ML022540009
| ML022540009 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, Catawba, McGuire  |
| Issue date: | 09/09/2002 |
| From: | Mccree V Division of Reactor Safety I |
| To: | Tuckman M Duke Energy Corp |
| References | |
| IR-02-006 | |
| Download: ML022540009 (52) | |
See also: IR 05000369/2002006
Text
1
September 9, 2002
Mr. M. S. Tuckman
Executive Vice-President
Nuclear Generation
Duke Energy Corporation
PO Box 1006
Charlotte, NC 28201-1006
SUBJECT:
MCGUIRE AND CATAWBA NUCLEAR STATIONS - NRC INSPECTION
REPORT 50-369/02-06, 50-370/02-06, 50-413/02-06 AND 50-414/02-06
Dear Mr. Tuckman:
On July 26, 2002, the NRC completed an inspection regarding your application for license
renewal for the McGuire and Catawba Nuclear Stations. The enclosed inspection report
presents the results of that inspection. The results of this inspection were discussed with
members of your staff on July 26, 2002, in a public exit meeting at the Duke Energy
Corporation offices.
The purpose of this inspection was to examine activities that support your application for
renewed license for the McGuire and Catawba facilities. The inspection consisted of a selected
examination of procedures and representative records, and interviews with personnel regarding
your proposed aging management programs to support license extension. In addition, for a
sample of plant systems, inspectors performed a visual examination of accessible portions of
the systems to observe any effects of equipment aging.
The inspection concluded that the existing aging management programs are being conducted
as described in your License Renewal Application and your plans for new aging management
programs appear acceptable to manage plant aging.
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRCs document system
(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room).
2
Should you have any questions concerning this report, please contact Caudle Julian at
(404) 562 - 4603.
Sincerely,
\\RA by Loren Plisco For\\
Victor M. McCree, Deputy Director
Division of Reactor Projects
Docket Nos. 50-369, 50-370 and 50-413, 50-414
License Nos. NPF-9, NPF-17 and NPF-35, NPF-52
Enclosure:
NRC Inspection Report w/attachments
cc w/encl: - See page 3
3
cc: w/encl:
Mr. Gary Gilbert
Regulatory Compliance Manager
Duke Energy Corporation
4800 Concord Road
York, South Carolina 29745
Ms. Lisa F. Vaughn
Duke Energy Corporation
422 South Church Street
Charlotte, North Carolina 28201-1006
Anne Cottingham, Esquire
Winston and Strawn
1400 L Street, NW
Washington, DC 20005
North Carolina Municipal Power
Agency Number 1
1427 Meadowwood Boulevard
P. O. Box 29513
Raleigh, North Carolina 27626
County Manager of York County
York County Courthouse
York, South Carolina 29745
Piedmont Municipal Power Agency
121 Village Drive
Greer, South Carolina 29651
Ms. Karen E. Long
Assistant Attorney General
North Carolina Department of Justice
P. O. Box 629
Raleigh, North Carolina 27602
Ms. Elaine Wathen, Lead REP Planner
Division of Emergency Management
116 West Jones Street
Raleigh, North Carolina 27603-1335
Mr. Robert L. Gill, Jr.
Duke Energy Corporation
Mail Stop EC-12R
P. O. Box 1006
Charlotte, North Carolina 28201-1006
Mr. Alan Nelson
Nuclear Energy Institute
1776 I Street, N.W., Suite 400
Washington, DC 20006-3708
North Carolina Electric Membership
Corporation
P. O. Box 27306
Raleigh, North Carolina 27611
Catawba Senior Resident Inspector
U.S. Nuclear Regulatory Commission
4830 Concord Road
York, South Carolina 29745
Manager - Nuclear Regulatory Licensing
Duke Energy Corporation
526 South Church Street
Charlotte, North Carolina 28201-1006
Mr. L. A. Keller
Duke Energy Corporation
526 South Church Street
Charlotte, North Carolina 28201-1006
Saluda River Electric
P. O. Box 929
Laurens, South Carolina 29360
Mr. Peter R. Harden, IV
VP-Customer Relations and Sales
Westinghouse Electric Company
6000 Fairview Road
12th Floor
Charlotte, North Carolina 28210
Mr. T. Richard Puryear
Owners Group (NCEMC)
Duke Energy Corporation
4800 Concord Road
York, South Carolina 29745
4
cc w/encl contd:
Mr. Richard M. Fry, Director
North Carolina Dept of Env, Health, and
Natural Resources
3825 Barrett Drive
Raleigh, North Carolina 27609-7721
County Manager of
Mecklenburg County
720 East Fourth Street
Charlotte, North Carolina 28202
Mr. Jeffrey Thomas
Regulatory Compliance Manager
Duke Energy Corporation
McGuire Nuclear Site
12700 Hagers Ferry Road
Huntersville, North Carolina 28078
McGuire Senior Resident Inspector
U.S. Nuclear Regulatory Commission
12700 Hagers Ferry Road
Huntersville, North Carolina 28078
Dr. John M. Barry
Mecklenburg County
Department of Environmental Protection
700 N. Tryon Street
Charlotte, North Carolina 28202
Mr. Gregory D. Robison
Duke Energy Corporation
Mail Stop EC-12R
526 S. Church Street
Charlotte, NC 28201-1006
Ms. Mary Olson
Nuclear Information & Resource Service
Southeast Office
P.O.Box 7586
Asheville, North Carolina 28802
Mr. Paul Gunter
Nuclear Information & Resource Service
1424 16th Street NW, Suite 404
Washington, DC 20036
Mr. Lou Zeller
Blue Ridge Environmental Defense League
P. O. Box 88
Glendale Springs, North Carolina 28629
Mr. Don Moniak
Blue Ridge Environmental Defense League
Aiken Office
P.O. Box 3487
Aiken, South Carolina 29802-3487
Mr. Henry J. Porter, Assistant Director
Division of Waste Management
Bureau of Land & Waste Management
S. C. Dept. of Health and Environ. Control
2600 Bull Street
Columbia, South Carolina 29201-1708
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.
50-369, 50-370 and 50-413, 50-414
License Nos.
NPF-9, NPF-17 and NPF-35, NPF-52
Report No:
50-369/02-06, 50-370/02-06, 50-413/02-06 AND 50-414/02-06
Licensee:
Duke Energy Corporation (DEC)
Facility:
McGuire Nuclear Station, Units 1 & 2 and
Catawba Nuclear Station, Units 1 & 2
Location:
12700 Hagers Ferry Rd.
Huntersville NC 28078
4830 Concord Rd.
York SC 29745
Dates:
July 8 - 26, 2002
Inspectors:
B. Crowley, Reactor Inspector
M. Farber, Reactor Inspector RIII
R. Moore, Reactor Inspector
K. Van Doorn, Reactor Inspector
H. Wang, Operations Engineer, NRR
Approved by:
Caudle Julian
Team Leader
Division of Reactor Safety
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I
Report Details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
I. Inspection Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
II. Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
A. Review of Mechanical Aging Management Programs . . . . . . . . . . . . . . . . . . . . . . . 1
1. Inservice Inspection (ISI) Plan
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2. Flow Accelerated Corrosion (FAC) Program . . . . . . . . . . . . . . . . . . . . . . . . . 2
3. Reactor Vessel Integrity Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
4. Reactor Vessel Internals (RVI) Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
5. Steam Generator Surveillance Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
6. Thimble Tube Inspection Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7. Alloy 600 Aging Management Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
8. Control Rod Drive Mechanism (CRDM) Nozzle and Other Vessel Closure
Penetration Inspection Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
9. Chemistry Control Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
10. Battery Rack Inspections
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
11. Heat Exchanger Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
12. Preventive Maintenance Activities - Carbon Steel Coatings Inspections . . . 9
13. Sump Pump Systems Inspection
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
14. Borated Water System Stainless Steel Inspection (BWSSSI) . . . . . . . . . . 10
15. Selective Leaching Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
16. Treated Water Systems Stainless Steel Inspection . . . . . . . . . . . . . . . . . . 11
17. Waste Gas System Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
18. Liquid Waste System Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
19. Fluid Leak Management Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
20. Boraflex Monitoring Program (McGuire Only) . . . . . . . . . . . . . . . . . . . . . . 14
21. Divider Barrier Seal Inspection and Testing Program . . . . . . . . . . . . . . . . 15
22. Galvanic Susceptibility Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
23. Ice Condenser Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
24. Thermal Fatigue Management Program . . . . . . . . . . . . . . . . . . . . . . . . . . 15
25. Reactor Coolant System (NC) Operational Leakage Monitoring Program . 16
26. Service Water Piping Corrosion Program . . . . . . . . . . . . . . . . . . . . . . . . . 16
27. Standby Nuclear Service Water Pond Dam Inspection . . . . . . . . . . . . . . . 17
28. Standby Nuclear Service Water Pond Volume Program (Catawba only) . . 17
29. Pressurizer Spray Head Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
B. Review of Electrical Equipment Aging Management Programs . . . . . . . . . . . . . . . 17
1. Non - EQ Insulated Cables and Connections Aging Management Program 17
2. Inaccessible Non-EQ Medium Voltage Cables Aging Management Program18
3. Applicant Response to Station Blackout Issue . . . . . . . . . . . . . . . . . . . . . . 18
C. Review of Structural Aging Management Programs . . . . . . . . . . . . . . . . . . . . . . . . 18
1. Containment Inservice Inspection Plan - IWE . . . . . . . . . . . . . . . . . . . . . . . 18
2. Containment Leak Rate Testing Program . . . . . . . . . . . . . . . . . . . . . . . . . . 20
3. Flood Barrier Inspection (McGuire) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
4. Inspection Program for Civil Engineering Structures and Components . . . . 21
5. Underwater Inspection of Nuclear Service Water Structures
. . . . . . . . . . . 22
6. Technical Specification SR 3.6.16.3 Visual Inspection . . . . . . . . . . . . . . . . 23
7. Crane Inspection Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
2
D. Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
E. Visual Observations of Plant Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
F. Future Implementation of License Renewal Commitments . . . . . . . . . . . . . . . . . . . . . . . . . 28
III .Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
ATTACHMENT 1 SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
ATTACHMENT 2 MCGUIRE AND CATAWBA NUCLEAR STATIONS AGING MANAGEMENT
PROGRAM INSPECTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
ATTACHMENT 3 LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
I
SUMMARY OF FINDINGS
IR 05000369-02-06, IR 05000370-02-06, 05000413-02-06, 05000414-02-06; 07/08-26 /2002;
Duke Energy Corporation, McGuire Nuclear Station, Units 1 & 2 and Catawba Nuclear Station,
Units 1 & 2. License Renewal Inspection Program, Aging Management Programs.
This inspection of License Renewal activities was performed by five regional office engineering
inspectors, and one staff member from the office of Nuclear Reactor Regulation. The
inspection program followed was NRC Manual Chapter 2516 and NRC Inspection Procedure 71002. This inspection did not identify any findings as defined in NRC Manual Chapter 0612.
The inspection concluded that the existing aging management programs are being conducted
as described in your License Renewal Application (LRA). Discussions with engineering staff
and review of available documentation for expansion of existing programs and creation of new
aging management programs demonstrated that plans were consistent with the LRA and
appear acceptable to manage plant aging.
At McGuire, the Applicant identified during this inspection that there was no surveillance
procedure for a visual inspection of the exposed surfaces of fire rated assemblies on an 18-
month frequency as required by Selected Licensee Commitment TR16.9.5.7. This situation has
existed since 1990. At Catawba, the Applicant identified that two fire protection surveillances
were being performed but, were not being correctly documented.
The inspectors noted that the Applicant was progressing toward implementation of aging
management programs. The Applicant had a written program document for Reactor Vessel
Integrity and had a draft program for the Reactor Vessel Interals inspections. The inspectors
observed that the Applicant had a good draft plan for tracking and implementing procedure
changes and other actions needed to implement future aging management programs. Full
implementation will be confirmed during a future inspection.
The inspectors performed numerous visual inspections on portions of plant equipment to
attempt to observe aging effects. The overall condition of plant equipment was generally very
good. At Catawba, in the pump house intake structure, the inspector observed some piping
with heavy corrosion caused by continuous spray from pump seal leakoff. The Applicant took
measurements to verify that the pipe wall thickness had not corroded below minimum allowable.
Attachment 1 presents a partial list of persons contacted and a list of the documents reviewed.
Attachment 2 presents the inspection sample selected. Attachment 3 presents a list of
acronyms used in this report.
1
Report Details
I. Inspection Scope
This inspection was conducted by NRC Region II inspectors, a Region III inspector, and
members of the NRR staff to interview Applicant personnel and to examine a sample of
documentation which supports the license renewal application (LRA). This inspection reviewed
the implementation of the Applicants Aging Management Programs. The team reviewed
supporting documentation and interviewed Applicant personnel to confirm the accuracy of the
LRA conclusions. Unless specifically stated otherwise, the Aging Management Programs were
reviewed for both sites.
For a sample of plant systems, inspectors performed visual examination of accessible portions
of the systems to observe any effects of equipment aging. Attachment 1 of this report lists the
Applicant personnel contacted and the documents reviewed. The Aging Management
Programs selected for inspection are listed in Attachment 2 of this report. A list of acronyms
used in this report is provided in Attachment 3.
II. Findings
A. Review of Mechanical Aging Management Programs
1. Inservice Inspection (ISI) Plan
The ISI Plan (Program), an existing program, is credited in the LRA as an aging management
program for the ASME Class 1 reactor coolant (RC) system, including exterior surfaces and
bolted closures; piping, valve bodies, and pump casings; pressurizer; reactor vessel and CRDM
pressure boundary components; reactor vessel internals; and steam generators (including
some secondary side components). In addition, the ISI Program is credited as an aging
management program for component supports. The McGuire Unit 1 ISI program has been
converted to a risk-informed (RI) ISI program (based on Westinghouse Topical Report WCAP-
14572) for the 3rd Interval. The applicable Code is ASME Section XI, 1995 Editon. Plans are to
convert the McGuire Unit 2 program to RI after completion of the 2nd Interval. The current Code
for McGuire Unit 2 is the 1989 Edition of ASME Section XI. Both Units at Catawba are in the
2nd Interval and the applicable Code is ASME Section XI, 1989 Edition.
The ISI Program is credited for managing loss of material, cracking, loss of pre-load, and
reduction in fracture toughness for: stainless steel, cast stainless steel, nickel-based alloy, low
alloy steel, and carbon steel. The program consists of performing surface and volumetric
nondestructive examinations of piping and components in accordance with the ASME Boiler
and Pressure Vessel Code and other augmented requirements such as NUREGs, Generic
Letters, etc. The ISI Program is controlled by:
Third Interval Inservice Inspection Plan McGuire Nuclear Station Unit 1 - General
Requirements and Volume 1, Revision 0
Second Interval Inservice Inspection Plan McGuire Station Units 1 & 2 - General
Requirements and Volume 1, Revision 3
Catawba Nuclear Station Second Ten-Year Interval Inservice Inspection Plan
2
The program documents are updated each 10-year interval and submitted to the NRC for
approval of any relief requests. Inspection plan and procedures implement the program.
The inspectors reviewed the applicable Aging Management Activity/Program as described in
the LRA and the supporting Aging Management Specification listed in Attachment 1. To verify
that the ISI Program was in place and was being implemented, the inspectors reviewed the
above program documents (ISI Plans), discussed various aspects of the program with
responsible Applicant personnel, and reviewed inspection plans and results as listed in
Attachment 1 of this report.
Also, periodic inspections of ISI activities are performed by NRC ISI inspectors during outages.
Recent inspections have found activities to be performed in accordance with program and plan
requirements.
