ML20247C017
| ML20247C017 | |
| Person / Time | |
|---|---|
| Site: | McGuire  |
| Issue date: | 05/18/1989 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20247C005 | List: |
| References | |
| NUDOCS 8905240324 | |
| Download: ML20247C017 (6) | |
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- ,,,e SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULAT10h REC 0VERYFROMSGTREVENTATMCGUIREUNIT1 CUKE POWER COMPANY MCGUIRE UNIT 1 00CKET NO. 50-369
1.0 INTRODUCTION
On Farch 7,1989, McGuire Unit 1 experienced a steam generator tube rupture (SGTR) event. The event is described by the hRC in Inspection Report 50-369/89-06 and 50-370/89-06, "McGuire Augmented Inspection Team (AIT)
Report" on April 10, 1989, and by the Duke Power Company (the licensee or Duke) in Licensee Event' Report 369/89-04 on April 20, 1989.
Following a meeting with the licensee on April 13, 1989, the NRC issued
" Confirmation of Action Letter for McGuire Unit 1 Restart" dated April 19, 1989, reflecting agreement between NRC and Duke that certain actions would occur prior to final ~ decision regarding restart. The actions were discussed during a subsequent meeting on May 5,1989 and documented by licensee's letter of May 8, 1989. The May 8 letter also forwarded a report describing Duke's assessnent of the failure causes, recovery efforts, and justification for return to power.
Four actions were to be completed prior to restart. These are summarized in the following evaluation.
2.0 'FVALUATION
- 1. Further Meetings and Reporting Regarding Cause of Tube Failure and Integration of These Results Into Eff ective Corrective Actions The McGuire Unit I tube rupture occurred in steam generator (S/G) B. Prior to the SGTR event, the plant had been operating normally at approximately 100%
power. The primary-to-secondary leak rate for the 3 months leading up to the event had been small, varying between 5 and 30 gallons per day.
Upon entry into the S/G B channel head, the rupture location was determined to be tube R18-C25 on the cold leg side. Visual inspection of the inside of the tube with a Welsh Allen video probe revealed the rupture to be a longitudinal split (i.e. , " fishmouth"), approximately 3.75 inches long with a maximum opening of about 3/8 inch. The top of the crack was located 0.5 inch above the lower-most support plate.
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The scope of the failure evaluation and recovery effort conducted by Duke and its consultants included the following:
I Eddy current testing and tube plugging 1
- bobbin probe: Full length inspection of all tubes in each steam generator was performed.
- rotating pancake coil (RPC) probe: A sample of 25 tubes in the immediate vicinity of the tube rupture location was inspected by this method.
Additional tubes were inspected to better characterize certain indications detected with the bobbin probe including tubes exhibiting groove-like or apparent fabrication or installation related indications.
- special RPC inspections: This testing was done at the request of the NRC staff to confirm bobbin coil inspection results indicating no detectable stress corrosion cracks. This testing was done on a sample of 100 tubes (on both the hot and cold leg sides) fabricated from the same heat of material as the ruptured tube.
Tube pull and examination
- tube R18-025 (ruptured tube)
- tube R19-C24 - This tube was pulled to permit video irspection of the outside diameter (0D) surface of tube R18-C25 prior to its removal.
- tube R13-C34 - This tube exhibited long groove signals during field eddy current testing and was pulled for metallurgical examination. ,
Duke described the major findings of this effort as follows:
The cause of the tube rupture was determined to be intergranular stress corrosion cracking (SCC) involving multiple initiation sites on the OD of the tube.
The rupture was contained within a long shallow groove (-0.001 inch deep and 0.040 inch wide) on the tube CD which runs axially from several inches below the rupture to about 20 inches above the rupture at the second support plate above the tubesheet. Axial and circumferential cracks were observed on the OD of the tube along the length of the groove above the rupture. The maximum depth of these cracks was about 30% of the original tube wall thickness.
The Inconel 600 tubing had an average grain size of ASTM 10 with inter-granular carbide present, indicative of a low temperature mill annealed microstructure. This is typical of mill annealed tubing microstructure during the McGuire tube production era.
Gross tensile properties of the tube met mill certification values. Bulk chemistry analysis of tube material were within specification values with no unusual contaminants present.
No definite corrosive species were identified in Energy Dispersive Spectro-scopy scans of the fracture surfaces.
The identification of disturbed metal near the groove indicated that the l
groove was probably made after annealing. Upset, smeared metal approximately 2 grains deep was observed at the edge of the groove. X-ray residual stress measurements indicated local tensile residual stresses slightly below yield strength level.
