ML080220255

License Renewal Application, Appendix B Through Environmental Report Page 2-59

ML080220255
Person / Time
Site:	Three Mile Island
Issue date:	01/08/2008
From:	AmerGen Energy Co
To:	Office of Nuclear Reactor Regulation
References
5928-08-20001
Download: ML080220255 (211)

Text

Appendix B - Aging Management Programs APPENDIX B AGING MANAGEMENT PROGRAMS TABLE OF CONTENTS B.1 INTRODUCTION.............................................................................................. B-3 B.1.1 Overview .......................................................................................................... B-3 B.1.2 Method of Discussion ....................................................................................... B-4 B.1.3 Quality Assurance Program and Administrative Controls ................................ B-4 B.1.4 Operating Experience....................................................................................... B-6 B.1.5 NUREG-1801 Chapter XI Aging Management Programs ................................ B-6 B.1.6 NUREG-1801 Chapter X Aging Management Programs ................................. B-8 B.2 AGING MANAGEMENT PROGRAMS ............................................................. B-8 B.2.0 NUREG-1801 Aging Management Program Correlation.................................. B-8 B.2.1 NUREG-1801 Chapter XI Aging Management Programs .............................. B-12 B.2.1.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD ................................................................................................ B-13 B.2.1.2 Water Chemistry............................................................................................. B-16 B.2.1.3 Reactor Head Closure Studs.......................................................................... B-19 B.2.1.4 Boric Acid Corrosion....................................................................................... B-21 B.2.1.5 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors.............................................. B-23 B.2.1.6 Flow-Accelerated Corrosion ........................................................................... B-27 B.2.1.7 Bolting Integrity............................................................................................... B-30 B.2.1.8 Steam Generator Tube Integrity..................................................................... B-33 B.2.1.9 Open-Cycle Cooling Water System................................................................ B-36 B.2.1.10 Closed-Cycle Cooling Water System ............................................................. B-40 B.2.1.11 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems .......................................................................................... B-44 B.2.1.12 Compressed Air Monitoring............................................................................ B-47 B.2.1.13 Fire Protection ................................................................................................ B-49 B.2.1.14 Fire Water System.......................................................................................... B-54 B.2.1.15 Aboveground Steel Tanks .............................................................................. B-57 B.2.1.16 Fuel Oil Chemistry.......................................................................................... B-59 B.2.1.17 Reactor Vessel Surveillance .......................................................................... B-64 B.2.1.18 One-Time Inspection ...................................................................................... B-68 B.2.1.19 Selective Leaching of Materials...................................................................... B-71 B.2.1.20 Buried Piping and Tanks Inspection............................................................... B-73 B.2.1.21 External Surfaces Monitoring ......................................................................... B-77 B.2.1.22 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components ................................................................................................... B-79 B.2.1.23 Lubricating Oil Analysis .................................................................................. B-81 B.2.1.24 ASME Section XI, Subsection IWE ................................................................ B-85 B.2.1.25 ASME Section XI, Subsection IWL................................................................. B-90 B.2.1.26 ASME Section XI, Subsection IWF ................................................................ B-94 B.2.1.27 10 CFR Part 50, Appendix J........................................................................... B-97 B.2.1.28 Structures Monitoring Program ...................................................................... B-99 B.2.1.29 Protective Coating Monitoring and Maintenance Program ........................... B-103 Three Mile Island Nuclear Station Unit 1 Page B-1 License Renewal Application

Appendix B - Aging Management Programs B.2.1.30 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements .................................................. B-106 B.2.1.31 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits ......................................................................................................... B-108 B.2.1.32 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements .................................................. B-111 B.2.1.33 Metal Enclosed Bus...................................................................................... B-113 B.2.1.34 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements .......................................................................... B-115 B.2.2 Plant Specific Aging Management Programs ............................................... B-118 B.2.2.1 Nickel Alloy Aging Management Program .................................................... B-118 B.3 NUREG-1801 CHAPTER X AGING MANAGEMENT PROGRAMS ............ B-124 B.3.1.1 Metal Fatigue of Reactor Coolant Pressure Boundary ................................. B-124 B.3.1.2 Concrete Containment Tendon Prestress .................................................... B-127 B.3.1.3 Environmental Qualification (EQ) of Electrical Components ........................ B-130 Three Mile Island Nuclear Station Unit 1 Page B-2 License Renewal Application

Appendix B - Aging Management Programs B.1 INTRODUCTION B.1.1 OVERVIEW License renewal Aging Management Program (AMP) descriptions are provided in this appendix for each program credited for managing aging effects based upon the Aging Management Review (AMR) results provided in Sections 3.1 through 3.6 of this application.

In general, there are four (4) types of AMPs:

• Prevention programs preclude aging effects from occurring.

• Mitigation programs slow the effects of aging.

• Condition monitoring programs inspect/examine for the presence and extent of aging.

• Performance monitoring programs test the ability of a structure or component to perform its intended function.

More than one type of AMP may be implemented for a component to ensure that aging effects are managed.

Part of the demonstration that the effects of aging are adequately managed is to evaluate credited programs and activities against certain required attributes.

Each of the AMPs described in this section has ten (10) elements which are consistent with the attributes described in Appendix A.1, Aging Management Review - Generic (Branch Technical Position RLSB-1) and in Table A.1-1 Elements of an Aging Management Program for License Renewal of NUREG-1800. The 10-element detail is not provided when the program is deemed to be consistent with the assumptions made in NUREG-1801. The 10-element detail is only provided when the program is plant specific.

Credit has been taken for existing plant programs whenever possible. As such, all programs and activities associated with a system, structure, component, or commodity grouping were considered. Existing programs and activities that apply to systems, structures, components, or commodity groupings were reviewed to determine whether they include the necessary actions to manage the effects of aging.

Existing plant programs were often based on a regulatory commitment or requirement, other than aging management. Many of these existing programs included the required license renewal 10-element attributes, and have been demonstrated to adequately manage the identified aging effects. If an existing program did not adequately manage an identified aging effect, the program was enhanced as necessary. Occasionally, the creation of a new program was necessary.

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Appendix B - Aging Management Programs B.1.2 METHOD OF DISCUSSION For those AMPs that are consistent with the assumptions made in Sections X and XI of NUREG-1801, or are consistent with exceptions, each program discussion is presented in the following format:

• A Program Description abstract of the overall program form and function is provided.

• A NUREG-1801 Consistency statement is made about the program.

• Exceptions to the NUREG-1801 program are outlined and a justification for the exceptions is provided.

• Enhancements or additions to the NUREG-1801 program are provided. A proposed schedule for completion is discussed.

• Operating Experience (OE) information specific to the program is provided.

• A Conclusion section provides a statement of reasonable assurance that the program is effective, or will be effective, once enhanced.

For those AMPs that are plant specific, the above form is followed with the additional discussion of each of the 10-elements.

B.1.3 QUALITY ASSURANCE PROGRAM AND ADMINISTRATIVE CONTROLS The Quality Assurance Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with the summary in Appendix A.2, Quality Assurance For Aging Management Programs (Branch Technical Position IQMB-1) of NUREG-1800. The Quality Assurance Program includes the elements of corrective action, confirmation process, and administrative controls, and is applicable to the safety-related and non-safety related systems, structures, and components (SSCs) that are subject to AMR. In many cases, existing activities were found adequate for managing aging effects during the period of extended operation. Generically the three elements are applicable as follows:

Corrective Actions:

A single corrective actions process is applied regardless of the safety classification of the system, structure, or component. Corrective actions are implemented through the initiation of an Issue Report (IR) in accordance with the Corrective Action Program established in response to 10 CFR 50, Appendix B. The Corrective Action Program requires the initiation of an Issue Report for actual or potential problems, including unexpected plant equipment degradation, damage, failure, malfunction or loss. Site documents that implement aging management programs for license renewal will direct that an Issue Report be prepared in accordance with those procedures whenever non-conforming conditions are found (i.e., the acceptance criteria are not met). It is noted that previous Corrective Action Programs referred to Condition Reports (CRs) or CAPs for documenting actual or potential problems and non-conforming conditions. These terms are synonymous with the term Issue Report.

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Appendix B - Aging Management Programs Equipment deficiencies are corrected through the Work Control Program in accordance with plant procedures. Although equipment deficiencies may initially be documented by the Work Control Program, the Corrective Action Program specifies that an Issue Report also be initiated, if required, for condition identification, assignment of significance level and investigation class, investigation, corrective action determination, investigation report review and approval, action tracking, and trend analysis.

The Corrective Action Program implements the requirements of the Exelon Quality Assurance Topical Report (QATR), Chapter 16, Corrective Action.

Specifically, Conditions Adverse to Quality and Significant Conditions Adverse to Quality are resolved through direct action, the implementation of Corrective Actions, and where appropriate, the implementation of Corrective Actions to Prevent Recurrence.

Confirmation Process:

The focus of the confirmation process is on the follow-up actions that must be taken to verify effective implementation of corrective actions. The measure of effectiveness is in terms of correcting and precluding repetition of adverse conditions. The Corrective Action Program includes provisions for timely evaluation of adverse conditions and implementation of any corrective actions required, including root cause determinations and prevention of recurrence where appropriate (e.g., Significant Conditions Adverse to Quality). The Corrective Action Program provides for tracking, coordinating, monitoring, reviewing, verifying, validating, and approving corrective actions, to ensure effective corrective actions are taken. The Corrective Action Program also monitors for potentially adverse trends. The existence of an adverse trend due to recurring or repetitive adverse conditions will result in the initiation of an Issue Report. The AMPs required for license renewal would also uncover any unsatisfactory condition due to ineffective corrective action.

Since the same 10 CFR 50, Appendix B corrective actions and confirmation process is applied for nonconforming safety-related and nonsafety-related systems, structures, and components subject to Aging Management Review (AMR) for license renewal, the Corrective Action Program is consistent with the NUREG-1801 elements.

Administrative Controls:

The document control process applies to all generated documents, procedures, and instructions regardless of the safety classification of the associated system, structure, or component. Document control processes are implemented in accordance with the requirements of 10 CFR 50, Appendix B, Quality Assurance Requirements for Nuclear Power Plants and Fuel Reprocessing Plants. Implementation is further defined in the Exelon Quality Assurance Topical Report (QATR), Chapter 6, Document Control.

Administrative controls procedures provide information on procedures, instructions and other forms of administrative control documents, as well as guidance on classifying these documents into the proper document type and Three Mile Island Nuclear Station Unit 1 Page B-5 License Renewal Application

Appendix B - Aging Management Programs as-building frequency. Revisions will be made to procedures and instructions that implement or administer aging management program requirements for the purposes of managing the associated aging effects for the period of extended operation.

B.1.4 OPERATING EXPERIENCE Operating experience is used in two ways at Three Mile Island Nuclear Station Unit 1 to enhance plant programs, prevent repeat events, and prevent events that have occurred at other plants from occurring at Three Mile Island Nuclear Station Unit 1. The first way in which operating experience is used is through the Three Mile Island Nuclear Station Unit 1 Operating Experience process (OPEX). The Operating Experience process screens, evaluates, and acts on operating experience documents and information to prevent or mitigate the consequences of similar events. The second way is through the process for managing programs. This process requires the review of program related operating experience by the program owner.

Both of these processes review operating experience from external and internal (also referred to as in-house) sources. External operating experience may include such things as INPO documents (e.g., SOERs, SERs, SENs, etc.),

NRC documents (e.g., GLs, LERs, INs, etc.), and other documents (e.g., 10 CFR Part 21 Reports, NERs, etc.). Internal operating experience may include such things as event investigations, trending reports, and lessons learned from in-house events as captured in program notebooks, self-assessments, and in the 10 CFR Part 50, Appendix B corrective action process.