During the review, the inspectors identified the following discrepancies when comparing the ISI
Plans with Section B3.20 and Table 3.1-1 of the McGuire and Catawba LRA:
Table 3.1-1 of the LRA lists the ISI Plan as an aging management program for loss of
material and cracking of pressurizer surge and spray nozzle thermal sleeves. The
McGuire and Catawba ISI Plans do not include these components.
Table 3.1-1 of the LRA lists the ISI Plan as an aging management program for cracking
and loss of material of the steam generator divider plates. The McGuire and Catawba
ISI plans do not include these components.
In both cases, the ISI plans were not the only aging management programs referenced. The
Applicant agreed with the discrepancies identified and stated that for the two components
identified, additional aging management reviews would be performed to determine if the
programs taken credit for (absent the ISI Plan) were adequate to manage aging of the
pressurizer spray and surge nozzle thermal sleeves and the steam generator divider plates.
In addition to the ASME Section XI Reactor Vessel Internals (RVI) Inspection that is conducted
once per 10 years, the Applicant identified future aging management inspection activities for the
Reactor Vessel Internals (see paragraph 4 below). Also, augmented inspections and
evaluations will be performed under the ISI program for a McGuire Unit 2 cast stainless steel
RC cold leg elbow to satisfy thermal embrittlement concerns. The Applicant will also include
aging management of Class 1 small bore piping (less than 4" NPS) in the ISI program using a
risk informed process. The risk informed ISI programs for McGuire include small bore Class 1
piping. The risk informed ISI programs for Catawba will be developed later.
The inspectors concluded that ISI activities are being conducted as described in the ISI Plans.
With the exception of the discrepancies for pressurizer spray and surge nozzle thermal sleeves
and the steam generator divider plates, the ISI program includes the systems and components
listed in the LRA, for which the LRA credited the ISI Program for aging management. Adequate
guidance had been provided to reasonably ensure that aging effects will be appropriately
managed.
2. Flow Accelerated Corrosion (FAC) Program
FAC is an aggressive material thinning of carbon steel piping materials resulting from high
energy steam/fluid flow. The FAC Program, an existing program, is credited in the LRA as an
3
aging management program for portions of the auxiliary feedwater (Catawba only), auxiliary
steam, boron recycle, feedwater, liquid radwaste (Catawba only), liquid waste recycle (McGuire
only), liquid waste monitor and disposal (McGuire only), steam generator blowdown recycle
(Catawba only), and turbine exhaust (McGuire only) systems.
The program is credited for managing the loss of material in carbon steel piping and
components and consists of monitoring the wall thickness of susceptible carbon steel piping
and components in various systems, and replacing affected piping prior to failure. In many
cases, FAC resistant materials are used for replacements. The program is consistent with the
guidelines of EPRI NSAC-202L, Recommendations for an Effective Flow-Accelerated Corrosion
Program. The program computer models susceptible systems and predicts wear rates. The
model is supplemented and updated with periodic thickness inspections of selected
components each cycle. Based on the model and inspection results, decisions are made on
pipe replacement schedules.
The FAC Program is controlled by Engineering Support Document (ESD), Flow Accelerated
Corrosion Program, Revision 3, and site specific programs and procedures as listed in
Attachment 1. The inspectors reviewed the applicable Aging Management Program as
described in the LRA and the supporting Aging Management Specification listed in Attachment
1. In addition to review of the above program implementing documents (ESD and site
procedures) and discussion of the program with responsible Applicant personnel, the inspectors
reviewed inspection plans and the FAC inspection outage reports, as listed in Attachment 1, for
past outages for each Unit to verify that the program was in place and being implemented. The
inspectors also reviewed the program implementation package detailed in Applicant
Specification CNS-1274.00-00-0016.
The inspectors concluded that the FAC Program was in place, had been implemented, and
included the systems and components identified in the LRA and should manage aging effects
as defined in the LRA. Adequate guidance had been provided to reasonably ensure that aging
effects will be appropriately managed.
3. Reactor Vessel Integrity Program
The RV Integrity Program, an existing program, is credited in the LRA as an aging management
program for managing reduction in fracture toughness for the RV. The program uses
toughness data from test of surveillance capsule specimens to analyze Pressurized Thermal
Shock (PTS), Upper Shelf Energy (USE), and to generate Pressure/Temperature (P/T) curves.
Additional monitoring of fluence received by the surveillance specimens, effective full power
years (EFPY), cavity dosimetry, and plant changes are used to perform these analyses. For
neutron embrittlement considerations, USE and PTS calculations are time limited aging
analyses per 10 CFR 54.3 that have been updated by the Applicant to cover the period of
extended license.
The Reactor Vessel Integrity Management activities are controlled by the ESD Reactor Vessel
Integrity Program, Applicant procedures, and engineering calculations, as listed in Attachment 1
below. The applicable requirements are detailed in the UFSARs, Technical Specifications, 10 CFR 50.61, and 10 CFR 50, Appendices G and H.
The inspectors reviewed the applicable Aging Management Program as described in the LRA
and the supporting Aging Management Specification listed in Attachment 1. In addition to
review of the above program implementing document (ESD) and discussion of the program with
4
responsible Applicant personnel, the inspectors reviewed plant specific data, including:
completed Maintenance Procedures (MPs) for removal of specimens; test results from capsule
specimens; Operator Aid Computer monitoring of EFPY; and calculation results for USE, PTS,
and P/T Curves, as listed in Attachment 1, to verify that the program was in place and being
implemented.
Although the ESD, Reactor Vessel Integrity Program had been issued and the various aspects
of the Program were in place and had been implemented, Applicant personnel indicated that
improvements in the program document are planned. The inspectors concluded that the
Reactor Vessel Integrity Program was in place, had been implemented, and was consistent with
the description in the LRA. The program should reasonably ensure that aging effects will be
appropriately managed.
4. Reactor Vessel Internals (RVI) Inspection
The RVI Inspection, is a new inspection that is credited in the LRA as an aging management
program for the RVIs. The program supplements the ASME ISI Plan and is credited for
managing cracking, reduction in fracture toughness, dimensional changes, and loss of pre-load
in stainless steel and cast stainless steel RVI components.
This is a new program to be implemented in the period of extended license. The inspections
will include visual and volumetric inspections. The inspections will be based on future
characterization of RVI aging effects developed from inspection of other nuclear plants,
inspection of Oconee internals, and activities of industry groups focused on internals aging
effects. McGuire Unit 1 will be DECs lead Westinghouse plant for RVI inspection, which is
planned for the 5th ISI interval. Based on the results of Oconee and McGuire Unit 1 inspections,
decisions will be made relative to inspection of McGuire Unit 2 and Catawba Units 1 and 2.
NRR Request for Additional Information (RAI) questions the validity of use of Oconee
inspection data because of different design plants (B&W versus Westinghouse). The Applicant
responded by stating that additional data is needed to properly evaluate the susceptible
locations for inspection and that Oconee results and results from other industry inspections will
provide some data prior to the McGuire and Catawba inspections. Although no inspections are
planned until the 5th McGuire ISI interval, in the period of extended operation, proposed ESD,
McGuire and Catawba Reactor Vessel Internals Aging Management Program, was currently
being drafted.
The inspectors reviewed the applicable Aging Management Program as described in the LRA
and the supporting Aging Management Specification listed in Attachment 1. In addition the
inspectors reviewed the above proposed ESD program implementing document and discussed
the planned program with responsible Applicant personnel.
The inspectors concluded that the planned inspections were in accordance with those identified
in the LRA.
5. Steam Generator Surveillance Program
The Steam Generator Surveillance Program, an existing program, is credited in the LRA as an
aging management program for the aging effects of cracking and loss of material in nickel-
based alloys 600 and 690 steam generator tubes and plugs. In addition, based on response to
NRR RAI 2.3.1-4, the program is also credited as an aging management program for cracking
and loss of material in alloy steel, stainless steel, and carbon steel tube supports. In addition to
5
Technical Specification requirements, inspections follow the recommendations of Electric
Power Research Institute (EPRI) Guidelines and Nuclear Energy Institute (NEI) 97-06, Steam
Generator Monitoring Guidelines. The program includes: periodic inspection of tubing and
plugs, secondary side inspections, tube integrity assessments, assessment of degradation
mechanisms, primary to secondary leakage monitoring, sludge lancing, maintenance and
repairs, and foreign material exclusion. The main program controls are the Steam Generator
Management Program, Revision 4, and associated procedures and plans.
The inspectors reviewed the applicable Aging Management Program as described in the LRA
and the supporting Aging Management Specification listed in Attachment 1. In addition to
review of the program implementing procedures and discussion of the program with responsible
Applicant personnel, the inspectors reviewed the most recently completed Steam Generator
Outage Reports for all four Units, as listed in Attachment 1. This review was to verify that the
Steam Generator Surveillance Program was in place and being implemented. The inspectors
also reviewed the completed Catawba LR program implementation package detailed in
Applicant Specification CNS-1274.00-00-0016.
The inspectors concluded that the Steam Generator Surveillance Program was in place, had
been implemented, and was consistent with the description detailed in the LRA. Activities in
place should reasonably ensure that aging effects will be appropriately managed.
6. Thimble Tube Inspection Program
The Thimble Tube Inspection Program, an existing program, is credited in the LRA as an aging
management program managing the effect of material loss due to fretting wear of thimble
tubes. The program was initiated in response to NRC Bulletin 88-09 and is controlled by site
calculations and implementing procedures as listed in Attachment 1.
The program consists of periodic eddy current (ECT) measurements of tube wall thickness and
engineering analysis to show that the wear rate will not result in violation of minimum wall
thickness through the life of the plant. The last measurements were taken in 2002 for McGuire
Unit 1,1993 for McGuire Unit 2, 1999 for Catawba Unit 1, and 1998 for Catawba Unit 2. Future
inspections are dictated based on wear rates.
The inspectors reviewed the applicable Aging Management Program as described in the LRA
and the supporting Aging Management Specification listed in Attachment 1. In addition to
review of the above program calculations and procedures and discussion of the program with
responsible Applicant personnel, the inspectors reviewed the completed inspection results for
the last inspections for each unit, including the engineering evaluation that determined the
acceptability of the thimble tubes. The inspectors also reviewed the completed McGuire and
Catawba LR program implementation packages detailed in Applicant Specifications MCC-
1274.00-00-0016 and CNS-1274.00-00-0016.
The inspectors concluded that the thimble tube inspection program had been implemented, was
consistent with the description in the LRA and should manage aging effects as defined in the
LRA.
7. Alloy 600 Aging Management Review
The Alloy 600 Aging Management Review is a new activity to ensure that nickel-based alloy
locations are identified and adequately inspected by other programs such as the ISI Plan, the
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Control Rod Drive Mechanism and Other Vessel Head Penetration Program, etc. A review will
be performed to locate all of the nickle-based alloy locations at McGuire and Catawba and
based on industry and Duke operating experience, inspection methods and frequency will be
adjusted as needed. Based on the LRA, the review will be completed following the issuance of
the renewed operating licenses and by the end of the initial license of McGuire Unit 1 and
Catawba Unit 1. Proposed Engineering Support Document (ESD), Alloy 600 Aging
Management Oconee, McGuire and Catawba Nuclear Stations, was being prepared at the time
of the inspection.
The inspectors reviewed the applicable Aging Management Program as described in the LRA
and the supporting Aging Management Specification listed in Attachment 1. In addition the
inspectors reviewed the above proposed ESD and discussed the planned activity with
responsible Applicant personnel. The alloy 600 program will accomplish the review to
determine the locations of alloy 600 and provide the details for inspection of each location.
Based on these discussions, much of the review has been completed and plans are to have the
Alloy 600 Aging Management Program issued by mid-2003. The inspectors concluded that the
planned inspections were in accordance with those identified in the LRA.
8. Control Rod Drive Mechanism (CRDM) Nozzle and Other Vessel Closure Penetration
Inspection Program
The Control Rod Drive Mechanism (CRDM) Nozzle and Other Vessel Closure Penetration
Inspection Program, a new program, is credited in the LRA as an aging management program
for primary water stress corrosion cracking (PWSCC) of high nickel alloy RV head penetrations
and is a complimentary program to the ISI Plan. For the remainder of this report, the program
is referred to as CRDM Nozzle Inspection Program. The Fluid Leak Management Program
and the Reactor Coolant System Operational Leakage Monitoring Program are used in
conjunction with the CRDM Nozzle Inspection Program to manage aging of reactor vessel head
A proposed document on PWSCC of Reactor Vessel Closure Head Penetrations to control the
inspection of CRDMs and other RV head penetrations was being prepared at the time of the
inspection.
The inspectors reviewed the applicable Aging Management Program as described in the LRA
and the supporting Aging Management Specification. In addition, the proposed ESD was
reviewed and the program was discussed with Applicant personnel. The Applicant indicated
that this program and the Alloy 600 Aging Management Review, detailed in paragraph 7 above,
would actually be part of the same program, the RV head penetrations being one of the
locations of nickle-based alloy.
The inspectors found that the LRA, Section B.3.9, was confusing relative to whether the
inspections detailed for CRDM penetrations were inspections currently being performed or
inspections to be performed in the future. The Applicant stated that the inspections detailed in
the LRA were new planned future inspections that had been identified prior to the most recent
industry cracking problems with CRDM nozzles, which are being handled under NRC Bulletins.
The Applicant further stated that, based on Oconee experience, DEC was aware of the
cracking issues prior to the issue of NRC Bulletin 2001-01 and took the Oconee experience into
account during preparation of LRA Section B.3.9. Based on review of the LRA and discussions
with Applicant personnel, planned inspections include both visual and volumetric inspections
and are to be performed after issuance of the renewed operating licenses and the end of the
7
initial license for McGuire Unit 1 and Catawba Unit 1. The Unit 1 results will provide leading
indicators for Unit 2 results at each station. The timing of the inspections may change based on
either DEC specific experience or industry experience. Visual inspections are to be performed
of all accessible CRDM type penetrations every refueling outage. A 100% visual inspection is
to be performed of the bare heads during each 10 year ISI interval. Volumetric inspections will
apply to the CRDM type penetrations and the head vent penetrations. The number of
penetrations inspected will be based on both Duke specific experience and industry experience.
After determining that the CRDM penetration inspections detailed in the LRA were identified
prior to all of the current industry inspections under NRC Bulletins 2001-01 and 2002-02, the
inspectors questioned the Applicant relative to additional planned inspections in response to
current CRDM cracking issues. This is also the subject of NRR RAI B.3.9-1. As noted above,
the Applicant pointed out that the Oconee CRDM cracking experience had been taken into
account in the LRA planned inspections. In addition, the licensee pointed out that in response
to NRC Bulletins and current industry cracking issues, bare metal inspections have been
performed for McGuire Unit 2 (March 2002) and Catawba Unit 1 (April 2002). The other two
units are to be inspected during the next refueling outages.
The NRC staff is currently reviewing issues associated with CRDM nozzle cracking and any
future regulatory actions that may be required as a result of those reviews will be addressed by
the staff in a separate regulatory action.
9. Chemistry Control Program
This is an existing mitigation program which is credited for managing the aging effects of loss of
material and/or cracking of components exposed to borated water, closed cooling water, fuel
oil, and treated water environments. The program manages the relevant conditions that lead to
the onset and propagation of loss of material and cracking which could result in loss of structure
or component intended function.
