ML17121A378
| ML17121A378 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/24/2017 |
| From: | Mladen F Virginia Electric & Power Co (VEPCO) |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML17121A378 (12) | |
Text
VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 April 24, 2017 United States Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE FALL 2016 REFUELING OUTAGE Serial No.
SPS-LIC/CGL Docket No.
License No.17-128 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 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 2016 refueling outage.
If you have any questions concerning this information, please contact Mrs. Candee G. Lovett at (757) 365-2178.
Very truly yours, Fred Mladen Site Vice President Surry Power Station
Attachment:
Surry Unit 1 Steam Generator Tube Inspection Report for the Fall 2016 Refueling Outage Commitments made in this letter: None
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 NRG Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, Maryland 20852-2738 Ms. B. Mozafari NRG Project Manager-North Anna U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 H-12 11555 Rockville Pike Rockville, Maryland 20852-2738 NRG Senior Resident Inspector Surry Power Station Mr. R. A. Smith Authorized Nuclear Inspector Surry Power Station Serial No.: 17-128 Docket No.: 50-280 Page 2 of 2
. ATTACHMENT SURRY UNIT 1 Serial No.: 17-128 Docket No.: 50-280 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE FALL 2016 REFUELING OUTAGE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)
SURRY UNIT 1 STEAM GENERATOR TUBE INSPECTION REPORT FOR THE FALL 2016 REFUELING OUTAGE Serial No.: 17-128 Attachment Docket No.: 50-280 Page 1 of 9 The following satisfies the Surry Power Station Technical Specification (TS) reporting requirement Section 6.6.A.3. During the Surry Unit 1 Fall 2016 End-Of-Cycle 27 (EOC27) refueling outage, Steam Generator (SG) inspections in accordance with TS 6.4.Q were completed for SG B.
The Unit 1 SGs are in the 4th inspection period, which has a duration of 72 Effective Full Power Months (EFPM). The Fall 2016 refueling outage was the third outage of,the 4th period.
Unit 1 exceeded 200°F on November 8, 2016; therefore, this report is required to be submitted by May 5, 2017. At the time of this inspection, the Unit 1 SGs had operated for 334 EFPM since the first inservice 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 provided 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 EOC27 refueling outage, primary side inspections were performed in SG B only. The eddy current inspections included the following:
Bobbin inspection of all in-service tubing except the Li-bends of Rows 1 and 2 and the U-bend of Tube R3 C20, Motorized Rotating Pancake Coil (MRPC) inspections of the Li-bends of Rows 1 and 2 and Tube R3 C20, 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),
Array inspection of hot leg straight sections of all in-service tubes with high residual stress, and MRPC inspections of locations of special interest based on bobbin and array inspection results.
Serial No.: 17-128 Attachment Docket No.: 50-280 Page 2 of 9 Note that Tube R3 C20 has a historical restriction above the 07C support plate.
The U-bend of this tube was inspected with an MRPC probe in lieu of a bobbin probe.
As-found and as-left visual examinations were performed in the primary side channel head in SG B. No degradation or other anomalous conditions associated with the divider plate, welds, cladding, channel head, channel head drain, or previously installed plugs were observed. Examination of the bottom of the bowl and drain in the dry condition showed no deg rad a ti on.
Secondary Side Secondary side inspections were performed in SG B only.
A visual inspection of the upper steam drum moisture separator components, feedring components, and top of bundle U-bend region components through the secondary manway was performed. This inspection was performed for all accessible steam drum components and structures, including the feedring exterior, the upper tube bundle, and ih tube support plate (TSP) by probe insertions through the primary moisture separators. No degradation or adverse conditions were noted during these inspections.
Sludge lancing was also performed in SG B.
Foreign Object Search and Retrieval (FOSAR) examinations were performed at the top of the tubesheet, in the annulus, and the no-tube lane, as required.
- 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 SG tube bundle. AVB wear, TSP wear, baffle plate wear, and foreign object wear were detected. No pitting or SCC 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.
I*
Serial No.: 17-128 Attachment Docket No.: 50-280 Page 3 of 9 Table 1-Inspection Method for Applicable Degradation Modes
~*..
