ML050630237

2004 Annual Operating Report

ML050630237
Person / Time
Site:	Cook
Issue date:	02/25/2005
From:	Jensen J Indiana Michigan Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP:NRC:5691
Download: ML050630237 (11)

Text

Indiana Michigan Power INDiANA Cook Nuclear Plant MICHIGAN One Cook Place Bridgman,MI 49106 POWER AERcom Aunit of American Electric Power February 25,2005 AEP:NRC:5691 Docket Nos: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P1-17 Washington, DC 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 2004 ANNUAL OPERATING REPORT Technical Specifications 6.9.1.4 and 6.9.1.5 of Appendix A to the Donald C. Cook Nuclear Plant Unit 1 and Unit 2 Operating Licenses require that an annual report be submitted to address personnel exposure, steam generator in-service inspection results, challenges to power-operated relief and safety valves, and information regarding any instances when the 1-131 specific activity limit was exceeded.

Consistent with these requirements, a copy of the 2004 annual operating report is attached.

This letter contains no new commitments. Should you have any questions, please contact Mr. John A. Zwolinski, Safety Assurance Director, at (269) 466-2428.

Sincerely, Site Vice President DB/rdw

Attachment:

2003 Annual Operating Report A o(-l

U. S. Nuclear Regulatory Commission AEP:NRC:5691 Page 2 C: J. L. Caldwell, NRC Region III K. D. Curry, Ft. Wayne AEP, w/o attachment J. T. King, MPSC, w/o attachment C. F. Lyon, NRC Washington, DC MDEQ - WHMD/HWRPS, w/o attachment NRC Resident Inspector

ATTACHMENT TO AEP:NRC:5691 2004 Annual Operating Report

1.0 INTRODUCTION

Plant Description Indiana Michigan Power Company is the licensee for Donald C. Cook Nuclear Plant. The plant is located north of Bridgman, Michigan. The plant consists of two nuclear units employing a Westinghouse pressurized water reactor nuclear steam supply system. Each reactor unit employs an ice condenser reactor containment system. The American Electric Power Service Corporation is the architect-engineer and constructor.

Unit I and 2 reactor licensed power levels are 3304 Mwt and 3468 Mwt, respectively. The main condenser cooling method is open cycle using Lake Michigan water as the cooling source for each unit.

2.0 PERSONNEL RADIATION EXPOSURE

SUMMARY

Page 2 of this attachment provides the number of station, utility, and contractor/other personnel receiving exposures greater than 100 millirem (mrem) in 2004. This estimated dose is based on electronic dosimetry and reported in the format specified by Regulatory Guide 1.16.

The values shown in the individual categories (routine maintenance, etc.) represent the number of people who received greater than 100 mrem in that particular category. The grand total figure represents the total number of people who received 100 inrem, whether in one of the categories or multiple categories. A specific person could receive doses in two or more categories, but they would be counted only once in the grand total. Also, a specific person could receive less than 100 mrem in several categories, but have a total dose greater than 100 mrem. As a result, the sum of the individual category totals does not necessarily equal the grand total.

Attachment to AEP:NRC:5691 Page 2 Reg Guide 1.16 Report INDIANA MICHIGAN POWER I COOK NUCLEAR PLANT Prepared for Year 2004 Number of Personnel and Person-Rem By Work and Job Function Number of Personnel > 100 mrem Total Person-Rem Station Utility Contractors Station Utility Contractors Employees Employees and Others Employees Employees and Others Reactor Operation & Surveillance