Each AMP summary in this appendix contains a discussion of operating experience relevant to the program. This information was obtained through the review of in-house operating experience captured by the Corrective Action Program, Program Self-Assessments, and Program Health Reports, and through the review of primarily post-2005 industry operating experience (industry operating experience prior to 2005 having been addressed by Revision 1 to NUREG-1801). Additionally, operating experience was obtained through interviews with system and program engineers. The operating experience in each AMP summary identifies past corrective actions that have resulted in program enhancements and provides objective evidence that the effects of aging have been, and will continue to be, adequately managed.

B.1.5 NUREG-1801 CHAPTER XI AGING MANAGEMENT PROGRAMS The following AMPs are described in the sections listed in this appendix. The programs are either generic in nature as discussed in NUREG-1801,Section XI, or are plant-specific. NUREG-1801 Chapter XI programs are listed in Section B.2.1. Plant-specific programs are listed in Section B.2.2. All generic programs are fully consistent with or are, with some exceptions, consistent with programs discussed in NUREG-1801. Programs are identified as either existing or new.

1. ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (Section B.2.1.1) [Existing]

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Appendix B - Aging Management Programs

2. Water Chemistry (Section B.2.1.2) [Existing]

3. Reactor Head Closure Studs (Section B.2.1.3) [Existing]

4. Boric Acid Corrosion (Section B.2.1.4) [Existing]

5. Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (Section B.2.1.5) [Existing]

6. Flow-Accelerated Corrosion (Section B.2.1.6) [Existing]

7. Bolting Integrity (Section B.2.1.7) [Existing]

8. Steam Generator Tube Integrity (Section B.2.1.8) [Existing]

9. Open-Cycle Cooling Water System (Section B.2.1.9) [Existing]

10. Closed-Cycle Cooling Water System (Section B.2.1.10) [Existing]

11. Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (Section B.2.1.11) [Existing]

12. Compressed Air Monitoring (Section B.2.1.12) [Existing]

13. Fire Protection (Section B.2.1.13) [Existing]

14. Fire Water System (Section B.2.1.14) [Existing]

15. Aboveground Steel Tanks (Section B.2.1.15) [Existing]

16. Fuel Oil Chemistry (Section B.2.1.16) [Existing]

17. Reactor Vessel Surveillance (Section B.2.1.17) [Existing]

18. One-Time Inspection (Section B.2.1.18) [New]

19. Selective Leaching of Materials (Section B.2.1.19) [New]

20. Buried Piping and Tanks Inspection (Section B.2.1.20) [Existing]

21. External Surfaces Monitoring (Section B.2.1.21) [New]

22. Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (Section B.2.1.22) [New]

23. Lubricating Oil Analysis (Section B.2.1.23) [Existing]

24. ASME Section XI, Subsection IWE (Section B.2.1.24) [Existing]

25. ASME Section XI, Subsection IWL (Section B.2.1.25) [Existing]

26. ASME Section XI, Subsection IWF (Section B.2.1.26) [Existing]

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Appendix B - Aging Management Programs

27. 10 CFR Part 50, Appendix J (Section B.2.1.27) [Existing]

28. Structures Monitoring Program (Section B.2.1.28) [Existing]

29. Protective Coating Monitoring and Maintenance Program (Section B.2.1.29) [Existing]

30. Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Section B.2.1.30) [New]

31. Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits (Section B.2.1.31) [Existing]

32. Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Section B.2.1.32) [New]

33. Metal Enclosed Bus (Section B.2.1.33) [Existing]

34. Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Section B.2.1.34) [New]

35. Nickel Alloy Aging Management Program (Section B.2.2.1)

[Existing]

B.1.6 NUREG-1801 CHAPTER X AGING MANAGEMENT PROGRAMS The following NUREG-1801 Chapter X AMPs are described in Section B.2.3 of this appendix as indicated. Programs are identified as either existing or new.

1. Metal Fatigue of Reactor Coolant Pressure Boundary (Section B.3.1.1) [Existing]

2. Concrete Containment Tendon Prestress (Section B.3.1.2) [Existing]

3. Environmental Qualification (EQ) of Electrical Components (Section B.3.1.3) [Existing]

B.2 AGING MANAGEMENT PROGRAMS B.2.0 NUREG-1801 AGING MANAGEMENT PROGRAM CORRELATION The correlation between the NUREG-1801 (Generic Aging Lessons Learned (GALL)) programs and the Three Mile Island Nuclear Station Unit 1 Aging Management Programs (AMPs) is shown below. Links to the sections describing the Three Mile Island Nuclear Station Unit 1 NUREG-1801 programs are provided.

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Appendix B - Aging Management Programs NUREG-THREE MILE ISLAND NUCLEAR STATION 1801 NUREG-1801 PROGRAM UNIT 1 PROGRAM NUMBER ASME Section XI Inservice Inspection, ASME Section XI Inservice Inspection, XI.M1 Subsections IWB, IWC, Subsections IWB, IWC, and IWD and IWD (Section B.2.1.1)

XI.M2 Water Chemistry Water Chemistry (Section B.2.1.2)

XI.M3 Reactor Head Closure Studs Reactor Head Closure Studs (Section B.2.1.3)

XI.M4 BWR Vessel ID Attachment Welds Not Applicable (BWR)

XI.M5 BWR Feedwater Nozzle Not Applicable (BWR)

XI.M6 BWR Control Rod Drive Return Line Nozzle Not Applicable (BWR)

XI.M7 BWR Stress Corrosion Cracking Not Applicable (BWR)

XI.M8 BWR Penetrations Not Applicable (BWR)

XI.M9 BWR Vessel Internals Not Applicable (BWR)

XI.M10 Boric Acid Corrosion Boric Acid Corrosion (Section B.2.1.4)

Not used. This AMP has been replaced in part by XI.M11A, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program (Section B.2.1.5). Guidance for the aging XI.M11 Nickel-Alloy Nozzles and Penetrations management of other nickel-alloy nozzles and penetrations is provided in the AMR line items of Chapter IV and is addressed by the plant specific Nickel Alloy Aging Management Program (Section B.2.2.1).

Nickel-Alloy Penetration Nozzles Welded to Nickel-Alloy Penetration Nozzles Welded to the XI.M11A the Upper Reactor Vessel Closure Heads of Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Pressurized Water Reactors (Section B.2.1.5)

Not used. The loss of fracture toughness in pump casings and valve bodies due to thermal Thermal Aging Embrittlement of Cast aging embrittlement is managed by XI.M1, XI.M12 Austenitic Stainless Steel (CASS) ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program (Section B.2.1.1).

Not used. The UFSAR Supplement commitment for PWR Vessel Internals (see Thermal Aging and Neutron Irradiation XI.M16) will be used to manage Loss of XI.M13 Embrittlement of Cast Austenitic Stainless Fracture Toughness/Thermal Aging and Steel (CASS)

Neutron Irradiation Embrittlement for the cast austenitic stainless steel vessel internals.

XI.M14 Loose Part Monitoring Not used. Not credited for aging management.

XI.M15 Neutron Noise Monitoring Not used. Not credited for aging management.

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Appendix B - Aging Management Programs NUREG-THREE MILE ISLAND NUCLEAR STATION 1801 NUREG-1801 PROGRAM UNIT 1 PROGRAM NUMBER TMI-1 will provide a commitment in the UFSAR supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs XI.M16 PWR Vessel Internals as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, an inspection plan for reactor internals will be submitted to the NRC for review and approval.

XI.M17 Flow-Accelerated Corrosion Flow-Accelerated Corrosion (Section B.2.1.6)

XI.M18 Bolting Integrity Bolting Integrity (Section B.2.1.7)

Steam Generator Tube Integrity (Section XI.M19 Steam Generator Tube Integrity B.2.1.8)

Open-Cycle Cooling Water System (Section XI.M20 Open-Cycle Cooling Water System B.2.1.9)

Closed-Cycle Cooling Water System (Section XI.M21 Closed-Cycle Cooling Water System B.2.1.10)

XI.M22 Boraflex Monitoring Not used. Not credited for aging management.

Inspection of Overhead Heavy Load and Light Inspection of Overhead Heavy Load and Light XI.M23 Load (Related to Refueling) Handling Systems Load (Related to Refueling) Handling Systems (Section B.2.1.11)

XI.M24 Compressed Air Monitoring Compressed Air Monitoring (Section B.2.1.12)

XI.M25 BWR Reactor Water Cleanup System Not Applicable (BWR)

XI.M26 Fire Protection Fire Protection (Section B.2.1.13)

XI.M27 Fire Water System Fire Water System (Section B.2.1.14)

Not Used. The aging effects associated with buried piping and tanks are managed by XI.M28 Buried Piping and Tanks Surveillance XI.M34, Buried Piping and Tanks Inspection program (Section B.2.1.20).

XI.M29 Aboveground Steel Tanks Aboveground Steel Tanks (Section B.2.1.15)

XI.M30 Fuel Oil Chemistry Fuel Oil Chemistry (Section B.2.1.16)

XI.M31 Reactor Vessel Surveillance Reactor Vessel Surveillance (Section B.2.1.17)

XI.M32 One-Time Inspection One-Time Inspection (Section B.2.1.18)

Selective Leaching of Materials (Section XI.M33 Selective Leaching of Materials B.2.1.19)

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Appendix B - Aging Management Programs NUREG-THREE MILE ISLAND NUCLEAR STATION 1801 NUREG-1801 PROGRAM UNIT 1 PROGRAM NUMBER Buried Piping and Tanks Inspection (Section XI.M34 Buried Piping and Tanks Inspection B.2.1.20)

Not Used. The aging effect of cracking in ASME Code Class 1 small bore-piping due to thermal and mechanical loading or One-Time Inspection of ASME Code Class 1 XI.M35 intergranular stress corrosion is managed by Small Bore-Piping XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program (Section B.2.1.1).

External Surfaces Monitoring (Section XI.M36 External Surfaces Monitoring B.2.1.21)

XI.M37 Flux Thimble Tube Inspection Not used. Not credited for aging management.

Inspection of Internal Surfaces in Inspection of Internal Surfaces in XI.M38 Miscellaneous Piping and Ducting Miscellaneous Piping Components and Ducting Components (Section B.2.1.22)

XI.M39 Lubricating Oil Analysis Lubricating Oil Analysis (Section B.2.1.23)

ASME Section XI, Subsection IWE (Section XI.S1 ASME Section XI, Subsection IWE B.2.1.24)

ASME Section XI, Subsection IWL (Section XI.S2 ASME Section XI, Subsection IWL B.2.1.25)

ASME Section XI, Subsection IWF (Section XI.S3 ASME Section XI, Subsection IWF B.2.1.26)

XI.S4 10 CFR Part 50, Appendix J 10 CFR Part 50, Appendix J (Section B.2.1.27)

Not used. The aging effects associated with masonry walls are managed by XI.S6, XI.S5 Masonry Wall Program Structures Monitoring Program (Section B.2.1.28).

Structures Monitoring Program (Section XI.S6 Structures Monitoring Program B.2.1.28)

Not used. The aging effects associated with RG 1.127, Inspection of Water-Control water-controlled structures are managed by XI.S7 Structures Associated with Nuclear Power XI.S6, Structures Monitoring Program (Section Plants B.2.1.28).

