ML20087H009

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Steam Generator Tube Inspection Report for the Fall 2019 Refueling Outage
ML20087H009
Person / Time
Site: Surry Dominion icon.png
Issue date: 03/11/2020
From: Mladen F
Virginia Electric & Power Co (VEPCO)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
20-016
Download: ML20087H009 (12)
v • d • e


Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 MAR 1 1 2020 United States Nuclear Regulatory Commission Serial No.20-016 Attention: Document Control Desk SPS-LIC/JWD RO Washington, DC 20555-0001 Docket No. 50-280 License No. DPR-32 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNIT 1 STEAM GENERAiO R TUBE INSPECTION REPORT FOR THE FALL 2019 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 NRG within 180 days after T av9 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 2019 refueling outage.

If you have any questions concerning this information, please contact Mr. Jacob W Dietrich at (757) 365-2161.

Very truly yours, Fred Mladen Site Vice President Surry Power Station

Attachment:

Surry Unit 1 Steam Generator Tube Inspection Report for the Fall 2019 Refueling Outage Commitments made in this letter: None

Serial No.20-016 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 Mr. V. Thomas 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 Mr. E. Miller NRC Project Manager - North Anna U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 B 1-A 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.20-016 Docket No. 50-280 ATTACHMENT 1 SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE FOR FALL 2019 REFUELING OUTAGE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION ENERGY VIRGINIA)

Serial No.: 20-016 Attachment 1 Docket No.: 50-280 page 1 of 9 SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE FALL 2019 REFUELING OUTAGE The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement section 6.6.A.3. During the Surry Unit 1 Fall 2019 End-Of-Cycle 29 (EOC29) refueling outage, Steam Generator (SG) inspections in accordance with TS 6.4.Q were completed for SG B.

This was the first inspection within the 5th period which has duration of 72 effective full power months (EFPM).

Surry Unit 1 exceeded 200°F on November 26, 2019; therefore this report woulq normally be required to be submitted by May 24, 2020. However, since May 24, 2020 is a Sunday and May 25, 2020 is Memorial Day, this report is instead required to be submitted by May 26, 2020. At the time of this inspection, the Unit 1 SGs had operated for 366.4 EFPM since the first in-service inspection.

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. 11 The report shall include:

a. The scope of inspections perlormed on each SG Primary Side During the Unit 1 EOC29 refueling outage, primary side inspections were performed in SG B. The eddy current inspections included the following:

Steam Generator B

  • Full length bobbin inspection of all in-service tubing except the u-bends of Rows 1 and 2
  • Rotating Coil inspections of the u-bends of Rows 1 and 2
  • Array inspection of all in-service tubes from TSH -17.89" to the lowermost hot leg support structure (either BPH or 01 H)
  • Array inspection of all in-service tubes from TSC -17.89" to the lowermost cold leg support structure (either BPC or 01C)
  • Full length Array inspection of an in-service tubes with high residual stress
  • Rotating Coil inspections of locations of special interest based on bobbin and array inspection results As-found and as-left visual examinations were performed in SG B hot-leg and cold-leg channel heads. No degradation associated with the divider plate, welds, cladding, channel head, channel head drain or previously installed plugs was observed. Examination of the bottom of the bowl and drain in the dry condition showed no degradation.

Serial No.: 20-016 Attachment 1 Docket No.: 50-280 page 2 of 9 Secondary Side Listed below is a summary of the secondary side work performed in the Surry Unit 1 steam generators during the EOC29 outage.

Steam Generator A, B, and C

  • Visual examination of historical foreign object-related l_ocations identified during previous outages and documented in the Surry 1R29 Degradation Assessment (ETE-CEP-2019-1004)
  • Visually map the entire region from the no-tube lane (NTL) to provide an accurate accounting of the tubesheet conditions prior to water lancing.
  • TTS "raking" (i.e., removal or spreading of material) and lancing of historical sludge, wires and bristles, as necessary.

