AEP-NRC-2017-13, Transmittal of 2016 Steam Generator Tube Inspection Report
| ML17150A304 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/24/2017 |
| From: | Lies Q Indiana Michigan Power Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| AEP-NRC-2017-13 | |
| Download: ML17150A304 (15) | |
Text
m INDIANA Indiana Michigan Power MICHIGAN Cook Nuclear Plant POWER One Cook Place Bridgman, Ml 49106 A unit ofAmerican Electric Power lndianaMichiganPower.com May 24, 2017 AEP-NRC-2017-13 10 CFR 50.4 Docket No.: 50-316 U. S. Nuclear Regulatory Commission A TIN: Document Control Desk Washington, DC 20555-0001 Donald C. Cook Nuclear Plant Unit 2 2016 STEAM GENERATOR TUBE INSPECTION REPORT Technical Specification (TS) 5.6.7 of Appendix A, to the Donald C. Cook Nuclear Plant (CNP) Unit 2 Operating License, requires a report to be submitted within 180 days after initial entry into Mode 4 following the completion of an inspection performed in accordance with TS 5.5.7, Steam Generator (SG) Program. CNP Unit 2 entered Mode 4 on December 21, 2016. This Teport details specific attributes of the inspection in accordance with TS 5.6.7. Consistent with these requirements, Indiana Michigan Power Company, the licensee for CNP Unit 2, is submitting the Unit 2 2016 SG Tube Inspection Report as an enclosure to this letter.
There are no new regulatory commitments made in this submittal. Should you have any questions, please contact Mr. Michael K. Scarpello, Regulatory A~airs Manager, at (269) 466-2649.
Sincerely, z::-j~
Site Vice President DB/kmh
Enclosure:
Unit 2 2016 Steam Generator Tube Inspection Report c: R. J. Ancona - MPSC MDEQ - RMD/RPS NRG Resident Inspector C. D. Pederson - NRG Region Ill J. K. Rankin - Washington D.C.
A. J. Williamson - Ft. Wayne AEP, w/o enclosure
Enclosure to AEP-NRC-2017-13 Unit 2 2016 Steam Generator Tube Inspection Report Introduction UNIT2 In October/November of 2016, steam generator (SG) inservice inspections were conducted on Donald C. Cook Nuclear Plant (CNP) Unit 2. In accordance with the reporting requirements of CNP Technical Specification {TS) 5.6.7; the results of the inspection are provided herein.
Unit 2 SG Description The four replacement Westinghouse SGs were initially placed in service in March of 1989.
Each SG contains 3,592 thermally treated alloy 690 tubes with an outside diameter of 0.875 inches, and a nominal wall thickness of 0.050 inches. The tubes are arranged in a square pitch pattern of 47 rows and 98 columns. All tubes in the eight innermost rows were thermally stress relieved after tube bending to reduce residual stress.
The tube support structure consists of seven 1.12 inch thick support plates with quatrefoil~
shaped tube holes, and three sets of anti-vibration bars that are located in the U-bend region of the tubes. There is a flow distribution baffle located between the tubesheet and the first support plate. The flow distribution baffle is 0. 75 inches thick with octafoil-shaped tube holes. The support plates, anti-vibration bars, and the flow distribution baffle are made of type 405 stainless steel.
The tubesheet is composed of ASME SA-508 Class 2a low alloy steel forging material and is 21.18 inches thick (without cladding). The surface of the tubesheet in contact with reactor coolant is clad with 0.20 inches of lnconel weld material, making the overall nominal tubesheet thickness with cladding, 21.38 inches. Tubes are hydraulically expanded along the full depth of the tubesheet, with the exception of nine tubes. These tubes lack hydraulic expansion in either the hot leg or cold leg tubesheet due to a manufacturing oversight.
- At the time of the 2016 inspection, the SGs had accumulated approximately 230.1 effective full power months of operation since their first inservice inspection and approximately 86.1 effective full power months of operation in the second sequential inspection period as defined in TS 5.5.7.d.2.a and b. The SGs operated approximately 49.5 effective full power months since they were all last inspected.
As detailed in item "A" which follows, the 100% inspection scope of the 2016 examination coupled with the previous inspection completed in the spring of 2012 which was also under the second period, exceeds the 100% TS inspection requirement for the second inspection interval.