Protective Coating Monitoring and Protective Coating Monitoring and XI.S8 Maintenance Program Maintenance Program (Section B.2.1.29)

Electrical Cables and Connections Not Electrical Cables and Connections Not Subject XI.E1 Subject to 10 CFR 50.49 Environmental to 10 CFR 50.49 Environmental Qualification Qualification Requirements Requirements (Section B.2.1.30)

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Appendix B - Aging Management Programs NUREG-THREE MILE ISLAND NUCLEAR STATION 1801 NUREG-1801 PROGRAM UNIT 1 PROGRAM NUMBER Electrical Cables and Connections Not Electrical Cables and Connections Not Subject Subject to 10 CFR 50.49 Environmental to 10 CFR 50.49 Environmental Qualification XI.E2 Qualification Requirements Used in Requirements Used in Instrumentation Circuits Instrumentation Circuits (Section B.2.1.31)

Inaccessible Medium Voltage Cables Not Inaccessible Medium Voltage Cables Not XI.E3 Subject to 10 CFR 50.49 Environmental Subject to 10 CFR 50.49 Environmental Qualification Requirements Qualification Requirements (Section B.2.1.32)

XI.E4 Metal Enclosed Bus Metal Enclosed Bus (Section B.2.1.33)

Not used. The metallic clamp portions of fuse XI.E5 Fuse Holders holders have no aging effects requiring management.

Electrical Cable Connections Not Subject to Electrical Cable Connections Not Subject to 10 XI.E6 10 CFR 50.49 Environmental Qualification CFR 50.49 Environmental Qualification Requirements Requirements (Section B.2.1.34)

Metal Fatigue of Reactor Coolant Pressure Metal Fatigue of Reactor Coolant Pressure X.M1 Boundary Boundary (Section B.3.1.1)

Concrete Containment Tendon Prestress X.S1 Concrete Containment Tendon Prestress (Section B.3.1.2)

Environmental Qualification (EQ) of Electrical Environmental Qualification (EQ) of Electrical X.E1 Components Components (Section B.3.1.3)

Three Mile Island Nuclear Station Unit 1 plant Nickel Alloy Aging Management Program N/A specific program (Section B.2.2.1)

B.2.1 NUREG-1801 CHAPTER XI AGING MANAGEMENT PROGRAMS This section provides summaries of the NUREG-1801 Chapter XI programs credited for managing the effects of aging.

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Appendix B - Aging Management Programs B.2.1.1 ASME SECTION XI INSERVICE INSPECTION, SUBSECTIONS IWB, IWC, AND IWD Program Description The TMI-1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program is an existing program that is part of the Inservice Inspection (ISI) program and includes inspections performed to manage cracking and loss of fracture toughness in Class 1, 2, and 3 piping and components within the scope of license renewal. The program provides for the periodic visual, surface, and volumetric examination and leakage testing of pressure-retaining piping and components including welds, pump casings, valve bodies, integral attachments, and pressure-retaining bolting. The program includes an alternate method approved in accordance with 10 CFR 50.55a which is used to determine the inspection locations, inspection frequency, and inspection techniques for Class 1 Category B-F and B-J, and Class 2 Category C-F-1 and C-F-2 welds in accordance with 10 CFR 50.55a(a)(3)(i). This method also addresses volumetric examination of welds less than NPS 4 inches.

In accordance with 10 CFR 50.55a(g)(4)(ii), the TMI-1 ISI program is updated each successive 120 month inspection interval to comply with the requirements of the latest edition of the ASME Code specified twelve months before the start of the inspection interval.

NUREG-1801 Consistency The TMI-1 Inservice Inspection aging management program is an existing program that is consistent with NUREG-1801 aging management program XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD with the exceptions described below.

Exceptions to NUREG-1801

• NUREG-1801 specifies the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD. The TMI-1 ISI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda.

The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

• NUREG-1801 specifies the use of ASME Section XI B&PV Code, which includes requirements for examining Class 1 Category B-F and B-J, and Class 2 C-F-1 and C-F-2 piping components. At TMI-1, an alternate method approved in accordance with 10 CFR 50.55a is used to determine the inspection frequency for Class 1 Category B-F and B-J, and Class 2 Category C-F-1 and C-F-2 welds in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. This method also addresses volumetric examination of welds less than NPS 4 Three Mile Island Nuclear Station Unit 1 Page B-13 License Renewal Application

Appendix B - Aging Management Programs inches. Other portions of the ASME Section XI ISI program outside of this scope remain unaffected.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking due to stress corrosion cracking, cracking due to thermal and mechanical loading, cracking due to cyclic loading, and loss of fracture toughness due to thermal aging embrittlement are being adequately managed. The following examples of operating experience provide objective evidence that the TMI-1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. In 2002, a nuclear oversight assessment of non-destructive examination (NDE) procedures governed by the ISI program discovered an inspection procedure that was not updated to reflect the currently applicable ASME Code and Addenda editions as referenced in the ISI program. A review was performed to determine any effect from citing the earlier code, and an extent of condition review was performed to ascertain the existence of any similar incorrect code date use. This example provides objective evidence that deficiencies in the ISI program are identified and entered into the corrective action process and that the program is updated as necessary to ensure that it remains effective for condition monitoring of piping and components within the scope of license renewal.

2. An NDE examination of a pressurizer surge line safe-end to surge nozzle weld in 2003 identified an indication of a single axial flaw within the nozzle butter or weld metal. The indication was evaluated and repaired via the corrective action process. The evaluation determined the most likely cause to be primary water stress corrosion cracking (PWSCC), and an expanded scope of examination of similar type welds was performed in accordance with code requirements, with no further indications found. The subject weld was added to the schedule for UT examination for the next two outages, after which it is returned to its normal schedule for examination. This example provides objective evidence that the program provides appropriate guidance for inspection and evaluation, that deficiencies are entered into the corrective action process, and that appropriate action (expansion of scope due to observed conditions) is taken as necessary to ensure effective condition monitoring of piping and components within the scope of license renewal.

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Appendix B - Aging Management Programs

3. In 2005, a focused-area self assessment of the TMI-1 ISI program identified improvement items for completeness of program documentation including referencing an NRC-issued SER for a weld repair in the program, referencing an NRC-issued SER addressing certification of VT-2 examiners in the program, and including information from the repair and replacement program in the work order used as the repair plan. These changes were made in revisions to the program documents and implemented by the work planners. This example provides objective evidence that deficiencies in the ISI program are identified and entered into the corrective action process and that the program is updated as necessary to ensure that it remains effective for condition monitoring of piping and components within the scope of license renewal.

4. A nuclear oversight audit in 2006 identified three work order repair plans for code-required VT-2 examinations that did not adequately document post-maintenance inspections per the requirements of ASME Section XI, specifically the system test temperature, pressure, hold time, and acceptance criteria for insulated, non-insulated, and buried components. The documentation of post-maintenance test (PMT) activities was determined to be adequate for routine maintenance activities, but did not meet ASME code requirements in the three plans identified. Implementing guidance on performing and documenting VT-2 examinations were reviewed and revised as necessary, with library copies of repair plan work orders revised to clearly reflect VT-2 examination documentation requirements. This example provides objective evidence that deficiencies are identified and entered into the corrective action process and that the program is updated as necessary to ensure that it remains effective for condition monitoring of piping and components within the scope of license renewal.

In 631 examinations performed under the TMI-1 Section XI Inservice Inspection program from 2001 through 2005, only two did not return a satisfactory result and required material repair.

Conclusion The continued implementation of the TMI-1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD aging management program provides reasonable assurance that the aging effects of cracking and loss of fracture toughness will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.2 WATER CHEMISTRY Program Description The TMI-1 Water Chemistry aging management program is an existing program that provides activities for monitoring and controlling the chemical environments of the TMI-1 primary cycle and secondary cycle systems such that aging effects of system components are minimized. Aging effects include cracking, denting, loss of material, reduction of heat transfer, and reduction of neutron-absorbing capacity. The primary cycle scope of this program consists of the reactor coolant system and related auxiliary systems containing reactor coolant (borated treated water), including the primary side of the steam generators. The secondary cycle portion of the program consists of various secondary side systems and the secondary side of the steam generators.

Major component types include reactor vessel, reactor internals, heat exchangers, pumps casing, boiler casings, filter housings, tanks, valve bodies, piping, and piping components. The Water Chemistry aging management program is consistent with EPRI 1002884, Pressurized Water Reactor Primary Chemistry Guidelines, Revision 5 and Plant Technical Specification limits for fluorides, chlorides, and dissolved oxygen. The Water Chemistry program will be enhanced to become consistent with EPRI 1008224, Pressurized Water Reactor Secondary Water Chemistry Guidelines, Revision 6. This enhancement will incorporate the continuous monitoring of sodium in steam generator blowdown.

Industry experience has shown water chemistry programs may not be effective in low flow or stagnant flow areas of plant systems. Therefore, components located in such areas at TMI-1 will receive a one-time visual inspection. This inspection will be performed as part of the TMI-1 One-Time Inspection (B.2.1.18) aging management program.

NUREG-1801 Consistency The Water Chemistry Program is consistent with the ten elements of aging management program XI.M2, Water Chemistry Program, specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements The TMI-1 Water Chemistry Program will be enhanced to include the continuous monitoring of steam generator blowdown for sodium during startup and hot standby conditions as required by EPRI 1008224, PWR Secondary Water Chemistry Guidelines, Revision 6. This enhancement will be implemented after replacement of the existing once-through steam generators and prior to the period of extended operation for TMI-1.

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Appendix B - Aging Management Programs Operating Experience The Water Chemistry aging management program is a preventative program that assures contaminants are maintained below applicable limits to prevent the aging of plant piping and components. Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking, denting, loss of material, reduction of heat transfer, and reduction of neutron-absorbing capacity are being adequately managed. The following examples of operating experience provide objective evidence that the TMI-1 Water Chemistry aging management program will be effective in assuring that intended functions will be maintained consistent with the current licensing bases for the period of extended operation:

1. In June 2002, feedwater sodium levels exceeding the Action Level 1 values of 1 ppb were identified. This was the only occurrence of a chemistry action level being exceeded at TMI-1 in the past five years. Investigation identified the cause of the sodium increase as a condenser tube leak on the B side of the main condenser.

Corrective actions included securing the moisture separator drains, rapid replacement of Powdex vessels, reduction of power to 50%,

and location and repair of the failed condenser tube. Prompt action to identify the cause of the high sodium level, and repair the tube led to the reduction of feedwater sodium below 1ppb within one day of discovery. This example provides objective evidence that a) deficiencies found during water chemistry monitoring activities are documented in the corrective action process, and b) water chemistry monitoring activity deficiencies are evaluated and corrective actions are properly implemented to maintain system intended functions.

2. A focused area self-assessment (FASA) of the TMI-1 Water Chemistry program was performed in March 2004. The objective of the FASA was to determine if procedures are in place for monitoring and controlling RCS chemistry. Specifically, procedure CY-AP-120-105, Reactor Coolant System Chemistry for Three Mile Island was reviewed against the requirements of current EPRI PWR Primary Water Chemistry Guidelines. The review identified dissolved oxygen action limits in the procedure that were inconsistent with the EPRI guidelines. The FASA verified that these differences were appropriately documented in an issue report and that appropriate procedure revisions were drafted. However, the revised procedure had not been issued at the time of the FASA. The FASA also revealed that procedure CY-AP-120-105 did not require documentation when diagnostic parameters varied from the EPRI guidelines. FASA recommendations called for this to be documented in the future as an industry best practice. Revised procedure CY-AP-120-105, incorporating these changes, was issued subsequent to the FASA. Documentation of RCS chemistry excursions, including lithium and dissolved oxygen values above action levels, was determined appropriate. No voluntary entries into actions levels occurred during this time period. Finally, the FASA included the observation of RCS sampling being conducted by a Three Mile Island Nuclear Station Unit 1 Page B-17 License Renewal Application

Appendix B - Aging Management Programs chemistry technician to assess proper performance and radiation control practices. No deficiencies associated with the sampling process were identified. This example provides objective evidence that a) assessments are performed to verify the effectiveness of program execution, b) deficiencies are documented in the corrective action process, and c) assessment deficiencies are evaluated and corrective actions implemented to maintain program effectiveness.

