ML15324A014

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Steam Generator Tube Inspection Report for the Spring 2015 Refueling Outage
ML15324A014
Person / Time
Site: Surry Dominion icon.png
Issue date: 11/06/2015
From: Lane N
Virginia Electric & Power Co (VEPCO)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
15-511
Download: ML15324A014 (13)
v • d • e


Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA~23261 November 6, 2015 United States Nuclear Regulatory Commission Serial No.15-511 Attention: Document Control Desk SPS-LIC/CGL R0 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 INSPECTION REPORT FOR THE SPRING 2015 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 1 report for the Spring 2015 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 1 Steam Generator Tube Inspection Report for the Spring 2015 Refueling Outage Commitments made in this letter: None

~AcoI K{~L

Serial No.: 15-511 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, Georgia 30303-1257 Ms. K. R. Cotton Gross NRC Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 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 G-9A 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.: 15-511 Docket No.: 50-280 ATTACHMENT SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE SPRING 2015 REFUELING OUTAGE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

Serial No.: 15-511 Attachment Docket No.: 50-280 bc pagel1 of 10 SURRY UNIT I STEAM GENERATOR TUBE INSPECTION REPORT FOR THE SPRING 2015 REFUELING OUTAGE The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement section 6.6.A.3. During the Surry Unit 1 Spring 2015 refueling outage (RFO),

steam generator (SG) inspections in accordance with TS 6.4.Q were completed for SG A and SG C.

This was the second inspection in the 4th inspection period which has duration of 72 effective full power months (EFPM).

Surry Unit 1 exceeded 200°F on May, 24 2015; therefore, this report is required to be*

submitted by November 20, 2015. The Surry Unit 1 SGs were replaced during Refueling Outage 5 (1981) and have accrued approximately 27.8 effective full power years (EFPY) of operation as of April 2015. Programmatically, the first sequential period begins after the first inservice inspection, thus the current SGs have accrued 317.7 EFPM.

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 included at the end of the 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 report shall include:

a. The scope of inspections performed on each SG, A summary of the tube examinations performed during the outage is provided in Table 1.

The primary side inspection activities included an as-found and as-left video/visual examination of both channel heads in SG A and SG C, specifically including:

  • All plugs; there was no evidence of plug leakage.
  • The divider plate weld region; no indications of degradation.
  • The bottom of the bowl per NSAL-12-1 and NRC IN 2013-20 with the bowl dry.

No abnormal or degraded conditions were identified.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 2 of 10 Table 1 - Primary Side Examination Scope Scope Description Extent SG AExams Cmped SGCoCExams ltd Bobbin Coil Exams Full Length TEC TEH 2838 2844 H/L Straight (Row 1-2) 07H TEH 182 185 H/L Candycane (Row 3-5) 070 TEH 277 277 C/L Straight (Row 1-5) 070 TEC 459 458 O/L Candycane (Row 3) 07H TEC 0 4 Restricted Tubes Various 2 2

  • Array Exams ______

H/L TSH Array (Baffle Plate) BPH TEH 2463 2469 H/L TSH Array (Non-Baffle Piate) 01H TEH 835 837 O/L TSC Array (Baffle Plate) BPC TEC 2463 2469 C/L TSC Array (Non-Baffle Plate) 010 TEC 835 837 Low Row U-bend MRPC Exams________________

U-bend +Point (Row 1-2) 070 07H 181 183 MRPC Special Interest U-bend Historical Spec Int Various 2 2 HIL Historical Spec Int Various 222 205 O/L Historical Spec Int Various 6 5 U-bend 1R26 Spec Int Various 15 1 HIL 1R26 Spec Int Various 16 39 C/L 1R26 Spec Int Various 47 24 Mag Bias Spec Int Various 3 8 1R26 PLP Bounding 02H 02H 0 8 Note: The H/L and C/L Array Exams were analyzed down to the H-star dimension.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 3 of 10 The following secondary side SG activities were performed during the Spring 2015 RFO:

SGs A, B. and C:

  • Upper bundle flush, sludge lancing, and post-lancing visual examination of the top-of-tubesheet annulus and no-tube lane to identify and remove any retrievable foreign objects (FOSAR).
  • Visual examination of historical foreign object-related locations identified in the Degradation Assessment.
  • Visual investigation of any accessible locations having eddy current signals potentially related to foreign objects.