- oegradation '<
f, Classification.* * : Mechanisril Loca-tio:n *
. Pr<?b~'Type **
Existing Tube Wear Anti-Vibration Bars Bobbin - Detection and Sizing Existing OD Pitting Top-of-Tubesheet (TIS)
Bobbin and +Point'- Detection
+Point' - Sizing Existing Tube Wear Tube Support Plate Bobbin - Detection
+Point' - Sizing Existing Tube Wear Freespan and TIS Bobbin and +Point' - Detection (foreign objects)
+Point' - Sizing Potential ODSCC Hot Leg TIS
+Point' - Detection and Sizing PWSCC Potential PWSCC Tube Ends N/A*
Potential Tube Wear Flow Distribution Baffle Bobbin - Detection
+Point' - Sizing Bulges, Dents, Manufacturing Potential ODSCC Anomalies, and Above-
+Point' - Detection and Sizing PWSCC Tubesheet Over Expansions (OVRs)
Tubesheet Crevice in Potential ODS CC Tubes With No Tube
+Point' - Detection and Sizing Expansions (NTEs)
Potential Tube Slippage Within Tubesheet Bobbin Detection Potential PWSCC Tubesheet
+Point' - Detection and Sizing Over Expansions (OXPs)
Potential ODS CC Row 1 and 2 U-bends
+Point' - Detection and Sizing PWSCC Potential ODSCC Freespan and Tube Supports Bobbin - Detection
+Point' - Sizing
- Inspection not required per technical specification alternate repair criteria.
- d. Location, orientation (if linear), and measured sizes (if available) of service induced indications, As stated in the (b) response above, service induced indications were identified. Tables 2 and 3 provide the required information.
Serial No.: 17-128 Attachment Docket No.: 50-280 Page 4 of 9 Table 2: Surry 1 Fall 2016 Inspection Summary - AVB Indications AVB Depth (%TW)
SG Row
, Col ETSS 96041.1 N'o.
2013 \\
2016.*
SGS 22 72 AV3 13 13 SGB 26 61 AV3 15 13 SGS 28 66 AV2 11 13 SGB 31 33 AV2 14 17 SGS 32 26 AV3 8
11 SGS 34 58 AV2 24 24 SGS 34 58 AV3 19 20 SGS 34 79 AV3 10 12 SGS 35 17 AV1 13 9
SGS 35 17 AV2 11 11 SGS 35 17 AV3 22 24 SGS 36 33 AV3 10 8
SGS 36 65 AV4 11 11 SGS 38 22 AV2 11 12 SGB 38 22 AV3 NR 12 SGS 38 25 AV3 NR 10 SGS 39 24 AV3 NR 13 SGB 39 29 AV2 NR 10 SGB 39 36 AV3 6
10 SGB 39 66 AV1 11 9
SGS 40 25 AV2 16 21 SGS 40 26 AV2 9
12 SGS 41 27 AV2 13 12 SGS 41 27 AV3 13 11 SGS 41 47 AV2 NR 10 SGB 42 29 AV2 15 16 SGS 42 30 AV2 14 13 SGS 42 30 AV3 10 11 SGS 43 32 AV2 13 14 SGS 43 34 AV3 6
13 SGS 45 37 AV2 NR 11 SGS 45 37 AV3 NR 11 SGS 45 38 AV2 NR 11 SGS' 46 45 AV2 20 16 NR = Not Reported during the previous outage
/
S.G*
'Row.
Coi Locati9n*
SGS 1
7 TSH
+0.27" SGS 31 15 SPH
+0.50" SGS 31 16 SPH
+0.50" SGS 32 15 SPH
+0.53" SGS 32 18 SPH
+0.53" SGS 33 18 SPH
+0.53" SGS 35 20 SPH
+1.09" 03H SGS 37 31
+26.69" SGB 40 50 TSH
+0.27" Table 3: Summary of Non-AVB-Wear Volumetric Degradation Signal.
M.ax:.*
~ial.*
Circ.*.
lr:iitially *.* Present Foreign p:>
ETss***.. Deptti'.Lengt **. Lengt'.
Reporte
- Priorfo
. *cause
- Object (O(ol°W) h (in)
- h. (in)
'd Current Remaining? :
I*;
I'-:
Outage?