3. In May 2006, routine water chemistry monitoring identified a high chloride concentration in the reactor coolant system (RCS). The chloride level exceeded the plant administrative goal of 20 ppb for RCS chlorides, but was below the level 1, 2, and 3 limits, established in accordance with the EPRI PWR Primary Water Chemistry Guidelines and Technical Specifications. A plant event and/or an incorrect analytical result were ruled out as causes of the condition. TMI site and corporate chemistry staffs participated in identifying the cause of the higher-than-goal chloride concentration as chloride elution from the in-service make-up and purification demineralizer. Multiple recovery options were considered. The chosen recovery plan called for replacing the resin in the make-up and purification demineralizer and returning it to service to remove chlorides from the RCS. An engineering review was performed to ensure the effectiveness of the plan. The corrective actions were implemented and the chloride concentration was successfully reduced below the administrative goal. This example provides objective evidence that a) deficiencies found during water chemistry monitoring activities are documented in the corrective action process, and b) water chemistry monitoring activity deficiencies are evaluated and corrective actions are properly implemented to maintain system intended functions.

Conclusion The enhanced Water Chemistry aging management program, supplemented by the One-Time Inspection Program (B.2.1.18), provides reasonable assurance that cracking, denting, loss of material, reduction of heat transfer, and reduction of neutron-absorbing capacity aging effects will be managed such that the systems and components with the scope of the program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.3 REACTOR HEAD CLOSURE STUDS Program Description The Reactor Head Closure Studs Aging Management Program is an existing program that provides for ASME Section XI inspections of reactor head closure studs and stud components to identify and manage cracking due to stress corrosion cracking, and loss of material due to wear, general, pitting and crevice corrosion. The program is implemented through station procedures based on the examination and inspection requirements specified in ASME Section XI Table, IWB-2500-1 and preventive measures described in NRC Regulatory Guide 1.65, Materials and Inspection for Reactor Vessel Closure Studs.

NUREG-1801 Consistency The Reactor Head Closure Studs Aging Management Program is consistent with NUREG-1801 Section XI.M3, Reactor Head Closure Studs, with the following exceptions:

Exceptions to NUREG-1801

• NUREG-1801, XI.M3, specifies the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda. The current TMI-1 ISI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

• NUREG-1801, X1.M3, specifies that surface examination uses magnetic particle, liquid penetration, or eddy current examinations to indicate the presence of surface discontinuities and flaws in the reactor head closure studs. The current TMI-1 ISI program for the third interval does not require surface examination. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

Enhancements None.

Operating Experience The Reactor Head Closure Studs Aging Management Program is implemented through the ASME Section XI, Subsections IWB, IWC and IWD, ISI Program that monitors the condition of the closure studs and stud components. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, and by inclusion the Reactor Head Closure Studs Program, is implemented and maintained in accordance with the general requirements for Three Mile Island Nuclear Station Unit 1 Page B-19 License Renewal Application

Appendix B - Aging Management Programs engineering programs. This provides assurance that the programs are effectively implemented to meet regulatory, process, and procedure requirements, including periodic reviews; qualified personnel are assigned as program managers, and are given authority and responsibility to implement the program; and adequate resources are committed to program activities.

A search of condition reports and ISI history was conducted, and no reports documenting deficiencies or problems with reactor head closure studs or stud components, or the Reactor Head Closure Studs Program, were found. The following examples of operating experience provide objective evidence that the Reactor Head Closure Studs program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. Reactor Closure Head Studs and Bolts 21 through 40 were UT and VT-1 examined during the Fall of 2005 with no reportable indications.

2. Reactor Closure Head Studs and Bolts 41 through 60 were UT, MT and VT-1 examined during the Fall of 2003 with no reportable indications.

3. Reactor Closure Head Studs and Bolts 41 through 60 were UT and MT examined during the Fall of 1999 with no reportable indications.

4. Reactor Closure Head Studs and Bolts 1 through 20 were MT examined in the Fall of 1991, and UT examined in the Fall of 1993 with no reportable indications.

Based on these results, the operating experience provides evidence that the ASME Section XI, Subsections IWB, IWC and IWD, ISI Program and maintenance practices are ensuring the continuing integrity of the reactor head closure studs and stud components.

Conclusion The Reactor Head Closure Studs program provides reasonable assurance that cracking and loss of material aging effects are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.4 BORIC ACID CORROSION Program Description The Boric Acid Corrosion aging management program is an existing program that provides for management of loss of material due to boric acid corrosion.

The program includes provisions to identify, inspect, examine and evaluate leakage, and initiate corrective action. The program relies in part on implementation of recommendations of NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Components in PWR plants and includes visual examinations of Alloy 600 components for stress corrosion cracking due to boric acid leakage.

NUREG-1801 Consistency The TMI-1 Boric Acid Corrosion program is an existing program that is consistent with NUREG-1801 aging management program XI.M10, Boric Acid Corrosion.

Exceptions to NUREG-1801 None Enhancements None Operating Experience Industry operating experience indicates that boric acid leakage can cause significant corrosion damage to susceptible plant structures and components.

The performance indicators for the TMI-1 Boric Acid Corrosion program show that the program is compliant with existing regulations and will be able to manage boric acid corrosion during the period of extended operation.

1. In November 2006, an active borated water leak was identified dripping from a reactor coolant valve threaded fitting. The leak produced boron crystal buildup on the fitting, piping, and grating below the fitting. The threaded fitting was repaired and the fitting and target piping and grating were cleaned. No degradation due to the borated water leakage was identified. The fitting was inspected again and no further leaking was detected.

2. Wet boron buildup was discovered in November 2006 on a differential pressure transmitter and other target components. The source of the leak was from a weeping relief valve through a stainless steel tailpipe onto grating, a stainless steel transmitter, and the concrete floor. The general area where the boric acid leak was occurring was inspected and no corrosion was observed. The majority of the components are stainless steel. There was no significant corrosion concern for the carbon steel components Three Mile Island Nuclear Station Unit 1 Page B-21 License Renewal Application

Appendix B - Aging Management Programs because of the ambient conditions. The leak from the relief valve (MU-V-158D) was repaired and the target areas were cleaned.

3. In November 2005, corrosion on the Reactor Building Emergency Cooling flanges (both the normal supply and drain lines) was detected. Samples of the material in the flange areas were obtained but the chemistry analysis did not positively indicate any boron in the material. It was assumed that the source of the leakage may have been from an old reactor coolant pump leak several years before. The boric acid would have been diluted to the point that it could not be found in the samples. The leakage caused only surface corrosion and the affected areas were cleaned.

4. A Focused Area Self Assessment (FASA) of the Boric Acid Corrosion program was performed in December 2005. The FASA team evaluated areas including procedure compliance and technical rigor, program implementation effectiveness, program continuous improvement, program organization and human performance, and compliance to regulatory requirements. The FASA team concluded that TMIs performance in all areas reviewed was satisfactory. The team noted no deficiencies, fourteen recommendations for improvement, and one strength. Recommendations are tracked and evaluated for inclusion into the program. This example provides objective evidence that the program is updated as necessary to ensure that it remains effective for condition monitoring of structures and components within the scope of license renewal.

The operating experience of the Boric Acid Corrosion program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Boric Acid Corrosion program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Boric Acid Corrosion program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The existing Boric Acid Corrosion program provides reasonable assurance that the identified aging effects are adequately managed so that the intended functions of structures and components within the scope license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.5 NICKEL-ALLOY PENETRATION NOZZLES WELDED TO THE UPPER REACTOR VESSEL CLOSURE HEADS OF PRESSURIZED WATER REACTORS Program Description The program for Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (Upper Head Nickel Alloy AMP) is an existing program that was developed by TMI-1 to respond to NRC Order EA-03-009. The Upper Head Nickel Alloy AMP provides for the management of cracking due to PWSCC in nickel-alloy vessel head penetration nozzles and includes the reactor vessel closure head, upper vessel head penetration nozzles and associated welds.

Detection of cracking, including cracking induced by PWSCC, is accomplished through implementation of a combination of bare metal visual examination and non-visual examination techniques. Examinations are performed by VT-2 certified personnel. Inspections completed to date have indicated no evidence of PWSCC in the vessel head penetration nozzles. Evaluations from the Fall 2005 refueling outage show a susceptibility ranking of "Low. Since TMI-1 replaced the head in 2003, the EA 03-009 ranking is Replaced, however the inspection requirements for Low and Replaced are the same. Plants in the "Low" or Replaced category require bare metal visual inspections at least once every third refueling outage or every five years, whichever comes first, and ultrasonic, eddy current, or dye penetrant testing every fourth refueling outage or every seven years, whichever comes first. Non-destructive examinations of the reactor pressure vessel head penetration nozzles and associated welds were performed on the new head prior to the Fall 2003 refueling outage when the reactor vessel upper head was replaced.

NUREG-1801 Consistency The TMI-1 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors aging management program is consistent with the ten elements of NUREG-1801 aging management program XI.M11A, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors.

Exceptions to NUREG-1801 None.

Enhancements None.

Operating Experience PWSCC is occurring in the VHP nozzles of U.S. PWRs, as described in the program description above. In addition, applicants for license renewal should reference plant-specific operating experience that is applicable to PWSCC of Three Mile Island Nuclear Station Unit 1 Page B-23 License Renewal Application

Appendix B - Aging Management Programs its VHP nozzles. Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that PWSCC of upper VHP nozzles is being adequately managed. The following examples of operating experience provide objective evidence that the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. During the Fall 2005 refueling outage, minor boric acid deposits were visible during the video inspection at three CRD flanges.

Deposits were dry with no significant buildup, and deposit colors were white and brown. Several dry semi-translucent boron drops were seen on the CRDM nozzles. No boron leakage targets were noted, and the deposits were small enough that they had not migrated beyond the flanges. No degradation was evident on the CRD surfaces. The video results were reviewed and the conditions noted for comparison during subsequent inspections.

The VT-2 inspection report identified evidence of leakage from above with no boron noted at the flange areas. Based on this VT-2 report and supporting video, the leakage locations were not considered to be bolted flange connection leaks and did not require repair.

The inspection found evidence of possible leakage at the CRD flanges, the issue was entered into and evaluated by the Corrective Action Process. As a result, one flange was reworked and no further leakage was found.

2. During the Fall 2005 refueling outage, a thin white film or streaking of boron was observed starting from the upper portion of the reactor head surface near a CRDM nozzle and running eastward to the lower/outer portion of the reactor head. Still photos were taken of the affected area. Two CRDMs had minor boron film running down from the above insulation. The insulation around the two CRDM nozzles and along nearby insulation seams had a heavier film of boron. The remaining reactor head bare metal surfaces did not have any other indication of boric acid staining. No indication of any corrosion was seen. The site performed one hundred percent VT-2 inspection of the reactor vessel head. The leakage appeared to be coming from an active Intermediate Closed Cooling water leak.

One of the CRDM venting locations is a CRDM that was identified with boron staining. Inspections previously identified water on the reactor head insulation just east of the venting CRDMs that corresponded to the area directly above the noted reactor head bare metal streaks. TMI-1 performed visual examination of remaining portions of reactor head bare metal surfaces and CRDM nozzles and no other evidence of leakage was observed. The site also Three Mile Island Nuclear Station Unit 1 Page B-24 License Renewal Application

Appendix B - Aging Management Programs researched the previous refueling outage history for previous leakage at the reactor head area.

TMI-1 then performed an augmented ISI visual examination of the bolted CRDM flange connection when the reactor head was on the storage stand. Boron staining/film was cleaned to the extent possible to eliminate confusion during future bare metal reactor vessel head examinations. The gasket was replaced on one drive, and no further leakage was found.

