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Category:Note to File incl Telcon Record
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[Table view]
Category:Verbal Comm
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[Table view] |
Text
June 10, 2002 MEMORANDUM TO: James W. Clifford, Chief, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation FROM: Robert J. Fretz, Project Manager, Section 2 /RA/
Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNIT NO. 2, FACSIMILE TRANSMISSION AND INFORMATION DISCUSSED IN A RECENT CONFERENCE CALL (TAC NO. MB4599)
The attached information was transmitted by facsimile on June 3, 2002, to PSEG Nuclear LLC (PSEG or the licensee). This information was provided in order to verify information members of the NRC staff had received during a recent conference call on Salem Unit No. 2 steam generators (SGs). In a phone call with the licensee on June 6, 2002, PSEG clarified that the single circumferential primary water stress corrosion cracking indication discovered at a top-of-tube sheet location should be attributed to SG 22. The NRC staff had originally assigned this indication to SG 23. PSEG added that the final inspection findings showed the following: (1) a total of 40 ligament crack indications at tube support plates, (2) 490 anti-vibration bar wear indications, and (3) 91 cold leg thinning indications.
Docket No. 50-311
Attachment:
Summary of Telephone Conference Call Between Members of the U.S. Nuclear Regulatory Commission Staff and PSEG Nuclear LLC, Re: Salem Nuclear Generating Station, Unit No. 2, Steam Generator Tube Inspections
MEMORANDUM TO: James W. Clifford, Chief, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation FROM: Robert J. Fretz, Project Manager, Section 2 /RA/
Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNIT NO. 2, FACSIMILE TRANSMISSION AND INFORMATION DISCUSSED IN A RECENT CONFERENCE CALL (TAC NO. MB4599)
The attached information was transmitted by facsimile on June 3, 2002, to PSEG Nuclear LLC (PSEG or the licensee). This information was provided in order to verify information members of the NRC staff had received during a recent conference call on Salem Unit No. 2 steam generators (SGs). In a phone call with the licensee on June 6, 2002, PSEG clarified that the single circumferential primary water stress corrosion cracking indication discovered at a top-of-tube sheet location should be attributed to SG 22. The NRC staff had originally assigned this indication to SG 23. PSEG added that the final inspection findings showed the following: (1) a total of 40 ligament crack indications at tube support plates, (2) 490 anti-vibration bar wear indications, and (3) 91 cold leg thinning indications.
Docket No. 50-311
Attachment:
Summary of Telephone Conference Call Between Members of the U.S. Nuclear Regulatory Commission Staff and PSEG Nuclear LLC, Re: Salem Nuclear Generating Station, Unit No. 2, Steam Generator Tube Inspections DISTRIBUTION PUBLIC RFretz JClifford PDI-2 R/F ACCESSION NO. ML021580052 OFFICE PDI-2/PM NAME RFretz DATE 6/10/02 OFFICIAL RECORD COPY
LICENSEE: PSEG Nuclear LLC FACILITY: Salem Nuclear Generating Station, Unit No. 2
SUBJECT:
SUMMARY
OF TELEPHONE CONFERENCE CALL BETWEEN MEMBERS OF THE U.S. NUCLEAR REGULATORY COMMISSION (NRC) STAFF AND PSEG NUCLEAR LLC, RE: SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 STEAM GENERATOR TUBE INSPECTIONS (TAC NO. MB4599)
On April 19, 2002, members of the NRC staff participated in a telephone conference call with PSEG Nuclear LLC (PSEG) representatives regarding steam generator (SG) tube inspection activities at Salem Unit No. 2.
Background
Tube integrity is integral to the safe operation of SGs. Because of past problems with tubes affecting the operation of SGs, the NRC continues to support activities related to improving tube integrity, as does the nuclear industry. During November 2000, following the indian Point 2 SG leakage event, the NRC developed a Steam Generator Action Plan (SGAP) to coordinate activities related to SGs, and to ensure that issues are appropriately tracked and dispositioned.
The plan consolidated numerous NRC action items related to SGs that originated from, or were associated with the following activities:
- evaluation and implementation of recommendations stemming from the NRC's Indian Point 2 Lessons Learned Task Group report
- evaluation and implementation of recommendations from NRR staff review of the Office of the Inspector General report on the IP2 steam generator tube failure event
- the NRC's review of the industry initiative related to SG tube integrity (i.e., NEI 97-06)
Conference Call The conference call was initiated by the NRC staff in accordance with SGAP Milestone 1.10.
This call is usually held after licensees have inspected a majority of the tubes, but before SG inspection activities have been completed. Topics discussed during the call included:
- indications identified to-date
- in-situ pressure test plans
- actions taken in response to lessons learned from the Indian Point 2 tube failure.