Enclosure to AEP-NRC-2017-13 Page2 A. The scope of inspections performed on each SG Primary Side Eddy Current Inspection Scope Summary:
Full Length Inspections:
- 100% inspection of the inservice tubes using a combination of bobbin coil and bobbin coil/rotating coil (+Point') examinations in all four SGs.
Targeted Inspections (Top of Tubesheet):
- 25% inspection of the inservice tubes in the hot leg and cold leg top of tubesheet region
(+/- 3.0") in SGs 21, 23 and 24 using a rotating coil (+Point').
- 100% inspection of the inservice tubes in the hot leg and cold leg top of tubesheet region (tube end to 151 support) in SG 22 using an Array probe.
Special Interest Examinations:
- Rotating coil (+Point') and Array probe inspections of selected special interest locations as determined from the results of the bobbin coil examination and historical indications of interest.
Note: As described on Page 11, Section E of this report, one tube was deplugged, examined by bobbin for investigative purposes and then replugged. In order to separate the results of this tube from the inservice tubes, it is called out separately in the last row of the table below.
The following table details the above noted inspections and the number of tubes examined.
EDDY CURRENT EXAMINATION
SUMMARY
,s<r21 .* *.* ** $~*23**** * *.:.SQ24 i'.Olie :*.1JMbe<:. :
- Tub.e.
.oeount~' Q"ourit ' count**
Full Length Bobbin Tube End Cold (TEC) 3200 3200 3196 to Tube End Hot TEH)
Hot Leg Straights Bobbin Upper Hot Leg 195 192 190 196 Support (7H) toTEH Hot Leg Bobbin Upper Cold Leg 196 196 196 196 Straig hts/U bend Support (7C) toTEH Bobbin 7C to TEC 388 386 392 7H to 7C 192 190 196 Hot Leg Array First Hot Leg Support 0 3586 0 0 Top of Tubesheet (1 H) toTEH
Enclosure to AEP-NRC-2017-13 Page 3
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' *"'"' '* *"* 1 Cold Leg Array First Cold Leg 0 3586 0 0 Top of Tubesheet Support (1 C) toTEC Hot Leg +PointllVI Hot Leg Top of 937* 0 924* 936*
Top of Tubesheet Tubesheet
( +/- 3")
Cold Leg +PointllVI Cold Leg Top of 927* 0 920* 921*
Top of Tubesheet Tubesheet
( +/- 3")
~
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Special Interest & Array 6th Hot Leg Support 0 32 0 0 Bounding (6H) toTEH Hot Leg Special Array Tube Sheet Hot 0 8 0 0 Interest to TEH Cold Leg Special Array Tube Sheet Cold 0 14 0 0 Interest toTEC I*. .... *1*'. ...... .....,,, ., . .1.,1.. '. ......,: *** .
11
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Hot Leg Special +Point vi Various 36 67 141 25 Interest Cold Leg Special +Point 11vi Various 7 80 43 3 Interest U-bend Special +Point 11vi Various 5 20 5 8 Interest Special Interest Array Various 0 0 0 22 Foreign Object De-Plugged Tube Bobbin TEC to TEH 0 1 0 0
- Hot and cold leg counts vary between the different legs as well as the different steam generators due to differing indications of interest in each area that were included within the individual examination plans Full Length Examinations:
Full length examinations were accomplished in five examination plans.
Plan one consisted of tubes inspected using a bobbin coil probe in a single full length pass (i.e.
TEC to TEH). This inspection included the inservice tubes in rows five though forty-seven.
This population ranged from 3196-3200 tubes, per steam generator.
Plan two consisted of the tubes inspected from 7H to TEH using a bobbin coil probe. Tubes in this "hot leg straight" plan were from rows one and two and accounted for 190 - 196 tubes per steam generator.
Plan three consisted of tubes inspected using a bobbin coil probe from 7C to TEH. Tubes in
Enclosure to AEP-NRC-2017-13 Page4 this "hot leg candy cane" plan were from rows three through four and accounted for 196 tubes per steam generator.
Plan four consisted of tubes inspected using a bobbin coil from the TEC to 7C. This inspection included the inservice tubes in rows one through four and accounted for 386 - 392 tubes per steam generator.
