ML11154A101

Steam Generator Tube Inservice Inspection Report for the 2010 Refueling Outage

ML11154A101
Person / Time
Site:	Surry
Issue date:	05/24/2011
From:	Gerald Bichof Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
11-289, SPS-LIC/CLG R0
Download: ML11154A101 (16)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 May 24, 2011 United States Nuclear Regulatory Commission Serial No.11-289 Attention: Document Control Desk SPS-LIC/CLG RO Washington, DC 20555-0001 Docket No. 50-280 License No. DPR-32 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNIT 1 STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE 2010 REFUELING OUTAGE Technical Specification 6.6.A.3 for Surry Power Station Units 1 and 2 requires the submittal of a Steam Generator Tube Inspection Report to the NRC within 180 days after T-avg exceeds 200°F following completion of an inspection performed in accordance with Technical Specification 6.4.Q, Steam Generator Program. Attached is the Surry Unit 1 report for the Fall 2010 refueling outage.

If you have any questions or require additional information, please contact Mrs. Candee G. Lovett at (757) 365-2178.

Very truly yours, G. T. Bischof  %-

Site Vice President Attachment Commitments made in this letter: None Po( fidlL

Serial No.: 111-289 Docket No.: 50-280 Page 2 of 2 cc: U.S. Nuclear Regulatory Commission Region II Marquis One Tower 245 Peachtree Center Avenue NE Suite 1200 Atlanta, GA 30303 Ms. K. R. Cotton NRC Project Manager U. S. Nuclear Regulatory Commission Mail Stop 0 8 G-9A One White Flint North 11555 Rockville Pike Rockville, Maryland 20852 Mr. J. S. Wiebe NRC Project Manager U. S. Nuclear Regulatory Commission Mail Stop 0 8 G-9A One White Flint North 11555 Rockville Pike Rockville, Maryland 20852 NRC Senior Resident Inspector Surry Power Station Mr. R. A. Smith Authorized Nuclear Inspector Surry Power Station

Serial No.: 11-289 Docket No.: 50-280 ATTACHMENT SURRY UNIT 1 STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE FALL 2010 REFUELING OUTAGE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

Serial No.: 11-289 Docket No.: 50-280 SURRY UNIT 1 STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE FALL 2010 REFUELING OUTAGE The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement in TS 6.6.A.3. During the Surry Unit 1 Fall 2010 (EOC23) refueling outage, Steam Generator (SG) inspections in accordance with TS 6.4.Q were completed for all three SGs.

The Unit 1 SGs were in the 3 rd inspection period which had a duration of 60 Effective Full Power Months (EFPM). The Fall 2010 outage was the last outage of the 3 rd period.

TS 6.6.A.3 requires a SG Tube Inspection Report to be submitted to the NRC within 180 days following the unit exceeding 200'F. Unit 1 exceeded 200'F on November 26, 2010; therefore this report is required to be submitted by May 25, 2011. At the time of this inspection, the current SGs had operated for 267.6 EFPM since the first inservice inspection.

For EOC23, an alternate tube repair criterion (ARC) was incorporated into the Surry Technical specifications to allow tubes with service-induced flaws located greater than 16.7 inches below the top of the tubesheet to not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 16.7 inches below the top of the tubesheet would be plugged upon detection. Associated with the ARC is a requirement to perform a one-time eddy current testing (ECT)-based measurement of the bottom of the expansion transition (BET) location for each tube on both the hot leg and cold leg. No significant deviation from the assumed BET value was found during a historical review of ECT data.

In the discussion below Bold Italicized wording represents TS verbiage and the required information is provided directly below each reporting requirement. A list of acronyms is attached at the end of this report.