Prior to 1989, no significant secondary side corrosion problems were in evidence. Duke's review of secondary side chemistry data, chemistry excursion data, and wet layup data identified ne significant concerns which would suggest that secondary chemistry might have promoted an aggressive corrosion condition in S/G B.
The failed tube had not been inspected since the baseline performed prior to Unit 1 operation.
Eddy current inspection of the other tubes in all four Unit 1 steam genera-tors and metallurgical examination of the R13-C34 revealed no indications of detectable OD stress corrosion cracking.
A crack propagation rate of approximately 0.7 mil / month was estimated by Duke based on laboratory and field data experience.
The pulled tube evidence, plant operating history, NDE inspection results and general operating experience with mill annealed Alloy 600 steam' generator tubing led to the following explanation of SCC of tube R18-C25 by Duke. A contaminant on the surface of tube R18-C25 at the groove location probably led to crack initiation near start of plant life. Continued plant operation washed this contaminant away and subsequent crack growth occurred slowly over time under the influence of the bulk secondary side water environment. This scenario is consistent with cold leg cracking, no evidence of similarly cracked tubes, cracking in the free span where chemical concentration is not credible, good chemical operating history and low mechanical loading severity. Current evidence points to a unique event. Although it is possible that more than one tube is involved in a contaminant scenario, the number of possibly affected tubes must be very small. The bobbin coil and RPC inspection results strongly ;
support this view. In addition, slow, long term crack rate behavior, which fully matches expectations from field and laboratory experience, provides for safe operation for tubes which may contain a shallow crack.
The staff has evaluated the licensee's failure investigation and recovery program to ensure steam generator tube integrity subsequent to plant restart. The staff was assisted by consultants from Brookhaven National Laboratory and Oak Ridge National Laboratory in the areas of metallurgy and eddy current testing, respec-tively. The following are the main points of the staff's evaluation:
The licensee's theory regarding the cracking mechanism notwithstanding, the uniqueness of tube R18-C25 in terms of its susceptibility to SCC has not been demonstrated.
Assuming that other tubes may be potentially susceptible to similar SCC ettack, the 100% bobbin coil eddy current inspection provides reasonable ,
confidence that none of these cracks currently penetrates deeper than 40 l to 50% of the tube wall thickness. This crack depth is the threshold l at which axial cracks would be detectable with the bobbin coil. Detection '
of circumferential cracks is not reliable with the bobbin probe; however, based on the cracking observed in tube R18-C25, such cracks would be expected to be accompanied by axial cracks.
RPC is more sensitive for detection of SCC than the bobbin coil as was evidenced by the fact that RPC did detect axial and circumferential cracks located above the rupture whose maximum depth was about 30%. The absence of SCC indications during the sample RPC inspections supports the licensee's contention that any other tubes with SCC (if they exist) must be relatively small in number.
McGuire Unit I will be operated for only about ten months prior to its next refueling outage (presently scheduled for March 12,1990) at which time the steam generators will be reinspected. Assuming that cracks whose depths are at the threshold of bobbin coil detectability are present at the time of plant restart, such cracks would not be expected to grow to the point where tube integrity is impaired prior to the next refueling outage, given the likely corrosion rate as indicated by laboratory and field experience.
The SGTR event at McGuire 1 was unique in the sense that it was not pre-ceded by significant primary-to-secondary leakage which would normally be i expected for SSC. The possibility that other tubes may be susceptible to l similar cracks cannot be ruled out at this time. Future eddy current inspections at this and possibly other plants will provide further
, information regarding the uniqueness of tube R18-C25. In the possible l absence of leak-before-break characteristics for this kind of cracking, I should other tubes be susceptible, then special emphasis must be placed on future eddy current examination programs to ensure their adequacy in determining steam generator tube integrity. To this end, Duke plans to evaluate various NDE methods for improved detection / characterization of conditions which led to the rupture of tube P18-C25. By letter dated May 8,1989, Duke has committed to a full 100% inspection of the steam generator tubes at both McGuire Units 1 and 2 at their next refueling outages, beginning with Unit 2 in July 1989. Duke has also committed to communicating the results of these inspections to the NRC staff in reports and meetings prior to restarting from each of these next refueling outages. .