Plan five utilized a rotating coil (+Point') probe to inspect the inservice row one and two tubes from 7H to 7C. This test plan population ranged from 190 - 196 tubes per steam generator.
This inspection plan was necessary as plans one through four present an un-inspected gap from 7H to 7C in row 1 and 2. This is a result of the inspection difficulties presented by the tight row U-bends and use of the standard 720 bobbin probe. As downsizing the bobbin probe would invalidate the probe qualification, the rotating coil was used to fill this gap.
Targeted Examinations (Top of Tubesheet):
A nominal 25% hot/cold leg top of tubesheet inspection was conducted using a +Point' probe in steam generators 21, 23 and 24. Unless otherwise programmed, the examination bounded top of tubesheet +/- 3" (in a few cases the extent was modified to obtain data on signals which fell outside the+/- 3" range).
With the detection of a small primary-to-secondary leak in SG 22 weeks before the inspection was scheduled to begin, the planned 25% +Point' tubesheet inspection in that steam generator was superseded by a 100% tube end to first support, hot and cold leg inspection using an Array probe. Note: The primary-to-secondary leak is discussed further in a separate section titled "ADDITIONAL INFORMATION" at the end of this report.
Special Interest Examinations:
The following special interest examinations were conducted using a +Point' probe (unless otherwise noted) on reported indications meeting the following criteria:
- All wear at tube support plates, anti-vibration bars and the flow distribution baffle
- All bobbin loose part (PLP) and/or Array PLP indications
- All locations affected by historical loose parts
- All foreign object affected tubes as identified by secondary side visual inspection
- All bobbin I-codes and new bobbin signals - Array was used on these indications if they were located between the tube end and the first support in SG 22
- All manufacturing burnish mark history (MBH), freespan history (FSH), non-quantifiable history (NQH) or non-quantifiable signal (NQS) - Array was used on these indications if they were located between the tube end and the first support in SG 22
- All historical non-hydraulically expanded/bulge indications - Array was used in SG 22
- All bobbin dent/ding signals <:: 2 volts at supports and all dent/ding signals <:: 5 volts at other locations
- All indications of proximity and/or freespan wear
- All historical permeability variation (PVN) indications
Enclosure to AEP-NRC-2017-13 Page 5 Channel Head and Plug Visual Inspections Each of the steam generator channel heads (hot and cold leg) was visually inspected in line with recommendations made in Westinghouse Nuclear Safety Analysis Letter (NSAL) 12-1. Key areas of interest included the low lying areas, the channel head cladding and the divider plate-to-channel head weld. The inspections looked for evidence of gross defects such as indications in welds, missing weld filler material, a breach in the weld material, unusual discoloration of the weld metal, dings or gouges. The results were noted as "satisfactory" meaning no problems, discrepancies and/or anomalous conditions were present. Additional visual inspections, outside of the NSAL scope were also performed. These inspections included views of the tube sheet cladding, and divider plate and nozzle dam ring. No degradation was identified from these inspections.
A visual inspection was performed on all prior installed plugs and those new plugs installed during the U2C23 inspection. No degraded plugs were identified.
In conjunction with the lnservice Inspection (ISi) Program and per ASME Code Case N-619 as amended by Regulatory Guide 1.147 (Revision 17) visual inspections were performed on the inner radius nozzles (inlet and outlet) on each steam generator. The results of these inspections were all termed acceptable.
Secondary Side Inspection Scope Secondary side inspections were performed in all four SGs. The scope included visual inspections in all four steam domes as well as at the top of the hot and cold leg tubesheets.