A report shall be submitted within 180 days after Tavg exceeds 200°F following completion of an inspection performed in accordance with the Specification 6.4.Q, "Steam Generator(SG) Program." The reportshall include:

a. The scope of inspectionsperformed on each SG The planned eddy current examination scope is identified below in Table 1. Scope expansions were implemented to bound foreign objects and foreign object related degradation, and to resolve ambiguous ("special interest") indications. In addition, the detection of a linear circumferential indication at the hot leg expansion transition in SG "C" (location SGC R30 C21 TSH) prompted expansion of the rotating probe inspection scope to include:

• 100% +Point examination of hot leg expansion transition region in SG "C"

• 20% +Point examination of cold leg expansion transition region in SG "C"

• Ghent probe and UT probe examination of SG "C" R30 C21 TSH No additional circumferential linear indications were identified as a result of this scope expansion. A complete summary of the tube examinations performed during the EOC23 outage is provided in the final inspection status (Table 2).

Page 1 of 13

Serial No.: 11-289 Docket No.: 50-280 Table 1 - EOC23 Planned ECT Examination Scope Scope SG "A" SG "B" SG "C" Bobbin probe: 178 100% 120 Full Length (except Row 1 and 2 U-bends) Exams Exams Rotating Probe: 100% 75% 29%

H/L Expansion Transition (TSH+/-3") Sample Sample Rotating Probe: 50%

Tubes with H/L OXP indications Sample (TSH-1 7.7" to TSH+3") Sample Rotating Probe:

Tier 1 High Stress Tubes 100% 100% 100%

(TSH-1 7.7" to TSH+3")

Rotating Probe: 100% 100% 100%

Tier 2 High Stress Tubes (TSH+/-3")

Rotating Probe: 100%

Row 1 and 2 U-bends (07C to 07H)

Rotating Probe: 20%

C/L Expansion Transition (TSC+/-3")

Rotating Probe: 528 C/L Periphery (50% five tubes deep, Exams TSC+/-3")

Rotating Probe: 20 Largest Voltage C/L OXPs Exams (TSC-1 7.7" to TSC+3")

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Serial Nc.: 11-289 Docket No.: 50-280 Table 2 - EO0C23 Actual ECT Examination Scope (Final Inspection Status)

SG "A" SG "B" SG "C" Scope Description Extent Acquired Acquired Acquired Bobbin Coil Exams ___....__ ....

Full Length TEHTEC 184 3047 138 C/L Candy Cane 7HTEC - 94 -

(Row 3)

C/L Straight (Row 1-2) 7CTEC - 179 H/L Straight (Row 1-3) 7HTEH - 273 MRPC Exams ____..

H/L Tubesheet (NTE) TEHTSH - - 6 H/L Tubesheet TSH TSHTSH 18 268 3

+3/-17.7 H/L Tubesheet TSH TSHTSH 3286 2431 1084

+/-3 Expansion TSH +/-3 TSHTSH - - 2223 C/L Tubesheet (NTE) TECTSC - 3 C/L Tubesheet TSC TSCTSC - 20 -

+3/-17.7 C/L Tubesheet (TSC TSCTSC 711 531 7

+/-3)

Expansion TSC +/-3 TSCTSC - - 669 U-bend RPC (R 1-2) 7C7H - 179 -

Special Interest__ _______

H/L Previous DNT >2V Various - 93 H/L Previous Indications Various - 20 -

H/L Bobbin Indications Various 6 18 1 C/L Previous DNT >2V Various - 3 -

C/L Previous Indications Various 2 - -

C/L Bobbin Indications Various 16 19 0 U-bend Previous DNT Various - 2 -

>2V U-bend Bobbin Various 11 1 0 Indications Bounding Tubes (TSC) TSCTSC 54 0 0 Bounding Tubes (TSH) TSHTSH - 0 0 Bounding Tubes Various 8 44 16 (Non TS)

Select Tube RPC Various 0 9 8 Ghent Probe Exams Various - - 10 Mag Bias Exams TSHTSH - 1 Total 4296 7231 4169 Page 3 of 13

Serial No.: 11-289 Docket No.: 50-280 The primary side workscope also included a video / visual examination of all six channel heads (as-found / as-left), specifically including all plugs, as well as the divider plate weld region. No anomalous conditions associated with the divider plate, previously installed plugs, or plugs installed during this outage were observed.