-Maintenance 5 0 0 1.987 0.000 0.314

-Operations 0 o o 1.840 0.000 0.200

-Health Physics 0 0 0 0.224 0.000 0.007

-Supervisory 0 0 0 0.016 0.000 0.001

-Engineering 0 0 1 0.203 0.003 0.166 Routine Maintenance

-Maintenance 2 0 0 3.678 0.020 1.041

-Operations 0 0 0 1.205 0.000 0.126

-Health Physics 12 0 0 3.520 0.000 0.093

-Supervisory 0 0 0 0.071 0.000 0.018

-Engineering 0 o o 0.345 0.003 0.190 Inservice Inspection

-Maintenance 2 0 7 0.781 0.000 3.562

-Operations 1 0 0 0.187 0.000 0.120

-Health Physics 0 0 0 0.106 0.000 0.000

-Supervisory 0 0 0 0.000 0.000 0.000

-Engineering 0 0 10 0.049 0.000 2.853 Special Maintenance

-Maintenance 0 0 0 0.718 0.000 1.867

-Operations 0 0 0 0.073 0.000 0.006

-Health Physics 0 0 0 0.111 0.000 0.002

-Supervisory 0 0 0 0.015 0.000 0.000

-Engineering 0 0 0 0.078 0.000 0.018 Waste Processing

-Maintenance 0 0 20 0.073 0.004 7.111

-Operations 0 0 1 0.060 0.000 0.109

-Health Physics 4 0 2 1.188 0.000 0.376

-Supervisory 0 0 0 0.029 0.000 0.000

-Engineering 0 0 1 0.062 0.000 0.380 Refueling

-Maintenance 33' 0 173 11.258 0.086 65.088

-Operations 22 0 19 6.239 0.000 5.541

-Health Physics 20 0 34 7.106 0.000 11.900

-Supervisory 3 0 0 0.787 0.000 0.191

-Engineering 4 0 45 1.805 0.048 23.749 Totals

-Maintenance 61 0 207 18.494 0.110 78.983

-Operations 33 0 22 9.603 0.000 6.102

-Health Physics 34 0 36 12.255 0.000 12.378

-Supervisory 3 0 ' 0 0.918 0.000 0.211

-Engineering 5 0 60 2.541 0.053 27.356 Grand Totals 136 O 325 43.811 0.163 125.030

Attachment to AEP:NRC:5691 Page 3 3.0 STEAM GENERATOR INSPECTIONS ACRONYM / DEFINITION ISTING

% TW Percent Through Wall BLG Bulge - Indication code signifying an expansion of the tube from the inside outward.

Defective An imperfection of such severity that it exceeds the plugging limit.

Degraded A tube containing imperfections greater then or equal to 20 percent of the nominal wall thickness caused by degradation.

DNG Ding - Indication code signifying a local reduction of the nominal tube diameter resulting from impact or kinking during steam generator fabrication, transportation, or operation.

DSI Distorted Support Indication - Indication code signifying an indication at a tube support that has poor depth correlation and requires additional evaluation.

DTS Distorted Tubesheet Expansion Signal - Indication code signifying an indication originally reported as distorted that is subsequently resolved to a non-repairable status by additional examination or historical reviews.

Freespan Region of tubing between support structures.

FSH Freespan History - Indication code referring to a previously reported indication in the freespan area that has been looked up in prior examinations and evaluated with a resulting determination that no signal change has occurred.

I - Code Indication type referring to distorted or non-quantifiable indications.

LPI Loose Part With Possible Indication - Identification code referring to an indication of a loose part that has possible wear associated with the identified loose part.

MBM Manufacturing Burnish Mark - Indication code referring to a tubing condition where localized tubing imperfections were removed in the tubing mill or fabrication shop by buffing and are detectable due to the effects of cold working and localized wall thinning.

MBH Manufacturing Burnish Mark History - Indication code referring to a previously reported manufacturing burnish mark that has been looked up in prior examinations and evaluated with a resulting determination that no signal change has occurred.

MBI Manufacturing Burnish Mark Indication- Indication code referring to a previously reported manufacturing burnish mark that has been looked up in prior examinations and evaluated with a resulting determination that a signal change has occurred.

NHE No Hydraulic Expansion - Indication code used to identify a tube on either the hot leg or cold leg location of the tubesheet that has no hydraulic expansion of the tubing to the tubesheet hole.

PVN Permeability Variation - Indication code referring to variations in the ability of a material to conduct magnetic flux lines.

Attachment to AEP:NRC:5691 P-age 4 PLP Possible Loose Parts - Indication code used to identify a potential foreign object on the secondary side of the steam generators.

Rxx/Cyy Typical identification scheme for a tube location coordinate corresponding to Row xx and Column yy SG Steam Generator TWD Throughwall Degradation - Indication code referring to a loss of tube material, typically expressed as a percentage of tube wall thickness.

VOL Volumetric - Indication code referring to volumetric degradation believed to be non-cracks.

3.1 2004 SG In-Service Inspections The tubing in the Unit 1 SGs was last eddy current inspected in October/November of 2003.

Inspection findings were included in the 2003 annual report submittal and therefore are excluded from this report. Based upon the results of the 2003 inspection and the previous inspection, the Unit I SG inspection interval is governed by the provisions of Technical Specification 4.4.5.3a. This specification allows an inspection interval of up to 40 calendar months once two consecutive inspections have yielded degradation category C-1 results. As such, the Unit I SGs will next be inspected in the fall of 2006.

During October of 2004, eddy current inspections were conducted on the Unit 2 SGs as detailed below. Based upon the favorable results of this inspection and in accordance with the provisions of Technical Specification 4.4.5.3a as noted above, the Unit 2 SGs continue to be on an inspection interval of up to 40 calendar months. As such, the Unit 2 SGs will next be inspected in the fall of 2007.

3.2 Unit 2 SG Description The four replacement Westinghouse model 54F SGs were initially placed in service in March of 1989.

