ML11159A025
| ML11159A025 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 05/24/2011 |
| From: | Jordan A Dominion Nuclear Connecticut |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 11-265 | |
| Download: ML11159A025 (8) | |
Text
Dominion Nuclear Connecticut, Inc.
Dominion Millstone Power Station Rope Ferry Road Waterford, CT 06385 MAY 2 4 20tt U.S. Nuclear Regulatory Commission Serial No.11-265 Attention: Document Control Desk NSS&L/MLC RO Washington, DC 20555-0001 Docket No.
50-423 License No.
NPF-49 DOMINION NUCLEAR CONNECTICUT, INC.
MILLSTONE POWER STATION UNIT 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING THE STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE END OF CYCLE 13 By letter dated October 28, 2010 (Agencywide Document Access and Management System (ADAMS) Accession No. ML103130038), Dominion Nuclear Connecticut, Inc. (DNC), submitted the results of the steam generator (SG) tube inservice inspections at Millstone Power Station Unit 3 (MPS3) for the End of Cycle 13 (EOC1 3). The U.S. Nuclear Regulatory Commission (NRC) reviewed the information provided by DNC and determined that additional information is needed in order to complete the review.
In a letter dated May 13, 2011, the NRC transmitted a request for additional information (RAI).
It was agreed DNC would respond to the RAI by June 6, 2011. Attachment 1 to this letter contains DNC's response to the RAI questions.
If you have any questions or require additional information, please contact Mr. William D. Bartron at (860) 444-4301.
Sincerely, Site V ce President - Millstone Attachments: (1)
Commitments made in this letter: None.
cc:
U.S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406-1415 J. D. Hughey Project Manager - Millstone Power Station U.S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop 08-BlA Rockville, MD 20852-2738 NRC Senior Resident Inspector Millstone Power Station
Serial No.11-265 Docket No. 50-423 Attachment, Page 1 of 7 ATTACHMENT RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING THE STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE END OF CYCLE 13 DOMINION NUCLEAR CONNECTICUT, INC.
MILLSTONE POWER STATION UNIT 3
Serial No.11-265 Docket No. 50-423 Attachment, Page 2 of 7 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING THE STEAM GENERATOR TUBE INSERVICE INSPECTION REPORT FOR THE END OF CYCLE 13 By letter dated October 28, 2010 (Agencywide Document Access and Management System (ADAMS)
Accession No. ML103130038), Dominion NuclearConnecticut, Inc. (DNC), submitted the results of the steam generator (SG) tube inservice inspections at Millstone Power Station Unit 3 (MPS3) for the End of Cycle 13 (EOC13). The U.S. Nuclear Regulatory Commission (NRC) reviewed the information provided by DNC and determined that additional information is needed in order to complete the review.
In a letter dated May XX, 2011, the NRC transmitted a request for additional information (RAI). It was agreed DNC would respond to the RAI by June 6, 2011. This attachment contains DNC's response to the RAI questions.
NRC RAI Question 01 The information provided in response to Technical Specification (TS) 6.9.1.7.j does not appear to follow the methodology outlined in your supporting technical documents for the H* alternate repair criteria.
In item a), you indicated that the administrative limit for operational leakage should be: leakage through faulted SG (500 gallons per day (GPD) - 2.49 x 0. 22 = 499.5 GPD). Later in the report, you indicated that the administrative limit for operational leakage is 499.5 GPD/2.49 = 200.6 GPD.
In order to calculate the administrative limit for operational leakage (for the next operating cycle),
consistent with the H* approved methodology, the accident induced leakage rate (for the next operating cycle) from all other sources, other than the tube end indications, must be determined. This value must then be subtracted from your accident induced leakage limit, (presumably 500 GPD based on your submittal), and the resultant value is then divided by 2.49.
If there is no projected accident induced leakage for the next operating interval from any other sources (e.g., plugs, flaws in the free-span), then the limit on operational leakage to account for the accident induced leakage from the tube ends during the next operating interval would be 500 GPD/2. 49, or 200.8 GPD. Since this number exceeds your current technical specification limit on operating leakage, the limit in your technical specifications would be governing.
Please confirm that the latter approach is being used to calculate your administrative limit for operational leakage and that you have determined the accident induced leakage from sources other than the tube ends for the next operating interval.