Secondary Side During the Surry Unit 1 EOC23 outage, secondary side visual examinations were performed at the top of the tubesheet in all three SGs and at selected flow distribution baffle plate locations in SGs "B" and "C." No adverse conditions were noted. As a preventive measure to address flow assisted corrosion (FAC) historically observed in the feedrings, the feedrings were replaced in all three SGs. Foreign Object Search And Retrieval (FOSAR) examinations were performed in each SG at the top of the tubesheet, in the annulus and no-tube lane.

b. Active degradationmechanisms found Degradation mechanisms targeted by the inspection plan included anti-vibration bar (AVB) wear, pitting, foreign object wear, tube support wear, and stress corrosion cracking (SCC) at various locations within the steam generator tube bundle. AVB wear, foreign object wear, one legacy tube support plate wear flaw, one legacy pit indication, and one legacy sludge lance wear flaw were detected. In addition, circumferential outside diameter stress corrosion cracking (ODSCC) was detected in one tube at the hot leg top of tubesheet in SG "C". Lists of service induced indications are provided in the TS 6.6.A.3.d discussion.

A one-time ARC was incorporated into the Surry Technical Specifications, effective during the EOC23 outage and during the operating cycle subsequent to the EOC23 outage. This ARC specifies that tubes with service-induced flaws located greater than 16.7 inches below the top of the tubesheet do not require plugging. Further, the ARC requires that tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 16.7 inches below the top of the tubesheet be plugged upon detection. No such degradation was identified during the current outage inspection.

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Serial No.: 11-289 Docket No.: 50-280

c. Nondestructive examination techniques utilized for each degradationmechanism The inspection program focused cn the degradation mechanisms listed in Table 6 and utilized the referenced eddy current techniques.

Table 6 - Inspection Method for Applicable Degradation Modes

-Degradation Classification Mechanism Location P robe Type, Existing Tube Wear Anti-Vibration Bars Bobbin - Detection and Sizing Bobbin and +Pointla- Detection Existing OD Pitting Top-of-Tubesheet +PointTM- Sizing Bobbin - Detection Existing Tube Wear Tube Support Plate Boin - Sion

+Pointr - Sizing Tube Wear Bobbin and +PointTM - Detection Existing (foreign objects) Freespan and "S +PointM- Sizing Existing ExistingPWSCC Hot Leg Top-of-Tubesheet +PointM- Detection and Sizing Existing PWSCC Tube Ends N/A (1)

Bobbin BointTM - Detection ection Potential Tube Wear Flow Distribution Baffle

+Point m- Sizing Bulges, Dents, Manufacturing Potential ODSCC Anomalies, and +PointM - Detection and Sizing PWSCC Above-Tubesheet Overexpansions (OVR)

Potential ODSCC Tubesheet Tubes withCrevice NTEs in +PointTM - Detection and Sizing Potential Tube Slippage Within Tubesheet Bobbin Detection Tubesheet +PointTM - Detection and Sizing Potential PWSCC Overexpansions (OXP)

Potential ODSCC Row 1 and 2 U-bends +PointM - Detection and Sizing PWSCC Potential ODSCC Freespan and Tube Supports BointTMection

+Point - Sizing (1) Inspection for this mechanism was not necessary under the "one-time" alternate repair criteria incorporated into the Surry Technical Specifications prior to EOC23.

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Serial No.: 11-289 Docket No.: 50-280

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications As stated in the TS 6.6.A.3.b discussion above, several wear type indications were noted.

Tables 8 and 9 provide the information for these indications.

One circumferentially oriented linear indication judged to have been caused by ODSCC at the hot leg expansion transition (top-of-tubesheet (TTS)) was identified in SG "C" (SGC R30 C21).

The indication had an overall circumferential extent of 730, an amplitude of 0.62 Volts

(+Point TM 300 kHz), and a percent degraded area (PDA) of 3.5.