Attachment
Inspection Scope PSEG stated that no primary-to-secondary leakage existed in Salem Unit No. 2 prior to shutdown. This has been the case for the past 2 to 3 cycles. Since no leakage existed, the licensee did not perform secondary side hydrostatic testing. The following table summarizes the initial inspection scope.
No. of Description % Inspected Method Exams Comments TE to TE 100% of all Bobbin in-service tubes Short Radius U-bends from 100% Row 2 Plus Point 420 All row 1 tubes were the 7H TSP to the 7C TSP 20% Row 3 previously plugged HL TTS (from 8" below 100% of all Plus Point 12,684 TTS to 2" above TTS) in-service tubes TS Anomalies Plus Point 71 HL Dents $ 1.0 volt (v) (as 100% 1H and 2H Plus Point 3,200 See Note measured with Bobbin) 20% 3H 930 HL Dents $ 5.0 v (as 20% 5H - 7H Plus Point See Note measured with Bobbin)
TSP ligaments Bobbin low frequency screening HL Freespan Dings $ 2.0 v 20% Plus Point 63 (as measured with Bobbin)
Installed Plugs 100% Visual Key: TE = Tube end C = Cold (e.g., 7C designates the no. 7 cold leg TSP)
TS = Tube sheet H = Hot (e.g., 2H designates the no. 2 hot leg TSP)
TSP = Tube support plate CL = cold leg TTS = Top of tube sheet HL = hot leg Note: The licensee stated that, during refueling outage 2R9, it had inspected all dented TSPs. During the last outage, 100% of the dents $ 1.0 v were inspected up to and including the 4H TSP. In addition, dents located in 5H to 7H TSPs were sampled. No indications were found above the 2H TSP during this outage. These inspections and results were used as the basis for the initial inspection scope for this outage.
In-situ Pressure Testing The licensee stated that the degradation in the SGs is mild and falls below the Condition Monitoring (CM) limits. Therefore, in-situ pressure testing was not required.
Tube Pulls The licensee stated that a tube pull was not required for this inspection.
Inspection Findings PSEGs inspection findings are summarized in the following table. The number of indications found for a specific degradation mechanism are shown for each SG.
SG SG SG SG Location Degradation Mechanism 21 22 23 24 Comments TTS Axial Primary Water Stress 11 8 4 2 Corrosion Cracking (PWSCC)
Circumferential PWSCC 1 See Note 1 TS Volumetric Outside Diameter 2 Stress Corrosion Cracking (ODSCC)
TSP Axial PWSCC 1 1 Circumferential PWSCC 1 Identified in 4.0 v dent in 01H TSP. First time detected at Salem Unit 2.
Axial ODSCC 2 1 Identified in 01H TSP.
Ligament Cracking See Note 2 AVB Wear 1 1 See Note 3 CL Thinning 2 4 See Note 4 Short N/A No flaws identified. Row 2 Radius U-bends were heat treated U-bends in 2R5 (1990).
Notes:
- 1. This indication was located 2.16" below the TTS and was identified by a rotating probe containing a Plus Point (+Pt) coil. It was subsequently inspected with an RG34 probe which did not confirm the indication. However, the tube was still plugged and stabilized.
- 2. 28 ligament cracks were identified. None exceeded the licensees acceptance criteria.
The licensee stated that the cracks have been traced to earlier eddy current data, and they do not believe this degradation mechanism is active. This was not the first outage that ligament cracking was identified.
- 3. 478 AVB wear indications were identified. These indications were depth-sized, and only two required plugging.
- 4. 100 indications were identified. These indications were depth-sized using bobbin coil data, and only 6 required plugging. The deepest CL thinning indication was 45%
through-wall. The licensee uses a plugging limit which is based on a SG-specific 95th percentile growth rate. The plugging limits used by the licensee ranged from 35%
through-wall to 40% through-wall (the technical specification limit). The licensee
periodically inspects CL thinning indications with a rotating probe to confirm the degradation mechanism.
The licensee determined that the amount of degradation has decreased from the previous SG inspection. PSEG believes this may be due to the most susceptible tubes having been plugged during previous outages.
Plugged Tubes The following table summarizes the total tubes plugged per SG during this outage.
SG Total Tubes Plugged 21 14 22 8 23 10 24 9
TELEPHONE CONFERENCE PARTICIPANTS SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 STEAM GENERATOR TUBE INSPECTIONS April 19, 2002 NRC Headquarters Bart Fu Carolyn Lauron Emmett Murphy Ken Karwoski Cheryl Khan April Smith John Tsao Robert Fretz NRC Region I Mel Gray Fred Jaxheimer Wayne Schmidt PSEG Nuclear LLC
