faulted loop value assumed in the accident analysis, defects below the 17-inch location will not cause the accident leakage performance criteria to be exceeded. This evaluation provides the basis for concluding that the defective tube end identified during the current outage, located more than 19 inches below the top of the expansion, did not violate the structural or leakage performance criteria at any time; hence, the required condition monitoring criteria were met by this defective tube. This tube was plugged during the current outage. Details of the plugging process utilized are provided in Reference 18 and are discussed in the operational assessment portion of this document.

The identified channel head damage was characterized and evaluated in detail. Ultrasonic examination of the tubesheet-to-channel-head transition region confirmed that no degradation extended into the base material, and a conservative evaluation of potential carbon steel corrosion rates concluded that the condition is acceptable for continued service without repair for the remaining licensed life of the unit.

Volumetric Dearadation (non-AVB wear)

Rotating probe inspections of top of tubesheet (TTS) locations on the hot side in conjunction with special interest examinations (flagged by the bobbin probe results) at various locations throughout the tube bundle identified indications of volumetric tube degradation not related to AVB wear. Rotating probe inspection results for these flaws are summarized in Table 3. Note that Table 3 includes tube SGA R41 C27 (discussed above) for completeness.

Two tubes contained indications of shallow damage at the top of the tubesheet on the hot side.

Both flaws had been reported and sized during the previous inspection (2002) and are believed to have been caused by either a foreign object or a manufacturing operation. A review of the historical eddy current data confirmed that the flaws did not change during the ensuing operating period. No eddy current test (ECT) indications of foreign objects were observed in the two tubes, and no secondary side visual examinations were attempted.

Page 1 1

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 A cluster of tube damage was identified in rows 32 through 35 and columns 26 and 27 at the top of tubesheet on the cold side. Although no foreign object was identified in this region during follow up secondary side inspection activities or by eddy current testing, the clustered relationship and location in a relatively high flow region strongly indicate that the damage was caused by a foreign object.

Another cluster of damage at the top of tubesheet on the cold side is also attributed to foreign object wear. The affected tubes (SGA R40 C28, SGA R40 C29, and SGA R41 C29) were damaged by a foreign object that also damaged SGA R41 C28, causing a tube leak in 1986. At the time of that outage, SGA R41 C28 was plugged and the offending foreign object was removed. The damage to the adjacent tubes was judged at the time to be insignificant and the tubes were left in service. During the current outage the flaws were detected and sized using modern sizing techniques now available. The damage is visible in a photo obtained during the current outage secondary side visual inspection (Figure 3).

Figure 3 - SGA Cold Leg Foreign Object Damage In general, two sizing techniques were used to determine the dimensions of the flaws. ETSS 21998.1, and its associated flat-bottom hole calibration standard, is appropriate for sizing volumetric indications which are less than 0.25" in length. This technique produces increasingly conservative depth estimates as the flaw length increases. For flaws greater than 0.25" long, the depth estimates are overly conservative. This conservatism was quantified by utilizing ETSS 21998.1 to measure the depth of the AVB wear scars on Surry eddy current calibration standard ADVB-031-96. The standard contains two AVB wear scars with known as-built dimensions. The results, summarized below, illustrate that ETSS 21998.1 substantially overestimates the depths and lengths of long (i.e., 0.375 inch) volumetric flaws.

Page 12

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 ETSS 21998.1 Sizing Conservatism Depth Length As-Built Wear Indicated by Estimated As-Buitt Wear Indicated by Estimated Scar Depth ETSS 21998.1 / Actual Scar Lengtfi ETSS 21998.1 1 Actual 20 %TW 39 om 1-95 0.376 inch 0.59 inch 1.57 37 %W 59 %W 1.59 0.376 inch 0.64 inch 1-70 During this inspection, plugging decisions were made on the basis of the more conservative ETSS 21998.1 depth estimate. ETSS 96910.1 was employed for those flaws whose dimensions were substantially greater than 0.25 and whose depths as estimated by ETSS 21998.1 were large (i.e. much larger than 40 Ohm). For these indications, plugging decisions were made on the basis of the ETSS 21998.1 results; however, the more realistic depth estimates provided by 96910.1 are used in this condition monitoring assessment.