Table 8 - AVB Indications Depth (%TW)

(ETSS Ro AVB 96004.1)

SG w Col No. 2007 2010 B 26 61 AV3 11 10 B 31 33 AV2 - 17 B 32 26 AV3 10 10 B 34 58 AV2 22 20 B 34 58 AV3 17 15 B 35 17 AV2 "10 11 B 35 17 AV3 20 19 B 38 21 AVI 13 10 B 38 21 AV2 - 13 B 38 22 AV2 - 10 B 39 36 AV3 - 10 B 40 25 AV2 21 18 B 40 26 AV2 - 10 B 41 27 AV2 11 11 B 41 27 AV3 8 11 B 42 29 AV2 15 15 B 42 30 AV2 - 13 B 42 30 AV3 - 12 B 43 34 AV3 12 B 46 45 AV2 15 Page 6 of 13

Serial No.: 11-289 Docket No.: 50-280 Table 9 - Summary of Non-AVB Wear Volumetric 1 T Foreign Max Depth Axial Lengtl Circ. Length Initially Signal Present Prior to Object In-Situ Plugged &

SG Row Col Location ETSS (0 "rw) (in) (in) Reported Current Outage? Cause Remaining? Tested? Stabilized?

Yes. No change since TSP A 2 57 06C-0.42" 96910.1 22 0.29 0.38 2006 nial reported.

initially ro rte Wear Wear n/a No No A 3 66 05C-0.75" 27901.1 29 0.29 0.38 2009 Yes. No change initially since reported. Foreign No No No Object A 6 88 TSH+0.31" 27901.1 26 0.30 0.37 2006 Yes. No change since Foreign No No No I_ II_ Iinitially reported. Object A 8 38 TSH+0.36" 21998.1 19 0.33 0.37 2001 Yes. No change since Legacy Pittin No No No I initially reported. Legacy Pittin __No No No A 34 67 TSH+0.01' 27901.1 25 0.27 0.34 2006 Yes. No change since Foreign No No No

_ _ _ _ _initially reported. Object No No No A 38 30 TSC+1.78" 27901.1 20 0.27 0.38 2006 Yes. No change since Foreignr No No No initially reported. Obect _

Historical B 1 7 TSH+0.27" 21998.1 26 0.82 0.37 2007 Yes. No change since SG Maint- No No No initially reported. enance B 31 15 BPH+0.56" 27901.1 21 0.30 0.40 2010 Yes (2003). Foreigrf No No No Change 2003 to 2010. Object B 31 16 BPH+0.56 27901.1 23 0.36 0.45 2010 Yes(2003). Foreigrf No No No Change 2007 to 2010. Obiect B 32 15 BPH+0.49" 27901.1 19 0.33 0.42 2010 Yes (1998). Foreigrf No No No

- Change 2003 to 2010. Obiect B 32 18 BPH+0.54" 27901.1 19 0.30 0.42 2010 Yes (2007). Foreigrf No No No B 32 - Change 2007 to 2010. Obiect B 33 18 BPH+0.55" 27901.1 22 0.30 0.48 2010 Yes (2003). Foreigrn No No No I_ _ II_-_IChange 2007 to 2010. Object B 35 20 BPH+1.13" 27902.1 16 0.63 0.45 2010 Yes (1998). Foreigrf No No No No change 1998 to 2010. Object Foreign B 37 22 02H-0.74" 27901.1 24 0.30 0.34 2010 No FOrign No (by ECT) No Yes FObject B 38 21 02H-0.59" 96910.1 28 0.33 0.42 2010 No Foreign Yes (by ECT No Yes I____ I________I___ Object ____ ____

B 40 50 TSH+0.27" 27901.1. 31 0.33 0.42 2007 Yes. No change initially since reported. Foreign No No No Object B 40 51 TSH+0.34" 27901.1 35 0.36 0.45 2007 Yes. No change since Foreign No No No initially reported. Object B 41 51 TSH+0.17" 27901.1 25 0.22 0.37 2007 Yes. No change since Foreign No No No initially reported. Object C 27 82 BPH+0.57' j

27901.1 30 0.38 0.46 2010 YFNo Yes (2000).