No degradation or adverse conditions were noted.

SG A:

  • Visual examination of accessible steam drum components and structures (including the feedring exterior), the upper tube bundle, and 7 th TSP via probe drops through the primary moisture separators. No degradation or adverse conditions were noted during this inspection.
b. Degradation mechanisms 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, tube support plate wear, one legacy pit indication, and one legacy sludge lance wear flaw were detected. No SOC was detected.
c. Nondestructive examination techniques utilized for each degradation mechanism, Inspections focused on the degradation mechanisms listed in Table 2 utilizing the referenced eddy current techniques.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 4 of 10 Table 2 - Inspection Method for Applicable Deciradation Modes Classification Degradation LoainPbeTp Mechanism LoainPbeTp Exsig Tb er Anti-vibration Bobbin - Detection Bars Bobbin and +PointTM - Sizing Tube Support Bobbin - Detection Exsin ue er Plate Bobbin and +PointTM - Sizing Tube Wear Existing (foreign Freespan, TTS, Bobbin and Array - Detection obet) FDB, TSPs +PointTM - Sizing Hot Leg Top-of-tubesheet Bobbin and Array - Detection Exsig OSC Sludge Pile +PointTM - Sizing Area At the Tube Existing PWSCC Ends Inspection not required per PARC TE + 4 Inches Existing PWSCC Hot Leg Top-of- Array - Detection and Sizing tubesheet Top-of- Bobbin - Detection Existing GD Pitting tubesheet +PointTM - Sizing Flow Potential Tube Wear Distribution Bbi eeto BaffleBobbin and +PointTM - Sizing Potential ODSCC Freespan and Array - Detection Tube Supports +PointTM - Sizing Hot Leg within Tubesheet PWSCC Array - Detection Potential Anomaly +PointTM - Sizing Locations

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 5 of 10

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications, As stated in item (b) above, several wear type indications were noted. Tables 3 and 4 provide the detailed information regarding these indications.

Table 3 - AVB Indications Depth (%TW)

SG Row Col AVB No. (ETSS 96041.1)

_____ _________2012 2015 SGA 9 54 AV1 11 13 SGA 12 45 AV2 11 14 SGA 12 45 AV4 - 13 SGA 12 47 AV4 13 15 SGA 30 57 AV2 15 14 SGA 30 57 AV3 - 13 SGA 32 14 AV4 - 10 SGA 32 48 AV3 14 15 SGA 32 65 AV2 11 12 SCA 32 66 AV2 11 15 SGA 32 69 AV2 22 23 SGA 32 69 AV3 15 17 SGA 32 69 AV4 19 19 SGA 33 16 AV2 12 12 SGA 33 63 AV3 20 26 SGA 33 63 AV4 15 22 SGA 33 66 AV1 12 15 SGA 33 66 AV2 15 15 SGA 34 59 AV2 11 17 SGA 35 17 AV2 10 11 SGA 35 78 AV2 14 15 SGA 36 47 AV1 11 13 SGA 36 75 AV2 15 15 SGA 36 76 AV2 10 10 SGA 37 75 AV2 11 12 SGA 38 62 AV4 10 10 SGA 39 42 AV1 12 20 SGA 39 71 AV4 10 11 SGA 39 72 AV4 15 14 SGA 40 42 AV1 14 21 SGA 40 69 AV4 13 11

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 6 of 10 Table 3 - AVB Indications (cntnud SGA 45 40 AV4 - 14 SGA 46 43 AV1 12 11 SGA 46 43 AV2 -10 SGA 46 44 AV1 13 14 SGA 46 44 AV4 - 12 SGA 46 45 AVI 15 12 SGA 46 45 AV4 10 9 SGC 22 7 AV3 -10 SGC 24 33 AV2 10 8 SGC 27 10 AV3 12 11 SGC 33 16 AV2 11 10 SGC 35 17 AVl 25 24 SGC 35 17 AV4 11 10 SGC 35 46 AV2 12 10 SGC 35 46 AV3 15 10 SGC 35 77 AV3 - 13 SGC 37 24 AV2 - 11 SGC 38 67 AV3 24 23 SGC 39 23 AVI 18 18 SGC 39 23 AV2 20 20 SGC 39 23 AV3 26 27 SGC 39 69 AV3 15 15 SGC 40 66 AV2 - 11 SGC 42 31 AVl 23 20 SGC 42 31 AV2 23 20 SGC 42 31 AV3 19 17 SGC 42 31 AV4 15 11 SGC 44 47 AV3 10 7 SGC 44 59 AV2 - 10 SGC 45 38 AV3 10 8 SGC 45 40 AV4 12 11 SGC 45 58 AV1 - 11 SGC 45 58 AV4 10 11