Each of the replacement SGs contains 3592 thermally treated alloy 690 tubes with an outside diameter of 0.875 inches and a nominal wall thickness of 0.050 inches. All tubes in the eight innermost rows were thermally stress relieved after bending. In addition, the tube bundle has an increased tube bend radius i.e. row 1 bend radius is equal to 3.14 vs. 2.19 in the original SGs, which further reduces the residual stress in the U-bend area.

The tube support structures consist of seven 1.12 inch thick support plates with quatrefoil holes and six anti-vibration bars that are located in the u-bend region of the tubes. There is also a flow distribution baffle located between the tubesheet and the first support plate. The flow distribution baffle is 0.75 inches thick with octofoil holes. The support plates, anti-vibration bars, and the flow distribution baffle are all made of type 405 stainless steel.

Attachment to AEP:NRC:5691 Page 5 The tubesheet is a nominal 21 inches thick and is made of ASME SA-508 Class 2a low alloy steel forging material with Inconel cladding on the primary side. With the exception of seven tubes that lack hydraulic expansion in either the hot or cold leg tubesheet due to a manufacturing oversight, all remaining tubes are fully hydraulically expanded into the tubesheet.

3.3 Inspection Scope The 2004 Donald C. Cook Nuclear Plant Unit 2 SG inspection scope consisted of:

• 25% full length inspection (except Row 1 and Row 2 U-bends) with a bobbin coil - All SGs

• 20% hot leg expansion transition, +/- 3 inches with a rotating coil - SGs 22 and 23

• 20% small radius (Row 1 and Row 2) U-bends with a rotating coil - SG 22

• Special interest rotating coil examinations of indications of interest reported during the bobbin coil examination - All SGs The following tables provide a count of the inspection scope.

Base . Exam. SG 21- SG 22- SG 23 SG 24 Examinations Extent Tubes Tubees Tubes itTubes

_________._ Exan'e'd ExaminedExaindined, Bobbin Coil Full Length* 900 900 900 900 Rotating Coil - Top of Tubesheet Hot Leg +/-3 inches 720 720 Expansion Transition Rotating Coil - Tube Rows 1 & 2, Small Radius from the Top Hot U-bends Leg Support to 40 _

the Top Cold Leg Support

• Except Row 1 and Row 2 U-bends where the bobbin coil is not considered to be qualified.

Attachment to AEP:NRC:5691 Page 6

,Special Interest -  ;,S

2 - ,SG 22 SG23 SG 24 Rotting Coil '- Indications 'Indications Indications Indications (Extent varies) Examined'ExaminedExamined Examined

> 2 volt DNG 12 8 10 13 Tubesheet BLG 18 14* 1 1 PVN I No No No Indications Indications Indications Historical Indications 10 6 13 12 FSH &MBH NHE No 3 4 No Indications Indications Additional Inspections No 111** 92** No in Areas of PLP Indications I Indications

• Total includes 11 BLG indications examined as part of the hot leg top of tubesheet examination

• • Locations selected to ensure complete bounding of (I1) possible loose part signals 3.4 Inspection Results Bobbin Coil Results:

The bobbin coil sample inspection resulted in four indications of wall-thickness penetration.

The four wear indications, TWD, were identified in SG 21 in two tubes. The indications reflected minor tube support wear which had been identified during previous inspections.

These indications were in the 2004 inspection plan for continued monitoring and growth rate trending. Review of these indications found essentially no change from the last inspection:

SG, Tube -Tube, "-; '.,Location . 2002 Results', 2004 Results Row - ' 'Column' ( W) 21 6 53 5uHot Leg Support- 6 6 0.63 inch 21 6 53 6t Hot Leg Support - 11 13 0.61 inch 21 6 54 4hHot Leg Support- 7 5 0.64 inch 21 6 54 5t Hot Leg Support - 4 4 0.62 inch As these indications were well below the 40% TW repair limit, they were allowed to remain in service.

Several other bobbin coil indications of interest (one DTI, one DSI, four MBIs, one PVN, and seven NHEs) required further characterization by rotating examination and as such were included in the special interest population. These indications are discussed under the rotating coil section of this report.

Attachment to AEP:NRC:5691 Page 7 Rotating Coil Results:

No indications of degradation were detected during the planned rotating coil inspections performed at the top of the tubesheet or in the U-bend area.

In addition to the planned rotating coil inspection scope, special interest rotating coil sample inspections were performed on DNG greater than or equal to 2 volts, freespan indications greater than or equal to 0.50 volts, historical tubesheet bulge indications, all bobbin "I codes",

all permeability indications and all indications of NHE. In addition, areas where PLPs were identified were aggressively inspected to ensure no tube damage was present.