Steam Generator B only

  • Visual investigation of any accessible locations having eddy current signals potentially related to foreign objects, and removal of retrievable foreign objects.
  • Visual examination in the steam drum of all accessible steam drum components and structures including the feedring and moisture separators. The upper tube bundle and 7th TSP were also inspected via the primary moisture separators. No secondary component degradation or any other condition adverse to quality was observed during these inspections.
b. Degradation mechanisms found AVB wear, legacy foreign object wear, one legacy sludge lance wear flaw, and several legacy small volumetric indications were detected. No stress corrosion cracking was detected.
c. Nondestructive examination techniques utilized for each degradation mechanism The inspection program focused on the degradation mechanisms listed in Table 1 and utilized the referenced eddy current techniques.

Serial No.: 20-016 Attachment 1 Docket No.: 50-280 page 3 of 9 Table 1 - Inspection Method for Applicable Degradation Modes Degradation Classification Location Probe Type Mechanism Bobbin - Detection and Existing Wear Anti-Vibration Bars Sizina Bobbin - Detection Existing Wear Tube Support Plate

+Point' - Sizing Bobbin and Array -

Tube Wear Existing Freespan and TTS Detection +Point' -

(Foreign Objects)

Sizina Bobbin - Detection Existing Tube Wear Flow Distribution Baffle

+Point' - Sizing Bobbin and Array -

Existing OD Pitting Top-of-Tubesheet (TTS) Detection +Point' -

Sizina Array - Detection Existing ODSCC PWSCC Hot Leg TTS

+Point' - Sizing Existing PWSCC Tube Ends N/A*

Tubesheet Array - Detection Potential PWSCC Overexoansions (OXP) +Point' - Sizing I

Bulges, Dents, Manufacturing Array/+Point - Detection Potential ODSCC PWSCC Anomalies, and Above-

+Point' - Sizing Tubesheet Overexpansions (OVR)

Tubesheet Crevice in Potential ODSCC N/A**

Tubes With NTE

+Point' - Detection and Potential ODSCC PWSCC Row 1 and 2 U-bends Sizina Freespan and Tube Bobbin - Detection Potential ODSCC Supports +Point' - Sizing Bobbin and Array -

High Residual Stress Potential ODSCC PWSCC Detection Tubes

+Point' - Sizing Potential Tube Slippage Within Tubesheet Bobbin - Detection

  • Inspection not required per technical specification alternate repair criteria
    • The tubes with no tubesheet expansion (NTE) have already been plugged

Serial No.: 20-016 Attachment 1 Docket No.: 50-280 page 4 of 9

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications As stated in the (b) response above, only volumetric service induced indications were identified. Tables 2 and 3 provide the required information.

Table 2 - Surry 1 EOC29 Inspection Summary-AVB Wear Indications Wear Depth (% TW)

ETSS 96041.1 SG Row Col AVB No. 2017 2019 B 22 72 AV3 13 18 B 26 61 AV3 13 14 B 28 57 AV1 - 10 B 28 66 AV2 13 12 I B 28 83 AV2 - 10 B 31 33 AV2 17 19 B 32 26 AV3 11 10 B 34 58 AV2 24 27 B 34 58 AV3 20 22 B 34 58 AV4 - 11 B 34 79 AV3 12 11 B 35 17 AV1 9 9 B 35 17 AV2 11 12 B 35 17 AV3 24 26 B 36 33 AV3 8 9 B 36 65 AV4 11 15 B 38 22 AV2 12 12 B 38 22 AV3 12 11 B 38 25 AV3 10 10 B 39 24 AV3 13 13 B 39 29 AV2 10 12 B 39 36 AV3 10 14 B 39 66 AV1 9 11 B 40 25 AV2 21 20 B 40 26 AV2 12 9 B 40 28 AV2 - 11

Serial No.: 20-016 Attachment 1 Docket No.: 50-280 page 5 of 9 Wear Depth (% TW)

ETSS 96041.1 SG Row Col AVB No. 2017 2019 B 41 27 AV2 12 12 B 41 27 AV3 11 10 B 41 47 AV2 10 12 B 42 29 AV1 - 12 B 42 29 AV2 16 17 B 42 30 AV2 13 15 B 42 30 AV3 11 14 B 43 32 AV2 14 13 B 43 34 AV3 13 14 B 43 39 AV2 - 11 B 45 37 AV2 11 11 B 45 37 AV3 11 12 B 45 38 AV2 11 11 B 46 45 AV2 16 17

Serial No.: 20-016 Attachment 1 Docket No.: 50-280 page 6 of 9 Table 3 - Surry 1 EOC29 Inspection Summary- Non-AVB Volumetric Degradation Max Depth Foreign Object Plugged &

SG Row Col Location (%TW) Cause Remaining? Stabilized?