No change since 2000.

Foreign Object ____

N Noo I No N

C 38 66 I

TSC+0.17' 27901.1 29 F 0.42 0.49 2009 Yes. No change since initially reported.

Foreign Object No No No V Formerly categorized as legacy pitting, now categorized as foreign object wear due to proximity to piece of wire which is lodged in place.

• This is the most likely cause based upon the flaw location which is slightly above the FDB. History review of available bobbin data indicates no PLP signal.

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Serial No.: 11-289 Docket No.: 50-280

e. Number of tubes plugged during the inspection outage for each active degradation mechanism Twenty tubes were plugged during tie EOC23 cutage (SG "A' = 6, SG "B" = 4, SG "C" = 10).

These tubes are identified in Tables 10 thro*gh 12. The bases for plugging performed during EOC23 are discussed in more detail below.

Hot Leq ODSCC .5 Top-of-Tubesheet One indication of ODSCC at the hot leg TTS was ;dentified in SGC R30 C21. SCC in this region of the tube bundle requires repair upon detection. This tube was stabilized and removed from service by plugging.

AVB Wear Indications (Bobbin 100% Program):

No AVB wear indications exceeding the 40 % through wall (TW) technical specification plugging limit or the 30 % TW preventive plugging limit for AVB wear were reported.

Non-AVB-Wear Volumetric Deqradation Two tubes, both in SG "B," with indications of volumetric degradation on the hot leg side of the 2 nd tube support plate (TSP) were identified during the EOC23 examinations. Since the wear in these tubes was due to a suspected possible loose part (PLP) that could not be visualiy verified (due to being on the upper side of the 2 nd TSP) both tubes were plugged and stabilized. The corresponding depth of each wear indication was 24 % TW (R37 C22) and 28 % TW (R38 C21).

One-Time Alternate Repair Criteria As a condition for the approval of the one-time ARC. Surry committed to remove from service all tubes having partial tubesheet expansion (PTE) or no tubesheet expansion (NTE). None of the Surry tubes have been identified as having PTEs; however 9 tubes have NTEs (all are in SG "C"). All of these tubes were plugged during the EOC23 outage.

During the development of the one-time ARC, it was assumed that the distance between the secondary tubesheet face and the BET was equal to 0.3 inches. Associated with the ARC is a requirement to perform a one-time ECT-based measurement of BET location for each tube on both the hot !eg and cold leg in order to confirm that there are no significant deviations from the assumed BET value. This evaluation was performed for all three Unit 1 steam generators utilizing prior outage ECT bobbin probe data. The evaluation identified tubes whose BET exceeds the assumed 0.3 inch value. The results are summarized in Tables 13 through 15.

The significance of BET locations that exceed the assumed 0.3 inch value was evaluated in Westinghouse document, "Assessment of the Effect of Variation in the Location of the BET on the Licensed Value of H*," LTR-SGMP-09-111, September 22, 2009. This evaluation demonstrated that the margin between the most conservative Monte Carlo calculated 95/95 H-Star value (11.71") and the H-Star depth specified in the Surry Technical Specification (16.7")

is 4.99". Since the calculated H-Star value (11.71") already includes an allowance of 0.3" for the location of the BET, the actual margin is 4.99" + 0.3" or 5.29". in addition, the calculated H-Star value corresponds to tubes located in the most limiting position within the tubesheet matrix. For all other tubes the margin between calculated H-Star value and the Technical Specification Page 8 of 13

Serial No.: 11-289 Docket No.: 50-280 value is even greater than 5.29". In light of this, it was concluded that the maximum BET location measured in the Surry Unit 1 SGs (1.55") does not represent a significant deviation from the assumed value. However, as an extra measure of conservatism, all tubes in which the BET location exceeds 1.0 inches were preventively plugged (six in SG "A," two in SG "B").