Table 3 provides estimates of the maximum depth as well as the axial and circumferential length for each flaw. For most flaws these values were used directly to evaluate structural integrity.

However, because each flaw's depth varies over its length, it would be very conservative to assume that the maximum depth of wear extends over the full length of the largest reported flaws. To address this issue, axial depth profiles of the three most significant flaws (SGA R34 C27, SGA R35 C27, and SGA R41 C29) were measured using the rotating probe. These profiles were evaluated in accordance with the technique described in Reference 9, Section 5.1.5 to determine the flaws' structurally significant depths and structurally significant lengths.

Reference 13 curves were applicable to the Unit 2 evaluation with results included in Table 3.

Page 13

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 Table 3 - Summary of Non-AVB Wear Volumetric Degradation Identified f

Present but A 40 28 BTSC 0.44 0.48 18 na na 35 na Does not exceed CM limit with the most FO NO No 6

$ conservative sizing technique (21998.1).

Detectable but 40 29 BTSC 0.47 0.47 19 na na 38 ~na Does not exceed CM limit with the most FO No No conselvative sizing technique (21998.1).

Detectable glL "a A 41 29 BTSC 0.57 0.53 42 37 0.28 .'3 60 0,29 Does not exceed CM limit with the most appropriate sizing technique (96910.1).

Yes (1991) FO No No A 41 27 *TSH Significant tube end damage. Affected axial length approximately 1.75' as indicated by Visual exam indicates probable offcenter RPC with most severe circumferential involvement of approximately 0.9'. Yes (visual) No drilling during 1991 hot leg plug removal.

Dama m indiiatx data used for CM conclusion Page 14

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 The CMA must compare the as-found degradation dimensions with appropriate condition monitoring (CM) limit which includes the effects of material strength variability, burst equation uncertainties, and NDE sizing uncertainties. Development of the CM limit must also include the effects of non-pressure accident loads if they could have a significant affect on the burst pressure of the degraded tubes.

A review of the screening guidance of Reference 14 provides the basis for concluding that non-pressure accident loads are not limiting for degradation of the type identified. From Reference 14 it is clear that circumferential degradation and the circumferential component of volumetric degradation is limiting with respect to non-pressure loads. Reference 14 advises that non-pressure loads are not significant contributors to burst for tubes with flaws that are below the top tube support and which are less than 270" in circumferential extent. All flaws listed in Table 3 are below the top tube support and the maximum circumferential extent reported was 0.67" or 88". Based on this discussion, it is appropriate to use the EPRI Flaw Handbook (Reference 9) approach, which considers pressure loading only, to establish the CM limit for all of the flaws listed in Table 3.

The appropriate Flaw Handbook model is that of volumetric wall loss with limited axial and circumferential extent (see Reference 9, Section 5.3.3). The details of this calculation are contained in Reference 13. This model was used in Reference 13 to establish the CM limit curves for Surry Unit 1. Since the ETSS sizing performance parameters have not changed since the curves were developed, and since the normal operating primary-to secondary-pressure for Unit 1 bounds that of Unit 2, these curves are equally applicable to Surry Unit 2.

A CM curve defines the limiting values of field-measured wear depth and length, which still meet the structural integrity performance criteria at a 90150 probabilitylconfidence level. If flaws lie on or below the curve, it can be concluded that the flaws did not exceed the CM limit. With the exception of SGA R41 C27 discussed earlier, the dimensions of each flaw identified in Table 3 are included on Figures 4 and 5. In most cases, the plotted dimensions are the maximum depth and axial length as indicated by the +Point probe. As discussed above, profiling was utilized for the largest flaws, and in these cases the plotted dimensions are the structurally significant depth and lengths. Since all of the reported wear falls below the CM curve it is concluded that none exceeded the structural performance criteria.

