NRC 2014-0015, Response to Request for Additional Information Spring 2013 Unit 1 (U1R34) Steam Generator Tube Inspection Report
| ML14062A047 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 03/03/2014 |
| From: | Millen M Point Beach |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NRC 2014-0015, TAC MF2800 | |
| Download: ML14062A047 (8) | |
Text
March 3, 2014 NRC 2014-0015 TS 5.6.8 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Point Beach Nuclear Plant, Units 1 Docket 50-266 Renewed License No. DPR-24 Response to Request for Additional Information Spring 2013 Unit 1 (U 1R34) Steam Generator Tube Inspection Report
References:
(1) Next Era Energy Point Beach, LLC letter to NRC, dated September 24, 2013, Spring 2013 Unit 1 (U1R34) Steam Generator Tube Inspection Report (ML13268A108)
(2) NRC e-mail to NextEra Energy Point Beach, LLC, dated January 15, 2014, Point Beach Nuclear Plant, Unit 1 -Draft Request for Additional Information re: Spring 2013 (U1 R34) Steam Generator Tube Inspection Report Review (TAC No. MF2800)
NextEra Energy Point Beach, LLC (NextEra) submitted the Spring 2013 Unit 1 (U1R34) Steam Generator Tube Inspection Report via Reference (1 ), documenting the scope and results of the inspection per prescribed Technical Specification Reporting Requirements.
The NRC Staff has determined additional information (Reference 2) is required to complete its evaluation. Enclosure 1 provides the NextEra response to the NRC Staff's request for additional information.
This letter contains no new Regulatory Commitments and no revisions to existing Regulatory Commitments.
Very truly yours, NextEra Energy Point Beach, LLC Michael Millen Licensing Manager Enclosure cc: Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW NextEra Energy Point Beach, LLC, 6610 Nuclear Road, Two Rivers, WI 54241
ENCLOSURE 1 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION SPRING 2013 UNIT 1 (U1R34) STEAM GENERATOR TUBE INSPECTION REPORT NextEra Energy Point Beach, LLC (NextEra) submitted the Spring 2013 Unit 1 (U1R34) Steam Generator (SG) Tube Inspection Report via Reference (1 ), documenting the scope and results of the inspection per prescribed Technical Specification Reporting Requirements.
The NRC Staff has determined additional information (Reference 2) is required to complete its evaluation. This enclosure provides the NextEra response to the NRC Staff's request for additional information.
Please clarify the results of the visual inspections of the channel head area. Was any degradation detected in either steam generator (SG)? If so, please discuss the nature of the degradation and its cause. For example, it appears that there may be some missing cladding in SG B. Why is the cladding missing? Please discuss any assessments performed regarding the acceptability of the conditions identified.
NextEra Response The SG channel heads were visually inspected. The inspections were performed prior to nozzle cover installation as early as possible after the primary manways were removed. A detailed inspection per NSAL 12-01 was conducted approximately 36 inches radially on each side of the divider plate, centered on the bottom of the bowl. A scan was also conducted on the remaining portion of the channel head cladding to ensure no areas of degradation were present on the channel head cladding . No indications of rust or other indication of cladding degradation were present in any of the Unit 1 SG A channel head inspections. The Unit 1 SG B channel head inspections monitored the interior surface condition and no rust or discoloration was identified in SG B Cold Leg channel head cladding or on the main part of SG B Hot Leg channel head cladding . Discoloration identified in U1 R30 around SG B Hot Leg Manway was visually monitored and showed no indication of further degradation. This indication has previously been reported in a letter to the NRC, Filing of Owner's lnservice Inspection Summary Report for Point Beach Nuclear Plant Refueling Outage U1 R30, dated August 6, 2007, (Reference 3), , Table 2, B Steam Generator Hot Leg Manway. The SG B Hot Leg channel head cladding had no other indications of rust on the cladding.
Tables 5-1, 5-2, 5-4, 5-5, and 5-6 contain indications recorded in previous outages that are now being recorded as "indication not reportable" (INR).
Please discuss any reviews of system performance that were made to ensure a quality inspection was being performed (e.g., was there more noise during the 2013 inspections than in prior inspections).
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NextEra Response All tubes with indication not recordable (INR) were reviewed and there was no detectable degradation (NOD). The indications previously recorded in tables 5-1, 5-2, 5-4, 5-5, and 5-6 with INR were monitored during ECT in U1 R34 and no increase was noted in the indication .
Therefore, NOD was recorded in the eddy current report and the final report recorded the indications as INR.
System performance was comparable to previous inspections dating back to 2008 with no appreciable change in noise levels. The same manufacturer of tester (Corestar Omni) and probes (Zetec) have been used compared to inspections used since 2008.
Please clarify the results of the tube plug inspections (e.g., was any degradation obsetVed, and were all plugs present and in their proper locations).
NextEra Response A video inspection of five installed plugs in SG A (hot and cold legs) and eight installed plugs in SG B (hot and cold legs) showed that all plugs are dry, in their proper location, and no degradation was detected on any of the installed plugs.