3. A visual inspection of the Reactor Vessel Head Control Rod Drive Mechanism (CRDM) nozzle penetrations was performed in October 2001 (prior to replacement of the RPV head in the fall of 2003).

From the visual inspection, twelve (12) CRDM nozzles were categorized as "suspect" due to residual boric acid deposits around the base of the nozzles. These "suspect" CRDM nozzles were subsequently examined using liquid penetrant testing (PT) and ultrasonic testing (UT) to obtain additional information for determination of through-wall nozzle defects. PT indications were identified on the j-groove weld associated with four CRDM nozzles.

An ultrasonic test (UT) of a Reactor Vessel Head Control Rod Drive Mechanism (CRDM) nozzle penetration was performed on October 19, 2001. The UT results indicated that the CRDM nozzle had 5 inner diameter (ID) flaws, none of which were through-wall. This nozzle had no J-groove weld PT indication.

This condition is consistent with industry experience with Primary Water Stress Corrosion Cracking (PWSCC) in reactor vessel head nozzles that have been evaluated as part of the NRC Generic Letter 97-01 and NRC Bulletin 2001-01. Reactor Vessel Head CRDM nozzle repair plans were developed and implemented prior to restart. The issue was self identified from visual, PT, and UT inspections of the Reactor Vessel Head nozzle penetrations (CRDM). A modification was designed to repair CRDM nozzles.

CRDM nozzles were repaired as prescribed. Subsequently, the RPV head was replaced in Fall 2003.

The operating experience of the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found.

Periodic self-assessments of the program are performed to identify the areas that need improvement to maintain the quality performance of the program.

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Appendix B - Aging Management Programs Conclusion The TMI-1 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors aging management program is credited for managing PWSCC of upper VHP nozzles.

The continued implementation of the TMI-1 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors aging management program provides reasonable assurance that PWSCC of upper VHP nozzles will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.6 FLOW-ACCELERATED CORROSION Program Description The Flow-Accelerated Corrosion (FAC) aging management program is an existing program that is based on EPRI guidelines in NSAC-202L-R3, Recommendations for an Effective Flow Accelerated Corrosion Program. The program provides for predicting, detecting, and monitoring wall thinning in piping, fittings, valve bodies, and feedwater heaters due to FAC.

Analytical evaluations and periodic examinations of locations that are most susceptible to wall thinning due to FAC are used to predict the amount of wall thinning in pipes, fittings, and feedwater heater shells. Program activities include analyses to determine critical locations, baseline inspections to determine the extent of thinning at these critical locations, and follow-up inspections to confirm the predictions. Inspections are performed using ultrasonic, radiographic, visual or other approved testing techniques capable of detecting wall thinning. Repairs and replacements are performed as necessary.

NUREG-1801 Consistency Program activities are consistent with the elements of aging program XI.M17, "Flow-Accelerated Corrosion," specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 specifies in XI.M17 that the program relies on implementation of the Electric Power Research Institute (EPRI) guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R2 for an effective FAC program. The TMI-1 FAC Program is based on the EPRI guidelines found in NSAC-202L-R3. The sections of NSAC-202L associated with the program elements were reviewed to show that revision 2 and 3 of the guidelines are equivalent with one difference: revision 3 allows an additional method for determining the wear of piping components from UT inspection. This method is called the Averaged Band Method. TMI-1 does not use this method at this time.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that wall thinning due to flow-accelerated corrosion is being adequately managed. The following examples of operating experience provide objective evidence that the Flow-Accelerated Corrosion program will be effective in assuring that intended function(s) would be maintained consistent with the CLB for the period of extended operation:

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Appendix B - Aging Management Programs

1. During the 2003 refueling outage, FAC inspections of several components were found to be thin. These components were analyzed to establish a safe life expectancy until 2005. These components were replaced in 2005. In addition, some components were experiencing high wear rates and were changed to a resistant material in 2005. Detailed stress analysis was performed to determine if the components would have to be changed out then or could last until the next outage in 2007. The FAC program manager stated that these components have been evaluated using the FAC evaluation model and are acceptable for continued service until the next refueling outage. The FAC program manager initiated the necessary ARs to include these items into the scope for 2007.

2. While at the semi-annual CHECKWORKS user group meeting in 2005 the FAC program manager performed benchmarking activities.

Numerous areas for improvement and areas for consideration were noted. All benchmarking items were incorporated into the FAC Notebook. Items were assessed and action taken on items applicable to TMI-1. Specific items dealt with subjects like weld degradation, low temperature FAC, margins, purchase of Cr (chromium) Analyzer and improved accuracy in wear predictions from single point data.

3. A FAC component in the line from the heater drain pump discharge to the main feedwater pump suction header was found thin. This FAC component was examined in 2005 as part of the remedial actions due to the high fluid velocities experienced in this line when the valve was isolated. This component has a predicted wear rate of 5.3 mils per year. This wear rate prediction is based on one set of data and an assumed starting point for the original wall thickness. It was determined this wear rate extended over the next two years would require 10.6 mils more than the required minimum thickness.

With the current minimum thickness value this component would not make it to 2007. A calculation for wear rate and the use of code case N-513 was applied. The component was found to be acceptable until 2007 with code case N-513 applied.

4. TMI-1 added to the FAC program scope the Main Feedwater Pump (MFP) recirculation lines in 2003. Wall thinning was found in the MFP recirculation lines in 2003 and 2005. The source of wear in the MFP recirculation lines was not caused by FAC. Repairs have been made to the lines.

The operating experience of the Flow-Accelerated Corrosion program did not show any adverse trend in performance. The FAC Program prediction capability at TMI-1 has been successful in finding wear early enough so that the repairs can be scheduled in a future outage. Also, no system or large bore (4" and greater) failures have been experienced due to FAC. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Flow-Accelerated Corrosion Three Mile Island Nuclear Station Unit 1 Page B-28 License Renewal Application

Appendix B - Aging Management Programs program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Flow-Accelerated Corrosion program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The FAC aging management program provides reasonable assurance that wall thinning aging effects are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.7 BOLTING INTEGRITY Program Description The Bolting Integrity aging management program is an existing program that provides for condition monitoring of pressure retaining bolted joints within the scope of license renewal. The Bolting Integrity program incorporates NRC and industry recommendations delineated in NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants, EPRI TR-104213, Bolted Joint Maintenance & Applications Guide, and EPRI NP 5769, Degradation and Failure of Bolting in Nuclear Power Plants, as part of the comprehensive corporate component pressure retaining bolting program.

The program provides for managing the loss of material due to general, pitting and crevice corrosion, microbiologically influenced corrosion and loss of preload due to thermal effects, gasket creep, and self-loosening, by performing visual inspections for pressure retaining bolted joint leakage. Inspection of ASME Class 1, 2, and 3 components is conducted in accordance with ASME Section XI. Non-Class 1, 2, and 3 component inspections rely on detection of visible leakage during routine observations and equipment maintenance activities. Procurement controls and installation practices, defined in plant procedures, ensure that only approved lubricants and torque are applied. The activities are implemented through station procedures. Other aging management programs also manage inspection of bolting and supplement this bolting integrity program. Structural bolting is managed as part of the Structures Monitoring aging management program. TMI does not use structure bolting with yield strength of greater than or equal to 150 ksi. Containment pressure retaining bolting is addressed by ASME Section XI, Subsection IWE, B.2.1.24. ASME Section XI, Subsection IWF aging management program, B.2.1.26, addresses aging management of ASME Section Class 1,2 & 3 piping and component supports. The aging management of crane and hoist bolting is covered by B.2.1.11, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems. Aging Management of heating and ventilation bolted joints is coved by B.2.1.21, External Surfaces Monitoring.

NUREG-1801 Consistency The Bolting Integrity aging management program is consistent with the ten elements of aging management program XI.M18, "Bolting Integrity," specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

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Appendix B - Aging Management Programs Operating Experience TMI-1 has experienced isolated cases of bolt corrosion, loss of bolt preload and bolt torquing issues. Review of operating history has not identified any cracking of stainless steel bolting. In all cases, the existing inspection and testing methodologies have discovered the deficiencies and corrective actions were implemented prior to loss of system or component intended functions.

1. Boron deposits were discovered on a partially insulated Make-up valve bonnet. The leak was not active at the time. One visible bonnet bolt had mild corrosion. A work activity was generated to remove the insulation and clean, inspect and correct as needed.

Engineering inspected and determined that the necessary repair is replacement of the diaphragm gasket, and replacement of the bonnet studs if there has been any wastage. Work requires the system to be out of service and is scheduled for the next outage.

2. During an In-service Test (IST) run for Decay Heat Removal pump two issues were discovered. One involved the mechanical seal nuts. One of the four nuts did not have positive thread engagement.

The second issue involved a loose nut on the pump frame. An Engineering evaluation of thread engagement and stress on the pump confirmed that the 3 fully engaged nuts provided adequate strength to hold the mechanical seal firmly in place when holding against maximum internal pressure. An assessment was made of 10 Condition Reports (CR's) for extent of condition for thread engagement. Information found during the investigation phase has been shared within maintenance. Specific attention was placed on recognition of issues as well as ensuring appropriate engagement is occurring during ongoing maintenance activities.

3. The emergency diesel generator exhaust manifold leaked oil on both control side and opposite control side of the engine. The manifolds leaked more than normal amounts of oil for approximately 3-4 days after the diesel was operated. The amount of leakage increased on both diesels after 1-2 runs on the new manifold gaskets. All bolts were visually checked to ensure full engagement via extent of condition checks on both diesels.

The operating experience of the Bolting Integrity program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Bolting Integrity program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Bolting Integrity program are performed to identify the areas that need improvement to maintain the quality performance of the program.

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Appendix B - Aging Management Programs Conclusion The Bolting Integrity aging management program provides reasonable assurance that aging effects are adequately managed so that the intended functions of bolting for pressure retaining joints within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.8 STEAM GENERATOR TUBE INTEGRITY Program Description The Steam Generator Tube Integrity program is an existing program that establishes the operation, maintenance, testing, inspection and repair of the steam generators to ensure that Technical Specification surveillance requirements, ASME Code requirements and the Maintenance Rule performance criteria are met. The program provides for identifying, maintaining and protecting the steam generator design and licensing bases and implements NEI 97-06. NEI 97-06 establishes a framework for prevention, inspection, evaluation, repair and leakage monitoring measures.

TMI-1 will replace the original Once-Through Steam Generators (OTSGs) with enhanced OTSGs prior to the period of extended operation. This decision was made based on industry and TMI-1 experience with tube degradation. The new OTSGs have improved design features including Alloy 690 tubes. The new OTSGs will have a design life of 40 years, which along with the Steam Generator Tube Integrity program will be effective in assuring that the intended functions will be maintained consistent with the CLB for the period of extended operation. The Steam Generator Tube Integrity program will continue when the new OTSGs are installed. The Steam Generator Tube Integrity program implements NEI 97-06 and the TMI-1 Technical Specification Surveillance Requirements, and is equally applicable to OTSGs with degraded tubes and to the new OTSGs.

NUREG-1801 Consistency The Steam Generator Tube Integrity Aging Management Program is an existing program that is consistent with NUREG-1801 aging management program XI.M19, Steam Generator Tube Integrity.

Exceptions to NUREG-1801 None.