The inspectors reviewed the program documentation, discussed the program with responsible
station personnel, and reviewed documentation of periodic chemistry sampling and trend
information. The station Chemistry Manual and Chemistry Management Procedures specified
sampling scope, acceptance criteria, frequency, and corrective actions for sample results not
withing the acceptance criteria. The inspectors verified that the systems and parameters
presently sampled were consistent with the program description in the Application.
The inspectors concluded that the Applicant had conducted adequate historic reviews of plant
specific and industry experience information to determine aging effects. The Applicant had
provided adequate guidance to ensure aging effects will be appropriately managed. As
implemented, there is reasonable assurance that the intended function of the fluid systems will
be maintained through the period of extended operation.
10. Battery Rack Inspections
This is an existing activity which is credited with managing the loss of material that could impact
the battery racks intended function of structural support. Loss of material due to aging and
cracking are the potential aging effects. The inspectors reviewed the program activity
documentation, including completed annual inspection documentation, Technical Specification
requirements for periodic battery inspections, and field verified the present material condition of
the racks.
8
The inspectors concluded that the Applicant had conducted adequate historic reviews of plant
specific and industry experience information to determine aging effects. The Applicant had
provided adequate guidance to ensure aging effects will be appropriately managed. As
implemented, there is reasonable assurance that the intended function of the fluid systems will
be maintained through the period of extended operation.
11. Heat Exchanger Activities
These are performance monitoring and condition monitoring programs to manage the aging
effects on heat exchangers exposed to raw water. The activities manage two aging effects.
They manage the aging effects due to fouling which impact the component heat transfer
function. They also manage aging effects due to the loss of material that can impact the
pressure boundary function of the equipment. The scope of the heat exchanger activities
includes heat exchangers in different systems which are composed of different materials and
include existing, enhanced, and new programs.
The inspectors reviewed the program documentation, including completed procedures and
corrective actions for existing programs. The LRA program enhancements were identified and
documented in MCS-1274.00-00-0016 and CNS-1274.00-00-0016, License Renewal
Commitments rev. 0. The new program commitments were documented in the UFSAR LRA
Supplement, Chapter 18. New programs were required for inspection and cleaning of safety
related pump motor air handling unit heat exchangers and pump motor oil coolers.
The inspectors noted two examples in which the aging management program descriptions for
heat exchanger activities in the application were inconsistent with the existing and proposed
practice. The existing and proposed heat exchanger maintenance activity for cleaning of heat
exchanger tubes of the ECCS pump motor air handling units is to perform cleaning based on
results of a heat exchanger differential pressure test (performance based activity). The
program description in the application states the tubes will be cleaned periodically (prescription
activity). The aging management program description for the Containment Spray (NS) heat
exchangers states that eddy current testing will be performed on the perimeter tubes of each
NS heat exchanger at least every 5 years. The existing practice is to do this, however there is
no procedure or scheduling document that designates which tubes to be tested or the interval.
The model work order for this activity designates the performance frequency as required.
Performance is currently based on history, component engineer knowledge and budget. In
both cases, current practices provide adequate monitoring of the heat exchangers material
condition, however, the aging management program description is inconsistent with the existing
and proposed activities.
The inspectors concluded that the Applicant had conducted adequate historic reviews of plant
specific and industry experience information to determine aging effects. The Applicant had
provided adequate guidance to ensure aging effects will be appropriately managed. As
implemented, with the minor exception noted, there is reasonable assurance that the intended
function of the fluid systems will be maintained through the period of extended operation.
9
12. Preventive Maintenance Activities - Carbon Steel Coatings Inspections
The preventive maintenance activities credited as aging management programs include the
Condenser Circulating Water (RC) System Internal Coating Inspection and the Refueling Water
Storage Tank (FWST) Internal Coating Inspection. These are existing programs that manage
loss of material from carbon steel components by verifying the integrity of the internal protective
coating.
The RC internal coating inspection addressed two purposes for license renewal. One is to
manage the loss of material to the internal and external surfaces of the large diameter RC
intake and discharge piping. The other was to provide symptomatic evidence of the condition of
other piping systems in a similar underground environment. The RC coatings inspections are
conducted at a 5 year interval. Catawba is presently in the process of removal and re-
application of internal coating due to improper original application. The FWST internal coatings
inspection assures the continued presence of intact coating to preclude the loss of material to
the carbon steel tanks exposed to borated water. The McGuire tanks were last inspected in
1999 and some repairs were performed. The inspection frequency is 10 years. The Catawba
tanks are stainless steel tanks and aging effects are addressed by the Chemistry Control
Program and the Borated Water Systems Stainless Steel Inspection. The inspectors reviewed
the program and activity documentation including documentation of past inspections and
corrective actions.
The inspectors concluded that the Applicant had conducted adequate historic reviews of plant
specific and industry experience information to determine aging effects. The Applicant had
provided adequate guidance to ensure aging effects will be appropriately managed. As
implemented, there is reasonable assurance that the intended function of the fluid systems will
be maintained through the period of extended operation.
13. Sump Pump Systems Inspection
The Sump Pump Systems Inspection is a new activity to perform a one time inspection to
characterize any loss of material to the internal and external surfaces of a limited set of
mechanical components exposed to sump environments. It will detect the presence and extent
of the loss of material due to crevice, general, pitting and microbiological induced corrosion.
The activity will inspect components at each site located in the Diesel Generator Room Sump
Pump System. This sump was selected as representative because it included all materials and
environments experienced by the other sump systems in the license renewal scope. The
inspection will use a volumetric examination technique to measure the parameter of wall
thickness to assess material loss.
The inspectors reviewed the inspection program and discussed the program with the
engineering staff. The LRA identified the actions items and criteria for the Sump Pump
Systems inspection. The inspections will be conducted prior to the end of the original operating
license.
There was no documentation of historic or plant specific and industry experience information to
determine aging effects for this equipment. The purpose of the inspection is to assess potential
aging effects. The Applicant had provided adequate guidance to ensure aging effects will be
appropriately assessed and managed. When implemented, there is reasonable assurance that
the intended function of the fluid systems will be maintained through the period of extended
operation.
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14. Borated Water System Stainless Steel Inspection (BWSSSI)
The BWSSSI is a new activity to perform a one time inspection of stainless steel components
exposed to alternate wetting and drying of borated water, to characterize the potential aging
that may be occurring. The scope of the activity will focus on the Containment Spray (NS)
system but the results will also apply to subject components in the Refueling Water System.
The program description in the application specifically identifies 12 subject locations in the NS
system and states that one location at each station will be inspected and the results will be
applied to the relevant portions of the NS and Refueling Water System.
The inspectors reviewed the program documentation in the application, reviewed the draft
implementation plan for this program, and discussed the program with the engineering staff.
These one time inspections will be conducted prior to the end of the initial operating license for
each station.
The inspectors noted an item in the application which was unclear. The Refueling Water
System Aging Management Review, Table 3.2-6, credits the BWSSSI as an aging
management activity for the Refueling Water Storage Tanks at Catawba to assess the aging
effects of cracking and loss of material. The aging management program discussion for
BWSSSI (Section B.3.4) does not specifically state the tank is included and does not identify a
population of components in the Refueling Water System which are included as an alternate
wetting and drying borated water environment.
There was no documented information available for historic reviews regarding the aging effects
due to long term exposure of stainless steel to an alternate wetting and drying borated water
environment. The inspectors concluded that when these inspections are implemented, there is
reasonable assurance that the intended function of the fluid systems will be maintained through
the period of extended operation.
15. Selective Leaching Inspection
This is a new program being developed to perform a one-time inspection to characterize any
loss of material due to selective leaching of system components exposed to raw water
environments. Selective leaching (a form of galvanic corrosion) is the dissolution of one metal
in an alloy at the metal surface which leaves a weakened network of corrosion products that are
revealed by a Brinnell Hardness check or equivalent as reduction in material hardness.
Uncertainty exists as to whether long term exposure to raw water environments could cause
loss of material due to selective leaching in brass and cast iron components such that they may
lose their pressure boundary function in the period of extended operation. This one-time
inspection will examine brass and cast iron components exposed to raw water to detect the
presence and extent of any loss of material due to selective leaching.
The program will monitor the hardness of the wetted surface of cast iron pump casings and
brass valve bodies. The program will perform a Brinnell Hardness Test or equivalent on one
cast iron pump casing in the exterior fire protection system at each site. The Brinnell Hardness
Test or an equivalent test is most easily performed on a pump casing and will be indicative of all
cast iron components. The exterior fire protection system contains a raw water environment
that is susceptible to selective leaching and will be bounding for the other environments in the
other systems. The selective leaching inspection will also test a sample of brass valves at each
site in the interior fire protection system. Valves selected for inspection should be continuously
11
exposed to stagnant or low flow raw water environments. If no parameters are known that
would distinguish the susceptible locations at each site, a select set of susceptible locations will
be examined based on accessibility, operational, and radiological concerns. The results of this
inspection will be applied to the brass components exposed to raw water environments in other
systems. For McGuire, this new inspection will be completed following issuance of renewed
operating licenses for McGuire Nuclear Station and by June 12, 2021 (the end of the initial
license of McGuire Unit 1). For Catawba, this new inspection will be completed following
issuance of renewed operating licenses for Catawba Nuclear Station and by December 6, 2024
(the end of the initial license of Catawba Unit 1).
The inspectors reviewed the program documentation and discussed the program with the
engineering staff. The inspectors concluded that the Applicant had conducted adequate
historic reviews of plant specific and industry experience information to determine aging effects.
The Applicant had provided adequate guidance to ensure the aging effects will be appropriately
managed. When implemented, there is reasonable assurance that the intended function of the
cast iron pump casings and brass valve bodies in the exterior and interior fire protection
systems will be maintained through the period of extended operation.
16. Treated Water Systems Stainless Steel Inspection
This is a new program being developed to perform a one-time inspection to characterize any
loss of material or cracking of stainless steel components resulting from exposure to
unmonitored treated water environments. An unmonitored treated water environment is one
that may contain conditions that can concentrate existing levels of contaminants or that may
simply start with a higher level of contaminants than those systems routinely monitored by the
chemistry control program. Examples of contaminants are halogens, sulfates, and dissolved
oxygen. Uncertainty exists as to whether exposure of stainless steel components located in an
unmonitored treated water environment could lead to loss of material or cracking such that
they may lose their pressure boundary function in the period of extended operation. This
activity will inspect stainless steel components to detect the presence and extent of any loss of
material or cracking.
The treated water systems stainless steel Inspection at McGuire will inspect stainless steel
components, welds, and heat affected zones, as applicable, in the McGuire nuclear solid waste
disposal system. The McGuire nuclear solid waste disposal system components within the
scope of license renewal are a mixture of unmonitored, treated water and spent resins sluiced
from demineralizers in various systems. The environment is expected to contain contaminants
in excess of the limits below which a concern would not exist for cracking and loss of material in
stainless steel. A concentration of any contaminants present would occur in areas of low flow
or stagnant conditions. As a result, inspections will be performed in stagnant and low flow lines
around the spent resin storage tanks using volumetric techniques. In addition to the volumetric
examination, a visual examination of the interior of a valve will be conducted to determine the
presence of pitting corrosion. The treated water systems stainless steel inspection at Catawba
will inspect stainless steel components, welds, and heat affected zones, as applicable, in the
drinking water system. The drinking water system receives water from the local municipality
that has contaminants in excess of limits below which a concern would not exist for cracking
and loss of material in stainless steel. Because of the higher starting level of contaminants, the
environment in the drinking water system is more likely to lead to cracking or loss of material if
it is occurring and bounds the environments of the containment valve injection water and solid
radwaste systems. In addition to the volumetric examination, a visual examination of the
interior of a valve will be conducted to determine the presence of pitting corrosion. Therefore,
12
the inspection results will serve as a leading indicator and can be applied to the containment
valve injection water and solid radwaste systems. For McGuire, this new inspection will be
completed following issuance of renewed operating licenses for McGuire Nuclear Station and
by June 12, 2021 (the end of the initial license of McGuire Unit 1). For Catawba, this new
inspection will be completed following issuance of renewed operating licenses for Catawba
Nuclear Station and by December 6, 2024 (the end of the initial license of Catawba Unit 1).
The inspectors reviewed the program documentation and discussed the program with the
engineering staff. The inspectors concluded that the Applicant had conducted adequate
historic reviews of plant specific and industry experience information to determine aging effects.
The Applicant had provided adequate guidance to ensure the aging effects will be appropriately
managed. When implemented, there is reasonable assurance that the intended function of the
stainless steel piping in the systems addressed in previous paragraph will be maintained
through the period of extended operation.
17. Waste Gas System Inspection
This is a new program being developed to perform a one-time inspection to characterize loss of
material and cracking, due to general, crevice, or pitting corrosion in carbon steel, stainless
steel, and brass waste gas system components resulting from exposure to unmonitored treated
water and gas environments. Unmonitored treated water is condensation of the water vapor
contained in the waste gas stream and effluent from the recombiners and separators. The gas
environment is a combination of nitrogen, hydrogen, oxygen, and fission product gases.
Uncertainty exists as to whether exposure to these environments could cause loss of material
or cracking of the waste gas system components such that they may lose their pressure
boundary function in the period of extended operation. The waste gas system inspection will
use a volumetric technique to inspect four sets of material/environment combinations. As an
alternative, visual examination will be used should access to internal surfaces become
available.
(1) For the brass seal water control valves on the waste gas compressors at Catawba
exposed to unmonitored treated water, an inspection will be performed on one of the
two seal water control valves.
(2) For carbon steel components exposed to unmonitored treated water environments at
each site, inspections will be performed on the lower portions of decay tanks and
associated drain lines where condensate is likely to accumulate. One of eight possible
locations at each site will be examined.
(3) For stainless steel components exposed to unmonitored treated water environments
at each site, inspections will be performed on the seal water path of the waste gas
compressor. One of two possible locations at each site will be examined.
(4) For the carbon steel components exposed to a gas environment at each site, an
inspection will be performed on components within the scope of license renewal located
between the volume control tanks and the waste gas compressor phase separators.
For McGuire, this new inspection will be completed following issuance of renewed operating
licenses for McGuire Nuclear Station and by June 12, 2021 (the end of the initial license of
McGuire Unit 1). For Catawba, this new inspection will be completed following issuance of
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renewed operating licenses for Catawba Nuclear Station and by December 6, 2024 (the end of
the initial license of Catawba Unit 1).
The inspectors reviewed the program documentation and discussed the program with the
engineering staff. The inspectors concluded that the Applicant had conducted adequate
historic reviews of plant specific and industry experience information to determine aging effects.
The Applicant had provided adequate guidance to ensure the aging effects will be appropriately
managed. When implemented, there is reasonable assurance that the intended function of the
carbon steel, stainless steel, or brass components in the waste gas system will be maintained
through the period of extended operation.
18. Liquid Waste System Inspection
This is a new program being developed to perform a one-time inspection to characterize any
loss of material and cracking of system components within the scope of license renewal
exposed to unmonitored borated and treated water environments and raw water environments.
An unmonitored borated or treated water environment is one that may contain conditions that
can concentrate existing levels of contaminants and are not routinely monitored by the
chemistry control program. Uncertainty exists as to whether exposure to these environments
could lead to loss of material and cracking such that they may lose their pressure boundary
function in the period of extended operation. This activity will inspect system components in the
various environments to detect the presence and extent of any loss of material and cracking.
The liquid waste system Inspection is cast iron, stainless steel and carbon steel components
exposed to unmonitored treated and borated water environments or raw water environments in
the following McGuire and Catawba systems:
-
component cooling system (McGuire) - the portion of the component cooling system of
concern is the stainless steel waste evaporator package exposed to an unmonitored
treated water environment of the liquid waste recycle system;
-
liquid waste recycle system (McGuire) - stainless steel components exposed to an
unmonitored borated water environment;
-
liquid radwaste system (Catawba) - stainless steel components exposed to an
unmonitored borated water, unmonitored treated water, or a raw water environment;
carbon steel and cast iron components exposed to a raw water environment.
