ML14069A173
| ML14069A173 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 02/26/2014 |
| From: | Scace S Dominion Nuclear Connecticut |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 14-058 | |
| Download: ML14069A173 (11) | |
Text
Dominion Nuclear Connecticut, Inc. ~Dominion Rope Ferry Rd., \Vaterford, CT 06385 Mailing Address: P.O. Box 128 Warerfbrd, CT 06385 dom.corn FEB,2 6 2014 U.S. Nuclear Regulatory Commission Serial No.14-058 Attention: Document Control Desk NLOS/WDC RO Washington, DC 20555 Docket No. 50-423 License No. NPF-49 DOMINION NUCLEAR CONNECTICUT, INC.
MILLSTONE POWER STATION UNIT 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING END OF CYCLE 15 STEAM GENERATOR TUBE INSPECTION REPORT By letter dated October 2, 2013, Dominion Nuclear Connecticut, Inc. (DNC) submitted information summarizing the results of the Millstone Power Station Unit 3 (MPS3), end of cycle 15, steam generator tube inspections performed during Refueling Outage 15 (spring 2013). In a letter dated January 30, 2014, the Nuclear Regulatory Commission (NRC) transmitted a request for additional information (RAI) to DNC related to the inspection report. DNC agreed to respond to the RAI by March 31, 2014.
The attachment to this letter provides DNC's response to the NRC's RAI.
If you have any questions regarding this submittal, please contact Mr, William D. Bartron at (860) 444-4301.
Sincerely, Site Vice President - Millstone Commitments made in this letter: None
Attachment:
Response to Request for Additional Information Regarding End of Cycle 15 Steam Generator Tube Inspection Report
Serial No.14-058 Docket No. 50-423 Page 2 of 2 cc: U.S. Nuclear Regulatory Commission Region I 2100 Renaissance Blvd, Suite 100 King of Prussia, PA 19406-2713 M. C. Thadani Project Manager - Millstone Power Station U.S. Nuclear Regulatory Commission One White Flint North, Mail Stop 08-Bl 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector Millstone Power Station
Serial No.14-058 Docket No. 50-423 ATTACHMENT RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING END OF CYCLE 15 STEAM GENERATOR TUBE INSPECTION REPORT DOMINION NUCLEAR CONNECTICUT, INC.
MILLSTONE POWER STATION UNIT 3
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 1 of 8 By letter dated October 2, 2013, Dominion Nuclear Connecticut, Inc. (DNC) submitted information summarizing the results of the Millstone Power Station Unit 3 (MPS3), end of cycle (EOC) 15, steam generator tube inspections performed during Refueling Outage 15 (3R15) (spring 2013). In a letter dated January 30, 2014, the Nuclear Regulatory Commission (NRC) transmitted a request for additional information (RAI) to DNC related to the inspection report. This attachment provides DNC's response to the NRC's RAI.
Question I Page 2 of Enclosure I to your October 2 letter indicates that secondary side activities were performed in Steam Generators (SGs) B, C, and D, including high-pressuresludge lancing and upper bundle flushing; a post-sludge lancing visual examination of the top-of-the-tubesheet annulus and no-tube lane; a visual investigation of accessible locations having eddy current testing indications potentially related to foreign objects; and, if present, removal of retrievable foreign objects. Please discuss the results of these inspections.
DNC Response The top-of-tubesheet (TTS) inspections revealed mostly clean conditions in SGs B, C, and D, with minor flake piles remaining. As typical, these sludge flakes were located at the 90 degree hand holes in the stay rod lance shadow zones near the water lance suction feet. In-bundle views along the periphery of SGs B, C, and D revealed the tubesheets to be very clean. The blowdown piping and center stay rod were in satisfactory condition and the no-tube lanes were clean. No TTS loose parts were identified by visual or eddy current examination that required removal from the SGs.
Question 2 Page 2 of Enclosure I to your October 2 letter indicates that secondary side upper internal examinations were performed in SG C. Please discuss the results of these examinations (e.g., was any degradation observed on any of the secondary side internals, were the tube support openings clear of deposits, etc.).
DNC Response Visual inspections of the steam drum and upper bundle regions of SG C were performed following Upper Bundle Flush (UBF) operations. The inspections of the steam drum, as well as upper bundle regions above the 7t" support plate, revealed SG C to be in good structural condition with no evidence of erosion or corrosion. The general area revealed a light, tightly adhering layer of deposit material on the surfaces inside the steam space.