No indications of degradation were detected during the sample DNG, freespan, and tubesheet bulge examinations.

Six bobbin 'I-code" special interest indications from the bobbin coil inspection were examined with a rotating coil:

• The one DTI was identified 0.04 inches below the secondary face of the hot leg tubesheet on tube R23/C29 in SG 22. This location was examined with a rotating coil and no degradation was detected. As a result the indication code was changed (resolved) to a DTS signifying a non-repairable status.

• The one DSI was identified 0.36 inches below the hot leg flow distribution baffle on tube R46/C37 in SG 22. This indication was examined with a rotating coil and a LPI was detected. This tube (R46/C37) was ultimately plugged due to associated loose part wear.

• The four MBIs were examined and were identified as VOL. Two of these indications were located in SG 21 (R14/C4, R11/C85) and two were located in SG 24 (R37/C35, RIO/C90). As a result of the rotating coil examination and historical comparisons, these four indications were revised to MBH indications. That is, an MBI from a previous inspection that had not changed and does not represent degradation.

The one PVN was identified 27.56 inches above the fourth hot leg support on tube R4/C42 in SG 21. This location was examined with a rotating coil and no degradation was detected.

The seven locations of NHE into the tubesheet were examined with a rotating coil. These indications were identified during previous examinations and dispositioned to be left in service; however, they are in the continued monitoring inspection plan to ensure no changes are occurring. No degradation was detected during the re-examinations.

Extensive bounding rotating coil examinations were conducted in areas of the tube bundle in SGs 22 and 23 where PLP signals were identified to ensure no tube damage had occurred. As previously noted, one tube in SG 22 (R46/C37) was discovered during the bobbin inspection

Attachment to AEP:NRC:5691 Page 8 that was reported as a DSI. This indication was reexamined with a rotating coil to better characterize the signal. A small metallic part was subsequently identified lodged between the flow distribution baffle and the tube. As the part could not be removed and tube wear sized at 33% TW was detected, the tube was plugged. One additional wire fragment was found during the secondary side visual examination that could not be removed. The wire had adhered to the base of tube R3/C55 in SG 22 at the top of the cold leg tubesheet. Eddy current found no degradation present at this location. Retrieval attempts were unsuccessful and the part was dispositioned to remain in place. Remaining PLP indications in SG 22 were dispositioned as sludge/scale buildup and not indicative of foreign objects. No other indications of degradation were identified during the loose part expansion program in SG 22.

PLP indications were also received in SG 23. As a result, bounding eddy current examinations were conducted'in the areas of interest. No other indications of degradation were identified during the loose part expansion program. Secondary side activities ultimately removed all confirmed foreign objects (three wire fragments and a 3/8 inch square nut) from this SG.

4.4 Plugged Tubes The tube in location R461C37 in SG 22 was plugged due to tube wear from a foreign object.

The indication was located just below the hot leg flow distribution baffle and was sized at 25 percent by the bobbin coil and 33 percent by rotating coil. As a result, this tube was considered degraded (greater than or equal to 20 percent wall loss). The examination did not identify any other tubes that were degraded or defective (greater than or equal to 40 percent wall loss) and as result, no other tubes were plugged. The as-left plugging levels are presented in the below table:

SG Total Tube: Overall Number of  :'Percentage of Plugged

.Locations Plugged Tubes Tubes.

21 3592 1 0.03 22 3592 5 0.14 23 3592 6 0.17 24 3592 4 0.11 All 14368 16 0.11 4.5 Degradation Category Based upon the favorable inspection results which identified only one degraded tube (SG 22, R46/C37) and no defective tubes, the 2004 Unit 2 SGs are considered to be in category C-1 as defined by Technical Specification 4.4.5.2:

C-I: Less than 5 percent of the total tubes inspected are degraded tubes and none of the inspected tubes are defective.

Attachment to AEP:NRC:5691 Page 9 C-2: One or more tubes, but not more than 1 percent of the total tubes inspected are defective, or between 5 percent and 10 percent of the total tubes inspected are degraded.

C-3: More than 10 percent of the total tubes inspected are degraded or more than 1 percent of the inspected tubes are defective.

4.0 CHALLENGES TO PRESSURIZER POWER OPERATED RELIEF VALVES (PORV)

AND SAFETY VALVES There were no challenges to the pressurizer PORVs or the pressurizer safety valves on either Unit 1 orUnit 2.

5.0 REACTOR COOLANT SPECIFIC ACTIVITY There were no instances in which the reactor coolant dose equivalent 1-131 specific activity exceeded Technical Specification 3.4.8 limits of 1 [LCi/g in either Unit I or Unit 2.

Compliance was determined by routine gamma spectrometry analysis of reactor coolant.