Table 10 - SG "A" EO023 Tube Plugging List SG Row Col Hot Leg i Cold Leg Repairfor.

~Reason STAB BHX with A 34 40 ROLLED ROLLED location NO offset < 1.0" BHX with A 35 40 ROLLED ROLLED location NO offset < 1.0" BHX with A 36 40 ROLLED ROLLED location NO offset < 1.0" BHX with A 37 40 ROLLED ROLLED location NO offset < 1.0" BHX with A 39 37 ROLLED ROLLED location NO offset < 1.0" BHX with A 43 40 ROLLED ROLLED location NO offset < 1.0" Table 11 - SG "B" EOC23 Tube Plugging List SG Row Col Hot Leg Cold Leg Reason for STAB Repair BCX with B 4 41 ROLLED ROLLED location NO offset < 1.0" BCX with B 4 51 ROLLED ROLLED location NO offset < 1.0" B 37 22 ROLL/STAB ROLLED FO WAR @ Yes 2H-0.74 B 38 21 ROLL/STAB ROLLED FO WAR @ Yes 2H-0.59 Page 9 of 13

Serial No.: 11-289 Docket No.: 50-280 Table 12- SG "C" EO0C23 Tube Plunnina List SG Row Col Hot Leg Cold Leg Reason for STAB Repair ___

C 12 35 ROLLED ROLLED Cold Leg NO NTE C 19 25 ROLLED ROLLED Cold Leg NO NTE C 26 10 ROLLED ROLLED Hot Leg NO NTE C 30 21 ROLL/STAB ROLLED SCI @ TSH- YES 0.03 C 35 42 ROLLED ROLLED Hot Leg NO NTE C 39 42 ROLLED ROLLED Hot Leg NO NTE C 39 43 ROLLED ROLLED Hot Leg NO NTE C 41 53 ROLLED ROLLED Cold Leg NO NTE C 42 45 ROLLED ROLLED Hot Leg NO NTE C 46 49 ROLLED ROLLED Hot Leg NO NTE Table 13 -- Number of BET Locations Exceeding 0.3 Inches Hot Leg Cold Leg SG A 869 61 SG B 33 256 SG C 198 10 Table 14 -- Number of BET Locations Exceeding 1.0 Inches Hot Leg Cold Leg SGA 6 0 SG B 0 2 SG C 0 0 Page 10 of 13

Serial No.: 11-289 Docket No.: 50-280 Table 15 -- Maximum Measured BET Location by SG Leg

f. Total number and percentage of tubes plugged to date Table 16 provides the plugging totals and percentages to date.

Table 16- Tube Plugging Summary Tubes Plugged Tubes Installed To Date To Date SG A 3,342 44(1.3%)

SG B 3,342 26 (0.8%)

SG C 3,342 36(1.1%)

Total 10,026 106 (1.1%)

g. The results of condition monitoring, including the results of tube pulls and in-situ testing None of the tube degradation identified in Surry Unit 1 SGs during the EOC23 outage violated the structural performance criteria, thereby providing reasonable assurance that none of these flaws would have leaked during a limiting design basis accident.

Based on the evaluations documented, all degradation identified during the fall 2010 inspection satisfied condition monitoring requirements for SG tube structural and leakage integrity.

Therefore, tube pulls and in-situ pressure testing were not necessary.

h. The effective pluggingpercentage for all plugging in each SG Since none of the Surry Unit 1 SG tubes have been sleeved, the effective plugging percentage is identical to the plugging percentages provided in the response to the TS 6.6.A.3.f discussion above.

i. For Unit I during Refueling Outage 23 and the subsequent operating cycle ... the primary to secondary LEAKAGE rate observed in each SG ... during the cycle preceding the inspection which is the subject of the report During the cycle preceding EOC23, no measurable primary-to-secondary leakage (i.e., >1 gallons per day (GPD)) was observed in any Unit 1 SG.

