ML053640392
| ML053640392 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/18/2006 |
| From: | Wang A NRC/NRR/ADRO/DORL/LPLG |
| To: | Oatley D Pacific Gas & Electric Co |
| Wang A, NRR/DLPM, 415-1445 | |
| References | |
| TAC MC8797 | |
| Download: ML053640392 (47) | |
Text
January 18, 2006 Mr. David H. Oatley General Manager and Vice President Acting Chief Nuclear Officer Pacific Gas and Electric Company Diablo Canyon Power Plant P.O. Box 56 Avila Beach, CA 93424
SUBJECT:
DIABLO CANYON POWER PLANT, UNIT NO. 1 - NRC ASSESSMENT OF 2005 (1R13) STEAM GENERATOR TUBE INSPECTIONS (TAC NO.: MC8797)
Dear Mr. Oatley:
On November 9, 2005, the NRC staff, participated in a conference call with Pacific Gas and Electric (PG&E/ the licensee) regarding the Diablo Canyon Power Plant, Unit 1 (DCPP) 2005 steam generator (SG) tube inspection activities. To facilitate the phone call, PG&E was provided some discussion points for the call. On November 8, 2005, PG&E provided preliminary information regarding the results of its inspection. This information is attached as.
Based on the information provided during the conference call, the NRC staff did not identify any issues that warranted additional follow-up at this time. Also, attached is a summary of the conference call.
This completes our review of the preliminary the preliminary results for the 2005 steam generator tube inspections at the Diablo Canyon Power Plant, Unit 1.
Sincerely,
/RA/
Alan B. Wang, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-275
Enclosure:
- 1) Assessment
Mr. David H. Oatley January 18, 2006 General Manager and Vice President Acting Chief Nuclear Officer Pacific Gas and Electric Company Diablo Canyon Power Plant P.O. Box 56 Avila Beach, CA 93424
SUBJECT:
DIABLO CANYON POWER PLANT, UNIT NO. 1 - NRC ASSESSMENT OF 2005 (1R13) STEAM GENERATOR TUBE INSPECTIONS (TAC NO.: MC8797)
Dear Mr. Oatley:
On November 9, 2005, the NRC staff, participated in a conference call with Pacific Gas and Electric (PG&E/ the licensee) regarding the Diablo Canyon Power Plant, Unit 1 (DCPP) 2005 steam generator (SG) tube inspection activities. To facilitate the phone call, PG&E was provided some discussion points for the call. On November 8, 2005, PG&E provided preliminary information regarding the results of its inspection. This information is attached as.
Based on the information provided during the conference call, the NRC staff did not identify any issues that warranted additional follow-up at this time. Also, attached is a summary of the conference call.
This completes our review of the preliminary the preliminary results for the 2005 steam generator tube inspections at the Diablo Canyon Power Plant, Unit 1.
Sincerely,
/RA/
Alan B. Wang, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-275
Enclosure:
- 1) Assessment
PUBLIC DTerao YDiaz-Castillo LPL4 Reading RidsNrrLALFeizollahi MMurphy CHolden RidsRidsNrrPMAWang RidsAcrsAcnwMailCenter RidsRegion4MailCenter AHiser ADAMS ACCESSION NO.: ML053640392 OFFICE LPLIV/PM LPLIV/LA LPLIV/BC NAME AWang LFeizollahi DTerao DATE 1/11/06 1/10/06 1/18/06 OFFICIAL RECORD COPY
NRC
SUMMARY
OF 2005 CONFERENCE CALL ON STEAM GENERATOR TUBE INSPECTIONS FOR REFUELING OUTAGE 13 PACIFIC GAS AND ELECTRIC COMPANY DIABLO CANYON POWER PLANT UNIT 1 DOCKET NO. 50-275 n November 9, 2005, the Nuclear Regulatory Commission (NRC) staff participated in a conference call with Diablo Canyon Unit 1 representatives to discuss the scope, results, and status of their ongoing steam generator (SG) tube inspections performed during the Fall 2005 (1R13) refueling outage. Diablo Canyon Unit 1 has four recirculating Westinghouse Series 51 steam generators. To facilitate the discussion, Pacific Gas & Electric Company, the licensee for Diablo Canyon Unit 1, submitted a preliminary briefing paper (attached to this summary) which addresses the discussion points contained in an NRC letter to the licensee dated October 31, 2005 (ML053040206). In addition to the written material provided by the licensee, the following additional clarifying information was discussed during the conference call.