The liquid waste system inspection will use a volumetric technique to inspect the
material/environment combinations located in each system listed above. As an alternative,
visual examination will be used should access to internal surfaces become available. For
McGuire, this new inspection will be completed following issuance of renewed operating
licenses for McGuire Nuclear Station and by June 12, 2021 (the end of the initial license of
McGuire Unit 1). For Catawba, this new inspection will be completed following issuance of
renewed operating licenses for Catawba Nuclear Station and by December 6, 2024 (the end of
the initial license of Catawba Unit 1).
The inspectors reviewed the program documentation and discussed the program with the
engineering staff. The inspectors concluded that the Applicant had conducted adequate
historic reviews of plant specific and industry experience information to determine aging effects.
The Applicant had provided adequate guidance to ensure the aging effects will be appropriately
14
managed. When implemented, there is reasonable assurance that the intended function of the
cast iron, stainless steel and carbon steel components in the systems addressed in previous
paragraph will be maintained through the period of extended operation.
19. Fluid Leak Management Program
The Applicant credited the existing Fluid Leak Management Program for aging caused by leaks
from systems containing boric acid. This program, however, serves to manage all types of
leaks via identification, tracking and evaluations. Personnel who identify leaks by various
means are required to enter the information into the tracking system and notify appropriate
personnel. Other programs such as the chemistry program and service water inspections are
credited for aging management for non-boric acid fluid systems. The Applicant also plans to
enhance the Inspection Program for Civil Engineering Structures and Components to
periodically observe for affects of aging from various leaks on mechanical components such as
piping and valves as well as structures. In addition, the Applicant credited the system pressure
testing process, the reactor coolant system Mode 3 walkdowns, and non-licensed operator
observations for this program. The inspectors reviewed the Applicants procedures/directives
and specifications, reviewed selected proposed procedure changes, reviewed the leakage
program data base, and held discussions with Applicant personnel including program owners at
both sites.
In general, the program was thorough and viable. The inspectors noted, at Catawba, that a
new program had been recently developed (Catawba Nuclear Site Directive 3.11.4, Site
Materiel Condition) which would result in coordinated and documented observations for aging
effects such as might be evidenced or caused by leaks. Therefore, this document would be an
appropriate reference for the Fluid Leak Management Program.
The inspectors noted that the procedures for evaluation of boric acid effects did not clearly
cover electrical components which the Applicant had credited. The inspectors also noted that
the recent revision to the civil structures program (EDM-410) to incorporate mechanical
components had not clearly covered acceptance criteria and personnel qualifications for
mechanical components. The Applicant stated that appropriate changes would be initiated to
address these observations.
The inspectors concluded that the Applicant had provided adequate guidance to assure that
aging effects will be appropriately managed via the Fluid Leak Management Program. When
implemented as described, there is reasonable assurance that intended functions of SSCs will
be maintained through the period of extended operation, in part, via this program.
20. Boraflex Monitoring Program (McGuire Only)
The Applicant credited the existing Boraflex Monitoring Program at McGuire for aging
management of the boraflex panels in the spent fuel storage racks. Catawba does not have
boraflex. The program monitors areal density of the panels and also monitors silica levels in
the spent fuel pool. The inspectors reviewed the Applicants procedures, reviewed recent areal
density test results, reviewed silica trends, reviewed a recent fuel pool calculation, and
discussed the program with Applicant personnel.
The inspectors noted that degradation will require changes to the fuel pool racks in the future,
however, when implemented as described, there is reasonable assurance that boraflex
degradation will be effectively managed through the period of extended operation.
15
21. Divider Barrier Seal Inspection and Testing Program
The Applicant credited the existing seal inspection program and associated procedures for
managing cracking and change in material properties of the divider barrier seal in each
containment and other elastomer pressure seals in containment. The program provides for
visual inspections of the seals and tensile testing of the divider barrier seal. The inspectors
reviewed applicable procedures and recent inspection and test results.
The inspectors concluded that the Applicant had provided adequate guidance to assure that
aging effects will be appropriately managed via the inspections. The program provides a
reasonable assurance that intended functions of the seals will be maintained through the period
of extended operation.
22. Galvanic Susceptibility Inspection
The Applicant plans to develop a one time inspection of a sample of locations where different
materials are connected, concentrating on carbon steel/stainless steel combinations in raw
water environments. The inspectors discussed with the responsible engineer the process by
which samples and inspection techniques will be selected. The inspectors concluded that the
Applicant had adequate plans to assure that aging effects due to galvanic corrosion will be
appropriately managed.
23. Ice Condenser Inspections
The Applicant credited the existing ice basket inspection and ice condenser engineering
inspection for managing aging of the ice condenser. The ice basket inspection consists of the
Technical Specification Surveillance inspection of two baskets in each azimuthal group and
basket inspections performed during refueling outages. The engineering inspection provides
for a visual inspection of structural components in the upper plenum, lower plenum, and top
deck blankets. The inspectors reviewed Applicant procedures and recent inspection results.
The inspectors concluded that the Applicant had provided adequate guidance to assure that
aging effects of the ice condenser will be appropriately managed via the inspections. The
inspections provide reasonable assurance that the intended functions of the ice condenser
affected by aging will be maintained through the period of extended operation.
24. Thermal Fatigue Management Program
The Applicant plans to utilize established procedures to monitor selected transients to confirm
that fatigue cycles do not exceed the maximum established by analyses for the 60 year period.
The inspectors reviewed the Applicants procedures for counting transients, reviewed
engineering documents, reviewed selected results of transient cycle counting, reviewed the
UFSAR, and held discussions with Applicant personnel. During the review, the inspectors
noted that all documents did not agree relative to which transients to count and the allowable
frequency for several transients. The Applicant stated that these problems were identified
during their review and PIPs had been generated to affect corrective action. The inspectors
also reviewed these PIPs. No transients were noted that were near the allowable frequency.
The inspectors concluded that the Applicant had provided adequate guidance to assure that
aging effects will be appropriately managed via the thermal fatigue management program.
When implemented as described, there is reasonable assurance that the intended functions of
16
systems and components relative to fatigue monitoring will be maintained through the period of
extended operation.
25. Reactor Coolant System (NC) Operational Leakage Monitoring Program
The Applicant credited the established program for detecting operational leakage in accordance
with Technical Specifications as a second line of defense against aging effects that may result
in leakage such as cracking or loss of mechanical closure. Leakage is monitored by a periodic
leakage calculation as well as measurement of Containment floor and equipment sump level,
measurement of condensate drain tank level change, and radioactivity monitoring of
containment and secondary systems. The inspectors reviewed Applicant procedures,
engineering guidance, and recent leakage calculation results.
The inspectors concluded that the NC Operational Leakage Monitoring Program contains
adequate guidance to provide an additional line of defense for aging caused leakage. The
program will provide additional assurance that the NC will remain functional during the period of
extended operation.
26. Service Water Piping Corrosion Program
The Applicant credited the existing Service Water Piping Corrosion Program for managing loss
of material in raw water systems. The program is credited for components in the Containment
Ventilation Cooling System, Exterior and Interior Fire Protection Systems, Nuclear Service
Water System (RN), and heat exchanger sub-components in the Containment Spray System,
Control Area Chilled Water System, and Diesel Generator Systems. Sample points have been
selected for ultrasonic testing in the RN system with various flow regimes. Corrosion rates are
trended for predictions of degradation. Additional stress analysis has been performed in some
cases to refine acceptance criteria and extend the life of some piping sections. In addition,
methods such as walkdowns, operator rounds, system testing, and maintenance activities serve
to identify through wall leaks. The Applicant plans to trend these leaks. The Applicant also
plans to remove an approximately 20-foot degraded portion of Unit 1, train A underground RN
piping at Catawba for evaluation. The RN system was considered the worst case indicator for
degradation. The Catawba station has been susceptible to general corrosion and
microbiologically-influenced corrosion (MIC) due to raw lake water chemistry. The Applicant
plans to add sample points in the fire protection system at Catawba. Historically, Catawba
experienced significant fouling in non-safety related systems and in the supply to the Auxiliary
Feedwater System (AFW), discovered by observations of decreased flows. Additional
management was applied to raw water systems via a special project. This resulted in cleaning
of safety related portions of RN and replacement of non-safety related piping and selected
safety related piping including the AFW. This project is ongoing. The inspectors reviewed
associated engineering documents, reviewed procedures, reviewed ultrasonic test data basis,
and held discussions with responsible engineering personnel.
The inspectors concluded that the Applicant had provided adequate guidance to assure that
loss of material in raw water systems will be adequately managed via the Service Water Piping
Corrosion Program. The existing program with enhancements will provide reasonable
assurance that the intended functions of the systems will be maintained through the period of
extended operation.
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27. Standby Nuclear Service Water Pond Dam Inspection
The Applicant credited the existing Standby Nuclear Service Water Pond Dam Inspection
Program performed in accordance with site Technical Specifications for management of
cracking and loss of material. The inspection includes the upstream and downstream slopes,
the spillway overflow/outlet, the right and left abutments, and the toe of the dam. The program
requires visual examination for erosion, settlement, slope stability, seepage, drainage system
condition, integrity of rip-rap, and environmental conditions. In addition, the Applicant performs
piezometric readings and settlement monitoring via surveys. Piezometer readings are trended.
The inspectors reviewed applicable procedures and recent inspection results.
The inspectors concluded that the Applicant had provided adequate guidance to assure that
aging effects of the dams will be appropriately managed. The program provides reasonable
assurance that intended functions of the dams will be maintained through the period of
extended operation.
28. Standby Nuclear Service Water Pond Volume Program (Catawba only)
The Applicant has determined that the existing program for managing sedimentation is
appropriate to credit for the RN pond at Catawba only. The program consists of a topographic
survey of the pond at least every five years. Calculations of pond volume are performed based
on the survey. The inspectors reviewed the applicable procedure and recent survey results.
The inspectors concluded that the Applicant had provided adequate guidance to assure the
sedimentation aging effects will be appropriately managed via the inspections. The program
provides reasonable assurance that the intended function of the RN pond will be maintained
relative to sedimentation through the period of extended operation.
29. Pressurizer Spray Head Examination
Based on an NRC Request for Additional Information No. 2.3.2.7 in a letter dated January 23,
2002; the Applicant indicated that a one time examination of the pressurizer spray head would
be performed. The Applicant plans to inspect the unit with the most hours of operation. Details
of this examination are yet to be developed. The inspectors held discussions with responsible
engineering personnel concerning the intended planning for the examination and reviewed the
Applicants Oconee Station implementation tracking document for a similarly planned
examination. The inspectors concluded that the Applicant appears to have adequate planning
initiated to assure the inspection will be performed.
B. Review of Electrical Equipment Aging Management Programs
1. Non - EQ Insulated Cables and Connections Aging Management Program
This is a new AMP that is yet to be developed. The Environmental Qualification (EQ) program
is a well established program to ensure that electrical components, such as cables, that may be
subject to a harsh environment are properly constructed to perform their intended function even
when subject to that harsh environment. This new program will perform periodic visual
inspections of accessible, i.e. able to be approached and viewed easily, non-EQ cables which
are in the scope of license renewal. The inspections will look for cable and connection jacket
surface anomalies such as embrittlement, discoloration, cracking, or surface contamination.
Such jacket surface anomalies are precursors of insulation aging degradation and may indicate
18
adverse localized equipment environments caused by heat or radiation which can accelerate
aging of electrical cables. These visual inspections are to be performed at least once every ten
years. The initial inspections are to be performed following the issuance of the renewed
operating licenses and prior to the end of the current operating license for Unit 1 at each site.
The Applicant had yet to develop inspection procedures for this AMP.
2. Inaccessible Non-EQ Medium Voltage Cables Aging Management Program
This is also a new AMP that is yet to be developed. The purpose of the AMP is to perform a
test on inaccessible, e.g. in conduit or direct buried, non-EQ medium voltage cables that are
exposed to significant moisture simultaneously with significant voltage. Significant moisture is
defined as exposure to long term, such as a few years, continuous standing water. Significant
voltage is defined as being energized for more than twenty-five percent of the time. The cables
are to be periodically tested to provide an indication of the condition of the conductor insulation
and the ability of the cable to perform its intended function. The actual type of test has yet to
be determined. The initial tests are to be performed following the issuance of the renewed
operating licenses and prior to the end of the current operating license for unit 1 at each site.
The tests will be repeated with a 10 year frequency. The Applicant had yet to develop
inspection procedures for this AMP.
3. Applicant Response to Station Blackout Issue
On April 1, 2002 NRC issued a memo to the industry informing them of the NRC staff position
on the license renewal rule 10 CFR 54.4 as it relates to the Station Blackout (SBO) rule 10 CFR 50.63. The position holds that the plant system portion of the offsite power system that is used
to connect the plant to the off site power source should be included in the scope of license
renewal. This is necessary because this is the power path that would be used to recover from a
SBO. The Applicant is aware of the position and has agreed to adjust their programs to
address the position. For McGuire and Catawba this resulted in adding components as subject
to aging management review. Isolated-phase bus installed to connect the unit generator to the
Unit Main Power System and nonsegregated-phase bus installed to connect the auxiliary power
transformers to the Normal Auxiliary Power Systems are now in scope. Passive switchyard
commodities such as transmission conductors, switchyard bus, and high voltage insulators are
also in scope. The Applicant performed an aging management review on the additional
components and concluded that they will perform their function during the period of extended
operation and that no additional aging managemnt programs are needed for these components.
At both McGuire and Catawba inspectors reviewed plant drawings with Applicant engineers to
understand what additional electrical equipment will be brought into scope. The inspectors
examined accessible portions of the additional equipment with Applicant engineers and found it
in acceptable condition.
C. Review of Structural Aging Management Programs
1. Containment Inservice Inspection Plan -IWE
The Containment Inservice Inspection Plan - IWE is generally applicable to both the McGuire
and the Catawba Nuclear Stations, except as otherwise noted.
The inspection plan for McGuire, MC-1042-CISI-0001, McGuire Nuclear Station 1&2 First
Interval Containment Inservice Inspection Plan, Revision 2, 8/27/01 and for Catawba, CN-
19
1042-CISI-0001, Catawba Nuclear Station Containment Inservice Inspection Plan, Revision 3,
6/5/01 are generally developed to implement applicable requirements of 10 CFR 50.55a and
cover both IWE and IWF examinations. There are several relief requests submitted by Duke
and approved by the NRC. These relief requests are 98-GO-001, Request for relief from
performing visual, VT-3 examinations on seals and gaskets; 98-GO-002, Request for relief
from performing bolt torque or tension test for pressure retaining bolting; 98-GO-003, Request
for alternative to the visual, VT-1 and volumetric examination requirements for areas subject to
augmented examination, 98-GO-007, Request for alternative to the ultrasonic thickness
measurement requirement of IWE-2500(c)(4); and 00-GO-001, Request for alternative to the
VT-2 examination requirements of IWE-5240. The inspectors reviewed the inspection plans,
relief requests and approving SERs and found them satisfactory.
The inspectors reviewed the most recent McGuire containment inservice inspection results.