2.1.3 Data Quality The EPRI NDE Guidelines, Revision 6, provided initial guidance on the methodology to be applied to verify data quality. Subsequent interim guidance (Reference 3) responded to technical concerns raised by the industry regarding the effect of noise on tube integrity parameters (probability of detection, sizing uncertainties). For each active, relevant or potential damage mechanism identified, it must be demonstrated that, under the conditions encountered during the inspection, no impairment of the site-qualified techniques' expected capabilities to detect and size tube degradation has occurred. The quality parameters were verified in accordance with Revision 6 and its associated data quality verification-related interim guidance.

The data analysis team performed manual verification for each tube andlor each calibration set as required.

Page 15

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 2.2 Operational Leakage Routine primary-to-secondary leakage monitoring is performed. During the past operating cycle no measurable leakage (Le. > 1 gpd) was observed. Consequently, the 150 gpd operational leakage limit was met.

2.3 Projected Accident Leakage None of the tube defects identified in the Surry Unit 2 steam generator " A violated the structural performance criteria providing reasonable assurance that none of these flaws would have leaked during a MSLB. As discussed earlier, the leakage resistance of the tubesheet expansion would have prevented tube SGA R41 C27 from leaking in excess of the accident leakage performance criteria during a postulated MSLB.

2.4 Condition Monitoring Conclusion Based on the evaluations of this report, degradation identified during the October 2006 inspection satisfy condition monitoring requirements for SG tube structural and leakage integrity.

Page 16

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 Figure 4 - Condition Monitorhg Assessment for Non-AVB Wear Volumetric Degradation - ETSS 96910.1

-90150 CM Limit A SGAR34C27 o SGAR41C29 Structurally Significant Length (in)

Page 17

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 Figure 5 - Condition Monitoring Assessment for Non-AVB Wear Volumetric Degradation ETSS 21998.1 9 0 1 5 0 CM Limit rn SGAR17C16

+ SGAR18C16 SGAR32C27

X SGAR33C27 SGAR34C26 A SGAR35C27*

r SGAR40C28 SGAR40C29 0.0 0.1 0.2 0.3 0.a: 0.5 0.6 0.7 0.8 0.9 1.O 1.1 1.2 Flew Length (in)

Page 18

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 3.0 Operational Assessment 3.1 Discussion NEI 97-06 requires that an operational assessment (OA) be performed to assess if the steam generator tubing will continue to meet the structural and leakage integrity requirements at the end of the upcoming cycle based upon the degradation mechanisms observed in the plant. This assessment needs to include site-specific degradation growth rates and NDE uncertainties for the largest flaw kept in service. The following sections summarize the growth rate evaluation and the NDE sizing uncertainty evaluations performed for the observed degradation mechanisms of AVB wear and foreign object wear to support the OA.

3.2 AVB Wear The guidance provided in Reference 6 states that structural integrity should be demonstrated at the next inspection by showing that the tube meets the performance criteria with an overall uncertainty based on a probability of 90%, evaluated at 50% confidence (90150). The guideline also indicates that growth rates should be based on 95/50 statistical criteria. This evaluation addresses AVB wear relative to tube integrity requirements with an OA performed to accommodate an operating interval of up to two cycles for the " A steam generator. The AVB indications identified during the current inspection were included in the statistical analysis of AVB growth summarized in Table 2. The AVB growth rate used for the operational assessment projection was based on the estimated upper 95/50 combined wear rate for all three Unit 2 steam generators including data obtained during this inspection. That value is 4.94 %TW/Cycle.

The effect of NDE probability of detection (POD) must also be considered in the OA. The beginning of cycle (BOC) AVB wear depth must be an upper bound estimate of the depth of wear left in service immediately following the SG tube inspection. This value must account for the fact that NDE processes have imperfect PODS, and must account for known flaws left in service following the tube inspection. Consistent with Reference 6, Table 9-1, the BOC AVB wear depth used in this analysis must be the larger of: 1) the largest flaw left in service, or 2) the flaw depth at a fraction detected of ~ 0 . 9 5based on the technique qualification program. In the Surry 2 SGs, the largest AVB wear flaw left in service was 29 % W . In the technique qualification program for ETSS 96004.1, wear flaws, ranging in depth from 4 %TW to 90 %TW, were detected. Therefore, the most limiting of these values is 29 %W. This confirms that it is appropriate to use the reported depths of AVB wear flaws left in service, adjusted to account for NDE uncertainty, to perform the OA.