Enhancements None. The existing Steam Generator Tube Integrity program will be applied as described for the new OTSGs.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking due to stress corrosion cracking, including intergranular attack, denting due to corrosion of carbon steel tubesheet, and loss of material due to fretting and wear are being adequately managed. The following examples of operating experience provide objective evidence that the Steam Generator Tube Integrity program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

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Appendix B - Aging Management Programs

1. Widespread inside diameter intergranular attack (ID IGA) was identified in the early 1980s, mostly near the upper end of the OTSG tubing. The degradation was determined to have occurred during a chemistry excursion while the plant was in a shutdown condition.

Repairs were performed using a kinetic expansion process that formed a new tube to tubesheet joint within the upper tubesheet.

The repair was reviewed and approved by the NRC in 1983. Since that time, TMI-1 has specified inspection acceptance criteria and leakage assessment methodology for the TMI-1 OTSG kinetic expansion joints that is unique to TMI-1. This inspection acceptance criteria and leakage assessment methodology has been reviewed and accepted by the NRC. During refueling outage 16 (Fall 2005), the kinetic expansion joints were inspected. These inspections found no growth of flaws in the kinetic expansion joints, and no trend of ongoing degradation due to ID IGA.

2. TMI-1 will replace the OTSGs with enhanced OTSGs prior to the period of extended operation. This decision was made based on industry and TMI-1 experience with tube degradation. During refueling outage 16 (Fall 2005), 100 tubes in A OTSG and 106 tubes in B OTSG were plugged due to unacceptable indications.

The inspections during this outage concluded that groove IGA, primary water stress corrosion cracking (PWSCC), outside diameter stress corrosion cracking (OD SCC) are active damage mechanisms. The results of TMI-1 tube inspections indicate increasing tube degradation and the probability of mid-cycle outages for inspection prior to the end of the current license. Currently, the A OTSG has 1661 plugged tubes and 247 sleeved tubes are in service. The B OTSG has 971 plugged tubes and 252 sleeved tubes are in service. The degradation mechanisms that have been identified historically in the current OTSGs include PWSCC, ID IGA, Intergranular stress corrosion cracking (IGSCC), outside diameter intergranular attack (OD IGA), High Cycle Fatigue, OD SCC, Tube-to-Tube Support Plate Wear Fretting and Severed Plugged Tube-to-Tube wear. However, the overall tube integrity meets all of the requirements of the current licensing basis. The new OTSGs will have a design life of 40 years, which along with the Steam Generator Tube Integrity program will be effective in assuring that the intended functions will be maintained consistent with the CLB for the period of extended operation.

3. TMI-1 has incorporated a Technical Specification change to implement the requirements of Generic Letter 2006-01 and the associated alternative Technical Specification requirements for ensuring tube integrity. Generic Letter 2006-01 required that all PWRs implement the alternative Technical Specification requirements or submit a description of their program for ensuring tube integrity. The Generic Letter indicated that existing Technical Specifications may not be sufficient to ensure that steam generator tube integrity can be maintained in accordance with current Three Mile Island Nuclear Station Unit 1 Page B-34 License Renewal Application

Appendix B - Aging Management Programs licensing and design basis. The revised Technical Specifications incorporate improved methodology based on NEI 97-06.

The operating experience of the TMI-1 Steam Generator Tube Integrity program has shown objective evidence that the program has identified degradation mechanisms in the steam generator and been effective in preventing failures prior to the loss of system intended function. There is sufficient confidence that the implementation of the Steam Generator Tube Integrity program will continue to effectively identify degradation prior to failure.

Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Steam Generator Tube Integrity program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The Steam Generator Tube Integrity program provides reasonable assurance that cracking and loss of material aging effects are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.9 OPEN-CYCLE COOLING WATER SYSTEM Program Description The TMI-1 Open-Cycle Cooling Water System aging management program is an existing program.

The GL 89-13 activities provide for management of aging effects in raw water cooling systems through tests and inspections per the guidelines of NRC Generic Letter 89-13. System and component testing, visual inspections, NDE (RT, UT, and/or ECT-Eddy Current Testing), and chemical treatment are conducted to ensure that aging effects are managed such that system and component intended functions and integrity are maintained.

The TMI-1 Open-Cycle Cooling Water System (OCCWS) aging management program (AMP) primarily consists of station GL 89-13 activities that include chemical and biocide injection, system testing, periodic inspections and NDE.

The program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW system or structures and components serviced by the OCCW system. Other activities include station maintenance inspections, component preventive maintenance (PM), plant surveillance testing, ISI, and inspections. These activities provide for management of loss of material (without credit for protective coatings) and buildup of deposit (including fouling from biological, corrosion product, and external sources) aging effects where applicable in system components exposed to a raw water environment.

Corporate and station procedures provide instructions and controls for preventive actions through raw water chemistry control (chemical and biocide injection), performance monitoring through station testing, and condition-monitoring and leak detection through inspection and testing of TMI-1 raw water systems in the scope of license renewal. The TMI-1 Inservice Pressure Testing Program provides for periodic leakage detection of aboveground and buried piping and components as well as inspection of aboveground piping and components.

OCCWS AMP testing and inspections at TMI-1 have detected buildup of deposit and loss of material aging effects in raw water system components prior to loss of system intended functions. GL 89-13 program assessments have been performed, and corrective actions have been implemented.

For heat exchangers, an aging management program that uses multiple attributes is considered necessary to effectively address all aging effects.

These AMP activities provide input into a total program that includes primary and secondary operating fluid chemistry controls, performance monitoring and inspections of all heat exchangers in the scope of license renewal at TMI-1 to manage loss of material, and buildup of deposit where applicable.

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Appendix B - Aging Management Programs NUREG-1801 Consistency The Open-Cycle Cooling Water System aging management program is consistent with the ten elements of aging management program XI.M20, Open-Cycle Cooling Water System, specified in NUREG-1801 with the following exceptions:

Exceptions to NUREG-1801 NUREG-1801 program scope consists of preventive measures to mitigate the aging effects of material loss and fouling due to micro- or macro-organisms and various corrosion mechanisms. The TMI-1 Open-Cycle Cooling Water System aging management program will also be used to manage the following aging effects and mechanisms for the internal surfaces of concrete circulating water piping:

• Cracking and expansion due to reaction with aggregates

• Cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel

• Increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack

• Increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide The TMI-1 Open-Cycle Cooling Water System aging management program activities are adequate for managing the aging effects of the internal surfaces of concrete circulating water piping.

Enhancements A new river water chemical treatment system will be installed to treat the river water systems for biofouling, including microbiologically-influenced (MIC) corrosion.

Operating Experience Significant microbiologically-influenced corrosion (MIC), failure of protective coatings, and fouling have been observed in a number of heat exchangers. The guidance of NRC GL 89-13 has been implemented for approximately 10 years and has been effective in managing aging effects due to biofouling, corrosion, erosion, protective coating failures, and silting in structures and components serviced by OCCW systems. Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, and fouling, reduction of heat transfer due to fouling, cracking and expansion due to reaction with aggregates, cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide are being adequately managed.

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Appendix B - Aging Management Programs The following examples of operating experience provide objective evidence that the Open-Cycle Cooling Water System program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. In November 2001, routine eddy current testing was performed on the 1B intermediate closed cooling water heat exchanger. The test results identified indications in 10 of the 369 tubes inspected. The indications ranged from 21% to 50% through-wall with two indications greater than 45% though-wall. After further NDE was performed, the two tubes with the larger indication were plugged to reduce risk of possible leakage during the next operating cycle.

Since there were no through-wall leaks, the degraded condition of the tubes had no impact on plant operation during the previous cycle.

An apparent cause evaluation was performed to determine the cause of the tube degradation. Review of maintenance history for the heat exchanger showed that 8 of the 10 tubes with indications were newly installed during the previous refueling outage. The early degradation of the tubes indicated the presence of a rapid pitting mechanism inside the heat exchanger. The evaluation concluded that the most significant mode of degradation was under-deposit corrosion, based the identification of silt in lower half of the heat exchanger. MIC or MIC-related ammonia-induced cracking was considered a contributing mode of degradation, as seasonal ammonia is present in the river. This operating experience example provides objective evidence that a) routine testing and NDE is effective at identifying degradation in cooling water systems in a timely manner; b) OCCW system deficiencies are evaluated and corrective actions are properly implemented to maintain system intended functions, and; c) deficiencies associated with OCCW inspection and activities are documented in the corrective action process.

2. In June 2002, a thru wall leak was identified in the 30-inch circulating water pipe upstream of valve CW-V-13C. The leak size was estimated to be approximately 1 gpm. Indications on the top surface of the pipe suggested microbiologically influenced corrosion (MIC) was the likely cause of the leak. Technical evaluation of the condition concluded that the flaw did not jeopardize the capabilities of the circulating water system. The system provides cooling water to the main condenser and the feedwater pump turbine condensers.

Evaluation of the leak took into consideration the effects of other leaks previously identified in this system. Due to orientation and location of the leak, there was no impact on nearby equipment including valve motor operators. An extent of condition review identified other action items addressing repair of piping upstream of valves CW-V-13C and CW-V-13D. Repairs were completed in the T1R15 outage. This operating experience provides objective evidence that a) a history of MIC exists at TMI-1; b) flaws caused by Three Mile Island Nuclear Station Unit 1 Page B-38 License Renewal Application

Appendix B - Aging Management Programs MIC are identified and properly evaluated for impact on plant operation, and; c) that repairs are scheduled and performed in a timely manner.

3. In December 2005, a microbiologically-influenced corrosion, (MIC) leak was discovered in the Nuclear River - Secondary River cross connect line. The leak was in a carbon steel pipe in a low flow area.

UT was performed on the leak area a few weeks after it was discovered, and results showed acceptable wall thickness except at the location of the leak. Per the ASME code case, UT examinations are required every 90 days until the leak is repaired. Subsequent UT examinations showed no further degradation beyond the original failure. The piping where the leak occurred was replaced during the outage in the fall of 2007. This operating experience provides objective evidence that a) flaws caused by MIC are identified and properly evaluated for impact on plant operation, b) deficiencies associated with OCCW inspection and activities are documented in the corrective action process, and; c) that repairs are scheduled and performed in a timely manner.

Problems identified in the operating experience of the Open-Cycle Cooling Water System program would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence.

There is sufficient confidence that the implementation of the Open-Cycle Cooling Water System program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Open-Cycle Cooling Water System program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The enhanced Open-Cycle Cooling Water System program will provide reasonable assurance that the identified aging effects are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.10 CLOSED-CYCLE COOLING WATER SYSTEM Program Description The Closed-Cycle Cooling Water System aging management program is an existing program that provides for managing aging of piping, piping components, piping elements and heat exchangers that are included in the scope of license renewal for loss of material and reduction of heat transfer and are exposed to a closed cooling water environment at TMI-1. The program provides for preventive, performance monitoring and condition monitoring activities that are implemented through station procedures. Preventive activities include measures to maintain water purity and the addition of corrosion inhibitors to minimize corrosion based on EPRI 1007820.

Performance monitoring provides indications of degradation in closed-cycle cooling water systems, with plant operating conditions providing indications of degradation in normally operating systems. In addition, station maintenance inspections and nondestructive examination (NDE) provide condition monitoring of heat exchangers exposed to closed-cycle cooling water environments.

NUREG-1801 Consistency The Closed Cycle Cooling Water System aging management program is consistent with the ten elements of aging management program XI.M21, Closed Cycle Cooling Water System, specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 refers to EPRI TR-107396 1997 Revision. TMI-1 implements the guidance provided in EPRI 1007820, which is the 2004 Revision to TR-107396.

EPRI periodically updates industry water chemistry guidelines, as new information becomes available. TMI-1 has reviewed EPRI 1007820 and has determined that the most significant difference is that the new revision provides more prescriptive guidance and has a more conservative monitoring approach.

EPRI 1007820 meets the same requirements of EPRI TR-107396 for maintaining conditions to minimize corrosion and microbiological growth in closed cooling water systems for effectively mitigating many aging effects.