A loose part was left lodged between tubes R30C78 and R31C78 during the 2004 SG tube inspections (1R12). During the 2005 (1R13) inspections, no indication of a possible loose part was present at this location. The licensee believes the loose part could be a small wire introduced during maintenance activities in previous outages. At the time of the phone call, foreign object search and retrieval (FOSAR) activities had not identified the loose part.
A summary of the repairable eddy current indications identified as of November 8 is shown in Table 2 of the attached information provided by the licensee. At the time of the call, there were no mixed mode indications identified at tube support plates (TSP). The total number of circumferential indications at TSP and at the top of the tubesheet (TTS) has increased since the last inspection. The indications have low voltages. Most of the dents with circumferential indications located at the TSP have voltages greater than 5 volts, although there are some dents with magnitudes of 3 volts. One dent measuring 0.7 volts was found to have a circumferential indication. This dent was at the first hot leg support of SG 1-1. The number of axial outside diameter stress corrosion cracking (ODSCC) indications at TSPs is well within the projection made by the probability of prior cycle detection (POPCD) method. The licensee stated that it has identified axial ODSCC at the TTS, which is somewhat atypical, but consistent with the operating experience of Westinghouse Series 51 steam generators.
Within the U-bend region, no indications of cracking had been found at the time of the call.
During the previous inspection, about 60 tubes were plugged for cracks in the U-bend. Given that U-bend examinations are ongoing, it was expected that some indications would be found.
A list of the most significant indications identified as of November 8 is shown in Table 3 of the attached information provided by the licensee. In this table, the licensee identified an axial primary water stress corrosion cracking (PWSCC) at a dented TSP. This tube had been plugged earlier (around cycle 6) and was deplugged during 1R11. The projected burst
pressure for this indication (based on an assessment performed following 1R12) was 4400 psi, compared to an estimated burst pressure of 4800 psi (based on the 1R13 results). This represents an under prediction of 400 psi, which makes the burst pressure analysis conservative. With respect to the implementation of the alternate repair criteria (ARC) for PWSCC at TSP elevations, there were some under predictions in the burst pressures for several indications but none of these under predictions exceeded 500 psi.
For the first time, a tube with an axial ODSCC indication at a TSP elevation is being plugged since it is at a TSP elevation which has an eddy current indication indicating that the TSP ligament may be cracked.
At the end of the conference call the licensee stated that the inspection results in steam generators 1-1 and 1-2 were identified as Category 3, which means that more than one percent of the total population of the tubes were found to be defective. The licensee will be submitting a formal report regarding their findings.
At the time of the conference call, the licensee was still finalizing some of their analysis and indicated that if there were significant changes, they would inform the NRC staff.
Pacific Gas and Electric Talking Points For NRC Phone Call On 1R13 SG Tube Inspections at Diablo Canyon Unit 1 November 9, 2005
- 1. Discuss any trends in the amount of primary-to-secondary leakage observed during the recently completed cycle.
In June 2005, a small leak (0.01 gpd) was detected and measured in the steam jet air ejector, based upon the presence of Argon 41. Subsequent weekly sampling has shown no detectable primary to secondary leakage. The leak is too small to determine the leaking SG.
- 2. Discuss whether any secondary side pressure tests were performed during the outage and the associated results.
No secondary side pressure tests were performed.
- 3. Discuss any exceptions taken to the industry guidelines.
Diablo Canyon Units 1 and 2 has one minor deviation of shall requirements of Revision 6 of the Secondary Water Chemistry Guidelines. Tables 5-2 and 5-3 of the Guidelines establish limits for exceeding 5% power. Diablo Canyon Units 1 and 2 apply these limits to 8% power.
- 4. For each steam generator, provide a description of the inspections performed including the areas examined and the probes used (e.g., dents/dings, sleeves, expansion-transition, U-bends with a rotating probe), the scope of the inspection (e.g., 100% of dents/dings greater than 5 volts and a 20% sample between 2 and 5 volts), and the expansion criteria. Also, discuss the extent of the rotating probe inspections performed in the portion of tube below the expansion transition region (reference NRC Generic Letter 2004-01, "Requirements for Steam Generator Tube Inspections").
Table 1 provides a summary of all inspections scheduled to be performed, and expansion criteria. As noted in the table, Plus Point inspection of the hot leg top of tubesheet extends to 8 inches below the TTS to meet W* ARC requirements, as specified in DCPP Technical Specifications.