The upper bound estimates of depth in 2006 presented in Table 2 already account for NDE sizing uncertainty; therefore, they need only be adjusted to account for future wear in order to determine upper bound projected 2009 depth estimates. It is anticipated that SG "A will be operated for up to two fuel cycles before the next inspection; therefore, the growth adder is 2 X 4.94 or 9.89 %TW. This value was used to generate the 2009 depth estimates provided in Table

2. The maximum projected 2009 depth is 52 % W which is well below the 64 %TW structural limit identified for AVB wear in Reference 2.

Hence, AVB wear is not expected to challenge the structural integrity performance criteria in SG "A" prior to the next inspection following two operating cycles. Further, the AVB wear findings during 2006 reinforce previous OA conclusions for SGs "B" and "C." Specifically, AVB wear is Page 19

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 not expected to exceed the structural performance criteria prior to the spring 2008 inspection of SGs "B" and "C."

3.3 Non-AVB Wear Tube Damage Tube damage not associated with AVB wear is described in detail in section 2.1.2. Specifically, this includes tube end damage caused by de-plugging, foreign object wear, and the shallow damage in two tubes caused either by foreign objects or a manufacturing process. Each is discussed below:

Tube End Damage IChannel Head Damage The tube end damage identified in tube SGA R41 C27 was the result of a de-plugging operation performed in 1991. No other tubes in the Surry Unit 2 SGs were de-plugged and left in service; hence, this is a unique condition. During the current outage, a "deep roll plug" was installed in the hot leg end of tube SGA R41 C27 to address its unique condition, and a normal roll plug was installed in the cold leg end.

The deep roll plugging process, described in Reference 18, utilized three individual roll expansions: the deep roll, the normal roll, and the shallow roll. The deep roll was installed above the damage area in a location where the tube was fully intact. This roll establishes the qualified structural joint between the plug OD and the tube ID. Since the degradation being addressed lies below the plug's structural joint, the potential for leakage and pull out with respect to the tubeltubesheet interface (i.e., the tube OD and tubesheet bore) must be considered. Although leak and load test results addressing the tubeltubesheet interface are not typically developed as part of any plug qualification, previous testing has shown that the installation of a rolled plug will also create a structural joint between the tube OD and tubesheet bore (Reference 18). More importantly Dominion's "H*" evaluation (Reference 15) concludes that a tube defect of any magnitude located below 17 inches below the top of the expansion will have no affect on the tube pull out resistance under bounding loading conditions, and will not cause primary-to-secondary leakage to exceed the accident leakage performance criteria. Since this conclusion is valid for an in-service tube, the presence of the deep roll provides additional assurance that this configuration will not cause the structural or leakage performance criteria to be violated during future operation.

The other two rolls in the deep roll plug are not required or credited in the qualification as structural joints and were installed primarily to isolate the exposed tubesheet carbon steel in this location from the primary coolant. It is likely however, that these rolls do in fact provide additional pull out and leakage resistance. As is evident in Figures 1 and 2, a ring of tube material is present at the very end of the tube. It is expected that the shallow roll, which seated against that short section of tubing and the region above it, formed a tight joint presenting a tortuous leakage path and allowing little or no primary coolant to contact the tubesheet material.

However, to the extent that the lower rolls do not isolate the carbon steel, it must be assumed that corrosion of the tubesheet material could occur.