- Not reported during the 2012 outage.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 7 of 10 Table 4 - Summarv of Non-AVB-Wear Volumetric Deglradation Ma xa ic Initially Signal Present Prior to Caus Fobjectn In Situ Plugged and SG Row Cal Location ETSS Depth Length Length ReportedbCurrentsOutagetRemainin

(%TW) (in) (in) Reported_ CurentOuageReainng Lancing SGA 1 86 TSC +16.01" 21998.1 31%TWi 0.77 0.43 2015 Yes (2001). No change. Equipment N/A No No Damage SGA 2 57 06C -0.34' 96910.1 16%TfW 0.24 0.38 2006 Yes. No change since TSP Wear N/A No No initially reported.

SGA 3 66 05C -0.69' 27901.1 28%TW 0.19 0.32 2009 Yes. No change since Foreign No No No

______initially reported. Object _______

SGA 6 88 TSH +0.35": 27901.1 26%TW 0.18 0.42 2006 Yes. No change since Foreign No No No initially reported. Object ______

SGA 8 38 TSH +0.41" 21998.1 16%TWI 0.19 0.38 2001 Yes. No change since Legacy No No No initially reported. Pitting_______

SGA 34 67 TSH +0.05" 27901.1 25%TW 0.29 0.37 2006 Yes. No change since Foreign No No No

______ ________initially reported. Object ______ ____ ______

SGA 38 30 TSC +1.96" 27901.1 20%TWN 0.24 0.37 2006 Yes. No change since Foreign No No No

_____initially reported. Object Not detectable with Frin N oN SGC 3 52 TSC +0.37" 27901.1 33%TW 0.27 0.37 2015 bobbin. No previous Fobject o o

+Point*. Ojc SGC 4 68 060 -0.28" 96910.1 9%TWi 0.34 0.38 2015 Yes (2006). Some TPWa / oN

____ _____ ______ ~change since 2006. TPWa / oN SGC 27 82 BPH +0.67" 27901.1 28%TW 0.23 0.49 2010 Yes (2000). No change Foreign No No No since 2000. Object _____________

SGC 29 77 02H -0.32" 27901.1 33%TWd 0.23 0.43 2015 No. Foreign Yes No Yes

_____ _______Object SGC 36 24 BPH -0.17" 96910.1 5%TWV 0.23 0.38 2012 Yes (2006). Not present TSP Wear N/A No No in 2000.

SGC 36 64 TSC -0.02" 27901.1 32%TW 0.27 0.48 2012 Yes. No change since Foreign No No No

___initially reported. Object SGC 36 66 TSC +0.03" 27901.1 26%TWI 0.28 0.43 2015 Notbdetectableewiths Foreign No No No

+PointtM" bjc SGC 38 66 TSC -0.53' 27901.1 28%TW 0.33 0.53 2009 Yes. No change since Foreign No No No initially reported. Object Not detectable with SGC 44 50 BPH -0.26' 96910.1 4%1W 0.24 0.32 2015 bobbin. No previous TSP Wear N/A No No

________________+PointTM.

Not detectable with SGC 45 52. BPH -0.31" 96910.1 4%TW 0.24 0.38 2015 bobbin. No previous TSP Wear N/A No . No

____ _______________________ ___________________ ______ +Pint'% __________________+PointT______.

Serial No.: 15-511 Docket No.: 50-280 Attachment Page 8 of 10

e. Number of tubes plugged during the inspection outage for each degradation mechanism, A total of five tubes in SG C were plugged during the Spring 2015 RFO. One tube required plugging as a result of SG inspections performed during the outage. This tube was plugged due to a foreign object wear indication with the foreign object still present and was stabilized on the hot leg. Four additional tubes were preventatively plugged due to permeabiiity signals. These tubes were tested with a magnetically biased probe. It was determined that they had no degradation and, therefore, met condition monitoring.

No tube plugging was required or performed in SG A.

f. The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator.

Table 5 provides the plugging totals and percentages to date.

