ML13149A229

Steam Generator Tube Inservice Inspection Report for the Fall 2012 Refueling Outage

ML13149A229
Person / Time
Site:	Surry
Issue date:	05/10/2013
From:	Lane N Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
13-237
Download: ML13149A229 (13)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 May 10, 2013 United States Nuclear Regulatory Commission Serial No.13-237 Attention: Document Control Desk SPS-LIC/CGL RO Washington, DC 20555-0001 Docket No. 50-281 License No. DPR-37 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNIT 2 STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE FALL 2012 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 Tavg 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 2 report for the Fall 2012 refueling outage.

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

Very truly yours, N. L. Lane Site Vice President Surry Power Station

Attachment:

Surry Unit 2 Steam Generator Tube Inspection Report for the Fall 2012 Refueling Outage Commitments made in this letter: None 4 -cý_Q-

Serial No.: 13-237 Docket No.: 50-281 Page 2 of 2 cc: U.S. Nuclear Regulatory Commission Region II Marquis One Tower 245 Peachtree Center Avenue NE Suite 1200 Atlanta, Georgia 30303-1257 Ms. K. R. Cotton NRC Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G9A 11555 Rockville Pike Rockville, Maryland 20852-2738 Dr. V. Sreenivas NRC Project Manager - North Anna U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G9A 11555 Rockville Pike Rockville, Maryland 20852-2738 NRC Senior Resident Inspector Surry Power Station Mr. R. A. Smith Authorized Nuclear Inspector Surry Power Station

Serial No.: 13-237 Docket No.: 50-281 ATTACHMENT I SURRY UNIT 2 180-DAY NRC REPORT REGARDING STEAM GENERATOR TUBE INSPECTION PER TECHNICAL SPECIFICATION 6.6.A.3

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 1 of 10 Surry Unit 2 Steam Generator Tube Inspection Report for the Fall 2012 Refueling Outage The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement section 6.6.A.3. During the Surry fall 2012 refueling outage, steam generator (SG) inspections in accordance with TS 6.4.Q were completed for SG A.

This was the second Inspection in the 4th inspection period which has a duration of 72 Effective Full Power Months (EFPM).

Surry Unit 2 exceeded 200'F on November 30, 2012; therefore, this report is required to be submitted by May 29, 2013. The SGs had operated for 301.8 EFPM at the time of this inspection.

Bold Italicized wording represents TS verbiage. The required information is provided under each reporting requirement as follows:

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. The only scope expansions required were those necessary to bound foreign objects and foreign object related degradation, as well as to resolve ambiguous indications. A complete summary of the tube examinations performed during the outage is provided in the final inspection status (Table 2).

The primary side scope also included a video / visual examination of both SG A channel heads (as-found / as-left), specifically including all plugs, the divider plate weld region, and the bottom of the bowl per Nuclear Safety Advisory Letter (NSAL) 12-01, "Steam Generator Channel Head Degradation."

Localized cladding degradation within the hot leg primary channel head was initially identified during the 2006 outage inspection and was characterized and evaluated in detail. During that outage, 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. This region was visually examined during the fall 2012 outage and no change in the indication was identified.

In addition, during the fall 2012 outage visual examination of the SG A hot leg primary manway flange-face, localized wastage was identified between the gasket seating surface and the bolt circle. This degradation was initially identified and documented during the fall 2006 outage and a comparison of images from 2006 and 2012 confirmed that no advancement of this degradation had occurred during the intervening period. It is likely that the degradation was caused by gasket leakage at some point prior to 2006.

No anomalous conditions other than those discussed above were identified.

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 2 of 10 A summary of the secondary side exams performed during the EOC24 outage is provided below.

• Visual inspection of upper steam drum moisture separator components, feedring components and top of bundle U-bend region components through secondary manway (SG A only). No degradation of these components was detected.

• Post lancing visual inspection of tube-to-shell annulus prior to dismounting of lancing equipment (SGs A, B, and C).

• Post lancing visual inspection of top-of-tubesheet annulus and divider lane region (SGs A, B, and C) including an inner bundle hot leg and cold leg examination in SG A only.

" Visual examination of historical foreign object-related locations (SGs A, B, and C).

• Visual investigation of any accessible locations having eddy current indications potentially related to foreign objects (SGs A, B, and C).

The visual examination performed in the steam drum of SG A indentified two large foreign objects on the upper deck. The objects were later determined to be FME barriers that had been installed during the spring 2011 feedring replacement project and had been inadvertently left in place. The two objects were removed and a visual examination of the top-hats revealed only rub marks at points in contact with the barriers. No associated reduction of material thickness was observed. As a consequence of this finding, SG B and C steam drums were opened and examined to determine if similar objects were present. These examinations identified no foreign objects in either SG.

During the course of post-lancing FOSAR examination, one object (Flexitallic gasket material) was identified and removed from SG A and two objects (flexitallic gasket material and small piece of metal) were identified and removed from SG C. No tube damage was associated with these loose parts.