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Serial No.: 11-289 Docket No.: 50-280

j. For Unit I during Refueling Outage 23 and the subsequent operating cycle ... the calculated accident induced LEAKAGE rate from the portion of the tubes below 16.7 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident induced LEAKAGE rate from the most limiting accident is less than 2.03 times the maximum operationalprimary to secondary LEAKAGE rate, the report should describe how it was determined.

The one-time ARC requires that the component of operational leakage from the prior cycle from below the H-star distance be multiplied by a factor of 2.03 and added to the total accident leakage from any other source and compared to the ailowable accident induced leakage limit.

Since there is reasonable assurance that no tube degradation identified during this outage would have resulted in leakage during an accident, the contribution to accident leakage from other sources is zero. Assuming that the prior cycle operational leakage of <1 GPD originated from below the H-star distance, and multiplying this leakage by a factor of 2.03, yields an accident induced leakage value of <2.03 GPD. This value is well below the 470 GPD limit for the limiting SG and provides reasonable assurance that the accident induced leakage performance criteria would not have been exceeded during a limiting design basis accident.

k. For Unit 1 during Refueling Outage 23 and the subsequent operating cycle ... the results of the monitoring for tube axial displacement (slippage). If slippage is discovered, the implicationsof the discovery and corrective action shall be provided.

The one-time ARC requires routine monitoring for tube slippage within the tubesheet and any tubes showing evidence of slippage require plugging. This condition could only occur if the tube severs circumferentially within the tubesheet, a condition which can be readily detected using bobbin probe inspection data. During the current outage inspection, no indications of tube slippage were identified during the evaluation of bobbin probe examination data from any of the three SGs. Note that only limited bobbin probe examinations were performed in SGs "A" and "C" during EOC23. All tubes in SGs "A" and "C" will be screened for slippage during EOC24.

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Serial No.: 11-289 Docket No.: 50-280 Acronyms ARC Alternate Repair Criteria AVB Anti Vibration Bar BCX Cold Leg BET BET Bottom of the Expansion Transition BHX Hot Leg BET BLG Bulge BPH Baffle Plate Hot C Column CM Condition Monitoring CMOA Condition Monitoring Operational Assessment C/L Cold Leg DEP Deposit DMT Deposit Management Treatment DNG Ding DNT Dent ECT Eddy Current Testing EFPY Effective Full Power Years EOC End of Cycle ETSS Eddy Current Technical Specification Sheets FAC Flow Assisted Corrosion FB Fan Bar FDP Flow Distribution Baffle FO Foreign Object FOSAR Foreign Object Search and Retrieval GPD Gallons Per Day LGV Localized Geometric Variation H/L Hot Leg LPI Loose Part Indication MBH Historical Manufacturing Brandish Mark MBM Manufacturing Burnish Mark MRPC Motorized Rotating Pancake Coil NOP Normal Operating Pressure NTE No Tube Expansion NQH Non-Quantifiable Historical Indication NQI Non-Quantifiable Indication OA Operation Assessment OD Outer Diameter ODSCC Outside Diameter Stress Corrosion Cracking OVR Over Roll OXP Over Expansion PLP Possible Loose Part PTE Partial Tubesheet Expansion PVN Permeability Variation PWSCC Primary Water Stress Corrosion Cracking

% TW Percent Throughwall R Row RPC Rotating Pancake Coil SG Steam Generator SLG Sludge SAI Single Axial Indication SCI Single Circumferential Indication SSI Secondary Side Inspection STAB Stabilized SVI Single Volumetric Indication Tavg Average Reactor Coolant System Temperature TEC Tube End Cold-leg TEH Tube End Hot-leg TSC Top of Tube Sheet Cold-leg i TSH Top of Tube Sheet Hot-leg TSP Tube Support Plate TTS Top of Tubesheet TW Through Wall UT Ultrasonic Testing VOL Volumetric Indication WAR Wear Indication Page 13 of 13