Yes. No 21998.1 21%
0.65" 0.37" 2007 change since Historical SG N/A TW initially Maintenance reported.
Yes. No 27901.1 19%
0.24" 0.38" 2010 change since Foreign No TW initially Object reported.
Yes. No 27901.1 25%
0.24" 0.38" 2010 change since Foreign No TW initially Object reported.
Yes. No 27901.1 18%
0.24" 0.38" 2010 change since Foreign No TW initially Object reported.
Yes. No 27901.1 18%
0.29" 0.38" 2010 change since Foreign No TW initially Object reported.
Yes. No 27901.1 19%
0.18" 0.38" 2010 change since Foreign No TW initially Object reported.
Yes. No 27902.1 16%
0.66" 0.38" 2010 change since Foreign No TW initially Object reported.
Yes.
Indication Small 15%
present in volumetric 21998.1 TW 0.24" 0.32" 2013 1994, but not with no N/A reported until change since array exam in 1994 2013 Yes. No 27901. 1 33%
0.34" 0.43" 2007 change since Foreign No TW initially Object reported.
1hsitu
- Tested?...
No No No No No No No No No Serial No.: 17-128 Attachment Docket No.: 50-280 be page 5 of 9 i>1~9g~d &~*
Stabilized?...
No No No No No No No No No
Axial Max Circ Initially SG Row Col Location' ETSS Depth
- Lengt Len gt Reporte
(%TW) h (in) h (in) d 40 51 TSH 27901.1 33%
0.35" 0.43" 2007 SGB
+0.33" TW SGB 41 51 TSH 27901.1 23%
0.24" 0.38" 2007
+0.12" TW TSC 31%
SGB 45 48
+2.80" 21998.1 TW 0.29" 0.38" 2013 Signal Present Prior to Cause
.Current Outage?
Yes. No change since Foreign initially Object reported.
Yes. No change since Foreign initially Object reported.
Yes.
Indication present in 1992 and Small reported as volumetric NQH since with no 1994, but not change since reported as 1994 VOL until array exam in 2013 Foreign Object Remaining?
No No N/A In Situ Tested?
No No No Serial No.: 17-128 Attachment Docket No.: 50-280 be page 6 of 9 Plugged &
Stabilized?
No No No
Serial No.: 17-128 Docket No.: 50-280 Attachment Page 7 of 9
- e. Number of tubes plugged during the inspection outage for each degradation mechanism, No tubes required plugging as a result of SG inspections performed during the EOC27 outage.
- 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
, )
- 11,1bes.Rlugged;T_o- '
.;,.* *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%)
- g. The results of condition monitoring, including the results of tube pulls and in-situ testing, All degradation identified during the Fall 2016 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. Therefore, tube pulls and in-situ pressure testing were
- not necessary.
- 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 EOC27, no measurable primary-to-secondary leakage (i.e., >1 GPO) was observed in any Unit 1 SG.
Serial No.: 17-128 Docket No.: 50-280 Attachment Page 8 of 9
- 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.
Assuming that the prior cycle operational leakage of <1 GPO 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 GPO. 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 B. Note that no bobbin probe examinations were performed in SG A and SG C during EOC27. All tubes in SG A and SG C were screened for slippage during EOC26 (no indications were identified) and will again be screened during EOC28.
AVB BPC BPH EFPM EOG FOSAR GPO MRPC NQH NTE OD ODSCC PARC OVR OXP PWSCC sec SG TSC TSH TSP TTS VOL Acronyms Anti-Vibration Bar Baffle Plate Cold Baffle Plate Hot Effective Full Power Months End of Cycle Foreign Object Search and Retrieval Gallons per Day Motorized Rotating P,ancake Coil Non Quantifiable History No Tube Expansion Outer Diameter Serial No.: 17-128 Docket No.: 50-280 Attachment Page 9 of 9 Outer Diameter Stress Corrosion Cracking Permanent Alternate Repair Criteria Over Roll Over Expansion Primary Water Stress Corrosion Cracking Stress Corrosion Cracking Steam Generator Tube Sheet Cold Tube Sheet Hot Tube Support Plate Top of Tubesheet Volumetric