Table I Primary Side Examination Scope Scope SG A SG B SG C Bobbin probe: 100%

Full Length (except row 1 and 2 u-bends)

Array Probe:

H/L Tubesheet and Expansion Transition Array Probe: 100%

C/L Tubesheet and Expansion Transition Plus Point Probe: 100%

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

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 3 of 10 Table 2 - EOC24 Actual ECT Examination Scope Scope Description Extent S/G A Bobbin Coil Exams Full Length TEHTEC 3034 H/L Straight (Row 1-2)* 7HTEH 185 H/L Candycane (Row 3) 7CTEH 93 C/L Straight (Row 1-3) 7CTEC 277 C/L Candycane (Row 3) 7HTEC 1 Array Exams H/L Array (Non-Baffle TSH1 H 834 Plate)

H/L Array (Baffle Plate) TSHBPH 2478 C/L Array (Non-Baffle TSClC 834 Plate)

C/L Array (Baffle Plate) TSCBPC 2478 MRPC Exams Ubend +PT (Row 1-2) 7H7C 184 Select Tube +PT Various 97 MRPC Special Interest HL Previous Indications Various 26 HL Previous DNT>2V Various 96 HL Indications Various 30 CL Previous Indications Various 3 CL Previous DNT>2V Various 5 CL Indications Various 23 Total 10678

• The H/L Straight exam total includes one row 3 tube.

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 4 of 10

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. Only AVB wear, foreign object wear, and tube support plate wear were detected during the current outage. No SCC was detected.

A permanent ARC (PARC) was incorporated into the Surry Technical Specifications, effective during the EOC24 outage. The PARC specifies that tubes with service-induced flaws located greater than 17.89 inches below the top of the tubesheet do not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 17.89 inches below the top of the tubesheet shall be plugged upon detection.

c. Nondestructive examination techniques utilized for each degradationmechanism Inspections focused on the following degradation mechanisms listed in Table 3 utilizing the referenced eddy current techniques.

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 5 of 10 Table 3 - Inspection Method for ADDlicable Dearadation Modes Classification Degradation Location Probe Type Mechanism Existing Tube Wear Anti-Vibration Bobbin - Detection Bars Bobbin and +PointTM - Sizing Tube Support Bobbin - Detection Plate Bobbin and +PointTM - Sizing Tube Eitn Wear (fore Freespan, TTS, Bobbin and Array - Detection Existing (foreign FDB, TSPs +PointTM - Sizing objects)

Hot Leg Top-of-Tubesheet Bobbin and Array - Detection Sludge Pile +PointTM - Sizing Area At the Tube Inspection not required per Existing PWSCC ends I i re TE + 4 Inches Potential PWSCC Hot Leg Top-of- Array - Detection and Sizing Tubesheet Top-of- Bobbin - Detection Existing OD Pitting Tubesheet +PointTM - Sizing Flow Flow Bobbin - Detection Potential Tube Wear Distribution Bobbin D - ion Baffle Baffle Bobbin and +PointTM - Sizing Potential ODSCC Freespan and Array - Detection Tube Supports +PointTM - Sizing Hot Leg Within Potential PWSCC Tubesheet Array - Detection Anomaly +PointTM - Sizing locations

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 6 of 10

d. Location, orientation(if linear), and measuredsizes (if available)of service induced indications As stated in the (b) response above, several service induced indications were noted. Tables 4 and 5 provide the detailed information regarding these indications.

Table 4- AVB Indications Depth AVB (%TW)

SG Row COL N(ETSS No. 96004.1) 2009 2012 A 25 57 AV2 17 16 A 26 9 AV4 11 12 A 26 86 AV3 22 17 A 28 69 AV3 10 9 A 29 70 AV2 11 11 A 30 12 AV1

• 10 A 30 64 AV2 11 7 A 36 19 AV4

• 14 A 36 62 AV2 24 24 A 36 62 AV3 16 14 A 36 62 AV4 28 27 A 36 66 AV2

• 12 A 36 66 AV3 10 10 A 37 20 AVI

• 13 A 37 20 AV4

• 12 A 38 57 AV1 14 13 A 38 72 AV4 25 23 A 38 74 AV4 19 17 A 40 25 AV4

• 12 A 40 49 AVI 12 11 A 40 49 AV2 10 10 A 40 49 AV3 11 11 A 40 65 AV2 21 18 A 40 65 AV3

• 10 A 40 65 AV4 12 10 A 40 66 AV3 10 9 A 42 29 AV4

• 10 A 44 35 AV2 12 15 A 44 38 AV2

• 11 A 45 44 AV2 12 11 A 46 45 AV1

• 13

• Not reported during that outage.

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 7 of 10 Table 5 - Summary of Non-AVB-Wear Volumetric Degradation Max Axial Circ. Signal Present Foreign Depth Length Length Initially Prior to Current Object SG Row Col Location ETSS (%TW) (in) (in) Reported Outage? Cause Remaining?