Please reconcile the numbers in Table 5-4 with the accompanying text. The table contains nine locations in SG A and the text indicates three were not reported in 2011 and three were reported in 2011.
NextEra Response Twenty (20) PLP indications were reported, nine (9) in SG A and eleven (11) in SG B.
Details are shown 'in Table 5-4.
Table 5-4 Elevation SG Row Column Location (Inches)
Comments New PLP (Possible Loose A 2 52 TSC +0.06 Part) in 2013 based on RPC (Rotating Pancake Coil).
New PLP in 2013 based on A 43 38 TSC +0.12 RPC.
New PLP in 2013 based on A 24 68 TSH +0.33 RPC.
New PLP in 2013 based on A 24 67 TSH +0.42 RPC.
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Elevation SG Row Column Location (Inches)
Comments Bobbin Indication only. RPC showed Indication Not Reported (INR) in U1 R34, A 26 53 TSH +0.96 therefore it is not a PLP.
Previously recorded in 2011, U1 R33, at same elevation with RPC.
Bobbin Indication only. RPC showed no indication Reported in U 1R34 therefore A 25 53 TSH +0.85 it is not a PLP. Previously recorded in 2011, U1 R33, at same elevation with RPC.
Bobbin Indication only. RPC showed no indication Reported in U 1R34 therefore A 26 52 TSH +0.86 it is not a PLP. Previously recorded in 2011, U1 R33, at same elevation with RPC.
New PLP in 2013 based on A 10 22 TSH +0.23 RPC.
New PLP in 2013 based on A 9 22 TSH +0.31 RPC.
New PLP in 2013 based on B 34 73 TSC +0.87 RPC.
New PLP in 2013 based on B 34 73 TSC +0.63 RPC .
New PLP in 2013 based on B 33 73 TSC +0.86 RPC.
New PLP in 2013 based on B 1 25 TSC +0.16 RPC.
New PLP in 2013 based on B 1 24 TSC +0.02 RPC.
New PLP in 2013 based on B 20 36 TSH +0.03 RPC.
New PLP in 2013 based on B 20 35 TSH +0.00 RPC.
New PLP in 2013 based on B 25 27 TSH +1.36 RPC .
New PLP in 2013 based on B 24 27 TSH +0.71 RPC .
New PLP in 2013 based on B 24 26 TSH +0.10 RPC.
New PLP in 2013 based on B 6 6 TSH +0.16 RPC .
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Original Text:
No degradation was observed in conjunction with these (20) indications. Three (3) of the indications in SG A were not reported during the previous inspection in 2011. The indications at R26, C53; R25, C53; and R26, C52 were reported at the same elevation as reported during the 2011 inspection.
Corrected Text:
No degradation was observed in conjunction with these (20) indications. There were nine (9) possible loose parts in SG A based on bobbin coil indications. All of the nine (9) indications were spun with RPC and six (6) had no detectable degradation (NOD) based on RPC while the remaining three (3) had no indication reportable (INR) (R26/C53, R25/C53, R26/C52). R26/C53, R25/C53, R26/C52 were previously recorded at the same elevation in 2011 with similar results.
Regarding the secondary side inspections, you indicate that moisture carryover modifications were made (presumably for a power uprate).
Please briefly describe the modifications, when they were made (during the 2013 outage or prior), when the power uprate was/is being implemented, and if the effects of the power uprate were included in determining the next inspection interval. Also, please clarify whether any degradation was noted during the secondary side inspections.
NextEra Response The NextEra extended power uprate license amendment request, dated 7 April 2009, (Reference 4) section 2.2.2.5.6, page 2.2.2-52 states:
The PBNP steam generators will be modified to reduce moisture carryover to less than or equal to the design basis of 0.25%. The anticipated modifications include:
- Reduce the mid-deck inlet vent area by 85% as compared to the existing vent area by installing mid-deck extension plates; change the open top pipe vent design to a flow diverter vent pipe design with vent caps to prevent direct entry of the steam/water vent flow into the gravity space.
- Replace the formed vanes in the double tier secondary separators by double pocket vanes.
Moisture carryover with these modifications is projected to be less than 0.25% at best estimate.
These modifications were performed in U 1R33 Refueling outage. Cycle 34 and 35 were at increased power levels. As a commitment for EPU stated in Reference 4, "A formal monitoring program for the steam generator steam drum components will be implemented prior to operation of each unit at EPU conditions. The monitoring will be conducted over two operating cycles to confirm components are performing adequately at EPU operating conditions." U1 R34 was the first inspection required at EPU conditions, and no degradation was identified on the Page 4 of 7
secondary side components in U1 R34. U1 R35 is the second scheduled secondary side inspection at EPU conditions for Unit 1.
For the J-nozzles, no anomalies were reported during the visual inspections in 2013. In 2011, however, several bum-through locations were identified near the J-nozzles.
Please clarify whether these locations were repaired during the prior outage or whether any degradation was noticed during the secondary side inspections (of the J-nozzles or any other structure, system, or component inspected).