No abnormal conditions were noted during the inspection.
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 2 of 8 The primary separator swirl vanes were in good condition. The vane edges were square with no indication of erosion or corrosion. The secondary separator chevrons appeared straight and the holes in the perforated plates were clear and unblocked. The drains, including the main drain and drain supports, were in good condition. Wedges, welds, and supports on the upper, mid, and lower decks appeared to be in a good condition.
On the lower deck, the feedwater piping and associated supports were in satisfactory condition. The thirty (30) feedring J-nozzles were visually inspected on the outer and inner diameter and were in satisfactory condition. The primary separator riser barrels appeared to be in good condition and unaffected by overspray from feedwater nozzles.
The U-bend region was inspected by lowering a video probe down through the primary separator swirl vanes. This method was used to access the anti-vibration bars (AVBs),
the mid span of the U-bend tubes, and the top of the 7 th tube support plate (TSP).
Deposit bridging of the tubes to the AVBs was observed, but much of the loose deposit material had been removed by the UBF process. Spalled deposits from the tubes were noted mid span of the top of the bundle and the 7 th TSP.
Some blockage of the TSP openings was observed. The accumulation of deposit material in the TSP flow holes was observed during visual examination and through the use of a low frequency eddy current technique called Deposit Mapping. The Deposit Mapping technique provided repeatable results for the entire tube bundle whereas the visual examination method (which entails dropping a video probe down through the SG swirl vanes) provided snapshots of random locations. An illustration of video probe travel path is provided in Figure 1.
In summary, the secondary side of the SG C steam drum and upper bundle region were in good condition with no visible damage, degradation, or abnormalities.
Question 3 Please discuss the scope and results of any tube plug inspections (e.g., was there any degradationand were all plugs in their properlocations).
DNC Response Prior to conducting the eddy current examination of the tubes in SGs B and D, a specific remote visual inspection and location verification process was used for the existing tube plugs (20 tubes in SG B and 86 tubes in SG D were plugged at the time of this visual examination). The objective of these examinations was to verify the presence and location of existing in-service plugs and to identify any potential abnormalities associated with the plugs. These examinations were conducted in accordance with the EPRI Pressurized Water Reactor Steam Generator Examination Guidelines.
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 3 of 8 The location verification of existing in-service plugs was assured through the use of the Machine Vision (MV) system in conjunction with a calibrated manipulator that uses the Electronic Plug Verification (EPV) program. The Machine Vision and manipulator systems are calibrated independently. Position verification is performed using the manipulator and Machine Vision by visiting two known locations at least ten tubes apart to ensure both systems match and agree on the location.
Visual examination of SG tube plugs are performed by qualified eddy current data acquisition personnel. Oversight is maintained during these examinations through the use of Quality Control (QC) inspectors. Personnel involved in the visual examinations
-receive specific training in this area. The visual examinations are conducted to look for evidence of plug leakage that may include excessive boron buildup, tubesheet protrusion, wetness around the tube plug, or any other abnormality. The visual examinations are recorded on electronic media and reviewed by the Millstone Steam Generator Program owner (i.e., a station licensee individual responsib!e for non-destructive examination).
During the visual examinations performed in 3R15, previously installed tube plugs were found to be in the proper location with no evidence of leakage or abnormalities.
Question 4 Please discuss the scope and results of any inspections performed in the SG primary channel heads.
DNC Response Upon opening the SG primary channel heads, a general, as-found inspection is initially performed to identify any obvious abnormalities such as the presence of foreign objects or discoloration. Any water remaining in the bottom of the bowl is then vacuumed out. A more detailed bowl scan is then performed which focuses on the SG tubesheet cladding, the tube-to-tubesheet welds, the partition divider plate (DP), stub runner (SR), DP-to-tubesheet cladding weld, DP-to-channel head weld, SR-to-DP weld, and the SR-to-tubesheet weld. These examinations are performed to identify any gross degradation in the welds. The cladding is examined visually for any discoloration or rust stains which could indicate a breach of the cladding. The examination of the cladding is performed during the as-found and as-left examination.