Historical SG B 1 7 TSH+0.36" 24%1W *NIA No Maintenance TSC+0.24" Unknown. Small B 12 51 12%1W *N/A No to 0.4" volumetric B 31 15 BPH+0.54" 19%1W Foreign Object No No B 31 16 BPH+0.51" 23%1W Foreign Object No No B 32 15 BPH+0.54" 18%1W Foreign Object No No B 32 18 BPH+0.55" 19%1W Foreign Object No No B 33 17 BPH+0.61" 15%1W Foreign Object No No B 33 18 BPH+0.66" 21%1W Foreign Object No No

-s 35 20 BPH+1.13" 16%1W Foreign Object No No Unknown. Small B 37 31 03H+26.89" 13%1W *N/A No volumetric B 40 50 TSH+0.26" 33%1W Foreign Object No No B 40 51 TSH+0.32" 34%1W Foreign Object No Nd B 41 51 TSH+0.17" 23%1W Foreign Object No No TSC+3.34" Unknown. Small B 45 48 29%1W *N/A No to 3.5" volumetric

  • Not foreign object related

Serial No.20-016 Attachment 1 Docket No. 50-280 Page 7 of 9

e. Number of tubes plugged during the inspection outage for each degradation mechanism No tubes were plugged during RFO 1R29.
f. The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator.

Table 4 provides the plugging totals and percentages to date.

Table 4 - Tube Plugging Summary Tubes Plugged To-Tubes Installed Date SGA 3,342 44 (1.3%)

SGB 3,342 26 (0.8%)

SGC 3,342 41(1.2%)

Total 10,026 111 (1.1%)

Since no sleeving has been performed in the Surry Unit 1 steam generators, the effective plugging percentage is the same as the actual plugging percentage.

g. The results of condition monitoring, including the results of tube pulls and in-situ testing All tubes with degradation identified during the spring 2019 inspection satisfied condition monitoring requirements for SG tube structural and leakage integrity. Further, the results from the current outage inspection validate prior outage operational assessment assumptions. Tube pulls and in-situ pressure testing were not required during the current outage.
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 EOC29, no measurable primary-to-secondary leakage was observed in any Unit 1 SG.
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) requires 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

Serial No.20-016 Attachment 1 Docket No. 50-280 Page 8 of 9 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. Since the prior cycle operational leakage was zero, the accident induced leakage originating from below the H-star d~stance would also be zero. This value is well below the 470 GPO 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 8. All tubes in SG A and C were screened for slippage during EOC28 (no indi.cations were identified),

and will again be screened during EOC30.

Serial No.20-016 Attachment 1 Docket No. 50-280 Page 9 of 9 Acronyms BPC Baffle Plate Cold BPH Baffle Plate Hot C/L Cold Leg ECT Eddy Current Testino EFPM Effective Full Power Month EOC End of Cvcle ETSS Examination Technique Specification Sheet GPO Gallons Per Dav H/L Hot Leg MRPC Motorized Rotating Pancake Coil NSAL Nuclear Safety Advisory Letter NTE No tube Expansion OD Outer Diameter ODSCC O.utside Diameter Stress Corrosion Cracking OVR Over Roll OXP Over Expansion PARC Permanent alternate repair criteria PLP Possible Loose Part PWSCC Primary Water Stress Corrosion Cracking TEC Tube End Cold-leg TEH Tube End Hot-leg TSC Top of Tube Sheet Cold-leq TSH Top of Tube Sheet Hot-leg TSP Tube Suooort Plate TTS Too of Tubesheet TW Through Wall

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