- 5. For each area examined (e.g., tube supports, dent/dings, sleeves, etc), provide a summary of the number of indications identified to-date of each degradation mode (e.g., number of circumferential primary water stress corrosion cracking indications at the expansion transition).
For the most significant indications in each area, provide an estimate of the severity of the indication (e.g., provide the voltage, depth, and length of the indication). In particular, address whether tube integrity (structural and accident induced leakage integrity) was maintained during the previous operating cycle. In addition, discuss whether any location exhibited a degradation mode that had not previously been observed at this location at this unit (e.g., observed circumferential primary water stress corrosion cracking at the expansion transition for the first time at this unit).
Table 2 provides the 1R13 Repairable indications and Tube Status Report as of 11-8-05 pm, and provides the number of indications identified to date of each degradation mode and steam generator tube location. Table 3 provides a list of the most significant indications of each damage mechanism. For SCC, the largest voltage indications are listed.
- 6. Describe repair/plugging plans.
Table 2 provides the number of tubes to be repaired to date. All repairs are performed by tube plugging at both hot and cold legs. Tubes being plugged with circumferential indications are evaluated for stabilization in accordance with vendor criteria.
- 7. Describe in-situ pressure test and tube pull plans and results (as applicable and if available).
To date, there are no indications that require in-situ pressure testing or tube pull.
- 8. Provide the schedule for steam generator-related activities during the remainder of the current outage.
Attached table provides the ECT status as of 11-8-05 pm. Closeout of ECT inspections is scheduled for 11-10, with tube plugging to follow.
- 9. Discuss the following regarding loose parts:
- what inspections are performed to detect loose parts
- a description of any loose parts detected and their location within the SG
- if the loose parts were removed from the SG
- indications of tube damage associated with the loose parts
- the source or nature of the loose parts if known Inspections performed to detect loose parts. 100% of the bobbin data is routinely reviewed for possible loose part (PLP) indications. In addition, a special in-depth analysis is performed for PLP indications in rows 1 and 2 and the outer 2 peripheral tubes. Plus Point data is routinely reviewed for PLP at the hot leg top of tubesheet during the 100% hot leg TTS exams. When PLP signals are detected by eddy current,
the locations are provided to FOSAR personnel for search and retrieval. FOSAR visual examinations of the tube sheet annulus and blowdown lane regions are performed to identify loose parts. If loose parts are detected by FOSAR, the locations are provided to eddy current data analysis personnel for further review.
Description of any loose parts detected and their location within the SG, and if they were removed from the SG. ECT data is still being collected, and PLP reviews are in progress. FOSAR inspections are currently being conducted. In SG 1-2, three small wire pieces (appear to be from a wire brush) were found by FOSAR and retrieved.
Indications of tube damage associated with the loose parts. When loose parts are identified, either by eddy current or FOSAR, a tube integrity assessment is performed based on a review of the eddy current data. All reviews conducted to date have concluded that no tube degradation or tube wear has resulted from loose parts.
Description of historical loose part. In SG 1-1, in 1R12, a repeat PLP indication (from 1R8 through 1R12) between SG 1-1 R30C78 and R31C78, 3 inches above the cold leg top of tubesheet, was detected by FOSAR. Reference INPO OE report 21468. No tube wear was detected by eddy current. Based on FOSAR videos, the object was lodged tightly between 2 tubes, was metallic, cylindrical, about 0.4 inches in diameter and 0.75 inch long, with a hole (about 0.1 to 0.2 inch diameter) that runs through its center. It resembled a machine curl. In letter PGE-04-50 dated April 23, 2004, Westinghouse performed a very conservative engineering assessment of the foreign object and concluded that continued SG operation with the object present in the secondary side will not affect SG tube integrity for at least one fuel cycle. Therefore, attempts to dislodge the object and cause a potentially loose part were discontinued, and the lodged object was left in place for Cycle 13. The origin of the foreign object part has not been conclusively determined. The bobbin PLP signal has been traced to 1R7 (1995), such that the object was likely introduced in 1R7 or earlier.
The SG secondary side was opened in 1R5, 1R6, and 1R7 for maintenance activities, such as machining associated with feedwater thermal sleeve replacement and feedring plug repair. These activities had the potential to introduce the foreign object.
In 1R13, bobbin exam of this tube location did not identify a PLP signal, thus the foreign object became dislodged in cycle 13. Again, ECT did not detect any tube wear at that location. The object may have migrated.