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{{#Wiki_filter:Accession No. ML113330778  
{{#Wiki_filter:Accession No. ML113330778 From:                   Tam, Peter Sent:                   Tuesday, November 29, 2011 3:24 PM To:                     'jrwaters@aep.com'; Helen Etheridge Cc:                     Karwoski, Kenneth; Johnson, Andrew; Beltz, Terry; Cusumano, Victor
 
From: Tam, Peter Sent: Tuesday, November 29, 2011 3:24 PM To: 'jrwaters@aep.com'; Helen Etheridge Cc: Karwoski, Kenneth; Johnson, Andrew; Beltz, Terry; Cusumano, Victor  


==Subject:==
==Subject:==
D.C. Cook Unit 1 - Record of discussion by phone regarding steam generator inspection (TAC ME7321)
D.C. Cook Unit 1 - Record of discussion by phone regarding steam generator inspection (TAC ME7321)
Helen: The NRC technical staff provided a summary (see below) of the conference call on 10/5/11 with you and others on the subject issue. Upon completion of the discussion, we have closed the TAC number shown above.
Helen:
Peter S. Tam Senior Project Manager (for D. C. Cook and Monticello) Plant Licensing Branch III-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Tel. 301-415-1451  
The NRC technical staff provided a summary (see below) of the conference call on 10/5/11 with you and others on the subject issue. Upon completion of the discussion, we have closed the TAC number shown above.
>>>>>>>>>>>>>>>>>>
Peter S. Tam Senior Project Manager (for D. C. Cook and Monticello)
Plant Licensing Branch III-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Tel. 301-415-1451


==SUMMARY==
==SUMMARY==
OF CONFERENCE CALL WITH DONALD C. COOK NUCLEAR PLANT UNIT 1 REGARDING THE 2011 STEAM GENERATOR TUBE INSPECTION RESULTS DOCKET NO. 50-315
OF CONFERENCE CALL WITH DONALD C. COOK NUCLEAR PLANT UNIT 1 REGARDING THE 2011 STEAM GENERATOR TUBE INSPECTION RESULTS DOCKET NO. 50-315 On October 5, 2011, the staff of the Steam Generator Tube Integrity and Chemical Engineering Branch (ESGB) of the Division of Engineering participated in a conference call with representatives of Indiana Michigan Power Company (the licensee) regarding their ongoing steam generator (SG) tube inspection activities at Donald C. Cook Nuclear Plant Unit 1.
 
On October 5, 2011, the staff of the Steam Generator Tube Integrity and Chemical Engineering Branch (ESGB) of the Division of Engineering participated in a conference call with representatives of Indiana Michigan Power Company (the licensee) regarding their ongoing steam generator (SG) tube inspection activities at Donald C. Cook Nuclear Plant Unit 1.
Information provided by the licensee after the call is provided as an attachment to the enclosure (Agencywide Documents Access Management System (ADAMS) Accession Numbers ML112920165 and ML112920187).
Information provided by the licensee after the call is provided as an attachment to the enclosure (Agencywide Documents Access Management System (ADAMS) Accession Numbers ML112920165 and ML112920187).
Donald C. Cook Nuclear Plant Unit 1 has four Model 51R recirculating SGs designed and fabricated by Babcock and Wilcox International. Each SG has 3,496 thermally treated Alloy 690 tubes that have an outside diameter of 0.875 inches, and a nominal wall thickness of 0.049 inches. The tubes are supported by Type 410 stainless steel, lattice-grid tube supports, and flat fan bars. The tubes were hydraulically expanded at each end for the full depth of the tubesheet.  
Donald C. Cook Nuclear Plant Unit 1 has four Model 51R recirculating SGs designed and fabricated by Babcock and Wilcox International. Each SG has 3,496 thermally treated Alloy 690 tubes that have an outside diameter of 0.875 inches, and a nominal wall thickness of 0.049 inches. The tubes are supported by Type 410 stainless steel, lattice-grid tube supports, and flat fan bars. The tubes were hydraulically expanded at each end for the full depth of the tubesheet.
 
Information provided by the licensee during the phone call that was not included in the attachments is summarized below.
Information provided by the licensee during the phone call that was not included in the attachments is summarized below.
The SGs are approximately 11 years old and the last tube inspection was performed in 2006. During the 2006 inspection, approximately 50 percent of the SG tubes were inspected and approximately 51 fan bar wear indications were identified. At the time of the call, the current inspections were approximately 90 percent complete and over 2000 fan bar wear indications had been identified. The majority of the new fan bar wear indications were located in the  U-bend region of high-row tubes (i.e., tubes in row 60 and above with larger bend radii). The licensee indicated that they would provide a tubesheet map to indicate the location of the tubes with fan bar wear. The tubesheet maps are included as attachments to this enclosure.
The SGs are approximately 11 years old and the last tube inspection was performed in 2006.
During the 2006 inspection, approximately 50 percent of the SG tubes were inspected and