During 3R1 5, both of the primary channel heads (hot leg and cold leg) in SGs B and D were inspected. The inspections revealed no degradation to any of the structures identified above. Additionally, no discoloration or rust stains were identified that would indicate a breach of the cladding.
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 4 of 8 Question 5 A number of new wear indications were reported during refueling outage (RFO) 15 both at the anti-vibration bars and at the tube support plates. Please discuss any insights on the reason for the increase in the number of indications. In addition, some of the wear indicationsat the tube support plates appeared to initiate and grow significantly over the last operating interval. Please discuss any insights on the growth of these indications.
Please discuss whether the size of these indications was consistent with your projections in your last operationalassessment. If not, please discuss any corrective action taken to address any underpredictions.
DNC Response AVB and TSP wear are both listed as existing degradation mechanisms in the 3R15 Degradation Assessment. The first eddy current evidence of TSP wear at MPS3 was recorded in SG D during 3R9 (spring of 2004). From that time through the most recent outage (3R15), the quantity and severity of new TSP wear indications has increased each outage.
During the 3R15 eddy current examinations, several new TSP wear indications were identified, including two which exceeded the 40% through-wall (TIW) technical specification plugging criteria (SGB R22 C80, 47%TW at 08C and SGD R44 C89, 45%TW at 08C). Although both wear indications required plugging, both were well below the condition monitoring structural limit. Seven additional tubes with new TSP wear, sized >15 %TW, were also preventively plugged to conservatively address uncertainty in the growth rate of these newly developed flaws.
Two explanations for the increased number and depth of TSP wear indications and the absence of growth in others are considered plausible. First, it is conceivable that increased feedwater flow resulting from the Stretch Power Uprate (SPU) has caused a global increase in tube crossflow velocity within the tube bundle. This in-turn could have increased the magnitude of flow induced vibration and the incidence of TSP wear. While this is possible, it is considered to be unlikely. A significant increase in the incidence of TSP wear was not observed in SGs A and C during the 3R14 inspection after operating for two fuel cycles in the uprated condition. In addition, no increase in the growth rate of AVB wear has been observed in any of the four SGs during any of the three inspections performed since the SPU was implemented. These findings do not appear to be consistent with a global increase in tube bundle crossflow velocity.
The second possible explanation for the most recent TSP inspection results may be attributed to the heavy deposit inventory on the secondary side of the MPS3 SGs. As documented in NRC Information Notice 2007-37, accumulated secondary side deposits in the Cruas Unit 4 SGs changed the local flow behavior and ultimately caused tube fatigue cracking and operational leakage. While this operating experience illustrates an extreme consequence of heavy deposition, the increase in the number of new TSP wear
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 5 of 8 indications identified during 3R15 may be an early bellwether of changed local flow conditions within the tube bundle. Under this scenario, areas of the tube bundle newly excited by flow induced vibration would be expected to respond in a manner similar to a new SG. That is, initial wear depth growth tends to be rapid in locations particularly susceptible to wear such as broaches with sharp edges or burrs. Subsequent volumetric growth tends to remain constant with time, and consequently, the depth growth rate slows with time. This behavior has been observed at many plants experiencing AVB wear, including MPS3. AVB wear approaching the plugging limit developed during the first MPS3 operating cycle. During subsequent cycles, newly developed AVB wear was much less significant. Today, AVB wear growth rates are very low.
Repair projections in the 3R15 Degradation Assessment predicted between 10 and 20 tubes would require plugging for wear-related degradation. The actual number of tubes plugged during 3R1 5 was 10; with eight of those discretionarily plugged.
Two corrective actions are being implemented to address the deposit loading on the secondary side of the SGs which has resulted in TSP blockage. Deposit Minimization Treatment (DMT), which is a soft chemical cleaning technique developed by AREVA, will be applied in the fall of 2014 to reduce the deposit loading and clear the TSP blockage.
This chemical cleaning process will be repeated again in the spring of 2016. The second corrective action is the injection of Poly Acrylic Acid (PAA). PAA is a high molecular weight polymer designed to "wrap up" incoming iron from the feed train and allow that iron to be passed through to the SG blowdown line prior to depositing in the SGs. PAA increases blowdown efficiency up to 40-50% and reduces the corrosion product accumulations.