The rate of carbon steel corrosion during operation with very low primary coolant oxygen is much lower than that during shutdown when the metal could be exposed to air. A sustained corrosion process requires a reliable supply of oxygen. Yet at most, the lower roll will allow coolant to weep into the location early in an operating cycle and weep out during shutdown conditions. In this constrained configuration, oxygen will be consumed by the corrosion process but will not be readily replenished. Any corrosion that occurs will advance at a rate much lower Page 20

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 than the general corrosion rates attributed to nominal operating and shutdown conditions. If corrosion does occur, the resulting formation of corrosion products will act to plug weepage paths, further isolating the carbon steel from primary coolant. (This effect has been observed in laboratory studies of corrosion in the crevices between tube and tubesheet in once through steam generators (OTSGs) (Reference 19)).

As a defense-in-depth assessment, disregarding these mitigating circumstances and assuming conservative corrosion rates occur (0.35 milslyear operating; 15 milslyear shutdown), the maximum carbon steel lost during the approximately 30 years of licensed operation remaining and during the ensuing refueling outages, would be only 34 mils (Reference 17). The corrosion would be limited to the region immediately adjacent to the tube end over an area approximately 2 inches long by 1 inch wide. Further, the tube end damage is oriented towards the channel head periphery, away from neighboring tubes and as such, the postulated corrosion would not impact the ligament between adjacent tubes. Damage of this magnitude would have no impact on the structural integrity of the tubesheet. As discussed previously, the H* evaluation concludes that damage below 17 inches below the top of the tube expansion will not adversely impact the structural or leakage integrity of the RCS pressure boundary.

Although general corrosion of the alloy 600 tube material is not a concern in primary coolant, it is possible that the portion of tube SGA R41 C27 extending below the structural joint could experience stress corrosion prior to the end of Surry's operating life. Unlike secondary side crevices that can develop locally aggressive environments by concentrating impurities in the bulk water, no comparable process occurs in the subcooled primary coolant; hence, the tube material in this location is not expected to corrode any more aggressively than that of in-service tubes. Should tube material corrosion occur in this location, the consequences are bounded by discussions above pertaining to the as-found perforated condition of the tube end.

As a routine part of the Surry SG program, each time primary side tube inspections are performed in a SG, a visual examination of the hot and cold leg plugs is also performed in that SG. These examinations will continue to be performed in the future. In the unlikely event that significant tubesheet corrosion occurs in tube SGA R41 C27, it would be revealed during the visual examination, indicated by corrosion product deposition on the end of the plug, and/or as plug denting. These inspections, the presence of the plug, and the location of the defect more than 17 inches below the top of the expansion transition provide reasonable assurance that this condition will not cause the steam generator structural or leakage performance criteria to be violated during future operation.

As discussed earlier, the identified channel head damage was characterized and evaluated in detail in Reference 17. Ultrasonic examination of the tubesheet-to-channel-head transition region confirmed that no degradation extended into the base material, and a conservative evaluation of potential carbon steel corrosion rates concluded that the condition is acceptable for continued service without repair for the remaining licensed life of the unit.

Foreign Obiect Wear The foreign object related flaws identified were scrutinized using bobbin and +Point probe techniques. Eddy current testing confirmed that no objects remain adjacent to any of the flaws identified during this inspection, and all but the two shallow indications (SGA R17 C16, SGA R18 C16) were visually confirmed to be absent of adjacent foreign objects. Hence, no objects remain adjacent to any volumetric flaws left in service following this inspection. The remaining Page 2 1

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 flaws have no capacity to continue progressing during future operation and pose no future threat to the structural integrity of the affected tubes. SG "C" contained the only newly identified objects which could conceivably cause tube damage and were removed during this outage; hence, they pose no future threat to tube integrity.

The potential for undetected foreign object wear and the development of new foreign object wear during the ensuing operating intervals in each SG must be considered. It is difficult to predict if and when foreign object wear, a random and inherently unpredictable phenomenon, will occur. However, by examining the aggregate operating history of the Surry Unit 2 SGs with respect to foreign object wear, a judgment of the risk can be developed. The end of cycle 20 (replacement cycle 16) inspections revealed significant foreign object wear flaws in SG " A ;

however, none exceeded the structural integrity performance criteria despite the fact that the SG had operated for three cycles since its last inspection. More broadly, for the last 20 years the SGs have often been operated for three cycles between inspections, yet no foreign object wear exceeding the performance criteria has been detected during that period. Future operating intervals will be limited to two fuel cycles, further reducing the risk of exceeding SG performance criteria. Robust secondary side visual examinations were performed in all three SGs during this outage and identified objects of significance were removed from the SGs.

