ML21243A313

Steam Generating Tube Inspection Report for the Spring 2021 Refueling Outage

ML21243A313
Person / Time
Site:	Surry
Issue date:	08/27/2021
From:	Lawrence D Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
21-255
Download: ML21243A313 (15)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 AUG 2 7 2021 United States Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE SPRING 2021 REFUELING OUTAGE Serial No.

SS&L/MMT Docket No.

License No.21-255 RO 50-280 DPR 32 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 Tav9 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 2021 refueling outage.

If you have any questions concerning this information, please contact Mr. Michael M.

True, Jr. at (757) 365-2446.

Dougla

. Lawrence Site Vice President

Attachment:

Surry Unit 1 Steam Generator Tube Inspection Report for the Spring 2021 Refueling Outage Commitments made in this letter: None

cc:

U.S. Nuclear Regulatory Commission Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, Georgia 30303-1257 Mr. Vaughn Thomas NRC Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 04 F12 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. G. Edward Miller NRC Senior Project Manager - North Anna U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E3 11555 Rockville Pike Rockville, Maryland 20852-2738 NRC Senior Resident Inspector Surry Power Station Mr. Rusty R. Richardson Authorized Nuclear Inspector Surry Power Station Serial No.21-255 Docket No. 50-280 Page 2 of 2

ATTACHMENT 1 SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE FOR SPRING 2021 REFUELING OUTAGE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION ENERGY VIRGINIA)

Serial No.21-255 Docket No. 50-280

SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE SPRING 2021 REFUELING OUTAGE Serial No.: 21-255 Docket No.: 50-280 page 1 of 12 The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement section 6.6.A.3. During the Surry Unit 1 Spring 2021 End-Of-Cycle 30 (EOC30) refueling outage, Steam Generator (SG) inspections in accordance with TS 6.4.Q were completed for SG A, 8, and C.

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

Surry Unit 1 exceeded 200°F on May 28, 2021; therefore, this report is required to be submitted by November 24, 2021. At the time of this inspection, the Unit 1 SGs had operated for 383.1 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." The report shall include:

a.

The scope of inspections performed on each SG.

Primary Side During the Unit 1 EOC30 refueling outage, primary side inspections were performed in SG A, B, and C. The eddy current inspections included the following:

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 01 C)

Full length Array inspection of all 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 the 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.

Secondary Side Serial No.: 21-255 Docket No.: 50-280 page 2 of 12 Listed below is a summary of the secondary side work performed in the Surry Unit 1 steam generators during the EOC30 outage.

Steam Generator A, B, and C Visual examination of historical foreign object-related locations identified during previous outages and documented in the Surry 1R30 Degradation Assessment (ETE-CEP-2021-1002).

Top of Tubesheet water lancing.

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. Perforations of two riser barrels due to erosion was identified in SG C. No other secondary component degradation or any other condition adverse to quality was observed during these inspections.

b. Degradation mechanisms found.

Primary side (tubes)

Degradation modes observed were anti-vibration bar (AVB) wear and various legacy volumetric indications (two maintenance related, several foreign object related, some TSP wear, and a few of undetermined origin). None of this degradation exceeded the 40% TW technical specification plugging criteria.

A single stress corrosion crack (PWSCC) was detected within the tubesheet of SG C.

Secondary side Perforations of two riser barrels due to erosion were identified in SG C.

Repairs were performed during the RFO by welding a 16"x16"x0.25" (thick) lnconel 600 impingement plate over each location of the erosion.

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.

Table 1 - Inspection Method for Applicable Degradation Modes Serial No.: 21-255 Docket No.: 50-280 page 3 of 12 Classification Degradation Location Probe Type Mechanism Existing Wear Anti-Vibration Bars Bobbin - Detection and Sizing Existing Wear Tube Support Plate Bobbin - Detection

+Point' - Sizing Tube Wear Bobbin and Array -

Existing (Foreign Objects)

Freespan and TTS Detection +Point' -

Sizing Existing Tube Wear Flow Distribution Baffle Bobbin - Detection

+Point' - Sizing Bobbin and Array -

Existing OD Pitting Top-of-Tubesheet (TTS)

Detection +Point' -

Sizing Existing ODSCC PWSCC Hot Leg TTS Array - Detection

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

Potential PWSCC Tubesheet Array - Detection Overexpansions (OXP)

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

+Point' - Sizing Tubesheet Overexpansions (OVR)

Potential ODSCC Tubesheet Crevice in N/A**

Tubes With NTE Potential ODSCC PWSCC Row 1 and 2 U-bends

+Point' - Detection and Sizing Potential ODSCC Freespan and Tube Bobbin - Detection Supports

+Point' - Sizing High Residual Stress Bobbin and Array -

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.: 21-255 Docket No.: 50-280 page 4 of 12

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications.

As stated in the (b) response above, volumetric service induced indications were identified. Tables 2 and 3 provide the required information.