The inspections were performed for Unit 1 in 1999 and Unit 2 in 2002. In general, the
inspections found the containment structures acceptable. Enclosure 13.3 of PT/1/A/4200/044,
Procedure Process Record for Containment Structural Integrity Inspection of MNS Unit 1,
Revision 1, 2/15/99 indicated that in many places the moisture barriers were removed or are
going to be removed and cited that, in many places, the barriers are not needed. However, in
other places, the degraded moisture barriers were replaced or are going to be replaced. The
inspectors asked the Applicant why barriers are needed in some places and not others. The
Applicant replied that some of the moisture barriers were not required per design. During
construction, cork was placed between the steel containment and the concrete floors as
expansion spaces. Moisture barriers/sealing material was applied to prevent moisture intrusion.
In most the places, there was no trace of moisture at the time of inspection, therefore, the
moisture barriers are not necessary. The only places that moisture barriers are needed are the
containment wall and mat junction and near the fuel transfer canal. When the moisture
barrier/sealing material degraded, they cracked, shrunk, and separated from the containment.
In the process of separation, they took the containment coating with them and left the steel
containment bare with primer. The cork absorbed moisture when moisture was present and
caused the steel containment to rust. Problem Investigation Process (PIPs) C-95-01464 and C-
98-03567 documented this fact. The Applicant decided to remove the moisture barrier/sealing
material where it is not needed to prevent further damage to the steel containment. The
inspectors agreed with this approach.
During review of the Catawba containment inservice inspection records, the NRC inspectors
noted some very low thickness readings in the UT data, especially for Catawba Unit 2 (2EOC11
- Containment ISI Record, File #CN-1144.09, Record #005687). The IWE Code has a 10
percent below nominal allowance but Record #005678 contains many thickness readings lower
than the 10 percent allowable. The nominal thickness of the free standing steel containment is
0.75 inches and the lowest reading is 0.623 which is only 83.1% of the nominal thickness.
Inspection records showed that these readings were discovered during the 2EOC10
containment ISI. A PIP had been issued to investigate this concern.
PIP C-00-01555 was issued on 3/27/00 and indicated that 9 points had readings less than 90%
of the nominal thickness ranging from 89.7% to 83.1%. In according to IWE-3512.3, the
Applicant performed an engineering evaluation which declared these low readings acceptable.
The reason is that the low readings were all in the vicinity of welds and they were not caused by
degradation, rather by field grinding in preparation for field welding. Section 2.2.7 of
Specification No. CNS-1144.11-00-0001, Specification for Field Welding and Erection
Tolerances of Containment Vessel, Revision 7, 2/28/83 indicates that for 0.75 inch thick
cylindrical plate the acceptable minimum thickness could be as low as 0.650 inches. Even
20
though the two lowest readings of 0.623" and 0.640" are lower than the 0.650" allowed by the
field welding specification, PIP C-00-01555 concluded: Because the 2 thinnest readings of
0.623" and 0.640" are not significantly less than the allowable 0.650" thickness, it is not
warranted to perform a detailed calculation to confirm the acceptability of these locally thin
areas. The PIP further states: The condition of the containment vessel is considered
acceptable. In accordance with IWE-3122.4, these UT readings are not considered to be
indicative of degradation, and the conditions are considered non-structural and have no
adverse affect on the structural integrity of the containment. All areas examined during
2EOC10 are scheduled to be examined in accordance with IWE-2420(b) and (c), as required by
IWE 3122.4(b). The 2EOC11 UT record showed the exact same readings at the two thinnest
places to confirm the PIPs conclusion. The inspectors agreed with this conclusion.
2. Containment Leak Rate Testing Program
The Duke Containment Leak Rate Testing Program, as described in Section 4.26 of Appendix
B of the LRA and Section 5.52 of the Technical Specifications (TS), is established to fulfill the
10 CFR 50, Appendix J, Option B, Type A testing requirements. Section 5.5.2 of the TS also
specifies the maximum allowable containment leakage rate, La, to be 0.3% of containment air
weight per day. The acceptance criteria, as specified in Section 5.5.2.a of the TS, is less than
0.75La. As stated in the Containment Inservice Inspection Plan - IWE section of this report, the
Applicant has requested relief from performing certain inservice inspections and to use the
containment leak rate test to verify the integrity of seals and gaskets of Class MC pressure
retaining components and CC components (98-G-001), to verify the pressure retaining bolting
of Class MC pressure retaining components and Class CC components (98-GO-002), and to
satisfy the requirements of IWE-5221 following repairs, replacements, or modifications (00-GO-
001). Therefore, the containment ILRTs will assure not only the containment satisfies the
Appendix J requirements but also provide confirmation that these reliefs are validated.
Duke document PT/1/A/4200/001 A, Containment Integrated Leak Rate Test, Revision 19,
11/9/00 lists the step by step procedure to perform the ILRT. The inspectors reviewed the
results of the last ILRT of both plants and found they are all within the allowable. The McGuire
ILRT shows that Unit 1 was 0.1482 wt%/day and Unit 2 was 0.1469 wt%/day. Catawba unit 1
was 0.0965 wt%/day and Catawba Unit 2 was 0.0906 wt%/day. They are all well below the
acceptance criteria of 0.225 wt%/day (0.75 x 0.3 wt%/day). The inspectors concluded that the
McGuire and Catawba ILRT demonstrated that the containments of all four units are in good
operable condition.
3. Flood Barrier Inspection (McGuire)
The flood barrier inspection program is plant specific and is for McGuire only. This program
uses a model work order, WO 93045301. The flood barriers to be inspected are internal flood
barriers. They are:
a.
Doorway curbs around rooms 500, 501, 502, and 503 for deterioration and
damage. Initiate repair if necessary. Curbs are shown on Drawing (DWG) MC-
1221-01.
b.
Curbs at diesel generator room entrance doors at EL 739' for deterioration and
damage. Curbs are shown on DWG MC-1170-01.
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c.
Sealed walls and penetrations between Auxiliary Building and Interior and
Exterior Doghouses at or below EL 755 - 3".
d.
Electrical and mechanical piping sleeves to ensure penetrations would give
adequate flood protection. Penetrations are shown on DWGs MC-1220-215 and
MC-1220-147.
e.
Expansion joint along floor at Reactor Building wall for proper flood protection.
f.
Sealed wall penetrations along column line AA on Els 733 and 750 from column
line 40 to column line 56.
g.
Electrical/Mechanical pipe sleeves, cable tray openings, personnel access
openings, pipe trenches, and equipment/personnel access openings for
adequate flood protection, initiate repair W/R if necessary. Penetrations are
shown on DWGs MC-1220-97 and MC-1220-98.
The inspectors reviewed McGuire Drawings MC-1220-97, Auxiliary Building - Units 1&2 Flood
Protection Wall Elevation, Revision 14, 2/22/02 and MC-1220-98, Auxiliary Building - Units
1&2 Flood Protection Penetration Schedule & Details, Revision 20, 4/30/02 which depict the
locations of flood protection barriers listed in Item g. above.
The inspectors also reviewed WO 98208190 which reported the results of the April, 2000 flood
barrier inspection of McGuire Unit 1. Only three minor observances were found and work
requests (W/R) were generated to have them corrected or repaired. W/R 98124570 was
generated to caulk the leak around door PD-3; W/R 98124574 was generated to tighten door
801E against the seal to form a flood tight barrier; and W/R 98124557 was generated to repair
the torn boots around penetrations 40 & 42. All other flood barriers inspected were in good
condition. The inspectors agreed with the Applicants assessment.
4. Inspection Program for Civil Engineering Structures and Components
Engineering Directives Manual, EDM - 410, Inspection Program for Civil Engineering
Structures and Components, Revision 8, 2/27/02 specifies the purpose of the document is to
provide a program for monitoring and assessing civil engineering structures and components
and their condition in order to provide assurance that they are capable of performing their
intended functions. The scope of the program includes all structures and components that are
within both the license renewal and maintenance rules. Table 410-2 lists all structures
subjected to the structural inspection program for both McGuire and Catawba Nuclear Stations.
Section 410.4.7 lists the qualifications of inspectors and evaluators and Section 410.4.8 lists the
inspection frequency to be every 5 years.
The inspectors reviewed the reports of the most recent civil structural inspection performed for
McGuire and Catawba and found that, even though the steel containment and the reactor
building shell are not covered by this program, the Duke inspector did performed visual
inspection on them, as part of their respective inspections. The steel containment is under the
ISI IWE inspection and the reactor building shell is under the Technical Specification SR 3.6.16.3 visual inspection programs.
The McGuire civil structural inspection was performed in 1997 and documented in File No. MC-
1462.00, McGuire Nuclear Station Units 1&2 1997 Inspection report for Civil Engineering
22
Structures and Components per EDM -410, 2/15/98. Section 2 of the report concludes that the
structures and components are capable of performing their intended function, including the
protection or support of nuclear safety-related systems or components. The report further
concludes that several degraded conditions were minor and do not affect the integrity of the
subject structure. All findings have been addressed via PIPs or by station W/Rs. Table 1 of the
report documents the structures and components that are inspected. Table 2 of the report lists
all the findings of that inspection. All findings are classified as acceptable, however, PIPs and
W/Rs were issued to address the findings and Attachment II of the report lists the appropriate
resolutions.
At McGuire the inspectors walked down the intake structure which houses the non-safety
related CCW pumps and the fire protection pumps. The CCW pumps are located in open air
on the upper level while the fire protection pumps are housed in the lower cubicles. The
inspectors also walked down the Nuclear Service water Pond Dam. The inspectors agreed with
the Applicants assessment from the 1997 inspection report.
The Catawba Nuclear Station, Units 1&2 were inspected between March 1997 and October
1998 and the results were documented in File No. CN-1642.00, Catawba Nuclear Station,
Units 1&2 1997-1998 Inspection of Civil Engineering Structures and Components, 10/13/98.
The summary report was issued 10/26/98 to list all recommendations to change the frequencies
of certain inspections to less than the normal frequency of five years.
The inspection revealed some bare spots inside the containment and issued work order (WO)
98023443 to repair them. The inspection also found trench covers were damaged or crushed
and WOs. 98044583 and 98046481 were issued to repair them. Based on the degree of
damage to the concrete covers, the Duke inspector recommended that the frequency to inspect
the trench covers should be every two years rather than the normal frequency of every five
years.
At Catawba the inspectors walked down the Low Pressure Intake Structure where the fire
pumps are located. The intake structure also houses the CCW (non-safety) pumps. The
inspectors visually inspected both the upper and lower level of the structure and found that the
structure itself is in good condition, however, there are some pipes that are in bad rusted
conditions. The inspectors also walked down the safety-related Nuclear Service Water Pump
House and found the above water portion of the trash rack and the structure is in good
condition. The Applicant informed the inspectors that the underwater inspection covers the
underwater portion of the trash racks and the structures.
5. Underwater Inspection of Nuclear Service Water Structures
The underwater inspection of nuclear service water structures for both McGuire and Catawba is
contained in a model work order 95065949, PM-Underwater Inspection of Raw Water
Structures, 8/22/95. The WO lists all steps necessary to perform the inspection.
The latest McGuire inspection was performed in June, 1999 by Eason Diving & Marine
Contractors, Inc. of Charleston, SC. The inspection covers the Low Level Intake Structure, the
Standby Nuclear Service Water (SNSW) Intake Structure, the SNSW Discharge Structure, the
CCW Intake Structure Wing Wall and Units 1&2 Discharge Structure as described in a letter
from the contractor dated 6/18/99. In the letter, the contractor describes that there was no
discrepancies found in all the underwater structures inspected, except some silt deposits. The
inspectors also reviewed reports from previous underwater inspections, by the same contractor,
23
and found there was a trash rack replaced for the Standby Nuclear Service Water Pond Intake
Structure (WO 93033689) in 1993.
The latest Catawba underwater structure inspection was performed in April 2002 by Eason
Diving and Marine Construction, Inc. of Charleston, SC. The inspection covers the Nuclear
Service Water (NSW) Pond Intake Structure B train, NSW Overflow Structure (Inlet and
Outlet), NSW Lake Intake Structure, NSW Pump and Valve Room B train, NSW Dam, and
Short and Long Leg Discharge Structure to NSW Pond. The inspection report, written and
submitted to Duke on May 10, 2002 did not find any deficiencies. The only findings were some
silt deposit and several of the stainless trash rack anchor bolts were loose but still performing
their intended function. The inspectors agreed that the underwater part of the structures, both
McGuire and Catawba, are in good condition.
6. Technical Specification SR 3.6.16.3 Visual Inspection
The surveillance requirements of Section SR 3.6.16.3 of the Technical Specification (TS) of
both McGuire and Catawba states Verify reactor building structural integrity by performing a
visual inspection of the exposed interior and exterior surfaces of the reactor building. Along
with the Civil Engineering Structures and Components Inspection, this is the inspection to
assure the operability of the reactor building. The frequency of this inspection is three times
every 10 years, coinciding with the containment inservice inspection plan frequency.
Duke document PT/2/A/4200/078, Containment Structural Integrity Inspection, for Catawba
Unit 2 specifies that the purpose of the inspection is to verify by general visual inspection the
structural integrity of the steel containment vessel and reactor shield building in accordance
with 10CFR50, Appendix J, .... The 1998 inspection was documented in PT/2/A/4200/078, and
page 19 of Enclosure 13.3 indicated four abnormalities (hair line crack on the exterior surface of
the reactor building, minor rust staining on top of the parapet wall, etc.), but all were considered
acceptable.
PT/2/A/4200/044 documents the 2000 McGuire Unit 2 Structural Integrity Inspection results.
Pages 36 - 45 of Enclosure 13.3 documents the inspection findings of the reactor shield
building during the 1999-2000 inspection. On page 36, the document indicates that brown
staining was seen at ceiling expansion joints on the exterior wall. The inspector decided they
were old stains and were not active at the time of the inspection. The condition is acceptable.
Acceptable minor degradations were also documented on Pages 37, 40, 41, 42,, 43, 44, 45.
Enclosure 13.3 of PT/1/A/4200/044 documented the results of the Structural Integrity Inspection
of McGuire Unit 1. Pages 34 & 35 of the Enclosure indicated that leaching was observed in
several places on the exterior surface of the Unit 1 Reactor Shield Building and the Duke
inspector determined that the conditions were acceptable.
The McGuire Units 1&2 reactor building was visually inspected during the 1997 Civil
Engineering Structures and Components Inspection. The final report, entitled, McGuire
Nuclear Station Units 1&2 1997 Inspection Report for Civil Engineering Structures and
Components Per EDM-410 Maintenance Rule Program was issued on 2/15/98. Attachment
- 1 of the report lists the building parts that were inspected. Section 1 of Attachment #1
documents the exterior surface of the reactor building shield wall, Section 2 documents the
containment vessel exterior and the reactor building shield wall interior, and Section 3
documents the containment vessel interior. Attachment II lists all the findings for each section.
For section 1, the reactor building exterior, most findings are minor and need no actions. In
24
area 1.8 - reactor building dome, work order (WO) 97012413 was generated to repair
coating/sealants in a parapet area. The inspectors concluded, in the report cover letter, dated
2/15/98, that none of the findings were judged to adversely affect structural integrity and were
classified as acceptable findings.
The 1997-1998 Catawba Inspection of Civil Engineering Structures and Components also
included visual inspections of the reactor buildings of both units. As documented in File No.
CN-1462.00, dated 10/13/98, Section 7.1 discusses the reactor building inspection but only
addressed the results of the reactor building internals. The reactor building shield walls were
not addressed. However, the inspector made some recommendations to change the
frequencies to monitor certain structures documented in a memorandum dated 10/26/98. The
memorandum also concluded that all the findings were considered to be acceptable. The NRC
inspectors agreed with these conclusions.