Areas examined included:
- Dryers/secondary side separators:
Inspect for proper vane arrangement, drain operability, erosion/corrosion, debris or deposits, loose/ damaged components and cracked weld joints
- Primary side separators:
Inspect for swirl vane and weld joint integrity, presence of tangential outlets/orientation and blockages of the perforated holes
Inspect for J-Nozzle position/ orientation/ integrity, J-tube to feedring interface for flow assisted corrosion, support bracket integrity, overspray staining/ deposits
- Steam drum general area:
Inspect each accessible deck noting condition of welds, ladders, supports, wedges, drain supports and hatch hinges and latches
- U-bend region:
Inspect from the primary separator openings for observations of deposit accumulation and hardware conditions near the anti-vibration bars and upper most support plate
Enclosure to AEP-NRC-2017-13 Page 6
- Post water lance inspections of the top of tubesheet:
This included the annulus, no-tube lane, blowdown piping, and shroud I flow distribution baffle plate condition
- Inner bundle top of tubesheet passes:
Performed on the hot and cold leg top of tubesheet areas to monitor the status of the sludge pile and water lancing effectiveness No abnormalities were identified by the above inspections. The post water lance top of tubesheet inspection did identify the presence of hard sludge/collars in each of the hot leg tubesheets. However, this is not considered a new or abnormal condition.
In addition to the above inspections, foreign object locations and possible loose part signals from eddy current were visually investigated where accessible. Retrieval efforts successfully removed the three new foreign objects that were confirmed through these actions.
Water Lancing Water lancing was performed in each SG and removed a total of 87 pounds of material from the four SGs.
B. Degradation mechanisms found The degradation mechanisms detected during the inspection were structure wear (anti-vibration bars and tube support plates) and two volumetric indications.
The table below summarizes the number of indications recorded in each SG during the inspection for the various mechanisms. The specific indication locations and their associated percent through-wall (%TW) depths are provided in the response to report item "D".
INDICATION COUNTS Anti-Vibration Bar Wear 0 2 1 0 3 Tube Support Plate Wear 10 0 59 10 79 Volumetric O 2 0 0 2 Anti-Vibration Bar (AVB) Wear A total of three AVB wear indications were reported. Two of the indications were located in SG 22 and one was located in SG 23. The SG 22 indications were new and were sized at 8% TW and 11 % TW. The indication in SG 23 was previously reported and was found to have grown from 11 % TW in the previous inspection to 15% TW in 2016. All of the affected tubes were left in service.
Tube Support Plate (TSP) Wear TSP wear was detected in three of the four steam generators as noted in the above table. Of the 79 total indications, 39 were new and 40 were repeat indications. All of the indications were
Enclosure to AEP-NRC-2017-13 Page 7
~ 20% TW with the largest being 13% TW. All of the TSP wear indications were returned to service.
Volumetric (VOL)
Two volumetric indications were detected by the bobbin probe in SG 22 just above the 5th hot leg support in outer periphery tubes (R46/C62 and R47/C57). The two volumetric indications demonstrated a change from history in the bobbin voltage since the previous U2C20, 2012 inspection. That is, the bobbin voltage increased from 0.25 volts (V) to 1.21V in tube R47/C57 and from O.SOV to 1.20V in tube R46/C62.
The bobbin signals in the raw channels demonstrated excellent correlation using the phase angle sizing curves set on the calibration standing with the ASME flat bottom holes. The indication in tube R47/C57 measured: 14% through-wall (TW), 14% TW and 14% TW on the 400 kHz, 200 kHz and 100 kHz raw channels respectively. The indication in tube R46/C62 measured 11 % TW, 11 % TW and 12% TW on the same frequencies. Both of these bobbin signals were reported as non-quantifiable indications and required subsequent diagnostic testing using a +Point' probe and elective testing with the Array probe to further characterize the indications.
Both locations were subsequently confirmed to be volumetric indications and found to exhibit wear-like degradation with no loose part present. The orientation (azimuthal position) of each indication was determined to be on the outboard side of the tube. That is, the indications were on the side of the tube facing the steam generator wrapper. Since this area was not accessible for visual inspection, conclusive visual determination of a loose part could not be confirmed.
Based on the indications' location (periphery) and the indications' shape and bobbin response, both indications appear to have been caused by a foreign object. A 30 tube bounding examination was conducted around the two indications using the Array probe and +Point' probe and no evidence of any other degradation or loose parts was reported.
Both indications were sized using +Point'. The most appropriate Electric Power Research Institute (EPRI) technique was determined to be Examination Technique Specification Sheet (ETSS) 27904.1 based on the flaw shape. The indication in tube R46/C62 has a maximum depth of 39% TW while the indication in tube R47/C57 had a maximum depth of 38% TW.
Neither of the two indications exceeded the tech spec plugging limit of 40% TW or the condition monitoring limit. The indications did not meet any criteria that would require plugging; nevertheless, both tubes were plugged and stabilized.