Table 5- Tube Pluggingc Summary TubesInstaled Tubes Plugged To-I , Date SG A 3,342 44 (1.3%)

SG B 3,342 26 (0.8%)

SG C 3,342 41 (1.2%)

Total 10,026 111 (1.1%)

g. The results of condition monitoring, including the results of tube pulls and in-situ testing, Based on results of the primary and secondary side inspections performed during this outage, the condition monitoring assessment for the Spring 2015 RFO concluded that the Surry Unit 1 SGs satisfy required structural and leakage integrity criteria. Therefore, pull

'tubes and in-situ testing were not necessary.

Serial No.: 15-511 Docket No.: 50-280 Attachment Page 9 of 10

h. The primary to secondary LEAKAGE rate observed in each SG (if it is not practical to 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, Routine primary-to-secondary leak monitoring is conducted in accordance with station procedures. During the cycle preceding the Spring 2015 RFO, no measurable primary-to-secondary leakage (i.e., >1 GPD) was observed.
i. 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 Permanent Alternate Repair Criteria (PARC) require that the component of operational leakage from the prior cycle from below the H-star distance be multiplied by a factor of 1.8 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 1.8 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.
j. The results of the monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

No indications of tube slippage were identified during the evaluation of bobbin probe examination data from SG A or SG C.

No bobbin probe examinations were performed in SG B during the Spring 2015 RFO.

All tubes in SG B were screened for slippage during the Fall 2013 RFO with no indications identified. The SG B tubes will again be screened during the Fall 2016 RFO.

Serial No.: 15-511 Docket No.: 50-280 Attachment Page 10 of 10 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 ECT Eddy Current Test EFPM Effective Full Power Months EFPY Effective Full Power Years 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 OD Outer Diameter ODSCC Outer Diameter Stress Corrosion Cracking PARC Permanent Alternate Repair Criteria PDA Percent Degraded Area PLP Possible Loose Part POD Probability of Detection PWSCC Primary Water Stress Corrosion Cracking PTE Partial Tube Expansion 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 SI PC Structural Integrity Performance Criteria SSI Secondary Side Inspection TE Tube End TEC Tube End Cold TEH Tube End Hot TSC Tube Sheet Cold TSH Tube Sheet Hot TSP Tube Support Plate TTS Top of Tubesheet

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA~23261 November 6, 2015 United States Nuclear Regulatory Commission Serial No.15-511 Attention: Document Control Desk SPS-LIC/CGL R0 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 INSPECTION REPORT FOR THE SPRING 2015 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 1 report for the Spring 2015 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 1 Steam Generator Tube Inspection Report for the Spring 2015 Refueling Outage Commitments made in this letter: None

~AcoI K{~L

Serial No.: 15-511 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, Georgia 30303-1257 Ms. K. R. Cotton Gross NRC Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 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 G-9A 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.: 15-511 Docket No.: 50-280 ATTACHMENT SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE SPRING 2015 REFUELING OUTAGE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

Serial No.: 15-511 Attachment Docket No.: 50-280 bc pagel1 of 10 SURRY UNIT I STEAM GENERATOR TUBE INSPECTION REPORT FOR THE SPRING 2015 REFUELING OUTAGE The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement section 6.6.A.3. During the Surry Unit 1 Spring 2015 refueling outage (RFO),

steam generator (SG) inspections in accordance with TS 6.4.Q were completed for SG A and SG C.

This was the second inspection in the 4th inspection period which has duration of 72 effective full power months (EFPM).

Surry Unit 1 exceeded 200°F on May, 24 2015; therefore, this report is required to be*

submitted by November 20, 2015. The Surry Unit 1 SGs were replaced during Refueling Outage 5 (1981) and have accrued approximately 27.8 effective full power years (EFPY) of operation as of April 2015. Programmatically, the first sequential period begins after the first inservice inspection, thus the current SGs have accrued 317.7 EFPM.

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 included at the end of the 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 report shall include:

a. The scope of inspections performed on each SG, A summary of the tube examinations performed during the outage is provided in Table 1.

The primary side inspection activities included an as-found and as-left video/visual examination of both channel heads in SG A and SG C, specifically including:

  • All plugs; there was no evidence of plug leakage.
  • The divider plate weld region; no indications of degradation.
  • The bottom of the bowl per NSAL-12-1 and NRC IN 2013-20 with the bowl dry.