7. Crane Inspection Program
The Applicant plans to utilize the existing crane inspection program with modifications. The
program is intended to manage loss of material, which has been identified as an aging effect for
crane rails and girders during the period of extended operation. The program detects aging
effects through visual examination of the crane rails and girders. Inspection procedures for
cranes and hoists are identified in plant procedures and are in accordance with industry
standards, plant experience, and other industry experience. Each crane and hoist is subject to
several inspections. Prior to initial use, all new, reinstalled, altered, modified, extensively
repaired, and newly erected cranes are inspected and the results of the inspections are
documented. Additional inspections are conducted prior to crane operation, quarterly, and/or
annually depending on the specific crane or hoist. The inspection frequencies for the cranes
and hoists are based on the guidance provided by ANSI B30.2.0 and ANSI B30.16. The
inspectors reviewed the License Renewal Application, Appendix B, which described program
requirements, associated procedures, engineering documents, and recent evaluation results.
In addition, the inspectors held discussions with site and corporate program owners in this area
and walked down the fuel handling and spent fuel pool cranes to assess existing conditions.
The inspectors concluded that the Applicant had conducted adequate historic reviews of plant
specific and industry experience information to determine aging effects. The Applicant had
established tracking items to assure implementation of proposed actions to support license
renewal and some procedures already had modifications outlined. In addition, the inspectors
concluded that the Applicant had provided adequate guidance to ensure that the aging effects
will be appropriately managed. When implemented as described, there is reasonable
assurance that the intended functions of the polar, fuel handling, and spent fuel pool cranes will
be maintained through the period of extended operation.
D. Fire Protection
During the previous Scoping and Screening inspection the inspectors observed that the license
renewal and plant design basis documents for McGuire and Catawba had differing, conflicting,
and sometimes vague definitions of the QA Condition 3 fire protection (FP) program, and the
basis for license renewal scoping of FP equipment was not clear. Therefore the inspectors
were unable to confirm that scoping and screening for FP systems and components had been
performed successfully in accordance with 10 CFR 54.4(a)(3). A number of RAIs had been
issued from NRR to Duke to resolve concerns pertaining to how much of the plant fire
protection equipment should be in scope for license renewal. As of the date of this inspection
25
the Applicant was still in disagreement with the NRR staff over how much of the plant fire
protection equipment should be in scope of license renewal.
During this inspection inspectors reviewed the past results of tests on fire protection equipment.
The LRA credits the Fire Protection Program to manage loss of material and fouling of fire
protection equipment such as sprinklers, fire hydrant piping loops and valves, and hose rack
valves. The Fire Protection Program credits existing plant surveillance procedures required by
Selected licensee Commitments (SLC) involving visual inspections to verify sprinkler condition
and performing flow tests and flushes of the system to verify that blockage of flow will not
prevent system function.
At McGuire inspectors reviewed the records of the following completed tests.
PT/1/A/4700/42 Tech Spec Fire Hose Station Valve Operability Test completed 3/3-4/01.
PT/2/A/4700/43 SLC Fire Hose Station Valve Operability Test completed 12/22-23/00.
MP/0/B/7700/051 Reactor Building Fire Hose Station Inspection completed for unit 2 3/12/02.
PT/0/A/4400/001E Fire Hydrant Operability Test and System Flush completed 2/8/02.
PT/2/A/4400/001L Fire Protection Containment Header Test completed 4/9/01.
PT/0/A/4400/001T Fire Protection System Auxiliary Building Flush and Flow Test completed
4/2/02.
At Catawba inspectors reviewed the records of the following completed tests.
PT/0/A/4400/001E Fire Hydrant Operability Test completed 7/1/02.
PT/0/A/4400/01S RY Fire Protection Flow Periodic Test completed 8/11/97.
PT/0/A/4400/001X Essential Area Sprinkler Alarm System Test completed 6/19/02.
PT/0/A/4400/01J Spray Valve Sprinkler System Periodic Test portions completed 10/16/01 and
5/11/02.
PT/0/A/4400/01W Valve Operability and Water Availability Visual Inspection completed 8/16/00.
The records reviewed appeared acceptable. At Catawba, the inspectors noted that the RY Fire
Protection Flow Periodic Test had exceeded its three year test frequency. Applicant engineers
explained that the test could not be completed when last attempted in April 2001 due to a
buried valve that would not completely close. The inspectors reviewed two PIPs, C-01-01612
and C-01-01954 which documented the problem. The temporary solution has been to tag the
valve open, its normal position, and declare the fire protection system Operable But Degraded
until the valve can be repaired.
At Catawba, the inspectors noted that the test results from the Valve Operability and Water
Availability Visual Inspection contained numerous entries remarking on dirty water and debris
coming out of hose stations during flushes. Applicant engineers explained that fire water
comes directly from the lake and contains much silt and debris so it is a continual challenge to
keep the system flushed.
A second part of the fire protection AMP is the Fire Barrier Inspections program which credits
existing plant surveillance procedures. Those procedures are required by SLC 16.9.5 and
periodically require visual inspection of fire barriers to detect loss of material due to corrosion of
fire doors, cracking of fire walls, and cracking/delamination and separation of fire barrier
penetration seals. The inspectors reviewed records of recent performance of the surveillance
procedures to determine success of the program.
26
At McGuire inspectors reviewed the following records.
PT/0/A/4250/004 Periodic Inspection of Fire Barriers
Fire Barrier Penetrations Seal Inspection Checklist unit 2 completed 1/7-21/02
Fire Barrier Penetrations Seal Inspection Checklist unit 1 completed 10/8-11/6/01
Fire Door Inspection completed 3/26-4/8/02
The records reviewed appeared acceptable. Subsequently during this inspection, inspectors
learned that the Applicant discovered at McGuire on 7/15/02 that a portion of this PT had
apparently not been performed since 1990. PIP number M-02-03466 was initiated by the
Applicant. It states that in 1990 one large surveillance was changed to be implemented by
several model work orders but no model work order was created for the portion that requires a
visual inspection of the exposed surfaces of each required fire rated assembly on a 18 month
frequency, thus the inspection was not being performed.
At Catawba on 7/17/2002, the Applicant discovered that workers were not completing
procedure documentation for fire door inspections and fire boundary inspections. The
inspectors reviewed PIP number C-02-03943 which documented the problem. The inspectors
were shown computerized work order records for performance of portions of test
PT/0/A/4200/048 Periodic Inspection of Fire Barriers and Related Structures. The work orders
indicated that portions of the test were performed 7/19/01, 9/13/01, 12/12/01, and 3/5/02. The
inspectors agreed with the PIP which states that the tests were being done by Applicant staff
but were not being documented as required on the PT forms.
The inspectors concluded that the Applicant was implementing periodic surveillances for fire
protection equipment. However there have been instances of failure to perform tests and
failure to properly document tests.
E. Visual Observations of Plant Equipment
During the inspection, the inspectors performed walkdown inspections of plant systems,
structures, and components (SSCs), and electrical cable to observe material condition and
inspect for aging conditions that might not previously have been recognized and addressed in
the LRA. Portions of the following systems and structures were included:
McGuire and Catawba
Component Cooling (KC)
Main Steam (SM) including PORVs and Safeties
Auxiliary Feedwater (CA)
Main Steam Auxiliary Equipment (SA) Steam Generator Blowdown (BB)
Fuel Pit Cooling (FC)
Turbine Exhaust (TE)
Feedwater Turbine Hydraulic Oil (LP) Spent Fuel Cooling (KF)
Main Steam Vent to Atmosphere (SV) Feedwater Turbine Lube Oil (LF)
Containment Spray System (NS) Chemical & Volume Control System (NV)
Nuclear Service Water System (RN) Recirculated Cooling Water (KR)
Residual Heat Removal System (ND) Safety Injection System (NI)
Standby Nuclear Service Water Pond Dam
Service Water Intake Structures
In addition, during recent refueling outages, NRC inspectors performed visual inspections of
equipment inside the McGuire Unit 2 and Catawba Unit 1 containments to assess material
27
condition and inspect for aging mechanisms that might not have been accounted for in the LRA.
The inspection details for McGuire Unit 2 are documented in NRC Inspection Report 50-
369,370/2002-05. On May 7, 2002, during the Catawba Unit 1 refueling outage, an inspector
performed walkdown inspections of accessible portions of plant systems, components,
structures and electrical cable inside of containment. Material condition of equipment and
structures inside of Unit 1 Containment was generally good and no aging mechanisms were
identified that were not accounted for the in Applicants License Renewal Program. The
inspector noted a minor buildup of boric acid residue and rust on some cable armor which was
followed up by the licensee and corrected. The following is a partial list of Catawba Unit 1
components and structures observed:
Cold Leg Accumulators, valves, and piping
Safety Injection lines and valves
AFW lines and penetrations
Reactor Coolant pumps base and supports
RC loop stop valves and check valves
Main Feedwater lines
Inner containment liner and coatings
biological wall structure
top of Pressurizer
Pressurizer spray valve piping
RCP seal piping
The observations of general material conditions included: inspection of piping components for
evidence of leaks or corrosion, inspection of coatings (piping, tanks, and structural
components), and inspection of electrical cable for indications of deterioration.
In general, the material condition at McGuire and Catawba was very good and no aging
management issues were identified. Coatings were in good condition and only a few minor
leaks were noted. In general, the minor leaks were captured in the Leak Management Program.
At McGuire, inspectors observed one leak on a containment spray pump that was not included
in the Leak Management Program. Engineers promptly initiated a work request to address the
issue. The inspectors did note the following material conditions that were in contrast to the very
good overall conditions:
The coatings on KC System supply and return piping to the McGuire Units 1 and 2 train B RHR
heat exchangers had deteriorated due to condensation. This deterioration of coatings and
continuous condensation had resulted in areas of surface rust. The condition appeared to be
superficial and thus was not considered to be an operability concern. However, the condition
was in contrast to the good condition of the remainder of the KC System piping in the McGuire
and Catawba Units.
Poor housekeeping conditions were noted on the bottom floors of the Catawba Units 1 and 2
interior Main Steam Doghouses.
During the tour of the lower levels of the RN pump house at Catawba, some external corrosion
was observed on RN piping which exceeded that observed in other portions of the plant.
Corrosion areas were observed which exhibited flaking and some depth. These corrosion
areas were aggravated by an improperly routed pump seal leakoff line which resulted in water
constantly splashing onto the piping. During the inspection, the Applicant cleaned the worst
28
areas observed and conducted ultrasonic wall thickness measurements. In each case the wall
thickness was well above design minimum thickness. Further review of plant records disclosed
that the Applicant had identified the same condition as potentially significant corrosion in
December, 1998 on a PIP No. C-98-04719. Also, in August, 2000; the Applicant had identified
a pump leak that was causing corrosion that needed to be corrected (PIP No. C-00-04315).
The Applicant stated that past corrective actions did not meet management expectations in that
these problems had not been appropriately pursued in a timely manner.
At McGuire, the inspectors walked down the portion of the Recirculated Cooling Water System
which had been inadvertently left out of scope as described in NRC Inspection Report 50-369,
370/2002-005. The inspectors confirmed that the appropriate portion of this system had been
added to the LR scope and the application had been updated via letter dated June 25, 2002.
F. Future Implementation of License Renewal Commitments
During the inspection the Applicant made a presentation to the inspectors describing the plans
for future implementation of procedure changes and other license renewal commitments. The
Applicant provided draft specifications MCS-1274.00-00-0016, McGuire License Renewal
Commitments, Revision 0 and CNS-1274.00-00-0016, Catawba License Renewal
Commitments, Revision 0 which are the documents controlling the implementation process. In
addition, completed or partially completed implementation packages for a number of Aging
Management Programs were provided for the inspectors review. Based on review of these
documents and discussions with Applicant personnel, the inspectors concluded that the
Applicant has a good implementation plan that, if completed as described, should ensure
proper implementation of license renewal commitments.
III.
Conclusions
The inspection concluded that the existing aging management programs are generally being
conducted as described in the License Renewal Application and that plans for new aging
management programs appear acceptable to manage plant aging.
The inspection concluded that the material condition of both the McGuire and Catawba plant is
very good with minor exceptions observed in isolated areas.
Exit Meeting Summary
The results of this inspection were discussed on July 26, 2002 with members of the Applicants
staff in an exit meeting open for public observation at the Duke Energy Corporation offices.
The Applicant acknowledged the findings presented and presented no dissenting comments.
During the exit meeting the inspectors asked the licensee whether any of the material examined
during the inspection should be considered proprietary. Applicant representatives replied that
no proprietary material was reviewed during the inspection.