Based on these observations, there is reasonable assurance that foreign object wear will not result in damage that exceeds the structural performance criteria prior to the next inspection of any of the three SGs.

3.4 Operational Leakage Although there are no findings indicative of a concern, sensitivity to primary-to-secondary leakage events will continue with conservative monitoring procedures. Incorporation of industry recommended limits, as indicated in Revision 2 to the EPRl Primary-to-Secondary Leakage Guideline, has been completed.

3.5 Projected Accident Leakage Tubes with degradation exceeding the Technical Specification plugging limit have been removed from service by plugging. Additional assurance that the tube with tube end damage will not cause significant or unacceptable accident leakage is provided via the H* bases described in detail in section 2.1.2. Since none of the identified degradation mechanisms are projected to exceed the structural performance criteria prior to the next inspection, and since there is no evidence of tube corrosion, there is reasonable assurance that the accident leakage performance criteria will not be exceeded prior to the next inspection of the Unit 2 SGs.

3.6 Operational Assessment Conclusion Based on the results of the current and past eddy current inspections and secondary side inspections, operation of SG " A for two cycles before the next planned tubing inspection will not cause the structural integrity and leakage performance criteria to be exceeded. If other issues are identified on other Surry steam generators in ensuing inspections, or other relevant industry findings are noted during the inspection of similar model steam generators, review of planned inspection intervals will be conducted per SG Program requirements. The results of the fall 2006 inspection of SG "A indicate that the existing operational assessments for the Unit 2 " 6and "C" steam generators remain valid. No change to the currently anticipated tube inspection of SGs

" B and "C"in spring 2008 is necessary.

Page 22

Serial No. 07-0099 Docket No. 50-281 Enclosure 2 4.0 References Surry Power Station Units 1 and 2 Steam Generator Monitoring and Inspection Plan, SPS-SGMIP-001 Revision 0, dated October 2003 Steam Generator Monitoring Program Pre-Outage Assessment, Surry Unit 2 - Fall 2006, dated October 12,2006 EPRI lnterim Guidance Letter, Rev. 6 Examination Guideline Implementation, Tube Noise Criteria, L. Womack, dated April 30, 2003 Surry Site Specific Eddy Current Analysis Guidelines (SRY-SGPMS-OO2), Revision 11, dated October 1,2006 Capabilities of Eddy Current Data Analysts to Detect and Characterize Defects in SG Tubes" D. H. Harris, 15th Steam Generator NDE Workshop, Long Beach, CA, July 1996, updated 1999.

EPRI, "Steam Generator Integrity Assessment Guidelines: Revision 1," TR-107621-R1, March 2000 Westinghouse Electric Company, WCAP-16095-P, Revision 0, January 2005 Not used EPRI, "Steam Generator Degradation Specific Management Flaw Handbook,"

1001191, January 2001

10. VPAP-0820, Dominion Virginia Plants, Steam Generator Program, October 2003

11. "SG Program Guidelines," NEI 97-06, Rev. 2, May 2005

12. AREVA, "Residual Stress Screening of Long Row SG Tubes in Surry Units 1 and 2,"

5 1-5054387-00, December 6,2004

13. AREVA, "Structural Evaluation of Surry Unit 1 Volumetric Tube Damage," 32-9020613-000, May 10,2006

14. EPRI, "lnterim Guidelines on Revised Structural Integrity Performance Criterion,"

SGMP-IG-05-01, January 17,2005

15. Westinghouse, "Steam Generator Alternate Repair Criteria for Tube Portion Within the Tubesheet at Surry Units 1 and 2," WCAP-16522-NP, December 2005