DNC Response The latter approach is correct and the accident induced leakage, from sources other than tube ends, has been determined to be 0 GPD. The discussion provided in our original response regarding the administrative leakage limit for operational leakage, was conservatively reduced by the operational leakage (0.22 GPD) times the leakage factor (2.49). The calculated administrative operational leakage limit is the accideht leakage limit through the faulted SG (500 GPD) minus other leakage (i.e., 0 GPD) divided by the value of 2.49 which equals 200.8 GPD. The description of this calculation follows:
Serial No.11-265 Docket No. 50-423 Attachment, Page 3 of 7 Calculated accident leakage from sources other than Tube End (TE) cracks is 0 GPD.
Maximum allowable leakage through the faulted SG = 500 GPD Administrative limit for operational leakage
= 500 GPD - 0
= 200.8 GPD 2.49 Since the calculated administrative limit of 200.8 GPD is greater than the 150 GPD operational leakage limit of TS 3.4.6.2.c, the TS limit is governing.
NRC RAI Question 02 TS 6.9.1. 7. a requires that a report of the scope of the inspection performed on each SG be generated.
Table 2 in the submittal implies that visual inspections of the plugs were performed and that a visual inspection of secondary side internals (other than for Foreign Object Search and Retrieval (FOSAR))
may have been performed.
Please discuss the scope and results of any tube plug inspections and or secondary side inspections (other than FOSAR).
DNC Response PLUG INSPECTIONS:
Existing plugs in SGs B and D were remotely visually examined during 3R13 Eddy Current Testing (ECT). The proper tube number, plug type, and plug position were verified. While a light boric acid coating was noted on some of the plugs, no evidence of leakage or degradation was identified.
In addition, the installation parameters for the 14 plugs (in seven tubes) installed during 3R13 were independently reviewed with the vendor's quality assurance representative to validate that installation complied with vendor specifications. No deficiencies were identified.
SECONDARY SIDE INSPECTIONS:
SG B Top of tubesheet inspections in SG B were performed following upper bundle flush (UBF) and water lance operations. The top of tubesheet annulus and divider lane were clean. Both the blowdown pipe and center tie rod were found to be in good condition.
SG D Top of tubesheet inspections in SG D were performed following UBF and water lance operations. The top of tubesheet and divider lane were clean. Both the blowdown pipe and center tie rod were found to be in good condition.
SG A Top of tubesheet inspections in SG A were performed following UBF and water lance operations. The top of tubesheet and divider lane were clean. Both the blowdown pipe and center tie rod were found to be in good condition.
Serial No.11-265 Docket No. 50-423 Attachment, Page 4 of 7 SG C Top of tubesheet inspections in SG C were performed on April 23, 2010. The annulus and no-tube/
blowdown lane were inspected and found to be clear of sludge deposits. Both the blowdown pipe and center tie rod were found to be in good condition.
SG C Upper Internals Examination UBF and water lance operations were performed during 3R13. Visual inspections were performed to provide a more detailed assessment of support fouling and flow accelerated corrosion (FAC). More detail on the upper internals examinations of SG C is provided below.
Internal inspections of the steam drum and upper bundle inspections above the 7th tube support plate (TSP) were performed on April 17, 2010. The secondary moisture separator chevrons were found to be in good condition. The perforated holes of the outer plate showed minor buildup of sludge in the bore of the holes. The chevrons were straight and showed a light coating of sludge deposit. The primary moisture separator swirl vanes were found to be in good condition. The vanes had a slight deposit on them but the edges were still sharp showing no indication of erosion.
It was noted that there was a heavy deposit of sludge on the steam drum shell wall of the upper deck. This deposit became thicker higher up on the shell.
Ladders, drains, wedges, supports and associated welds throughout SG C were found to be acceptable.
The 30 J-nozzles located on the main feedwater pipe were internally and externally inspected and found to be in good condition. Nozzles 1, 15, 16 and 30 had a weld overlay applied during a previous outage. Internally, the erosion and corrosion damage of these four nozzles had not advanced since the last inspection.
Some of the primary separator riser barrels showed some minor erosion from overspray of the J-nozzles. The erosion/roughness is very minor and is of no concern at this time, but will continue to be monitored during future outages. See Figure 1.
A video probe was lowered down through several swirl vanes to access the upper tube bundle 7th TSP and U-bend region. The anti-vibration bars (AVBs) showed some bridging of sludge deposits between the tube and bars, see Figure 2. The 7th TSP broaches showed a slight ridge of sludge at the bottom of the TSP, see Figure 3. None of the broaches viewed were found to be fully blocked. The deposit on the top of tubesheet appeared to be similar to what was observed on the AVBs, thick, but otherwise not easily disturbed.