A 6 60 5H-0.58 96910.1 7 %TW 0.32 0.42 2009 Yes. No signal TSP n/a change since 2002. Wear A 11 45 TSH+0.88 27901.1 25 %TW 0.21 0.40 2012 Yes. No signal Foreign No change since 2006. Object A 15 16 TSH+0.25 27901.1 24 %TW 0.34 0.40 2012 No signal present Foreign No in 2006 exam. Object A 17 16 TSH+0.05 27901.1 29 %TW 0.34 0.53 2002 Yes. No signal Foreign No change. Object A 18 16 TSH+09 27901.1 27 %TW 0.32 0.40 2002 Yes. No signal Foreign No change. Object A 32 27 TSC+0.02 27901.1 21 %TW 0.30 0.37 2006 Yes. No signal Foreign No change. Object A 33 27 TSC+0.11 27901.1 25 %TW 0.35 0.40 2006 Yes. No signal Foreign No change. Object A 39 24 TSH+0.37 27901.1 20 %TW 0.29 0.42 2009 Yes. No signal Foreign No I _ change since 2006. Object A 42 52 TSC+0.27 27901.1 20 %TW 0.30 0.40 2009 Yes. No signal Foreign No change since 2009. Object A 43 61 BPH+0.54 27901.1 24 %TW 0.34 0.42 2009 Yes. No signal Foreign No change since 2002. Object Yes. Possible minor A 43 64 BPH+0.59 27901.1 24 %TW 0.36 0.40 2009 signal change 2002 Foreign No to 2009. No change Object since. I _I

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 8 of 10

e. Number of tubes plugged during the inspection outage for each active degradation mechanism No tubes required plugging as a result of SG inspections performed during the EOC24 outage.

f. Total number and percentage of tubes plugged to date Table 6 provides the plugging totals and percentages to date.

Table 6 - Tube Pluggging Summary Tubes Installed Tubes Plugged To-Date SG "A" 3,342 30 (0.9%)

SG "B" 3,342 18(0.5%)

SG "C" 3,342 46(1.4%)

Total 10,026 94 (0.94%)

g. The results of condition monitoring, including the results of tube pulls and in-situ testing The condition monitoring assessment of the EOC24/REOC20 structural and leakage integrity concluded that 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. Therefore there was no need to pull tubes or In-situ test.

h. The effective pluggingpercentage for all plugging in each SG Since none of the Surry Unit 2 SG tubes have been sleeved, the effective plugging percentage is identical to the plugging percentages provided in the response to (f).

i. The primary to secondary LEAKAGE rate observed in each SG (if it is not practicalto assign the LEAKAGE to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report During the cycle preceding the EOC24 outage, no measurable primary-to-secondary leakage

(>1 GPD) was observed in any Unit 2 SG.

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 9 of 10

j. The calculated accident induced LEAKAGE rate from the portion of the tubes below 17.89 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 1.80 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

The PARC requires that the component of operational leakage from the prior cycle from below the H-star distance be multiplied by a factor of 1.80 and added to the total accident leakage from any other source, and compared to the allowable 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 1.80 as required by the PARC, yields an accident induced leakage value of <1.8 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. The results of the monitoring for tube axial displacement (slippage). If slippage is discovered,the implicationsof the discovery and correctiveaction shall be provided.

No indications of tube slippage were identified during the evaluation of bobbin probe examination data from SG A. All tubes in SGs B and C were screened for slippage during EOC23 and will again be screened during EOC25.

Serial No.: 13-237 Docket No.: 50-281 Attachment 1 Page 10 of 10 LIST OF ACRONYMS AILPC Accident Induced Leakage Performance Criteria ARC Alternate Repair Criteria AVB Anti-Vibration Bar BET Bottom of Expansion Transition BOC Beginning Of Cycle BPC Baffle Plate Cold BPH Baffle Plate Hot CDS Computer Data Screening C/L Cold Leg CM Condition Monitoring assessment DA Degradation Assessment DMT Deposit Minimization Treatment DNT Dent ECT Eddy Current Test EOC End Of Cycle ETSS Examination Technique Specification Sheet FK Foreign Object Identifier FAC Flow Assisted Corrosion FDB Flow Distribution Baffle FOSAR Foreign Object Search And Retrieval GPD Gallons Per Day H/L Hot leg MRPC Motorized Rotating Pancake Coil NTE No Tube Expansion OA Operational Assessment ODSCC Outer Diameter Stress Corrosion Cracking PDA Percent Degraded Area PLP Possible Loose Part POD Probability Of Detection PTE Partial Tube Expansion PWSCC Primary Water Stress Corrosion Cracking QDA Qualified Data Analyst, REOC Replacement End Of Cycle RPC Rotating Pancake Coil (also a generic term for rotating probes of any kind)

SCC Stress Corrosion Cracking SG Steam Generator SIPC Structural Integrity Performance Criteria SSI Secondary Side Inspection TE Tube End TEC Tube End Cold TEH Tube End Hot TSC Top of Tube Sheet Cold-Leg TSH Top of Tube Sheet Hot-Leg TSP Tube Support Plate TTS Top of Tubesheet TW Through Wall