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- 2. Further Meetings Regarding Tube Plugs Prior to the McGuire SGTR, events or findings at other nuclear power plants (e.g., North Anna, Millstone 2, V.C. Summer) and associated laboratory / engineering analyses revealed that some B&W and Westinghouse Alloy 600 mechanical tube plugs were susceptible to inservice failure due to primary water stress corrosion cracking (PWSCC). During the course of the McGuire Unit 1 unplanned outage, the NRC met with B&W and Westinghouse Owners Groups regarding cause and generic corrective actions. The use of mechanical plugs and future plans for McGuire Unit I were discussed during the May 5 meeting and in the Duke report transmitted May 8, 1989.
The Westinghouse mechanical plugs of concern are from Huntington heats NX3513 HX3962 and NX4523. Although there are several Westinghouse mechanical plugs in McGuire Unit 1 S/Gs (20 in S/G A and 2 in S/G C), none are from the heats of concern. Rather, they are from heats NX1989, NX2386 and NX2387 which exhibit preferred microstructural characteristics and are not expected to degrade in a manner leading to the type of evert (plug top release) that occurred at North Anna. Accordingly, the NRC agrees with the licensee that Westinghouse plugs currently installed in McGuire Unit I may remain in service throughout the current fuel cycle.
B&W mechanical plugs used in McGuire Unit 1 S/Gs are of the rolled plug type.
ere Although all replaced B&W mechanical at McGuire Unitplugs 1 in April of the ribbed 1989. type The rolled hadplug alsoofbeen concern used, they w(as first revealed during metallurgical examination of a plug removed from V. C.
Summer) are from heat W592-1, with plugs in the hot leg end of the tubes considered the most susceptible to failure by PWSCC. Prior to the McGuire unplanned outage, there were 156 W592-1 rolled plugs in Unit 1 S/Gs, of which 83 were in hot leg ends of tubes. During the outage all hot leg W592-1 rolled plugs were inspected by RPC technique and all with indications (i.e., 7) were removed from service. The licensee notes that these plugs are not susceptible to plug top release, and that PWSCC in the toe transition of the plug would result in a " leak-before-break" condition. Moreover, the operating experience with W592-1 rolled plugs indicates that PWSCC will not propagate to a fully severed condition in one fuel cycle. Based on the 100% hot leg inspection of these plugs in April 1989, the licensee concluded that the plugs can remain in service for an additional fuel cycle, et which time they will be reinspected and/or removed. We have reviewed the operating experience and licensee's inspection results and concur with the licensee's conclusion.
- 3. Completion Of Procedural Changes For Entry Conditions Ir.to Emergency Operating Procedures During the McGuire SGTR event, the actual primary-to-secondary leak rate was estimated to be about 540 to 600 gpm. This leak rate exceeds the normal primary coolant makeup capability using both charging pumps and the normal makeup flow path. Based upon the Westinghouse Emergency Response Guidelines (WERG), this event should be managed in accordence with the Emergency Operating Procedures (EOP) developed for a SGTR. However, throughout the McGuire event,
Duke did not enter the E0P for SGTR. Instead, procecures used during the event called for manually opening the safety injection flow p'ath with two charging pumps running. This provided more than " normal makeup flow. The licensee treated this event as a steam generator tube leak and, thus, did not enter the E0P.
I In response to the staff concern, Duke in its letter dated April 26, 1989,
) committed to procedural changes. These changes are now in place and eliminate the manual realignment to the safety injection flow path while a steam generator !
tube leak is in process. Thus, for an event with the primary-to-secondary leak rate greater than the normal primary coolant makeup capability, a manual or automatic safety injection (which is an entry condition for the E0P) would cause the E0P to be utilized. These changes bring the McGuire post-SGTR response into compliance with the intent of WERGs. Accordingly, the staff finds this acceptable.
- 4. Com)1etion Of Certain Items From The NRC's AIT Report Of April 10, 1989 lo 3e Determined From Discussions With The Team Leader Region I! staff, including the AIT Team Leader and NRC Resident Inspector at McGuire, have reviewed Duke's letter dated April 26, 1989, discussing Unit I restart which contained the licensee's response to procedure concerns and findings from the AIT. The April 26 letter, as well as discussions held with l the AIT Team Leader between April 20-21, 1989, have satisfactorily resolved these concerns and findings. Resolution of open items frcm the AIT report not relating to restart will be reflected in followup inspection reports in the usual manner.
3.0 CONCLUSION
l Based on the above evaluation, the staff concludes that the actions taken by Duke Power Company to recover from the SGTR event provide an adequate basis to support restart of McGuire Unit 1 and that the actions confirmed by NRC letter of April 19, 1989, have been satisfactorily completed.
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