No abnormal or degraded conditions were identified.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 2 of 10 Table 1 - Primary Side Examination Scope Scope Description Extent SG AExams Cmped SGCoCExams ltd Bobbin Coil Exams Full Length TEC TEH 2838 2844 H/L Straight (Row 1-2) 07H TEH 182 185 H/L Candycane (Row 3-5) 070 TEH 277 277 C/L Straight (Row 1-5) 070 TEC 459 458 O/L Candycane (Row 3) 07H TEC 0 4 Restricted Tubes Various 2 2

  • Array Exams ______

H/L TSH Array (Baffle Plate) BPH TEH 2463 2469 H/L TSH Array (Non-Baffle Piate) 01H TEH 835 837 O/L TSC Array (Baffle Plate) BPC TEC 2463 2469 C/L TSC Array (Non-Baffle Plate) 010 TEC 835 837 Low Row U-bend MRPC Exams________________

U-bend +Point (Row 1-2) 070 07H 181 183 MRPC Special Interest U-bend Historical Spec Int Various 2 2 HIL Historical Spec Int Various 222 205 O/L Historical Spec Int Various 6 5 U-bend 1R26 Spec Int Various 15 1 HIL 1R26 Spec Int Various 16 39 C/L 1R26 Spec Int Various 47 24 Mag Bias Spec Int Various 3 8 1R26 PLP Bounding 02H 02H 0 8 Note: The H/L and C/L Array Exams were analyzed down to the H-star dimension.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 3 of 10 The following secondary side SG activities were performed during the Spring 2015 RFO:

SGs A, B. and C:

  • Upper bundle flush, sludge lancing, and post-lancing visual examination of the top-of-tubesheet annulus and no-tube lane to identify and remove any retrievable foreign objects (FOSAR).
  • Visual examination of historical foreign object-related locations identified in the Degradation Assessment.
  • Visual investigation of any accessible locations having eddy current signals potentially related to foreign objects.

No degradation or adverse conditions were noted.

SG A:

  • Visual examination of accessible steam drum components and structures (including the feedring exterior), the upper tube bundle, and 7 th TSP via probe drops through the primary moisture separators. No degradation or adverse conditions were noted during this inspection.
b. Degradation mechanisms 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, tube support plate wear, one legacy pit indication, and one legacy sludge lance wear flaw were detected. No SOC was detected.
c. Nondestructive examination techniques utilized for each degradation mechanism, Inspections focused on the degradation mechanisms listed in Table 2 utilizing the referenced eddy current techniques.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 4 of 10 Table 2 - Inspection Method for Applicable Deciradation Modes Classification Degradation LoainPbeTp Mechanism LoainPbeTp Exsig Tb er Anti-vibration Bobbin - Detection Bars Bobbin and +PointTM - Sizing Tube Support Bobbin - Detection Exsin ue er Plate Bobbin and +PointTM - Sizing Tube Wear Existing (foreign Freespan, TTS, Bobbin and Array - Detection obet) FDB, TSPs +PointTM - Sizing Hot Leg Top-of-tubesheet Bobbin and Array - Detection Exsig OSC Sludge Pile +PointTM - Sizing Area At the Tube Existing PWSCC Ends Inspection not required per PARC TE + 4 Inches Existing PWSCC Hot Leg Top-of- Array - Detection and Sizing tubesheet Top-of- Bobbin - Detection Existing GD Pitting tubesheet +PointTM - Sizing Flow Potential Tube Wear Distribution Bbi eeto BaffleBobbin and +PointTM - Sizing Potential ODSCC Freespan and Array - Detection Tube Supports +PointTM - Sizing Hot Leg within Tubesheet PWSCC Array - Detection Potential Anomaly +PointTM - Sizing Locations

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 5 of 10

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications, As stated in item (b) above, several wear type indications were noted. Tables 3 and 4 provide the detailed information regarding these indications.