approximately 51 fan bar wear indications were identified. At the time of the call, the current inspections were approximately 90 percent complete and over 2000 fan bar wear indications had been identified. The majority of the new fan bar wear indications were located in the U-bend region of high-row tubes (i.e., tubes in row 60 and above with larger bend radii).
The licensee indicated that they would provide a tubesheet map to indicate the location of the tubes with fan bar wear. The tubesheet maps are included as attachments to this enclosure.
The planned inspection scope for the SG tubes was a 100 percent sample of all four SGs using the bobbin probe. At the time of the call, the largest wear indication found was 28 percent through wall and approximately 48 tubes with wear greater than 20 percent through wall had been detected. A rotating pancake coil (RPC) was being used to inspect a 20 percent sample of the largest fan bar wear indications.
The planned inspection scope for the SG tubes was a 100 percent sample of all four SGs using the bobbin probe. At the time of the call, the largest wear indication found was 28 percent through wall and approximately 48 tubes with wear greater than 20 percent through wall had been detected. A rotating pancake coil (RPC) was being used to inspect a 20 percent sample of the largest fan bar wear indications.
At the time of the call, the licensee had not yet decided upon the future inspection frequency of the SGs, but indicated that they were planning on plugging the 13 tubes that had been identified with through wall wear greater than or equal to 23 percent. By plugging these tubes, the licensee calculated that they would maintain the option of skipping the SG inspections during the next refueling outage while ensuring that the tube integrity performance criteria will continue to be met.
At the time of the call, the licensee had not yet decided upon the future inspection frequency of the SGs, but indicated that they were planning on plugging the 13 tubes that had been identified with through wall wear greater than or equal to 23 percent. By plugging these tubes, the licensee calculated that they would maintain the option of skipping the SG inspections during the next refueling outage while ensuring that the tube integrity performance criteria will continue to be met.
The licensee indicated that by comparing measured wear indications from this SG inspection with measured wear indications from the 2006 SG inspections, the upper 95 th percentile growth rate was calculated to be approximately 4.8 percent per effective full power year. However, in response to questions, the licensee also noted that a few tubes that showed no wear indications in 2006 showed greater than 20 percent wear indications this outage. Because this could potentially indicate a high growth rate mechanism in the SGs, the licensee was checking to see if the indications were previously detectable. The licensee also indicated that there were a small number of wear indications at the tube support plates (TSPs) in the SGs.  
The licensee indicated that by comparing measured wear indications from this SG inspection with measured wear indications from the 2006 SG inspections, the upper 95th percentile growth rate was calculated to be approximately 4.8 percent per effective full power year. However, in response to questions, the licensee also noted that a few tubes that showed no wear indications in 2006 showed greater than 20 percent wear indications this outage. Because this could potentially indicate a high growth rate mechanism in the SGs, the licensee was checking to see if the indications were previously detectable. The licensee also indicated that there were a small number of wear indications at the tube support plates (TSPs) in the SGs.
 
In response to questions, the licensee stated that they had not identified any transients or events since the 2006 inspections that might have influenced vibration levels (i.e. wear rates) such as major SG/plant upsets or major changes in SG fouling or feed/steam flow rates.
In response to questions, the licensee stated that they had not identified any transients or events since the 2006 inspections that might have influenced vibration levels (i.e. wear rates) such as major SG/plant upsets or major changes in SG fouling or feed/steam flow rates.  
Fouling at the TSPs in the SGs had been mapped during the 2006 inspections and approximately 100 pounds of total sludge had been indicated in all the SGs. The mapping was being repeated at the time of the call this outage. The inspection processes used in 2006 were the same as being used during the current outage and the noise and data quality from the current outage were virtually identical to that in the 2006 outage.
 
Fouling at the TSPs in the SGs had been mapped during the 2006 inspections and approximately 100 pounds of total sludge had been indicated in all the SGs. The mapping was being repeated at the time of the call this outage. The inspection processes used in 2006 were the same as being used during the current outage and the noise and data quality from the current outage were virtually identical to that in the 2006 outage.  
 
The licensee indicated that they had implemented a Measurement Uncertainty Recapture Power Uprate that the NRC approved in December 2002, but had not implemented any other types of power uprates. Additionally, the licensee indicated that they had experienced a turbine failure about 3 years ago, but could not identify and transients or operating experience that might account for the increased fan bar wear.}}
The licensee indicated that they had implemented a Measurement Uncertainty Recapture Power Uprate that the NRC approved in December 2002, but had not implemented any other types of power uprates. Additionally, the licensee indicated that they had experienced a turbine failure about 3 years ago, but could not identify and transients or operating experience that might account for the increased fan bar wear.}}

Latest revision as of 20:02, 6 February 2020

Record of Discussion by Phone on 10/5/11 Regarding Steam Generator Inspection
ML113330778
Person / Time
Site: Cook American Electric Power icon.png
Issue date: 11/29/2011
From: Tam P
Plant Licensing Branch III
To: Etheridge H
Indiana Michigan Power Co
Tam P
References
TAC ME7321
Download: ML113330778 (2)
v • d • e