29
ATTACHMENT 1
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Applicant
S. Chu, License Renewal Engineer
T. Cox, License Renewal Engineer
P. Colaianni, License Renewal Engineer
G. Comer, License Renewal Engineer
R. Gill, License Renewal Manager
M. Haze Hine, License Renewal Engineer
D. Keiser, License Renewal Engineer
R. Nader, License Renewal Engineer
G. Robison, License Renewal Manager
M. Semmler, License Renewal Engineer
T. Shiel, Duke Public Relations
NRC
R. Franovich, Licensing Project Manager, NRR
L. Reyes, Regional Administrator, RII
D. Roberts, Senior Resident Inspector, Catawba
S. Shaeffer, Senior Resident Inspector, McGuire
R. Taylor, Reactor Inspector
LIST OF DOCUMENTS REVIEWED
General License Renewal Documents
Application To Review the Operating Licenses for McGuire Nuclear Station Units 1 and 2 and
Catawba Nuclear station Units 1 and 2
McGuire Nuclear Station Updated Final Safety Analysis Report, Revision 13
Catawba Nuclear Station Updated Final Safety Analysis Report, Revision 8
Safety Evaluation Report Related to the License Renewal of Oconee Nuclear Station Units 1,2,
&3, NUREG 1723, March 2000
DPS, CNS, MCS-1274.00-00-005, License Renewal Aging Management Programs and
Activities, Revision 0
MCS-1274.00-00-0007, Structures and Structural Components Screening and Aging
Management Review for License Renewal, Revision 1
30
CNS-1274.00-00-0007, Structures and Structural Components Screening and Aging
Management Review for License Renewal, Revision 1
MCS-1274.00-00-0016, McGuire License Renewal Commitments, Revision 0
CNS-1274.00-00-0016, Catawba License Renewal Commitments, Revision 0
Existing Plant Procedures and Programs
General
Catawba Technical Specification Units 1&2, Amendment 189/182
McGuire Technical Specification Units 1&2, Amendment 184/166
Inservice Inspection
Third Interval Inservice Inspection Plan McGuire Nuclear Station Unit 1 - General Requirements
and Volume 1, Revision 0
Second Interval Inservice Inspection Plan McGuire Nuclear Station Units 1 & 2 - General
Requirements and Volume 1, Revision 3
Catawba Nuclear Station Second Ten-Year Interval Inservice Inspection Plan
Inservice Inspection Pressure Test Plan - McGuire Nuclear Station Unit 1 - Third Inspection
Interval
QAL-15, Inservice Inspection (ISI) Visual Examination, VT-2, Pressure Test, Revision 19
McGuire MP/0/A/7650/076, Controlling Procedure for System Pressure Testing of ASME Piping
Systems
Catawba Inservice Inspection Pressure Test Plan, Revision 3
Catawba MP/0/A/7650/088, Controlling Procedure for Systems Pressure Testing of ASME
Section XI Duke Class A, B, and C Systems and Components, Revision 025
Framatome Procedure 54-ISI-364-00, Remote Under Water In-Vessel Visual Inspection of
Reactor Pressure Vessels, Vessel Internals, and Components in Pressurized Water Reactors,
Revision 00
DPC Engineering Support Document, Flow Accelerated Corrosion Program, Revision 3
McGuire Unit 1 Piping Erosion Control Program, Revision 11
McGuire Unit 2 Piping Erosion Control Program, Revision 11
31
McGuire MP/0/B/7700/103, Erosion/Corrosion Component Inspection, Revision 001
Catawba SM/0/B/8530/001, Flow Accelerated Corrosion Component Inspection, Revision 003
Reactor Vessel Integrity Program
Engineering Support Document Reactor Vessel Integrity Program, Revision 4
McGuire MP/0/7150/033, Irradiation Capsule Removal From Lower Internals, Revision 003
McGuire MP/0/A/7150/115, Irradiation Capsule Off-Site Shipment, Revision 002
Catawba MP/0/A/7150/085, Irradiation Capsule Removal From the Reactor Lower Internals,
Revision 4
WCAP-14799, Analysis of Capsule W From the Duke Power Company McGuire Unit 2 Reactor
Vessel Radiation Surveillance Program
WCAP-14993, Analysis of Capsule Y From the Duke Power Company McGuire Unit 1 Reactor
Vessel Radiation Surveillance Program
WCAP-15449, Evaluation of Pressurized Thermal Shock for Catawba and McGuire Units 1 &2
@ 54EFPY
WCAP-15117, Analysis of Capsule V and the Dosimeters for Capsules U and X from Duke
Power Company Catawba Unit 1 Reactor Vessel Radiation Surveillance Program
WCAP-15243, Analysis of Capsule V and the Capsule Y Dosimeters from the Duke Energy
Catawba Unit 2 Reactor Vessel Radiation Surveillance Program
WCAP 15285, Catawba Unit 2 Heatup and Cooldown Curves for Normal Operation Using Code
Case N-460
WCAP-15448, Catawba Unit 1 Heatup and Cooldown Curves for Normal Operation Using Code
Case N-460 for 51 EFPY
MP/0/A/7150, Vessel Cavity Dosimetry Capsule Removal and Installation
Steam Generator Surveillance
Steam Generator Management Program, Revision 4
Thimble Tube Inspection Program
Calculation MCC-1553.0-00-0014, Incore Instrumentation Thimble Tube Wear Review, Revision
3
Calculation CAC-1553.03-00-007 Catawba 1 ECT Results and Actions Required, Revision 2
Calculation CAC-1553.03-00-0011, Catawba 2 ECT Results and Actions Required, Revision 3
32
PT/0/A/4550/034, Incore Detection Thimble Eddy Current Testing, Revision 002
NBE-715, Multifrequency Eddy Current Examination of Flux Thimble Tubing at Catawba and
McGuire Nuclear Stations, Revision 0
NBE-716, Evaluation of Eddy Current Data for Flux Thimble Tubing at Catawba and McGuire
Nuclear Stations, Revision 0
Chemistry
Catawba (CNS) Chemistry Management Procedure 3.4.17.1, Primary Chemistry, Rev. 43
Catawba (CNS) Chemistry Management Procedure 3.4.17.6, Closed Cooling (HVAC) Systems,
Rev.25
Catawba (CNS) Chemistry Management Procedure 3.4.17.2, Secondary Chemistry, Rev. 26
Catawba (CNS) Chemistry Management Procedure 3.4.17.5, Oil Systems, Rev 10
McGuire (MNS) Chemistry Manual Section 3.6, Closed Cooling Systems Analytical
Requirements and Corrective actions, Rev. 16
McGuire (MNS) Chemistry Manual Section 3.7, Chemistry Sample Collection and
Specifications, Rev. 8
McGuire (MNS) Chemistry Manual Section 3.4, Water Treatment Systems Analytical
Requirements and Corrective Actions, Rev. 13
McGuire (MNS) Chemistry Manual Section 3.2, Secondary Systems Analytical Requirements
and Corrective Actions, Rev. 23
McGuire (MNS) Chemistry Manual Section 3.1, Primary Analytical Requirements and Corrective
Actions, Rev. 12
Cranes
NSD 104 Nuclear Policy Manual - Materiel Condition/Housekeeping, Cleanliness/Foreign
Material
Duke Power Company Lifting Program, Rev. 5
MP/0/B/7650/007 Annual Inspection of Electric, Air Operated, and Hand Operated Hoists, Rev.
8
MP/0/A/7150/110 Control Rod Drive Mechanism (CRDM) Missile Shield Lifting Rig Inspection,
Rev. 2
MP/0/A/7150/111 NC Pump Motor Lifting Rig Inspection, Rev. 1
MP/0/A/7150/136 Inspection of Reactor Vessel Head and Internals Lift Rigs, Rev. 0
33
MP/0/A/7650/085 Load Path in Ice Condenser, Rev. 1
IP/0/B/3262/001 Overhead Cranes and Hoists Electrical Inspection and Maintenance,
Rev. 4
MP/0/A/7700/096 Quarterly/Annual Inspection and Servicing of Overhead and Gantry Cranes,
Rev. 6
MP/1/A/7650/060 Operation of Polar Crane in Unit 1 Upper Containment, Rev. 16
MP/2/A/7650/116 Operation of Polar Crane in Unit 2 Upper Containment, Rev. 9
Batteries
Catawba IP/O/A/3710/008, Vital Battery and Terminal Inspection, Rev.17
Catawba IP/O/A/3710/018, Maintenance Procedure for SAFT Model SBM 227-2 and SBM 277-
2 Battery and Rack, Rev. 24
Catawba IP/O/B/3710/022/, 250/125 VDC SSF Auxiliary power System (ETM) Batteries
Periodic Inspection, Rev. 22
McGuire IP/O/A/3061/007, GNB Vital Battery and Terminal Post Inspection, Rev. 13
McGuire IP/0/A/3061/004F, DG Battery (NiCAD) Maintenance, Rev. 0
Heat Exchangers
Catawba PT/2/A/4400/006A, NS Heat Exchanger 2A Heat Capacity Test, Rev. 24
Catawba MP/O/A/7650/056, Heat Exchanger Corrective Maintenance, Rev. 19
Calculation CNC-1223.13-00-0002, Acceptable RN Flow and Fouling in the NS Heat
Exchangers for One RN Pump Operation, Rev. 5
Catawba PT/1/A/4400/006B, NS Heat Exchanger 1B Heat Capacity Test, Rev. 24
Catawba Predefined work order 98374380 01, NS Heat Exchanger B, Remove/Restore
Channel End Bell Cover, dated 7/17/00
McGuire PT/1/A/4208/010A, NS 1A Heat Exchanger Heat Balance Test, Rev 25
McGuire MCM 1301.02.0058-002, SSS Diesel Vendor Manual, dated 8/2/01
McGuire MP/0/A/7450/040, Control Room Chiller Condenser Corrective Maintenance, Rev. 7
McGuire MP/0/A/7450/036, Chemical Cleaning of Service Water System Piping and Heat
Exchanger, Rev 6
McGuire Model Work Order 98399233, Clean RN Side of NS 1A AHU
34
McGuire MP/0/A/7150/058, NV Pump American Standard Oil Coolers Corrective Maintenance,
Rev. 13
McGuire MP/0/A/7150/118, NI Pump American Standard Oil Cooler Corrective Maintenance,
Rev. 3
McGuire MP/0/A/7700/013, Component Cooling Heat Exchanger Corrective Maintenance, Rev.
6
McGuire PT/1/A/4350/032A, KD Heat Exchanger 1A RN Differential Pressure Test, Rev. 13
Structural
MC-1042-CISI-0001, McGuire Nuclear Station 1&2 First Interval Containment Inservice
Inspection Plan, Rev. 2
PT/1/A/4200/044, Procedure Process Record for Containment Structural Integrity of MNS Unit
1, Rev. 1
PT/2/A/4200/078, Containment Structural Integrity Inspection
EDM-410, Inspection Program for Civil Engineering Structures and Components, Rev. 8
MP/0/A/7700/031, McGuire Nuclear Station Flood Seal Installation and Repair, Rev. 8
IP/0/A/3090/010, Sealing Safety-Related Equipment Outside Containment and Doghouses,
Rev. 12
CN-1042-CISI-0001, Catawba Nuclear Station Containment Inservice Inspection Plan, Rev. 3
Model Work Order PM-Underwater Inspections of Raw Water Structures, July 11, 2002
PT/0/A/7700/093, Trenching and Excavation, Rev. 0
Model Work Order 93045301,PM/1XNA/Inspect Internal Flood Barriers, July 28, 2000
Work Order 98208190, Unit 1 Flood Barriers Inspection, April 3, 2000
PT/1/A/4200/001 Q, Penetration Leak Rate Test, Rev. 23
PT/2/A/4200/001 B, Electrical Penetration O-Ring Seal Leak Rate Test, Rev. 10, March 1, 2002
PT/2/A/4200/044, McGuire Nuclear Station Unit 2 - Containment Structural Integrity Inspection,
Rev. 2, September 29, 2000
PT/1/A/4200/001 A, Containment Integrated Leak Rate Test, Rev. 19
Fluid Leak Management
Nuclear System Directive (NSD)-413, Fluid Leak Management Program, Revision 1
35
NSD-513, Primary to Secondary Leak Monitoring Program, Revision 1
Catawba Nuclear Site Directive 3.11.4, Site Materiel Condition, Revision 0
Catawba PT/1/A/4150/001 H, Inside Containment Boric Acid Check, Revision 7
Catawba PT/2/A/4150/001 H, Inside Containment Boric Acid Check, Revision 7
Reactor Coolant System Operational Leakage
McGuire PT/1/A/4150/001 D, Identifying NC System Leakage, Revision 5
McGuire PT/1/A/4150/001 B, Reactor Coolant System Calculation, Revision 46
Catawba PT/1/A/4150/001 D, NC System Leakage Calculation, Revision 43
Catawba PT/2/A/4150/001 D, NC System Leakage Calculation, Revision 47
Catawba PT/1/B/4600/028, Determination of Steam Generator Tube Leak Rate for Unit 1,
Revision 3
Catawba PT/2/B/4600/028, Determination of Steam Generator Tube Leak Rate for Unit 2,
Revision 3
Service Water Inspections
McGuire PT/0/B/4700/063, Periodic Inspection of Service Water Piping for Corrosion Induced
Thinning, Revision 3
Catawba PT/0/B/4600/026, Periodic Inspection for Corrosion Induced Wall Thinning, Revision 4
McGuire PT/0/A/4400/004, Standby Nuclear Service Water Pond Dam Inspection, Revision 7
Catawba PT/0/A/4400/004, Standby Nuclear Service Water Pond Dam Periodic Inspection,
Revision 20
Catawba PT/0/A/4600/015, Standby Nuclear Service Water Pond Topographic Survey,
Revision 2
Fluid Leak Management
Catawba MP/0/A/7650/088; Controlling Procedure for Systems Pressure Testing of ASME
Section XI Duke Class A, B, and C Systems and Components, Revision 25
McGuire MP/0/A/7700/080; Inspection, Evaluation and Cleanup of Boric Acid on Alloy, Carbon
and Stainless Steel Components, Revision 5
Catawba MP/0/A/7650/040; Inspection, Evaluation and Cleanup of Boric Acid Spills on Alloy,
Carbon Steel and Stainless Steel Components, Revision 6
36
McGuire MP/0/A/7650/076, Controlling Procedure for System Pressure Testing of ASME Piping
Systems, Revision 11
McGuire Maintenance Directive 2.18, Control of the Mode 3 Full Temperature and Pressure
Walkdown, Revision 0
McGuire OMP 5-5, NLO Surveillance, Revision 12
Ice Condenser Inspections
McGuire SM/0/A/8510/002, Ice Basket Inspection, Revision 3
Catawba SM/0/A/8510/002, Ice Basket Inspection, Revision 6
Catawba SM/0/A/8510/007, Ice Basket Corrective Maintenance and Tracking, Revision 13
Various
Catawba Model Work Order 91005512, Inspect Underground Unit 1 RC System Piping, dated
6/6/97
Catawba Work Order 98278898, RC Blast-Recoat Inside of RC Piping, dated 11/4/01
McGuire Calculation MCL-1148.00-00-0048, Visual Inspection and Acceptance Criteria for the
Refueling Water Storage Tank (FWST), Rev. 1
McGuire PT/0/A/4550/036, SFP Storage Rack Boraflex Examination Controlling Procedure,
Revision 2
McGuire PT/0/A/4200/005, Divider Barrier Seal Inspection, Revision 8
Catawba PT/0/A/4200/042, Access Door and Hatch Seal Periodic Inspection and Replacement,
Revision 10
Catawba PT/0/A/4200/043, Divider Barrier Seal Inspection, Revision 5
Plant Engineering Procedure No. 3.04, Documentation of Allowable Operating Transient Cycles
(Catawba), Revision 2
Plant Records
Inservice Inspection Report Unit 1 McGuire 2001 Outage 7/EOC-14
Inservice Inspection Report Unit 2 McGuire 2002 Outage 6/EOC-14
Inservice Inspection Report Unit 1 Catawba 2000 Refueling Outage EOC12 (Outage 4)
Inservice Inspection report Catawba Unit 2 2001 Refueling Outage EOC11 (Outage 4)
McGuire Unit 1 Pressure Test Status Log, 2nd Interval
37
McGuire Unit 1 - 3rd Interval Pressure Testing Examination Zone Report
McGuire Unit 2 Pressure Test Status Log 2nd Interval
McGuire Completed Procedure MP/0/A/7650/076, Pressure Test 1A (2EOC14) (Item
B15.050.001)
Catawba Unit 2 Framatome RV 10-Year ISI - Visual Inspection Evaluation, 11/10/95
Completed MP/0/A/7650/088 for Catawba Unit 1 EOC 13
Completed MP/0/A/7650/088 for Catawba Unit 2 EOC 11
Completed Framatome Procedure 54-ISI-364-00, IVVI Inspection Data Sheet, McGuire Unit 1
ISI-EOC 14
McGuire Unit 1 EOC-14 Erosion Inspection Log
McGuire Unit 2 EOC-14 Erosion Inspection Log
McGuire Unit 1 Piping Erosion/Corrosion Inspection Program Data Base 5/23/2001