Enhancements A one-time inspection of selected components in stagnant flow areas will be conducted to confirm the absence of aging effects resulting from exposure to closed cycle cooling water. Also, a one-time inspection of selected CCCW chemical mix tanks and associated piping components will be performed to verify corrosion has not occurred on the interior surfaces of the tanks and associated piping components.

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Appendix B - Aging Management Programs Operating Experience Degradation of closed-cycle cooling water systems due to corrosion product buildup or through-wall cracks in supply lines has been observed in operating plants. Accordingly, operating experience demonstrates the need for this program. Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking due to stress corrosion cracking, loss of material due to general, pitting, crevice, and galvanic corrosion, and reduction of heat transfer due to fouling are being adequately managed. The following examples of operating experience provide objective evidence that the Closed-Cycle Cooling Water System program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. In February 2003, molybdate fell below the minimum limit during a system flush of the Decay Heat Closed Cooling Water (DHCCW) system. A chemistry recommendation was written to add molybdate to keep the system concentration above the limit. A follow up sample after the addition showed the molybdate to be above the minimum level.

The molybdate concentration fell below the specification value during a system flush to reduce chloride below the chloride goal concentration. A planned flush was scheduled to decrease the chloride concentration of the system below the goal value. The flush was planned well before the specification concentration for chlorides was reached. This type of flush is needed periodically because the biocides used contribute to the chloride concentration in the system and the chloride builds up after multiple biocide additions. A chemistry recommendation to make a proactive addition of molybdate was generated to minimize out of spec hours that might be encountered when the flushing process started. In addition, an increased monitoring frequency was established to ensure that out of specification hours would be minimized during the flushing process. The molybdate concentration dropped below the minimum value for a short period of time during the flushing process (i.e. nine hours). An evaluation showed that the carbon steel was protected during the nine-hour period of time. In addition, there is no indication that any protective coatings on the system were at risk while the system was brought back into the desired band. In other words, the system was protected during the flush and actions taken to minimize the out of specification hours reduced risk of corrosion during the flush. This operating experience example provides objective evidence that a) routine sampling and chemical analysis of the cooling water is effective at identifying off normal chemistry parameters in a timely manner; b) CCCW chemistry monitoring activity deficiencies are evaluated and corrective actions are properly implemented to maintain system intended functions, and; c) deficiencies associated with CCCW chemistry monitoring activities are documented in the corrective action process.

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Appendix B - Aging Management Programs

2. In early 2002, the closed cooling water (CCCW) chemistry program was converted to nitrite-free treatment to reduce the risk of nitrites being converted to ammonia by microbiological activity. At that time, all CCCW subsystems had biological activity associated with residual sludge. After program conversion, the subsystems ammonia levels were frequently monitored until nitrites were no longer detected in process water. Ion chromatography testing replaced a specific ion electrode testing method to improve testing accuracy. Eventually, ammonia was no longer detected in CCCW subsystems either by TMI plant chemistry or by vendor testing.

However, in December 2002, routine water chemistry monitoring identified a high chloride concentration in the closed cooling water subsystems. The ammonia level exceeded the plant administrative goal of 2.0 ppm for closed cooling water for the first time since 1995.

Immediate corrective actions included testing to confirm proper copper corrosion inhibitor concentrations and issuing recommendations to flush the three affected subsystems to reduce ammonia concentrations. Additionally, a detailed system review was performed to determine if any connecting or interfacing plant systems could add ammonia to the closed cooling water subsystems. The review showed that no interfacing systems or components were sources of ammonia. The ion chromatography analytical procedure was also reviewed and tested for accuracy correctness. Samples of the two biocides routinely added to the subsystems were mixed at normal treatment concentration and tested for ammonia using ion chromatography procedure. Both products tested positive for ammonia. Each showed concentrations of ammonia similar to those measured in the three affected subsystems. Corrective actions included reducing ammonia levels in the CCCW subsystems to normal levels and improving the product evaluation and procurement procedures used for the purchase of new treatment chemicals.

This operating experience example provides objective evidence that a) CCCW chemical monitoring processes are upgraded to improve effectiveness; b) routine sampling and chemical analysis of the cooling water is effective at identifying off normal chemistry parameters in a timely manner. c) CCCW chemistry monitoring activity deficiencies are evaluated and corrective actions are properly implemented to maintain system intended functions, and d) deficiencies associated with CCCW chemistry monitoring activities are documented in the corrective action process.

3. In May 2002, weekly chemistry analysis of closed cooling systems resulted in pH levels in three closed cooling systems below the specification limit. Chemistry recommendations were initiated to add sodium hydroxide to increase pH values over the next two days.

Follow-up testing showed the pH returned to acceptable levels.

This operating experience example provides objective evidence that routine sampling and chemical analysis of the cooling water is Three Mile Island Nuclear Station Unit 1 Page B-42 License Renewal Application

Appendix B - Aging Management Programs effective at identifying off normal chemistry parameters in a timely manner.

TMI-1 has had no instances of closed-cycle cooling water system chemistry sample results out of specification since 2003.

The operating experience of the Closed-Cycle Cooling Water System program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Closed-Cycle Cooling Water System program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Closed-Cycle Cooling Water System program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The enhanced Closed-Cycle Cooling Water System aging management program will provide reasonable assurance that loss of material, cracking, and fouling aging effects are adequately managed so that the intended functions of components exposed to closed-cycle cooling water environments within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.11 INSPECTION OF OVERHEAD HEAVY LOAD AND LIGHT LOAD (RELATED TO REFUELING) HANDLING SYSTEMS Program Description The Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems aging management program is an existing program that provides for periodic visual inspections of cranes and hoists in the scope of 10 CFR 54.4. The program includes structural components that make up the bridge, the trolley, the rail system, structural bolting, and lifting devices, and includes cranes and hoists that meet the provisions of NUREG-0612, Control of Heavy Loads at Nuclear Power Plants.

The aging management program is implemented through station procedures that are based on ASME/ANSI B30.2, B30.16 and rely upon visual inspection to manage loss of material. Structural bolting is monitored for loss of preload by inspecting for loose or missing bolts, or nuts. Inspection frequency is annually for cranes and hoists that are accessible during plant operation and every 2 years for cranes and hoists that are only accessible during refueling outages.

The program will be enhanced to include visual inspection of rails in the rail system for loss of material due to wear, and visual inspection of structural bolting for loss of material due to corrosion. Acceptance criteria will be enhanced to require significant loss of material due to wear or corrosion be evaluated or corrected to ensure the intended function of the crane or hoist is not impacted. The enhancements will be implemented prior to entering the period of extended operation.

NUREG-1801 Consistency With enhancements, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems aging management program is consistent with the ten elements of aging management program XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems," specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements

• The program will be enhanced to require visual inspection of the rails in the rail system for loss of material due to wear.

• The program will be enhanced to require visual inspection of structural bolts for loss of material due to general corrosion.

• Acceptance criteria will be enhanced to require evaluation of significant loss of material due to wear of the rail in the rail system.

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Appendix B - Aging Management Programs Operating Experience

1. In 1997, Wolf Creek discovered polar crane rail clamping plate studs broken. The failures were randomly distributed around the perimeter of the rail and attributed to fatigue. Wolf Creek identified similar failures in 1992 on the polar crane and the turbine building crane. Evaluation by Wolf Creek determined that failure of 5 studs out of 840 studs did not impact the intended function of crane.

Inspections conducted on the TMI-1 polar crane rail system have not identified broken clamping plate studs.

2. In 1995, Trojan Nuclear Plant identified a failed section of reactor building crane rail. Visual, metallographic examination and evaluation of the condition by the licensee concluded that failure was preexisting and was caused by inappropriate use of cutting torch during construction. This operating experience was reported in NRC Information Notice (IN) 96-26, Recent Problems with Overhead Cranes. TMI-1 review of IN 96-26 concluded that no action is required because the problem is attributed to original construction.

3. In 1999, Whiting Corp. issued a 10 CFR Part 21 Notice for the reactor building polar crane. Whiting determined that the main hoist drum-bearing pedestal at the gear end of the drum and the trolley top flange weld in the area of the pedestal might be overstressed.

Whiting recommends a visual and of the pedestal truck weld and top trolley plate web welds for cracks. If cracks or indications are detected Whiting recommended a repair.

In response to the 10 CFR Part 21 Notice, TMI-1 conducted visual examination of the welds as recommended by Whiting. The welds were found to be representative of good workmanship without evidence of any distress, cracking, or distortion, and the weld size result showed that it is in excess of the manufacturers analyzed weld size.

4. A review of approximately 400 TMI-1 corrective action reports (IRs) did not identify history of loss of material due to corrosion in cranes in hoists structural members or loss of material due to wear in the rail system. The IRs were generated to document issues related to active components, procedure noncompliance such as missed inspection frequency, and personnel safety issues. Issue Report No.00181799 was issued to document loose bolts and cracked welds found during the 2003 biannual inspection of the reactor building polar crane as described below.

5. During inspection of the polar crane bridge rail support system (diagonal bracing), bolts were found loose and one support was found to have a cracked weld. This condition was found by visual examination during the periodic inspection of the crane in accordance with procedure R2009396. Additional inspections Three Mile Island Nuclear Station Unit 1 Page B-45 License Renewal Application

Appendix B - Aging Management Programs revealed cracked welds on 4 other pairs of braces for a total of 5 out of 16 pairs of diagonal braces. Engineering investigation for the cause of the loose bolts determined that the condition of the bolts was not due to age related degradation. The bolts were purposely installed loose per design requirements to accommodate thermal expansion of the girder. The cause of the identified cracked welds was not found in the reviewed documentation. However engineering evaluation documented in ECR 03-00872 concluded that the cracked welds in 5 of the 16 lateral braces do not impact the intended function of the polar crane. The polar crane inspection implementing procedure was revised to require visual examination of the welds in each of the 16 lateral (diagonal) braces for new cracks and crack growth each time the crane is inspected in the future.

Conclusion The enhanced Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems aging management program will provide reasonable assurance that loss of material and loss of preload aging effects are adequately managed so that the intended functions of cranes and hoists structural components within the scope of license renewal are maintained consistent with current licensing basis (CLB) during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.12 COMPRESSED AIR MONITORING Program Description The Compressed Air Monitoring aging management program is an existing program that provides for managing the internal surface aging effects of loss of material due to general, pitting and crevice corrosion, and the reduction of heat transfer due to fouling for piping and components in a compressed air system.

The TMI-1 aging management activities consist of preventive and condition-monitoring measures to manage the aging effects.

NUREG-1801 Consistency The TMI-1 Compressed Air Monitoring aging management program is an existing program that is consistent with NUREG-1801 aging management program XI.M24, Compressed Air Monitoring program.

Exceptions to NUREG-1801 None.

Enhancements The Compressed Air Monitoring program will be enhanced to include instrument air system air quality testing for dew point, particulates, lubricant content, and contaminants to ensure that the contamination standards of ANSI/ISA-S7.0.01-1996, paragraph 5 are met. These enhancements will be made to the existing program GL 88-14 Instrument Air Program.

In addition the Compressed Air Monitoring program will be enhanced to include air sampling activities on a representative sampling of headers on a yearly basis in accordance with ASME OM-S/G-1998, Part 17 and EPRI TR-108147.

Enhancements will be implemented prior to entering the period of extended operation.

