05000338/LER-2010-002
| Document Numbersequential Revmonth Day Year Year Month Day Year 05000Number No. | |
| Event date: | 07-14-2010 |
|---|---|
| Report date: | 09-08-2010 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown |
| 3382010002R00 - NRC Website | |
1.0 DESCRIPTION OF THE EVENT On July 14, 2010, at 1834 hours0.0212 days <br />0.509 hours <br />0.00303 weeks <br />6.97837e-4 months <br />, with North Anna Unit 1 at 98 percent power, Mode 1, an investigation of increased containment sump pumping frequency identified through wall leaks on a sample line from the "C" Steam Generator (SG) upstream of the isolation valve.
This insulated pipe is one inch carbon steel, Class 601, ASME Class 2 line. When the piping insulation was removed, two steam plumes were visible upstream and downstream of a pipe support. The affected section of piping is not isolable from the steam generator (EIIS Sys - AB, Component — SG) and an on-line repair was not practical. Since the leak degradation mechanism and continued structural integrity could not be determined per Technical Requirements Manual TR 3.4.6, the "C" SG was declared inoperable.
Operations therefore declared the "C" Reactor Coolant System (RCS) (EIIS Sys — AB) loop inoperable and entered the six hour limiting action of Technical Specification (TS) 3.4.4. At 1934 hours0.0224 days <br />0.537 hours <br />0.0032 weeks <br />7.35887e-4 months <br /> on July 14, 2010, Operations personnel commenced ramping Unit 1 offline.
The six hour limiting action of TS 3.4.4 was cleared at 2354 hours0.0272 days <br />0.654 hours <br />0.00389 weeks <br />8.95697e-4 months <br /> when Unit 1 entered Mode 3.
2.0 SIGNIFICANT SAFETY CONSEQUENCES AND IMPLICATIONS This event posed no significant safety implications since the sample line leak did not impact the safe operation of the reactor. Leakage to the containment sump (EDS Sys - BP, Component — SUMP) was minimal with an increase from a steady state of approximately .020 gallons per minute (GPM) on July 1, 2010 to a maximum of .263 GPM on July 14, 2010. A rupture of the one inch surface sample line attached to the secondary side of the "C" SG would remain well bounded by current UFSAR analysis and this would not be considered to be a precursor to a more significant event. Therefore, the health and safety of the public were not affected by this event.
A non-emergency 4-hour report was made to the NRC Operations Center at 1953 hours0.0226 days <br />0.543 hours <br />0.00323 weeks <br />7.431165e-4 months <br /> on July 14, 2010, in accordance with 10 CFR 50.72(b)(2)(i). This event is reportable pursuant to 10 CFR 50.73(a)(2)(i)(A) for the completion of a nuclear plant shutdown required by the Technical Specifications.
3.0 CAUSE The cause is attributed to external corrosion caused by water intrusion under the insulation of carbon steel piping. A vulnerability to this corrosion mechanism exists for carbon steel lines which are insulated but which generally operate at relatively low ambient temperatures. Under these conditions water may become trapped under and in the insulation without the necessary thermal conditions to dry. The potential for this condition is more likely in the vicinity of pipe supports or valves that break the continuity of insulation lagging.
The cause of this condition is that a credible failure mechanism for a passive component �NRC FORM 366A (9-2007) PRINTED ON RECYCLED PAPER was not recognized in the Single Point Vulnerability (SPV) process and therefore an effective mitigation strategy which would have precluded the failure was not established.
The Equipment Reliability (ER) process considered this piping to be passive equipment which is normally exempt from ER classification and excluded from SPV review criteria.
4.0 IMMEDIATE CORRECTIVE ACTION(S) The failed section of the sample line piping was replaced. An immediate extent of condition review identified similar piping configurations in two inch and smaller connections on Blowdown, Wet Layup, and Sample System piping from all three SGs. Inspections and ultrasonic thickness evaluations were performed on these pipe segments. As a result, the repair for the "C" SG surface sampling line piping was expanded to include approximately eight feet of pipe and a small section of piping was replaced on the "B" SG sample line.
Ultrasonic Test (UT) readings indicated the replaced sections of pipe on the "B" SG sample line were above minimum wall but were approaching the minimum wall thickness limit.
5.0 ADDITIONAL CORRECTIVE ACTIONS Piping systems on both units are being identified and evaluated for susceptibility to similar failures. Equipment Reliability classifications and SPV evaluations will be updated as required, including any necessary mitigation strategies. Currently, there is no indication of leakage in Unit 2. The SPV procedure is being updated to include the credible failure mechanism to ensure that similar piping is properly evaluated in the future.
6.0 ACTIONS TO PREVENT RECURRENCE The actions noted above are sufficient to prevent recurrence.
7.0 SIMILAR EVENTS None.
8.0 ADDITIONAL INFORMATION Unit 2 was operating at 100 percent power, Mode 1, and was not affected by this event.
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