McGuire Unit 2 Piping Erosion/Corrosion Inspection Program Data Base 3/27/2002
Catawba Nuclear Station Unit 1 Flow Accelerated Corrosion Inspection Program Database,
7/11/2002
Catawba Nuclear Station Unit 2 Flow Accelerated Corrosion Inspection Program Database,
10/11/2001
Catawba FAC Inspection Program Health Report Unit 1 Cycle 12 through 1EOC12
Catawba FAC Inspection Program Health Report Unit 2 Cycle 11 through 2EOC11
Completed McGuire Unit 1 MP/0/A/7150/033, Irradiation Capsule Removal From the Reactor
Lower Internals 4/27/97
Completed Catawba Unit 1 MP/0/A/7150/085, Irradiation Capsule Removal From the Reactor
Lower Internals 12/6/97
Completed Catawba Unit 2 MP/0/A/7150/085, Irradiation Capsule Removal From the Reactor
Lower Internals 9/13/98
McGuire and Catawba Calculation DPC-1201.01-006, MCC-1201.01-00-0044, CNS-1201.01-
00-0020, USE and RTPTS Values for Reactor Vessel Nozzle Region Locations
McGuire Nuclear Station Unit 1 Steam Generator Outage Report 1EOC14, March 2001,
Including Attachments A through M
McGuire Nuclear Station Unit 2 Steam Generator Outage Report 2EOC14, March 2002,
Including Attachments A through L
38
Catawba Nuclear Station Steam Generator Maintenance Outage Summary Report, 1EOC-12,
File No. 208.20
Catawba Nuclear Station Steam Generator Maintenance Outage Summary Report 2EOC-10
Duke Engineering & Services SG Outage Summary Report for Catawba Nuclear station Unit 2
EOC 11, including Sludge Lance Report and SGMEP 105 Assessment of Potential Degradation
Mechanisms
Completed McGuire 1EOC14 (2001) PT/0/A/4550/034, Incore Detection Thimble Tube Eddy
Current Testing, including results
Completed McGuire 2EOC8 (1993) PT/0/A/4550/034, Incore Detection Thimble Tube Eddy
Current Testing, including results
Completed PT/0/A/4600/10, Incore Detector Thimble Eddy Current Testing - 9/30/98 (Catawba
2EOC9)
Completed NBE-715, Multifrequency Eddy Current Examination of Flux Thimble Tubing at
Catawba and McGuire Nuclear stations , Revision 0 - 9/30/98 (Catawba 2EOC9)
Catawba Unit 2 @EOC11, Containment ISI Record File # CN-1144.09, Record #005687,
CNS-1144.11-00-0001,Specification for Field Welding and Erection Tolerances of Containment
Vessel, Revision 7, February 27, 1983
PT/1/A/4200/01L, Catawba Nuclear Station Leak Rate Test Report Unit 1, November, 2000
PT/2/A/4200/01L, Catawba Nuclear Station Leak Rate Test Report Unit 2, February, 1993
File No. MC-1462.00, McGuire Nuclear Station Units 1&2 1997 Inspection report for Civil
Engineering Structures and Components per EDM -410, 2/15/98
File No. CN-1642.00, Catawba Nuclear Station, Units 1&2 1997-1998 Inspection of Civil
Engineering Structures and Components, 10/13/98
Current Catawba and McGuire Station Fluid Leak Management Data Base for Active Leaks
Current Transient Cycle Data for Catawba and McGuire Stations
NET-158-01, Badger Test Campaign at McGuire Unit 1, Revision 0
NET-158-02, Badger Test Campaign at McGuire Unit 2, Revision 0
Work Order (WO) 98446789-01, Catawba 1 Inspect Barrier Seal
WO 98374805-01, Catawba 2 Inspect Divider Barriers
WO 98277323, Catawba 1 Remove/Replace CRDM Missile Shields
WO 98373468, Catawba 2 Remove/Replace CRDM Missile Shields
39
WO 98446797, Catawba 1 Remove/Replace Reactor Coolant Pump C Hatch
WO 98373480, Catawba 2 Remove/Replace Reactor Coolant Pump B Hatch
WO 95023567-01, Catawba 1 Inspect Equipment Hatch at Pressurizer Base
WO 97002629-01, Catawba 2 Inspect Equipment Hatch at Pressurizer Base
WO 98483507, Catawba 1 Remove/Replace Pressurizer Hatches
WO 98457108, Catawba 2 Remove/Replace Pressurizer Hatches
WO 94054584, Catawba 1 Inspect Pipe Chase Equipment Hatch
WO 96090788, Catawba 2, Inspect Pipe Chase Equipment Hatch
WO 98277014, Catawba 1 Inspect Emergency Hatch
WO 94054753, Catawba 2 Inspect Emergency Hatch
WO 95991812, Catawba 1 Steam Generator D Enclosure Manway
WO 97022560, Catawba 2 Steam Generator C & D Enclosure Manways
WO 98137581, Catawba 1 Steam Generator A Enclosure Manway
WO 98015392, Catawba 2 Steam Generator A Enclosure Manway
WO 98482515, Catawba 1 Ice Condenser Lower Access Door Seal
WO 98053873, Catawba 2 Ice Condenser Lower Access Door Seal
WO 97063057, Catawba 1 Inspect Incore Instrument Hatch
WO 98031975, Catawba 2 Inspect Incore Instrument Hatch
WO 98294398, McGuire 1 Inspect Divider Barrier Hatch Seal
WO 98479011, McGuire 1 Inspect Pressurizer Hatch Seal
WO 98294183, McGuire 1 Remove/Replace Reactor Coolant Pump A Hatch
WO 98294180, McGuire 1 Inspect CRDM Missile Shield Seals
WO 94019594, McGuire 1 Inspect Steam Generator A Manway
WO 98400544, McGuire 1 Inspect Submarine Hatch Seal
WO 98294393-02, McGuire 1 Divider Barrier Seal Inspection
WO 98410174-01, McGuire 2 Divider Barrier Seal Inspection
40
WO 98409999, McGuire 2 Remove/Replace Reactor Coolant Pump A Hatch
WO 98483233, McGuire 2 Inspect CRDM Missile Shield Seals
WO 97094010, McGuire 2 Inspect Steam Generator A Manway
WO 98410173, McGuire 2 Inspect Divider Barrier Hatch Seal
WO 98483592, McGuire 2 Inspect Pressurizer Hatch Seal
WO 98410172, McGuire 2 Inspect Submarine Hatch Seal
WO 85059218, McGuire 1 Ice Condenser Basket Inspection
WO 85058480, McGuire 2 Ice Condenser Basket Inspection
WO 98293709-01, Catawba 1 Perform Inspection of Ice Condenser Baskets
WO 98374383-01, Catawba 2 Perform Inspection of Ice Condenser Baskets
McGuire Unit 1-EOC 14 Ice Condenser Inspection Report
McGuire Unit 1 Ice Condenser Upper Inspection dated 06/20/2002
McGuire Unit 1 Ice Condenser Lower Inspections dated 03/16 and 04/10/2001
McGuire Unit 1 Ice Condenser Top Deck Inspection dated 04/10/2001
McGuire Unit 2-EOC 14 Ice Condenser Inspection Report
McGuire Unit 2 Ice Condenser Upper Inspection dated 06/19/2002
McGuire Unit 2 Ice Condenser Lower Inspections dated 03/09 and 03/14/2002
McGuire Unit 2 Ice Condenser Top Deck Inspection dated 03/14/2002
Catawba Unit 1 Ice Condenser Lower Plenum Inspection dated 11/15/2000
Catawba Unit 2 Ice Condenser Lower Plenum Inspection dated 09/15/2001
Catawba Unit 2 Ice Condenser Intermediate Deck Inspection dated 10/16/2001
Catawba Unit 2 Ice Condenser Top Deck Inspection dated 10/15/2001
Catawba Unit 1 NC System Leakage Results 11/01/2001 through 07/11/2002
Catawba Unit 2 NC System Leakage Results 08/05/2001 through 07/07/2002
McGuire Unit 1 NC Leakage Three year Trend
McGuire Unit 2 NC Leakage Three Year Trend
41
Catawba Annual Standby Nuclear Service Water Pond Dam Inspection Summary dated
12/05/2001
McGuire Annual Inspection of Standby Nuclear Service Water Dam and WCCB Dikes
Summary dated 06/06/2002
Catawba Standby Nuclear Service Water Pond Topographic Survey Results dated 06/07/2000
PROBLEM INVESTIGATION PROCESS (PIP) DOCUMENTS
PIP M-02-1122, Internal Piping Inspection Unit 2 Condenser Circulating Water System B.
PIP M-98-00249, Life Expectancy of Unit 1 FWST Internal Coating Exceeded
PIP M-97-3386, Evaluate Requirement for Vessel Code Related Inspections of FWST
PIP C-98-03567, Corrosion of steel containment vessel near VX fan pit floor Catawba Unit 2
PIP C-95-01464, Containment vessel corrosion identified during SCV Inspection
PIP C-00-01555, UT examinations revealed many locations where containment shell plate
thickness is less than 90% of nominal
PIP C-02-03802, Service Water Pump Leakoff Line not properly Routed
PIP C-98-04719, Potential Significant Corrosion on Nuclear Service Water Components
PIP C-00-04315, Leak at Nuclear Service Water Pump 1A
PIP M-02-02098, Thermal Fatigue Management Program Transient Definition
PIP C-02-01928, Thermal Fatigue Management Program Transient Definition
PIP C-96-00344, Evaluation of PORV Actuation
PIP C-02-02618, Thermal Fatigue Management Program Transient Inconsistencies
PIP M-02-02413, Thermal Fatigue Management Program Transient Inconsistencies
PIP C-02-04043, Corrosion Identified on the RN System during License Renewal Walkdown
STATION DRAWINGS
Duke Dwg. MC-1330-01.00, Intake, Discharge and Low Level Intake Pipes, General layout,
Rev. 11
Duke Dwg. MC-1330-5, Condenser Cooling Water Discharge Pipes, Layout and Details, Rev.
10
MCFD-1563-01.00
Flow Diagram of Containment Spray System (NS), Revision 5
42
Engineering Documents
Engineering Support Document - Lifting Program/Cranes and Hoists, Rev. 0
System Health Report for Catawba Station Nuclear Service Water, Second Quarter, 2002
McGuire Engineering Guide 2.4, Workplace Guide for Documentation of Allowable Operating
Transient Cycles, Revision 1
CNS-1274.00-00-0009, Time-Limited Aging Analysis of Mechanical System Thermal Fatigue for
License Renewal, Revision 0
Calculation MCC-1553.12-00-0020, Region Designation for Individual Spent Fuel Pool Storage
Cells at McGuire, Revision 1
McGuire Engineering Support Program Primary System Leakage Control ESD, Revision 1
McGuire Service Water Pipe Inspection Program ESD
McGuire Service Water Pipe Corrosion Manual, Revision 9
Catawba Service Water Pipe Inspection Program dated 01/08/2001
Catawba Service Water Pipe Inspection Program Health Report, 2002Q1
MMP-001, Guideline for Engineering Disposition of Boric Acid Leakage, Revision 1
Special Engineering Procedure (SEP)-092-06, Procedure for Measuring the Boron-10 Areal
Density of Boraflex in PWR Spent Nuclear Fuel Storage Racks, Revision 3
43
ATTACHMENT 2
MCGUIRE AND CATAWBA NUCLEAR STATIONS
AGING MANAGEMENT PROGRAM INSPECTION
AGING MANAGEMENT PROGRAM
APPLICATION
LOCATION
Alloy 600 Aging Management Review
B.3.1
Bottom-Mounted Instrumentation Thimble Tube
Inspection Program
B.3.5
Control Rod Drive Mechanism Nozzle and Other
Vessel Closure Penetrations Inspection Program
B.3.9
Flow Accelerated Corrosion Program
B.3.14
Inservice Inspection Plan
B.3.20
Reactor Vessel Integrity Program
B.3.26
Reactor Vessel Internals Inspection
B.3.27
Reactor Vessel Neutron Embrittlement
4.2
Steam Generator Surveillance Program
B.3.31
Boraflex Monitoring Program (McGuire only)
B.3.3
Divider Barrier Seal Inspection and Testing Program
B.3.11
Fluid Leak Management Program
B.3.15
Galvanic Susceptibility Inspection
B.3.16
Ice Condenser Inspections
B.3.18
Metal Fatigue
4.3
Reactor Coolant System Operational Leakage
Monitoring Program
B.3.25
Service Water Piping Corrosion Program
B.3.29
Standby Nuclear Service Water Pond Dam Inspection
B.3.30
Standby Nuclear Service Water Pond
Volume Program (Catawba only)
4.7.3
Pressurizer Spray Head Examination
RAI 2.3.2.7-1
Battery Rack Inspections
B.3.2
Chemistry Control Program
B.3.6
Heat Exchanger Activities
B.3.17
Preventive Maintenance Activities
B.3.24
Sump Pump Systems Inspection
B.3.32
Borated Water Systems Stainless Steel Inspection
B.3.4
Crane Inspection Program
B.3.10
Liquid Waste System Inspection
B.3.22
Selective Leaching Inspection
B.3.28
Treated Water Systems Stainless Steel Inspection
B.3.34
Waste Gas System Inspection
B.3.36
Containment Inservice Inspection Plan - IWE
B.3.7
Containment Leak Rate Testing Program
B.3.8
Flood Barrier Inspection (McGuire only)
B.3.13
44
AGING MANAGEMENT PROGRAM
APPLICATION
LOCATION
Inspection Program for Civil Engineering Structures
and Components
B.3.21
Technical Specification SR 3.6.16.3 Visual Inspection
B.3.33
Underwater Inspection of Nuclear Service Water
Structures
B.3.35
B.3.12
Inaccessible Non-EQ Medium Voltage Cables Aging
Management Program
B.3.19
Non-EQ Insulated Cables and Connections Aging
Management Program
B.3.23
45
ATTACHMENT 3
LIST OF ACRONYMS USED
Auxiliary Building
Aging Management Review
Anticipated Transient Without Scram
Branch Technical Position
Condenser Circulating Water
CFR
Code of Federal Regulations
Control Rod Drive Mechanism
DBS
Design Basis Specification
DGB
Diesel Generator Building
Effective Full Power Years
Engineering Support Document
Environmental Qualification program
Fuel Building
Fire Hazards Analysis
Fire Protection
Inservice Inspection
Low Pressure Service Water
LR
Maintenance Procedure
NFB
New Fuel Building
Nominal Pipe Size
Non-Safety-related
Nuclear Service Water
NRC Office of Nuclear Reactor Regulation
Problem Investigation Process
Power Operated Relief Valves
Pressurized Thermal Shock
Primary Water Stress Corrosion Cracking
P/T
Pressure/Temperature
Quality Assurance
Request for Additional Information
RI
Risk Informed
RTPTS
Reference Temperature Pressurized Thermal Shock
RVI
Reactor Vessel Internals
Refueling Water Storage Tank
Resistance Temperature Detector
Station Blackout event
Spent Fuel Pool
SNSW
Standby Nuclear Service Water
SR
Safety-related
Systems, Structures, and Components
SSF
Standby Shutdown Facility
46
Time-Limited Aging Analysis
Updated Final Safety Analysis Report
UHI
Upper Head Injection System
USE
Upper Shelf Energy
Duke two letter system designator system
Standby Shutdown Diesel System
CA
Auxiliary Feedwater System
Feedwater System
CL
Feedwater Condensate Seal System
Condensate System
Condensate Storage System
Diesel Generator Engine Fuel Oil System
Refueling Water System
KC
Component Cooling Water
KD
Diesel Generator Cooling Water System
KF
Spent Fuel Cooling System
KR
Recirculated Cooling Water System
LD
Diesel Generator Engine Lube Oil System
LF
Feedwater Pump Turbine Lube Oil System
Feedwater Pump Turbine Hydraulic Oil System
NC
ND
Residual Heat Removal System
NI
Safety Injection System
NS
Containment Spray System
NV
Chemical and Volume Control System
NW
Containment Valve Injection Water System
RC
CondenserCirculating Water System
RN
Nuclear Service Water System
Main Steam Supply to Auxiliary Equipment
Main Steam System
Steam Supply to Feedwater Pump Turbine System
Main Steam Vent to Atmosphere System
Feedwater Pump Turbine Exhaust
TF
Feedwater Pump Turbine Steam Seal System
Auxiliary Building Ventilation System
VD
Diesel Building Ventilation System
VE
Annulus Ventilation System
Fuel Handling Building Ventilation System
VG
Diesel Generator Starting Air System
VI
Instrument Air System
VN
Diesel Generator Air Intake and Exhaust System
VR
Reactor Building Control Rod Drive Ventilation System
VX
Containment Air Return & Hydrogen Skimmer System
WN
Diesel Generator Room Sump Pump System
ZD
Diesel Generator Engine Crankcase Vacuum System