16. Dominion, "Steam Generator Condition Monitoring Assessment and Operational Assessment, Surry Unit 2 Refueling Outage Inspection, S2-R19 (Replacement EOC15) Spring 2005," April 17,2005

17. Dominion, "Steam Generator Channel HeadKube Sheet Corrosion, Surry Power Station," ET-MAT-06-0002, Revision 0, November 2006

18. AREVA CR2006-4748

19. AREVA, "Corrosion Evaluation of Millstone 2 CEDM IDTB Weld Repair," 51-5016343-01, Revision 1, September 29, 2003 Page 23

Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 ATTACHMENT 1 Three Letter Codes GENERAL CODES ANF ANOMALY NOT FOUND -Indicates that a previously reported anomaly cannot be found within .50" of the location where the anomaly was previously called.

ANR ANOMALY NOT REPORTABLE - lndicates that a previously reported anomaly does not meet the present reporting criteria.

BDA BAD DATA (retest) lndicates that the data for the specified tube is not acceptable for analysis due to poor signal quality. The tube will be re-tested to the required extent.

INF INDICATION NOT FOUND - lndicates that a previously reported INDICATION has not been found in the data being analyzed or that a tubelsignal is being re-tested for positive identification (PID) and no signal is present in the retest data.

INR - INDICATION NOT REPORTABLE - Indication called in previous inspections that are still detectable but fall below current reporting criteria.

LAR - Lead Analysts Review - Condition not directly covered by the guidelines, ETSS, or other documentation that the data analyst feels should be brought to the attention of the resolution andlor job lead analyst. Diagnostic testing or PID verifications that the analyst believes are not the correct tube number and/or the correct tube location shall be identified as LAR.

NDD NO DETECTABLE DISCONTINUITY - The recorded data has no signal responses meeting the criteria established in the Site Specific Analysis Guidelines for degradation, damage precursors or anomalies.

NDF - No Degradation Found - Used to address a special interest location where no signal meeting the RC criteria (MBM, DNT, etc) is present. Location of rotating coil data verses the bobbin coil shall be verified to ensure correct location was inspected.

NT - NO TEST (re-test) - lndicates that the tube ROW, COLUMN was encoded on the tape; however, no inspection data was recorded for analysis.

OBS OBSTRUCTED - Blockage of a tube that prevents passage of a defined minimum size probe through the tube.

PID - POSITIVE IDENTIFICATION - Verification of a signal at the same reported ROWICOL and at the same reported tube location.

PLG PLUG - lndicates that the tube at the specified location has been plugged.

PVN - PERMEABILITY VARIATION - Condition where the test coil impedance changes due to a change in the tubing materials inherent tendency to conduct magnetic flux lines.

PLP - POSSIBLE LOOSE PART - lndicates the possible presence of a loose part in the generator.

RST RESTRICTED - Blockage of a tube that prevents passage of a probe beyond a specified location within the tube.

TIU TUBE I.D. UNCERTAIN (re-test) - lndicates that the ROW andlor COL identifier for a given tube is in doubt.

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Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 ATTACHMENT 1 (Continued)

BOBBIN CODES BLG BULGE - An area along the tube where the diameter of the tube has been abruptly deformed in an outward direction as compared to the nominal tube diameter.

CUD COPPER DEPOSIT The presence of copper deposits on the outside of the tube.

DNT - DENT - An area along the tube where the diameter of the tube has been abruptly reduced compared to the nominal tube diameter.

LGV LOCAL GEOMETRIC VARIATION - A local reduction in tube diameter usually associated with a localized change in conductivity of the tube. LGV signals are caused by dings introduced during manufacturing/installation process and do not represent a discernible wall loss. The signals must be verified by history review to be called with bobbin (See rotating probe DNG code).

MBM - MANUFACTURING BURNISH MARK A tubing condition where localized tubing imperfections were removed by buffing and are detectable due to the effects of cold working and minor localized wall thinning. The signal must be verified by history review to be called with bobbin.