Table 2 - Surry 1 EOC30 Inspection Summary - AVB Wear Indications Wear Depth (% TW)

ETSS 96041.1 SG Row Col AVB No.

Previous Current EOC28 EOC30 A

9 54 AV1 13 11 A

12 45 AV1 13 17 A

12 45 AV4 12 15 A

12 47 AV4 15 12 A

21 86 AV2 11 9

A 30 57 AV2 12 16 A

30 57 AV3 12 14 A

32 14 AV4 9

12 A

32 48 AV3 11 15 A

32 65 AV2 11 17 A

32 66 AV2 9

10 A

32 69 AV2 21 25 A

32 69 AV3 16 20 A

32 69 AV4 17 21 A

33 16 AV2 12 11 A

33 63 AV3 20 25 A

33 63 AV4 16 20 A

33 66 AV1 11 11 A

33 66 AV2 13 11 A

34 59 AV2 12 16 A

34 62 AV2 12 A

35 17 AV2 12 14 A

35 78 AV2 14 14 A

36 47 AV1 11 9

SG Row Col AVB No.

A 36 75 AV2 A

36 76 AV2 A

37 75 AV2 A

37 75 AV3 A

38 62 AV1 A

38 62 AV4 A

38 73 AV3 A

39 42 AV1 A

39 71 AV2 A

39 71 AV4 A

39 72 AV2 A

39 72 AV4 A

40 42 AV1 A

40 69 AV4 A

44 55 AV2 A

45 40 AV4 A

46 43 AV1 A

46 43 AV2 A

46 44 AV1 A

46 44 AV4 A

46 45 AV1 A

46 45 AV4 B

22 72 AV3 B

26 61 AV3 B

28 57 AV1 B

28 66 AV2 B

28 83 AV2 B

31 33 AV2 B

32 26 AV3 B

34 58 AV2 B

34 58 AV3 Wear Depth (% TW)

ETSS 96041.1 Previous Current 15 13 11 11 12 13 12 11 12 8

14 11 15 15 13 11 INR 10 INR 11 10 15 13 11 13 10 12 11 12 11 11 11 13 8

13 13 15 11 12 15 14 10 12 EOC29 EOC30 18 17 14 16 10 12 12 12 10 9

19 18 10 12 27 27 22 23 Serial No.: 21-255 Docket No.: 50-280 page 5 of 12

SG Row Col AVB No.

B 34 58 AV4 B

34 79 AV3 B

35 17 AV1 B

35 17 AV2 B

35 17 AV3 B

36 33 AV3 B

36 65 AV4 B

38 22 AV2 B

38 22 AV3 B

38 25 AV3 B

39 24 AV3 B

39 29 AV2 B

39 36 AV3 B

39 66 AV1 B

40 25 AV2 B

40 26 AV2 B

40 28 AV2 B

41 27 AV2 B

41 27 AV3 B

41 47 AV2 B

42 29 AV1 B

42 29 AV2 B

42 30 AV2 B

42 30 AV3 B

43 32 AV2 B

43 34 AV3 B

43 39 AV2 B

45 37 AV2 B

45 37 AV3 B

45 38 AV2 B

46 45 AV2 Wear Depth (% TW)

ETSS 96041.1 Previous Current 11 13 11 11 9

11 12 14 26 26 9

10 15 15 12 13 11 14 10 10 13 12 12 12 14 13 11 11 20 18 9

12 11 12 12 14 10 13 12 11 12 11 17 16 15 15 14 13 13 15 14 15 11 13 11 14 12 13 11 9

17 18 EOC28 EOC30 Serial No.: 21-255 Docket No.: 50-280 page 6 of 12

SG Row Col AVB No.

C 22 7

AV3 C

24 33 AV2 C

27 10 AV3 C

33 16 AV2 C

34 16 AV2 C

35 17 AV1 C

35 17 AV4 C

35 46 AV2 C

35 46 AV3 C

35 77 AV3 C

37 24 AV2 C

38 67 AV3 C

39 23 AV1 C

39 23 AV2 C

39 23 AV3 C

39 69 AV3 C

40 66 AV2 C

42 31 AV1 C

42 31 AV2 C

42 31 AV3 C

42 31 AV4 C

43 31 AV2 C

44 59 AV2 C

45 38 AV3 C

45 40 AV4 C

45 58 AV1 C

45 58 AV4 Wear Depth (% TW)

ETSS 96041.1 Previous Current 11 11 8

10 13 14 10 11 11 11 25 25 11 12 14 13 15 14 8

12 12 12 23 22 19 18 21 21 29 30 13 16 8

12 24 24 24 24 21 22 15 16 14 13 8

12 8

11 11 14 7

10 9

11 Serial No.: 21-255 Docket No.: 50-280 page 7 of 12

Serial No.21-255 Docket No. 50-280 Page 8 of 12 Table 3 - Surry 1 EOC30 Inspection Summary - Non-AVB Volumetric Degradation Max Depth Foreign Object Plugged &

SG Row Col Location ETSS (3/4TW)

Cause Remaining?