NextEra Response No repairs were conducted on the secondary side of SG A or SG B and no degradation was noticed during the secondary side inspections. Weld burn through was previously reported in a letter to the NRC, Fall 2005 Unit 1 (U12R29) Steam Generator Tube Inspection Report, dated February 21, 2006, page 6; (Reference 5), and a letter to the NRC, Response to Request for Additional Information Fall 2011 Unit 1 (U1 R33) Steam Generator Tube Inspection Report, dated September 25, 2012, (Reference 6) with continued monitoring in SG A J-nozzles 2, 3 and 28, and SG B, 7, 11, and 14. Weld burn through is from construction, not flow induced corrosion, and does not affect J-nozzle operation.
You indicate that any primary water stress corrosion cracking that might develop in the next two operating cycles would be unlikely to exceed the structural or leakage integrity performance criteria.
Please clarify whether this assessment accounted for the fact that some tube ends (at least 50 percent in SG A) were not inspected during the 2013 outage. The NRC staff notes it is not clear whether the 50 percent of the tube ends inspected during 2013 were the same or different than those tube ends inspected in 2011.
NextEra Response Point Beach inspected 100% of the tubesheet in SG Bin both U1 R33 and U1 R34 with no new indications noted in U1 R34. U1 R34 inspected 50% of the tubesheet in SG A and inspected the other 50% of SG A tubesheet in U1 R33. Therefore, the entire tubesheet of SG A has been inspected between U1 R33 and U1 R34 and no indications were detected. No leakage has been attributed to the more than 200 circumferential PWSCC indications near the tube end in at least six other plants. Based on this industry history, it is unlikely that any PWSCC indications that might develop in the next two operating cycles would violate the structural integrity and leakage performance criteria.
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During the 2011 and 2013 outages, 50 percent of the U-bend region, of the row 1 and 2 tubes, was inspected.
Please discuss the extent to which the 50 percent sample in 2013 included tubes inspected during the 2011 outage.
NextEra Response SG A inspected 50% of Row 1 and Row 2 U-bends with Motorized Rotating Pancake Coil (MRPC). The tubes inspected in U1 R34 were not inspected in U1 R33.
SG B inspected 50% of Row 1 and Row 2 U-bends with MRPC. These were the same tubes inspected in U1 R33. All of the Row 1 and Row 2 U-bends were inspected with Bobbin coils.
U1 R34 was the first inspection in the 41h In-service Inspection (lSI) Period for Point Beach Unit 1 at 10.03 EFPM of the 60 EFPM period. 50% of SG A and SG B low row U-bends inspected in U1 R34 meet the criteria to inspect 50% of the low row U-bends within 30 EFPM of the current period. U1 R33 was the last inspection in the 3rd lSI period at 56.8 EFPM of the 60EFPM period. SG A and Beach had 50% of the Low Row U-bends inspected in U1 R33 meeting the criteria to inspect 50% within the last 30 EFPM of the 3rd lSI period.
It was indicated that the primary-to-secondary leak rate is in the range of 0.0 to 0.2 gallons per day, and that this leakage has essentially remained constant since at least 1991. Following the 2011 outage, a similar report was provided, but the primary-to-secondary leakage value was quoted as 0. 2 to 0.4 gallons per day.
Please clarify the leakage rate.
NextEra Response The 0.0-0.2gpd leakage reported in Reference (1) is based off the Cycle 34 primary to secondary leakage data taken from the steam air ejector samples. The Fall 2011 report, U1 R33 (Reference 7), documented a leak rate of 0.2-0.4gpd. This current leak rate is considered consistent with past reports. The leak has been present since 1991 and has fluctuated over the cycles at a low rate.
References:
(1) NextEra Energy Point Beach, LLC letter to NRC, dated September 24, 2013, Spring 2013 Unit 1 (U1 R34) Steam Generator Tube Inspection Report (ML13268A108)
(2) NRC e-mail to NextEra Energy Point Beach, LLC, dated January 15, 2014, Point Beach Nuclear Plant, Unit 1 - Draft Request for Additional Information re: Spring 2013 (U1 R34) Steam Generator Tube Inspection Report Review (TAC No. MF28000)
(3) Nuclear Management Company, LLC letter to NRC, dated August 6, 2007, Filing of Owner's lnservice Inspection Summary Report for Point Beach Nuclear Plant Refueling Outage U1 R30, (ML072180594)
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(4) NextEra Energy Point Beach, LLC letter to NRC, dated April 7, 2009, License Amendment Request 261 Extended Power Uprate (ML091250564)
(5) Nuclear Management Company, LLC letter to NRC, dated February 21, 2006, Fall 2005 Unit 1 (U1 R29) Steam Generator Tube Inspection Report (ML060600189)
(6) NextEra Energy Point Beach, LLC letter to NRC, dated September 25, 2012, Response to Request for Additional Information Fall 2011 Unit 1 (U1 R33) Steam Generator Tube Inspection Report (ML12270A037)
(7) NextEra Energy Point Beach, LLC letter to NRC, dated May 29, 2012, Fall 2011 Unit 1 (U1 R33) Steam Generator Tube Inspection Report (ML12150A287)
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