Text

Accession No. ML113330778 From: Tam, Peter Sent: Tuesday, November 29, 2011 3:24 PM To: 'jrwaters@aep.com'; Helen Etheridge Cc: Karwoski, Kenneth; Johnson, Andrew; Beltz, Terry; Cusumano, Victor

Subject:

D.C. Cook Unit 1 - Record of discussion by phone regarding steam generator inspection (TAC ME7321)

Helen:

The NRC technical staff provided a summary (see below) of the conference call on 10/5/11 with you and others on the subject issue. Upon completion of the discussion, we have closed the TAC number shown above.

Peter S. Tam Senior Project Manager (for D. C. Cook and Monticello)

Plant Licensing Branch III-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Tel. 301-415-1451

SUMMARY

OF CONFERENCE CALL WITH DONALD C. COOK NUCLEAR PLANT UNIT 1 REGARDING THE 2011 STEAM GENERATOR TUBE INSPECTION RESULTS DOCKET NO. 50-315 On October 5, 2011, the staff of the Steam Generator Tube Integrity and Chemical Engineering Branch (ESGB) of the Division of Engineering participated in a conference call with representatives of Indiana Michigan Power Company (the licensee) regarding their ongoing steam generator (SG) tube inspection activities at Donald C. Cook Nuclear Plant Unit 1.

Information provided by the licensee after the call is provided as an attachment to the enclosure (Agencywide Documents Access Management System (ADAMS) Accession Numbers ML112920165 and ML112920187).

Donald C. Cook Nuclear Plant Unit 1 has four Model 51R recirculating SGs designed and fabricated by Babcock and Wilcox International. Each SG has 3,496 thermally treated Alloy 690 tubes that have an outside diameter of 0.875 inches, and a nominal wall thickness of 0.049 inches. The tubes are supported by Type 410 stainless steel, lattice-grid tube supports, and flat fan bars. The tubes were hydraulically expanded at each end for the full depth of the tubesheet.

Information provided by the licensee during the phone call that was not included in the attachments is summarized below.

The SGs are approximately 11 years old and the last tube inspection was performed in 2006.

During the 2006 inspection, approximately 50 percent of the SG tubes were inspected and

approximately 51 fan bar wear indications were identified. At the time of the call, the current inspections were approximately 90 percent complete and over 2000 fan bar wear indications had been identified. The majority of the new fan bar wear indications were located in the U-bend region of high-row tubes (i.e., tubes in row 60 and above with larger bend radii).

The licensee indicated that they would provide a tubesheet map to indicate the location of the tubes with fan bar wear. The tubesheet maps are included as attachments to this enclosure.

The planned inspection scope for the SG tubes was a 100 percent sample of all four SGs using the bobbin probe. At the time of the call, the largest wear indication found was 28 percent through wall and approximately 48 tubes with wear greater than 20 percent through wall had been detected. A rotating pancake coil (RPC) was being used to inspect a 20 percent sample of the largest fan bar wear indications.

At the time of the call, the licensee had not yet decided upon the future inspection frequency of the SGs, but indicated that they were planning on plugging the 13 tubes that had been identified with through wall wear greater than or equal to 23 percent. By plugging these tubes, the licensee calculated that they would maintain the option of skipping the SG inspections during the next refueling outage while ensuring that the tube integrity performance criteria will continue to be met.

The licensee indicated that by comparing measured wear indications from this SG inspection with measured wear indications from the 2006 SG inspections, the upper 95th percentile growth rate was calculated to be approximately 4.8 percent per effective full power year. However, in response to questions, the licensee also noted that a few tubes that showed no wear indications in 2006 showed greater than 20 percent wear indications this outage. Because this could potentially indicate a high growth rate mechanism in the SGs, the licensee was checking to see if the indications were previously detectable. The licensee also indicated that there were a small number of wear indications at the tube support plates (TSPs) in the SGs.

In response to questions, the licensee stated that they had not identified any transients or events since the 2006 inspections that might have influenced vibration levels (i.e. wear rates) such as major SG/plant upsets or major changes in SG fouling or feed/steam flow rates.

Fouling at the TSPs in the SGs had been mapped during the 2006 inspections and approximately 100 pounds of total sludge had been indicated in all the SGs. The mapping was being repeated at the time of the call this outage. The inspection processes used in 2006 were the same as being used during the current outage and the noise and data quality from the current outage were virtually identical to that in the 2006 outage.

The licensee indicated that they had implemented a Measurement Uncertainty Recapture Power Uprate that the NRC approved in December 2002, but had not implemented any other types of power uprates. Additionally, the licensee indicated that they had experienced a turbine failure about 3 years ago, but could not identify and transients or operating experience that might account for the increased fan bar wear.

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