Table 3 - AVB Indications Depth (%TW)

SG Row Col AVB No. (ETSS 96041.1)

_____ _________2012 2015 SGA 9 54 AV1 11 13 SGA 12 45 AV2 11 14 SGA 12 45 AV4 - 13 SGA 12 47 AV4 13 15 SGA 30 57 AV2 15 14 SGA 30 57 AV3 - 13 SGA 32 14 AV4 - 10 SGA 32 48 AV3 14 15 SGA 32 65 AV2 11 12 SCA 32 66 AV2 11 15 SGA 32 69 AV2 22 23 SGA 32 69 AV3 15 17 SGA 32 69 AV4 19 19 SGA 33 16 AV2 12 12 SGA 33 63 AV3 20 26 SGA 33 63 AV4 15 22 SGA 33 66 AV1 12 15 SGA 33 66 AV2 15 15 SGA 34 59 AV2 11 17 SGA 35 17 AV2 10 11 SGA 35 78 AV2 14 15 SGA 36 47 AV1 11 13 SGA 36 75 AV2 15 15 SGA 36 76 AV2 10 10 SGA 37 75 AV2 11 12 SGA 38 62 AV4 10 10 SGA 39 42 AV1 12 20 SGA 39 71 AV4 10 11 SGA 39 72 AV4 15 14 SGA 40 42 AV1 14 21 SGA 40 69 AV4 13 11

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 6 of 10 Table 3 - AVB Indications (cntnud SGA 45 40 AV4 - 14 SGA 46 43 AV1 12 11 SGA 46 43 AV2 -10 SGA 46 44 AV1 13 14 SGA 46 44 AV4 - 12 SGA 46 45 AVI 15 12 SGA 46 45 AV4 10 9 SGC 22 7 AV3 -10 SGC 24 33 AV2 10 8 SGC 27 10 AV3 12 11 SGC 33 16 AV2 11 10 SGC 35 17 AVl 25 24 SGC 35 17 AV4 11 10 SGC 35 46 AV2 12 10 SGC 35 46 AV3 15 10 SGC 35 77 AV3 - 13 SGC 37 24 AV2 - 11 SGC 38 67 AV3 24 23 SGC 39 23 AVI 18 18 SGC 39 23 AV2 20 20 SGC 39 23 AV3 26 27 SGC 39 69 AV3 15 15 SGC 40 66 AV2 - 11 SGC 42 31 AVl 23 20 SGC 42 31 AV2 23 20 SGC 42 31 AV3 19 17 SGC 42 31 AV4 15 11 SGC 44 47 AV3 10 7 SGC 44 59 AV2 - 10 SGC 45 38 AV3 10 8 SGC 45 40 AV4 12 11 SGC 45 58 AV1 - 11 SGC 45 58 AV4 10 11

- Not reported during the 2012 outage.

Serial No.: 15-511 Attachment Docket No.: 50-280 bc page 7 of 10 Table 4 - Summarv of Non-AVB-Wear Volumetric Deglradation Ma xa ic Initially Signal Present Prior to Caus Fobjectn In Situ Plugged and SG Row Cal Location ETSS Depth Length Length ReportedbCurrentsOutagetRemainin

(%TW) (in) (in) Reported_ CurentOuageReainng Lancing SGA 1 86 TSC +16.01" 21998.1 31%TWi 0.77 0.43 2015 Yes (2001). No change. Equipment N/A No No Damage SGA 2 57 06C -0.34' 96910.1 16%TfW 0.24 0.38 2006 Yes. No change since TSP Wear N/A No No initially reported.

SGA 3 66 05C -0.69' 27901.1 28%TW 0.19 0.32 2009 Yes. No change since Foreign No No No

______initially reported. Object _______

SGA 6 88 TSH +0.35": 27901.1 26%TW 0.18 0.42 2006 Yes. No change since Foreign No No No initially reported. Object ______

SGA 8 38 TSH +0.41" 21998.1 16%TWI 0.19 0.38 2001 Yes. No change since Legacy No No No initially reported. Pitting_______

SGA 34 67 TSH +0.05" 27901.1 25%TW 0.29 0.37 2006 Yes. No change since Foreign No No No

______ ________initially reported. Object ______ ____ ______

SGA 38 30 TSC +1.96" 27901.1 20%TWN 0.24 0.37 2006 Yes. No change since Foreign No No No

_____initially reported. Object Not detectable with Frin N oN SGC 3 52 TSC +0.37" 27901.1 33%TW 0.27 0.37 2015 bobbin. No previous Fobject o o

+Point*. Ojc SGC 4 68 060 -0.28" 96910.1 9%TWi 0.34 0.38 2015 Yes (2006). Some TPWa / oN

____ _____ ______ ~change since 2006. TPWa / oN SGC 27 82 BPH +0.67" 27901.1 28%TW 0.23 0.49 2010 Yes (2000). No change Foreign No No No since 2000. Object _____________

SGC 29 77 02H -0.32" 27901.1 33%TWd 0.23 0.43 2015 No. Foreign Yes No Yes

_____ _______Object SGC 36 24 BPH -0.17" 96910.1 5%TWV 0.23 0.38 2012 Yes (2006). Not present TSP Wear N/A No No in 2000.