C. Nondestructive examination techniques utilized for each degradation mechanism The table below summarizes the nondestructive examination (NOE) techniques utilized for the degradation mechanisms identified in item "B" above.
Enclosure to AEP-NRC-2017-13 Page 8
SUMMARY
OF INSPECTION TECHNIQUES Oer:n~nstra~edr.
- A:ppii'ct;itlilify .:Ot'
,* )i)eg'r:~datiot1::'* *
. *.:Niedhtfoi'sm **
- Freespan Volumetric Bobbin /Absolute Mix Wear, Amplitude Analysis Support Wear Bobbin 96004.1 Loose Part Wear with Detection (AVB, FOB, TSP) part present Sizing For Service For Structure Wear Detection of foreign material based on material composition and proximity of foreign material to the PLP Wear at tube, based on EPRI Freespan, TSP and 27903.1 reports 1020631 and
+Point' Expansion Transition.
27904.1 1018561. Sizing For Service Morphology For sizing of PLP Dependent Wear when part is (part not present) present based on EPRI Report 1020631 on an as needed basis as yields conservative results.
+Point +Point I Differential Mix 96910.1 Broached TSP Wear FOB Wear Diagnostic Phase Analysis Detection AVB Anti-Vibration Bar PLP Possible Loose Part EPRI Electric Power Research Institute TSP Tube Support Plate ETSS Examination Technique Specification Sheet FOB Flow Distribution Baffle
. Enclosure to AEP-NRC-2017-13 Page 9 D. Location, orientation (if linear), and measured sizes (if available) of service induced indications Indication sizing is summarized below:
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21 3 47 5 5th hot leg support - 0.59" Left in service 21 6 47 7 5th hot leg support- 0.64" Left in service 21 6 51 6 5m hot leg support - 0.62" Left in service 12 5th hot leg support - 0.6" 21 6 53 6 5th hot leg support - 0.53" Left in service 13 5th hot leg support - 0.6" 21 6 54 10 4th hot leg support - 0.55" Left in service 8 5th hot leg support - 0.57" 21 12 50 7 5th hot leg support - 0.64" Left in service 21 47 57 7 7tn cold leg support - 0.65" Left in service Ii:** .. **i I:. ,.,,.,. "*. i li''"'****'Y/* ********.>.> .* !*********. >**"**:*'i:*; ....* ,... , ** *,*'! i" ;.;.'V 22 45 49 8 AV4+0.32" Left in service 22 46 46 11 AV4+0.27" Left in service 22 46* 62 39 5m hot leg support+0.85" Stabilized and plugged 22 47* 57 38 5th hot leg support +1.63" Stabilized and pluaaed
- . . i 23 1 37 6 5m hot leg support- 0.65" Left in service 9 5th hot leQ support - 0.67" 23 1 42 6 em hot leg support - 0.64" Left in service 23 1 45 7 5m hot leg support- 0.65" Left in service 7 5th hot leg support - 0.64" 23 1 47 6 5tn hot leQ support - 0.62" Left in service 23 1 54 8 em hot leg support - 0.62" Left in service 23 3 38 3 5th hot leg support - 0.67" Left in service 5 5th hot leg support - 0.67" 23 3 57 5 5tn hot leg support - 0.62" Left in service 8 5th hot leg support- 0.62" 23 3 75 7 5m hot leg support - 0.65" Left in service 23 3 79 5 5th hot leg support- 0.67" Left in service 23 4 55 7 5m hot leg support - 0.67" Left in service 8 5th hot leg support - 0.69" 23 4 56 5 5m hot leg support - 0.65" Left in service 10 5th hot leg support - 0.67" 23 4 57 7 em hot leg support - 0.69" Left in service 23 4 59 5 5m hot leg support - 0.65" Left in service 6 5th hot leg support - 0.69" 23 4 64 6 5m hot leQ support - 0.67" Left in service 23 5 47 8 em hot leg support - 0.67" Left in service 23 5 49 7 5th hot leg support - 0.67" Left in service
Enclosure to AEP-NRC-2017-13 Page 10
'SG: **Row' .,.,,Column ' Depth v Location ** * . ' ""....tube Qispo$ition. .