Stabilized?

Lancing A

1 86 TSC +15.63" 21998.1 27 Equipment N/A No Damage A

2 57 06C-0.37" 96910.1 13 TSP Wear N/A No A

3 66 05C -0.74" 27901. 1 25 Foreign Object No No A

6 88 TSH +0.33" 27901.1 25 Foreign Object No No A

8 38 TSH +0.37" 21998.1 16 Legacy Pitting N/A No A

34 67 TSH +0.04" 27901.1 23 Foreign Object No No TSC +0.11 27901. 1 22 A

38 27 Foreign Object No No TSC +0.74 27901. 1 24 A

38 30 TSC +1.78" 27901.1 21 Foreign Object No No B

1 7

TSH+0.24" 21998.1 22 Historical SG N/A No Maintenance B

12 51 TSC+0.48" 21988.1 11 Unknown. Small N/A No volumetric B

31 15 BPH +0.59" 27901. 1 20 Foreign Object No No B

31 16 BPH +0.59" 27901.1 23 Foreign Object No No B

32 15 BPH +0.59" 27901.1 18 Foreign Object No No B

32 18 BPH +0.61" 27901.1 19 Foreign Object No No B

33 17 BPH+0.61" 27901. 1 15 Foreign Object No No B

33 18 BPH +0.62" 27901. 1 19 Foreign Object No No B

35 20 BPH +1.11" 27902.1 17 Foreign Object No No B

37 31 04H-24.37" 21998.1 12 Unknown. Small N/A No volumetric B

40 50 TSH +0.31" 27901. 1 33 Foreign Object No No B

40 51 TSH +0.31" 27901.1 34 Foreign Object No No B

41 51 TSH +0.16" 27901.1 23 Foreign Object No No

SG Row Col Location ETSS B

45 48 TSC+2.55" 21998.1 C

3 52 TSC +0.37" 27901.1 C

4 68 06C -0.31" 96910.1 C

15 49 04H -0.57" 96910.1 C

26 85 BPH + 0.55" 27901.1 C

27 82 BPH +0.61" 27901.1 C

29 82 BPH + 0.58" 27901.1 C

36 24 BPH -0.23" 96910.1 C

36 64 TSC +0.07" 27901.1 C

36 66 TSC +0.03" 27901.1 C

38 66 TSC +0.19" 27901.1 C

44 50 BPH -0.28" 96910.1 C

45 52 BPH -0.31" 96910.1 Max Depth (3/4TW)

Cause 33 Unknown. Small volumetric 32 Foreign Object 12 TSP Wear 15 TSP Wear 30 Foreign Object 28 Foreign Object 28 Foreign Object 6

FDB Wear 29 Foreign Object 25 Foreign Object 28 Foreign Object 5

FDB Wear 4

FDB Wear Foreign Object Remaining?

N/A No N/A N/A No No No N/A No No No N/A N/A Plugged &

Stabilized?

No No No No No No No No No No No No No Serial No.21-255 Docket No. 50-280 Page 9 of 12 As stated in the (b) response above, one stress corrosion crack (PWSCC) was detected within the tubesheet of SG C. Table 4 provides the required information.

Table 4 - Surry 1 EOC30 Inspection Summary - Stress Corrosion Cracking SG Row Col Location Degradation %TW Orientation Length Voltage Probe C

11 42 TSH-PWSCC 41 Circumferential 28° 0.74

+Point 0.34

e. Number of tubes plugged during the inspection outage for each degradation mechanism.

Tube Row 11 Col 42 was stabilized and plugged during RFO 1 R30.

Serial No.21-255 Docket No. 50-280 Page 10 of 12

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

SG B 3,342 26 (0.8%)

SGC 3,342 42 (1.3%)

Total 10,026 112 (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 2021 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 EOC30, 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 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

Serial No.21-255 Docket No. 50-280 Page 11 of 12 operational leakage was zero, the accident induced leakage originating from below the H-star distance 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 A, B, and C.

BPC BPH C/L ECT EFPM EOC ETSS GPO H/L MRPC NSAL NTE OD ODSCC OVR OXP PARC PLP PWSCC TEC TEH TSC TSH TSP TTS TW Acronyms Baffle Plate Cold Baffle Plate Hot Cold Leq Eddy Current Testing Effective Full Power Month End of Cycle Examination Technique Specification Sheet Gallons Per Day Hot Leq Motorized Rotating Pancake Coil Nuclear Safety Advisory Letter No tube Expansion Outer Diameter Outside Diameter Stress Corrosion Cracking Over Roll Over Expansion Permanent alternate repair criteria Possible Loose Part Primary Water Stress Corrosion Crackinq Tube End Cold-leg Tube End Hot-leg Too of Tube Sheet Cold-leg Top of Tube Sheet Hot-leq Tube Support Plate Top of Tubesheet Throuqh Wall Serial No.21-255 Docket No. 50-280 Page 12 of 12