Figure 1 Primary Separator in SG C
Serial No.11-265 Docket No. 50-423 Attachment, Page 5 of 7 Figure 2 AVB to Tube Deposit Bridging Figure 3 7 th TSP Broach
SUMMARY
Based on the inspections and activities performed during 3R13, no degradation or conditions were found that could impact the performance of the SGs for the next two cycles of operation.
NRC RAI Question 03 A list of newly reported tube support plate (TSP) wear indications is provided in Table 7 of the submittal. Results for previously reported volumetric degradation (non-support related) wear is summarized in Table 9. Tube R30 C52 in SG B appears in both tables with the same wear indication.
Please clarify whether the wear indication for tube R30 C52 in SG B is new or previously reported.
Additionally, clarify whether it is a TSP wear indication or a non-support related indication since Table 9 lists the results for the previously reported, non-support related, volumetric degradation and the only entry in the table has a suspected cause of TSP wear.
DNC Response The indication in R30 C52 at 05H was first detected and reported during 3R1 1 (2007). A review of the bobbin coil data from 3R7 (2001) and 3R9 (2004) was performed after the initial detection during 3R1 1 and showed that the R30 C52 wear indication had been present since 2001 at the same approximate bobbin coil response voltage and phase angle. This review showed that the wear had been present
Serial No.11-265 Docket No. 50-423 Attachment, Page 6 of 7 since 2001 with no significant growth. During 3R1 1, the surrounding tubes were examined with the
+PointTM coil with no Possible Loose Part (PLP) detections and no additional wear indications in the surrounding tubes. There was no PLP indication in the R30 C52 wear location. Since the flaw depth was less than 40% through-wall (TW), and there was no continuing growth, the tube was retained in service.
The thickness of the MPS3 TSPs 5 through 8 is 1.12" so the location of the flaw is near the lower edge of the TSP. The length of the indication is 0.3" as sized with Examination Technique Specification Sheet (ETSS) 96910.1. During 3R13, the ECT Lead Level III determined that the indication in this tube was actually TSP wear. A second TSP wear indication was also reported in SG D tube R35 C73, as listed in Table 7 of the October 28, 2010 submittal. The indication in R30 C52 had been previously reported as a non-support related degradation. Table 9 indicates that the suspect cause of this indication was reclassified as TSP wear during 3R13.
In summary, there is only one indication in R30 C52. It had been reported prior to 3R13 as a non-support related volumetric degradation, but was reclassified as a TSP wear during 3R1 3. There is no significant growth in the indication.
NRC RAI Question 04 The report stated that three tubes in SG B had shallow probable foreign object wear in locations that were not accessible by FOSAR. The report further stated that the three inaccessible tubes were removed from service since the probability of continued wear growth could not be confirmed visually.
Table 8, which summarizes the results for the newly reported non-support related volumetric degradation, shows the three tubes that were plugged in SG B, but also indicates that the suspected cause was due to a foreign object that is no longer present.
Please clarify whether the foreign object has been confirmed to be no longer present at the tubes in question.
DNC Response During 3R13, probable shallow foreign object wear was detected in SG B tubes R3 C113 and R3 C114 (below 05C support) and in tube R37 C68 (below 03H support). Due to the elevation of these locations, they were not accessible for Secondary Side Inspection (SSI). Since ECT did not detect the presence of a foreign object, the indications in the three tubes were considered to be foreign object wear with no detectable object present. Because the area was not accessible for SSI, there was no way to confirm whether the foreign object was no longer present at or near the tubes in question. The certainty of no future wear was not high enough to retain the tubes in service.
NRC RAI Question 05 Please clarify the nature of the indication in tube R44 C98 in SG B listed in Table 8 of the submittal.
DNC Response One tube in SG B (R44 C98 at 02H +15.77) had a newly reported volumetric indication that was sized at 29% TW using ETSS 21998.1. The length of the indication was measured as 0.27" and the arc was
Serial No.11-265 Docket No. 50-423 Attachment, Page 7 of 7 measured as 0.29" by ECT. A review of historical bobbin data determined that this indication had been present since the baseline examination and had not changed significantly. The tube was retained in service.
Improvements in eddy current probes, instruments and methods have reduced the residual noise in the data and have improved probability of detection of smaller indications. This indication was reported, examined with +PointTM and sized during 3R1 3. With the knowledge that the indication existed, it was possible to find the same indication in the earlier bobbin coil data.