Question 6 Please clarify whether any high row tubes have potentially elevated residual stresses, as evidenced by the eddy currentdata (i.e., 2-sigma tubes). If there are such tubes, please discuss how many tubes there are and whether any rotatingprobe (or array)exams were performed on these tubes at locations such as the expansion transition,dents, or dings.
DNC Response An evaluation of the MPS3 SG high row tubing (Rows 11 through 59) was performed to identify potentially elevated residual stresses, as evidenced by the eddy current data (i.e., 2-sigma tubes). A tube is considered to be highly susceptible to the early onset of Stress Corrosion Cracking (SCC) due to elevated residual stress when the offset voltage from both legs is more than two standard deviations below the regression line. These are classified as the Tier 1 tubes. In order to define a potential buffer zone population, tubes that display a 2-sigma value on only one leg, are classified as Tier 2 tubes.
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 6 of 8 The method recommended by the Electric Power Research Institute, Steam Generator Management Program (i.e., Westinghouse "Linear Regression Technique") to identify potentially high stress tubes assumes a linear relationship between the offset voltage and the row number. This method has demonstrated however, that there is a relatively steady decrease in the average offset voltage from Row 11 through approximately Row
- 45. After Row 45, there appears to be no obvious relationship between voltage and row number, (i.e., the average for these rows is fairly constant with no decreasing trend toward the higher rows). Using this method, 88 Tier 1 tubes in the four SGs were identified as being susceptible to the early onset of SCC; however, only one of these tubes was in a row higher than Row 45. This illustrates that the linear regression method may be biased toward selecting tubes in lower rows.
Since there appeared to be a bias in the results using the linear regression method, another approach was also applied in which an average and a standard deviation were calculated for each row in each SG. An offset voltage was considered to be an outlier if it was more than two times the standard deviation below the average voltage for the given row. This method identified 125 tubes as most susceptible to SCC (Tier 1). Using this method, 20% of the tubes identified (i.e., 25 of 125) were in rows higher than Row
- 45. The ratio of the total population of tubes greater than Row 45 to the tubes greater than Row 10 is about 17%. Therefore, the "Row" method appears to provide a more equal weighting to those tubes in the higher rows than the linear regression method.
Throughout the four MPS3 SGs, a total of 159 tubes were identified as Tier 1 tubes, while a total of 1243 tubes were identified as Tier 2 tubes. Of the Tier 1 tubes, 54 tubes failed both the linear regression and row criteria, 34 tubes failed only the linear regression criteria, and 71 tubes failed only the row criteria.
Number of Tubes Which Failed the 2-Sigma Screening Criteria (Tier 1/Tier 2)
Regre - Row B Regression Row. Total that Failed
.R eMsethods4Methdd Method Method , Either or Both
.5G..ethd. Mehod Methods OnY Only Total Total. ... Methods A 12/141 23/90 32/86 44/227 55/176 67/317 B 5/140 17/86 8/60 13/200 25/146 30/286 C 9/134 18/65 12/93 21 /227 30/158 39/292 D 8/189 13/85 2/74 10/263 15/159 23/348 Total 34 / 604 71/326 54/313 88/917 125/639 159/1243 If SCC is detected at any location in any SG tube, the database of Tier 1 and Tier 2 tubes will then be used to validate the 2-sigma theory for increased susceptibility due to elevated residual stresses and to define the population scope for expanded examinations.
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 7 of 8 Although a thorough evaluation of the MPS3 steam generator tubes with regard to potentially elevated residual stresses and susceptibility to SCC was performed, DNC has elected to perform a comprehensive examination scope that encompasses the locations most susceptible to SCC in all steam generator tubing. During 3R15, the array probe examination scope included 100% of the hot-leg expansion transitions, approximately 13% of the cold leg expansion transitions, and 100% of the over-expansions in those tubes. Additionally, a rotating coil examination was performed on 50% of the hot-leg dents and dings greater than or equal to 2 volts.
Question 7 During RFO 14, several tubes were plugged since the bottom of the expansion transition was greater than 1-inch below the top of the tubesheet. Please confirm that the bottom of the expansion transition was less than 1-inch below the top of the tubesheet in all tubes in the SGs inspected during RFO 15.
DNC Response In all the SG tubes inspected during 3R15, the bottom of the expansion transition was less than 1-inch below the top of the tubesheet.
Serial No.14-058 Docket No. 50-423 Attachment 1, Page 8 of 8 Figure 1 Video Probe Travel Path