MMB - MULTIPLE MANUFACTURING BUFF MARK - Multiple MBM signals in close proximity over a length of tube. The signals must be verified by history review to be called with bobbin.

NQI - NON-QUANTIFIABLE INDICATION -A bobbin signal requiring rotating coil examination for disposition.

NQN NON-QUANTIFIABLE NONDEGRADED A bobbin signal which was formally classified as NQI but has been determined to be anomalous or of a type which does not represent degradation.

PDS POSTIVE DRIFT SIGNAL - Long (several inches to several feet) drift signals evident on absolute channels caused by variations in tube concentricity associated with the pilgring process. The signals may be located at random elevations and are generally only in one leg of the tube.

PTE PARTIAL TUBE EXPANSION - Code used when only some portion of parent tube has been expanded into the carbon steel tube sheet. PTE shall be reported at the axial location(s) where nominal tube expansion ends and the partial begins, from the 4001100 mix channel. Bobbin andlor rotating coil data shall be carefully analyzed in the non-expanded crevice region.

NTE NO TUBE EXPANSION - Code used when the parent tube has NOT been expanded into the carbon steel tube sheet from the top of the tube sheet to approximately 2 . 5 from the tube end. NTE shall be reported from the 400/100 mix channel, location as TSH +0.00. Bobbin and/or rotating coil data shall be carefully analyzed in the non-expanded crevice region.

ROTATING PROBE CODES DNG DING - A localized inward displacement of the tube caused by a mechanical impact on the OD surface.

MAA MULTIPLE AXIAL ANOMALY - Multiple axially oriented signals located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

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Serial No. 07-0099 Docket No. 50-28 1 Enclosure 2 ATTACHMENT 1 (Continued)

MCA - MULTIPLE CIRCUMFERENTIALLY ORIENTED ANOMALY - Multiple circumferentially oriented signals located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

MA1 MULTIPLE AXIAL INDICATION - Multiple axially oriented signals that the rotating coil data shows to result from flaws in the tube.

MBM MANUFACTURING BURNISH MARK A tubing condition where localized tubing imperfections were removed by buffing and are detectable due to the effects of cold working and minor localized wall thinning.

MCI MULTIPLE CIRCUMFERENTIALLY ORIENTED INDICATION - Multiple circumferentially oriented signals reported from rotating probe data that the rotating coil data shows to result from flaws in the tube.

MMB - MULTIPLE MANUFACTURING BUFF MARK - Multiple MBM signals in close proximity over a length of tube.

NQN - NON-QUANTIFIABLE NONDEGRADED -A bobbin NQI signal which is determined to be anomalous or not to represent degradation.

PIT PIT Localized attack on tubing resulting from non-uniform corrosion rates caused by the formation of local corrosion cells. At Surry, the condition produces small volumetric indications with approximately the same axial and circumferential extent.

SAA - SINGLE AXIAL ANOMALY - A single axially oriented signal located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

SCA SINGLE CIRCUMFERENTIALLY ORIENTED ANOMALY A single circumferentially oriented signal located at the top of the tube sheet that the rotating coil data shows to result from an anomalous condition in the tube.

SAI SINGLE AXIAL INDICATION - A single axially oriented signal that the rotating coil data shows to result from a flaw in the tube.

SCI SINGLE CIRCUMFERENTIALLY ORIENTED INDICATION A single circumferentially oriented signal that the rotating coil data shows to result from a flaw in the tube.

VOL VOLUMETRIC - lndications of volumetric wall loss indicative of general localized thinning, wear or impingement.

SVllMVl SINGLE VOLUMETRIC INDlCATlONlMULTlPLEVOLUMETRIC INDICATIONS - Indications of volumetric wall loss indicative of general local inter-granular attack (IGA or IGNSCC).

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Serial No. 07-0099 Docket No. 50-281 Enclosure 2 ATTACHMENT 2 Surry Steam Generator Sketches Page 1

Serial No. 07-0099 Docket No. 50-281 Enclosure2

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Model 51F