SGC 36 64 TSC -0.02" 27901.1 32%TW 0.27 0.48 2012 Yes. No change since Foreign No No No

___initially reported. Object SGC 36 66 TSC +0.03" 27901.1 26%TWI 0.28 0.43 2015 Notbdetectableewiths Foreign No No No

+PointtM" bjc SGC 38 66 TSC -0.53' 27901.1 28%TW 0.33 0.53 2009 Yes. No change since Foreign No No No initially reported. Object Not detectable with SGC 44 50 BPH -0.26' 96910.1 4%1W 0.24 0.32 2015 bobbin. No previous TSP Wear N/A No No

________________+PointTM.

Not detectable with SGC 45 52. BPH -0.31" 96910.1 4%TW 0.24 0.38 2015 bobbin. No previous TSP Wear N/A No . No

____ _______________________ ___________________ ______ +Pint'% __________________+PointT______.

Serial No.: 15-511 Docket No.: 50-280 Attachment Page 8 of 10

e. Number of tubes plugged during the inspection outage for each degradation mechanism, A total of five tubes in SG C were plugged during the Spring 2015 RFO. One tube required plugging as a result of SG inspections performed during the outage. This tube was plugged due to a foreign object wear indication with the foreign object still present and was stabilized on the hot leg. Four additional tubes were preventatively plugged due to permeabiiity signals. These tubes were tested with a magnetically biased probe. It was determined that they had no degradation and, therefore, met condition monitoring.

No tube plugging was required or performed in SG A.

f. The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator.

Table 5 provides the plugging totals and percentages to date.

Table 5- Tube Pluggingc Summary TubesInstaled Tubes Plugged To-I , Date SG A 3,342 44 (1.3%)

SG B 3,342 26 (0.8%)

SG C 3,342 41 (1.2%)

Total 10,026 111 (1.1%)

g. The results of condition monitoring, including the results of tube pulls and in-situ testing, Based on results of the primary and secondary side inspections performed during this outage, the condition monitoring assessment for the Spring 2015 RFO concluded that the Surry Unit 1 SGs satisfy required structural and leakage integrity criteria. Therefore, pull

'tubes and in-situ testing were not necessary.

Serial No.: 15-511 Docket No.: 50-280 Attachment Page 9 of 10

h. The primary to secondary LEAKAGE rate observed in each SG (if it is not practical to 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, Routine primary-to-secondary leak monitoring is conducted in accordance with station procedures. During the cycle preceding the Spring 2015 RFO, no measurable primary-to-secondary leakage (i.e., >1 GPD) was observed.
i. 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 Permanent Alternate Repair Criteria (PARC) require that the component of operational leakage from the prior cycle from below the H-star distance be multiplied by a factor of 1.8 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 1.8 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.
j. The results of the monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

No indications of tube slippage were identified during the evaluation of bobbin probe examination data from SG A or SG C.

No bobbin probe examinations were performed in SG B during the Spring 2015 RFO.

All tubes in SG B were screened for slippage during the Fall 2013 RFO with no indications identified. The SG B tubes will again be screened during the Fall 2016 RFO.

Serial No.: 15-511 Docket No.: 50-280 Attachment Page 10 of 10 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 ECT Eddy Current Test EFPM Effective Full Power Months EFPY Effective Full Power Years 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 OD Outer Diameter ODSCC Outer Diameter Stress Corrosion Cracking PARC Permanent Alternate Repair Criteria PDA Percent Degraded Area PLP Possible Loose Part POD Probability of Detection PWSCC Primary Water Stress Corrosion Cracking PTE Partial Tube Expansion 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 SI PC Structural Integrity Performance Criteria SSI Secondary Side Inspection TE Tube End TEC Tube End Cold TEH Tube End Hot TSC Tube Sheet Cold TSH Tube Sheet Hot TSP Tube Support Plate TTS Top of Tubesheet

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