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23 5 50 7 5tn hot leg support - 0.65" Left in service 6 5th hot leQ support - 0.65" 23 5 51 6 4tn hot leg support- 0.58" Left in service 5 5th hot leQ support - 0.62" 23 5 89 8 5tn hot leg support - 0.67" Left in service 23 6 42 5 5th hot leg support - 0.64" Left in service 23 6 50 6 5tn cold leg support - 0.62" Left in service 23 6 53 8 em hot leg support - 0.67" Left in service 23 6 82 5 4th hot leg support - 0.53" Left in service 23 7 44 9 3rd hot leg support - 0.55" Left in service 6 4th hot leg support - 0.63" 7 5th hot leg support - 0.6" 6 5th hot leg support - 0.67" 23 7 46 6 3ra hot leg support - 0.58" Left in service 8 5th hot leg support - 0.65" 9 5th hot leg support- 0.71" 9 th hot leg support - 0.65" 23 7 48 7 4m hot leg support - 0.67" Left in service 7 5th hot leg support - 0.67" 9 5th hot leg support - 0.67" 23 7 49 7 em cold leg support - 0.6" Left in service 23 7 50 7 4m hofleg support- 0.56" Left in service 23 7 51 7 5tn hot .leg support - 0.65" Left in service 23 7 55 6 5tn hot leg support - 0.6" Left in service 23 9 43 6 th hot leg support - 0.62" Left in service 23 12 51 6 7th hot leg support - 0.65" Left in service 23 12 54 6 4th hot leg support - 0.6" Left in service 9 th hot leg support- 0.56" 23 16 35 8 3rd hot leg support - 0.6" Left in service 23 16 50 5 4m hot leg support- 0.59" Left in service 23 17 45 8 3rd hot leQ suooort - 0.58" Left in service 23 28 47 6 7m cold leg support - 0.63" Left in service 23 33 32 6 1st hot leg support - 0.54" Left in service 23 35 58 4 7m cold leg support - 0.62" Left in service 23 46 53 8 7m hot leQ support - 0.69" Left in service 23 46 59 7 tn hot leg support - 0. 74" Left in service 23 47 50 15 AV3-0.32" Left in service
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24 2 43 8 em hot leg support - 0.67" Left in service 24 2 47 8 5m hot leg support- 0.51" Left in service 8 5th hot leg support - 0.57" 24 3 44 8 5m hot leg support - 0.59" Left in service 7 5th hot leg support- 0.63" 24 4 45 10 5th hot leg support- 0.61" Left in service 7 5th hot leg support- 0.61"
Enclosure to AEP-NRC-2017-13 Page 11
... :<Depth~: ft.1.t>'e.'bispdsitioh
- o/o. ,fW:<,,
24 6 47 7 24 7 46 7 Left in service 24 7 54 9 Left in service
- Additional details on the two volumetric indications are contained in the table below:
.sG* .. ' Ro:w: c<:>1umn :tocauo:n'ii': *:*.*
1 1::
1 11 * '~'*::stss* :*i:i:>
11
- tnnax . ,:,"~xiiH 1 ** Jc ire~ *:*;:
- t)epttf:*:' L~ng~h ' .Extent,::. : :
- .:.o/o.:JW,* ,,~(in;), d~gr~~~L 12 NIA N/A 39 0.32 80 25 0.32 80 22 47 57 5 hot leg Bobbin 14 N/A N/A support +1.63" 27904.1 38 0.40 79 27903.1 23 0.40 79 E. Number of tubes plugged during the inspection outage for each degradation mechanism
': ,**:: ':1:::.-*,
Tube Support Wear 0 0 0 0 0 Anti-Vibration Bar Wear 0 0 0 0 0 Volumetric 0 2 0 0 2 In addition to the two tubes that were plugged in SG 22, one out of service tube in SG 22 (Row 8/Column 3) was unplugged on both ends, tested by bobbin and replugged with mechanical alloy 690 thermally treated plugs. The only notable bobbin signal was a large factory over expansion above the cold leg tubesheet. The original welded plugs were installed during steam generator manufacture to address the over expansion and were made of alloy 600 material.
The replacement was a proactive measure to remove the alloy 600 plug material from the steam generator.
F. The number and percentage of tubes plugged to date, and the effective plugging percentage in each SG The following table identifies the total number/percentage of tubes plugged for each SG to date:
'Nurnber1"<:>fi'rub~s**:: ,1.:i:.pfi.JtfgingiPE~rcentage* *I , , , ., *: ... ' . . . : . ' *.:
0 I:':.:,,**.,,"""" .::. * <:**. Ii:: ..::*:*Plugged
- . " ' . :To.Date
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,: .*:::. *. u:::<:** *"
SG 21 3,592 1 0.028 SG 22 3,592 8 0.223 SG 23 3,592 6 0.167 SG24 3,592 4 0.111 Total 14,368 19 0.132
Enclosure to AEP-NRC-2017-13 Page 12 G. Results of condition monitoring, including the results of tube pulls and in-situ testing Evaluation of the indications found during the 2016 inspection indicated that the condition monitoring requirements for structural and leakage integrity were satisfied.
Degradation specific condition monitoring limits were applied to the indications for each degradation mode (anti-vibration, tube support wear and volumetric). As shown in the figures below, no degradation exceeded the technical specification repair limit of 40% TW or the structural condition monitoring limits. As wear indications will leak and break at essentially the same pressure differential, leakage integrity for anti-vibration and tube support plate wear at a much lower faulted differential pressure (2,560 psid) was also demonstrated.
If the volumetric indications are treated as a form of wear-like indication, the same methodology applies, thus the leakage integrity is also demonstrated by the volumetric curve below. Since the volumetric indications resemble an elliptical patch of degradation, leakage due to pop-through was also considered. That is, when considering the worst case accident differential, the largest volumetric indication continues to remain bounded by the pop-through curve at a bounding 0.5 inch length as illustrated in the last figure, thus confirming leakage integrity is satisfied for both volumetric indications.
ANTI-VIBRATION BAR WEAR CONDITION MONITORING LIMIT ETSS 96004.1 All SGs AVB Wear Condition Monitoring Curve DC Cook U2C23 October2016 70.0 I
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Enclosure to AEP-NRC-2017-13 Page 13 TUBE SUPPORT PLATE WEAR CONDITION MONITORING LIMIT ETSS 96004.1 All SGs TSPWearCondition Monitoring Curve DC Cook U2C23 October2016 70.0 I
--3dP=4640 ._
60.0 50.0
\ x NOE Data@ 1.12 inch Bounding Length
~~
w a
40.0 30.0
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z 20.0 10.0 0.0 1--
0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Length VOLUMETRIC CONDITION MONITORING LIMIT ETSS 27904.1 SG22 VOL Indications Condition Monitoring Curve DC Cook U2C23 October2016 70.0 I
\. --3dP=4640 60.0 *-
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20.0 10.0 l
0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Length
Enclosure to AEP-NRC-2017-13 Page 14 POP-THROUGH CURVE FOR LARGEST VOLUMETRIC INDICATION DC Cook 2 Pop-Through Depth Vs. Length at Delta Pressure of 4640 psid 100
....-Pop-Through 90
-tt-"95150 VOL Depth" 80
~
- Ii.
"E Ci.
c 50 iii 70 60
"' ~
~ 40 f
30 20 10 0
0 0.2 0.4 0.6 0.8 1.2 1.4 1.6 Physical Length (in.)
The inspection found no indications that met the criteria for in-situ pressure testing and no tubes were required to be pulled.
ADDITIONAL INFORMATION On August 12, 2016, a small (0.04-0.08 gallons per day) primary to secondary leak was detected prior to the scheduled unit shutdown of CNP Unit 2. The leak was subsequently linked to SG 22 and as a result, the eddy current inspection scope for that steam generator was revised to include a 100% Array probe inspection from the tube end to the first support in both the hot and cold legs. This was based on the supposition that the leak was most likely foreign object related as this steam generator had no detectable degradation during the previous inspection and alloy 690 tubing has demonstrated resistance to degradation forms other than wear. However, the full length bobbin examination, the Array inspection and the secondary side visual inspections failed to identify the source of the leak. Upon unit restart and replacement of two damaged fuel assemblies, the leak became undetectable. Plant operations continue with normal leakage monitoring/response actions in place.
L ____