Operating Experience Industry operating experience indicates that internal degradation can cause significant degradation to susceptible plant components. The following examples of operating experience provide objective evidence that the Compressed Air Monitoring program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation

1. Examples of leakage in the TMI instrument air system were reported in a number of TMI Issue Reports (IR s) initiated from April 2002 to October 2003. Plant personnel found this leakage during the conduct of plant activities not directly associated with instrument air system activities. Examples such as these support the fact that plant personnel are aware of the impact to plant equipment from Three Mile Island Nuclear Station Unit 1 Page B-47 License Renewal Application

Appendix B - Aging Management Programs instrument air leakage and they are routinely identifying leaks. In order to close these IRs the leaks are repaired and if appropriate root cause analysis is performed to minimize reoccurrences.

2. Performance of the air dryers is actively monitored and maintained within acceptance criteria as evidenced by reports initiated between April and June 2004. Operators are continuously monitoring dew point as a part of rounds. When the instrument air quality is not within acceptance limits, corrective actions are immediately taken to resolve the condition.

3. Air quality tests were conducted on other air systems such as Service Air in June 2006. The results of these air quality tests were analyzed for content, reviewed by the system manager and entered into the corrective action process as appropriate. The corrective action process includes an evaluation of these conditions for applicability to other air systems and through this process recommendations are identified that improve instrument air quality in other plant air systems.

Conclusion The enhanced Compressed Air Monitoring aging management program will provide reasonable assurance that the identified aging effects are adequately managed so that the intended functions of components within the scope license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.13 FIRE PROTECTION Program Description The Fire Protection program is an existing program that provides for aging management of various fire protection related components within the scope of License Renewal.

The program provides for visual inspections of fire barrier penetration seals for signs of degradation, such as change in material properties, cracking, and hardening, through periodic inspection, surveillance and maintenance activities.

The program provides for visual inspection of fire barrier walls, ceilings and floors in structures within the scope of license renewal for the aging effects of cracking, and loss of material. Periodic visual inspections of fire doors are performed for signs of degradation such as holes in skin, wear, or missing parts. Fire door clearances are checked during periodic inspections and when fire doors and components are repaired or replaced. Additionally, periodic functional tests of fire doors are performed. The program will provide for managing loss of material aging effects for the fuel oil lines for the TMI-1 diesel-driven fire pumps by the performance of periodic surveillance tests. The program will provide for aging management of external surfaces of the TMI-1 carbon dioxide and halon fire suppression system components through periodic operability tests and visual inspections for corrosion and mechanical damage.

These inspections and tests are implemented through station procedures and recurring task work orders.

NUREG-1801 Consistency The Fire Protection program is consistent with the ten elements of aging management program XI.M26, "Fire Protection," specified in NUREG- 1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 recommends visual inspection and functional testing of the halon and CO2 fire suppression systems at least once every six months.

Procedurally, the TMI-1 halon fire suppression system currently undergoes operational testing and inspections every 18 months, and the TMI-1 low-pressure carbon dioxide fire suppression system undergoes operational testing and inspections every 24 months. Additionally, the halon fire suppression system undergoes more frequent visual inspections for system charge (storage tank pressure at least every 3 months, and storage tank weight at least every 6 months), and the low-pressure carbon dioxide fire suppression system undergoes a visual storage tank level and pressure check at least weekly.

These test frequencies are considered sufficient to ensure system availability and operability based on the stations operating history that shows no aging related events that have adversely affected system operation.

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Appendix B - Aging Management Programs Similar exceptions to the NUREG-1801 recommended frequency for periodic function test of the halon and CO2 fire suppression systems were previously approved by the NRC in NUREG-1796, Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2, and in NUREG-1875, Safety Evaluation Report Related to the License Renewal of Oyster Creek Generating Station. In each case for these plants, periodic functional testing of the halon and CO2 fire suppression systems is currently performed every 18 months.

(Additionally, for Dresden and Quad Cities, the Technical Requirements Manual permits a testing frequency of once every two years.) The NRC staff found that on the basis of plant experience, the testing frequency was adequate for aging management considerations. For these plants, as for TMI-1, station operating history indicated that there were no occurrences of aging related events having adversely affected system operation.

A review of the functional surveillance tests performed for the TMI-1 halon and CO2 systems within the last five years confirmed that there have been no occurrences of aging related events that adversely affected either systems operation.

The December 2006 halon system functional test was completed with all steps satisfactory after an evaluation of a repeated switch actuation required for multiple fan start determined that the switch had not been manually operated properly for the test. No occurrence of any aging related degradation having adversely affected the systems operation was observed. The June 2005 halon system functional was completed with all steps satisfactory. No occurrence of any aging related degradation having adversely affected the systems operation was observed. During the February 2004 halon system functional test, a fan motor failed and required replacement, and a valve limit switch required adjustment to properly indicate the associated valve was fully open. No occurrence of any aging related degradation of passive components having adversely affected the systems operation was observed.

The November 2005 CO2 system functional test was completed with all steps satisfactory. Although an evaluation determined that a damaged fire damper grill was redundant and did not require replacement, the primary grill for the damper is functional for foreign material exclusion and the damper and system are operable. No occurrence of any degradation of passive components due to aging having adversely affected the systems operation was observed. During the November 2003 CO2 system functional test, an electro-thermal link did not fully melt, causing a damper to not fully close. The link was replaced and the test re-performed satisfactorily. A CO2 tank level was found low due to performance of a test and was subsequently re-filled. No occurrence of any aging related degradation having adversely affected the systems operation was observed. The October 2001 CO2 system functional test was competed with all steps satisfactory. No occurrence of any aging related degradation having adversely affected the systems operation was observed.

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Appendix B - Aging Management Programs On the basis of TMI-1 plant experience that no occurrence of any aging related degradation having adversely affected either the halon or the CO2 systems operation has been observed, the test frequencies are considered sufficient to ensure system availability and operability, and are adequate for aging management considerations.

Enhancements The Fire Protection program will be enhanced as follows:

1. The program will provide for additional inspection criteria for degradation of fire barrier walls, ceilings, and floors

2. The program will provide specific fuel supply line inspection criteria for diesel-driven fire pumps during tests Enhancements will be implemented prior to the period of extended operation.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that concrete cracking and spalling due to freeze-thaw, aggressive chemical attack, and reaction with aggregates; loss of material due to corrosion of embedded steel, wear, general, pitting, crevice corrosion, and other means; change in material properties due to various degradation mechanisms; cracking due to various degradation mechanisms; and hardening and loss of strength due to elastomer degradation are being adequately managed. The following examples of operating experience provide objective evidence that the Fire Protection program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. During a fire penetration seal inspection in accordance with procedures in 2006, a seal in the floor of the control room was found degraded. This seal exhibited foam shrinkage, and the RTV sealant applied as a binder between the foam and the curb during seal installation was less than adequate to last the life of the seal. A fire watch was established, the seal was scheduled for repair and the condition corrected. A determination was made to examine all remaining seals of similar size, configuration and environment, and the subject seal was the only one to exhibit the shrinkage problem.

This example provides objective evidence that operating experience regarding foam seal failures is considered when establishing inspection criteria, that foam shrinkage will be detected during walkdown examinations, and that compensatory actions as directed by procedure (fire watch) are enacted.

2. During a Triennial Fire Inspection walkdown in 2002, inspectors noted that fasteners were missing from metal plate closures that connect the metal-clad fire-rated wall to the concrete fire-rated wall in the control building, in some instances causing gaps. An evaluation determined that the operability of the fire barriers and Three Mile Island Nuclear Station Unit 1 Page B-51 License Renewal Application

Appendix B - Aging Management Programs walls was not affected since the gaps were bounded by clearance criteria for rated fire doors, and also because redundant plates on the opposing sides of the wall were intact. The missing fasteners were installed, all similar installations were inspected, and the inspection procedures were revised to direct inspection for similar construction discrepancies. This example provides objective evidence that discrepancies are documented in the corrective action process, and that the program is updated as necessary to ensure that it remains effective in identifying conditions for evaluation and repair in order to maintain component intended functions.

3. A daily surveillance in 2002 identified a degraded condition of a fire door sill plate. Anchors attaching the sill plate were sheared such that the plate was mislocated, causing a gap in excess of allowable acceptance criteria. Per the Fire Protection program, a time clock was initiated and compensatory measures were taken. An evaluation determined a cart or other device passing through the doorway damaged the sill plate. The door was replaced with a new door that achieved required clearance gaps without use of a sill plate, so that the problem would not reoccur. This example provides objective evidence that discrepancies are documented in the corrective action process, that compensatory measures are taken per the program, and that evaluations and repair are performed in order to maintain component intended functions.

4. In 2005, an evaluation of repeated fire door latch failures requiring compensatory fire watches determined that the commercially designed locksets were failing due to severe usage conditions. The evaluation determined that a heavy-duty model designed for institutional service was more appropriate for the high cycling and differential pressure conditions experienced by the subject fire doors. The locksets were replaced resulting in more reliable service. This example provides objective evidence that the programs surveillance activities identify degradations, that degradations are entered into the corrective action process, and that evaluations and repair are performed in order to maintain component intended functions.

5. A review of TMI-1 operating experience has shown no reports of loss of function of the diesel-driven fire pumps as a result of corrosion or degradation of the fuel oil system.

6. In 2005, surveillance identified that a halon system solenoid valve located in the air intake tunnel stuck open after a test actuation. An evaluation determined that the valve, while showing some discoloration due to corrosion, was operable and fully capable of actuating when required to suppress a fire in the air intake tunnel. It was determined that the harsh environment of the air intake tunnel, and the valves inaccessibility in the event of a fire in the tunnel, warranted a proactive replacement of the valve, along with the other similar valves also located in the air intake tunnel. This example Three Mile Island Nuclear Station Unit 1 Page B-52 License Renewal Application

Appendix B - Aging Management Programs provides objective evidence that the programs surveillance activities identify degradations, that degradations are entered into the corrective action process, and that evaluations and repair are performed in order to maintain component intended functions.

In October 2002 and December 2005, two NRC-conducted triennial fire protection inspections were performed at TMI-1. The objective of these inspections was to assess whether TMI-1 has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained. A total of only three findings were cited (two in 2002 and one in 2005), each with a classification of very low safety significance and treated as a non-cited violation.

Conclusion The enhanced Fire Protection program covers various fire protection related components within the scope of license renewal including fire barrier doors, walls, ceilings, floors, and penetration seals. It also covers external surfaces of the halon and carbon dioxide fire suppression system components. In addition, the program covers the fuel oil systems for the diesel-driven fire pumps. The enhanced Fire Protection aging management program will provide reasonable assurance that the aging effects are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.14 FIRE WATER SYSTEM Program Description The Fire Water System program is an existing program that will manage identified aging effects for the water-based fire protection system and associated components, through the use of periodic inspections, monitoring, and performance testing. The program provides for preventive measures and inspection activities to detect aging effects prior to loss of intended functions.

System functional tests, flow tests, flushes and inspections are performed in accordance with guidance from NFPA standards. Fire system main header flow tests are conducted at least once every three years. Hydrant flushing and inspections are conducted at least once every twelve months. The condition of the fire pumps is confirmed once every 18 months by performance of a pump functional test. The Fire Service Head (Altitude) Tank is inspected internally once every 5 years. Sprinkler system inspections are performed at least once every refueling outage. The fire water system is maintained at the required normal operating pressure and monitored such that a loss of system pressure is immediately detected and corrective actions initiated. The system flow testing, visual inspections and volumetric inspections assure that the aging effects of loss of material due to corrosion, microbiologically influenced corrosion (MIC), or biofouling are managed such that the system intended functions are maintained.

NUREG-1801 Consistency The Fire Water System aging management program is consistent with the ten elements of aging management program XI.M27, "Fire Water System,"

specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements The Fire Water System program will be enhanced to include:

1. Periodic non-intrusive wall thickness measurements of selected portions of the fire water system at intervals that do not exceed every 10 years.

2. Sampling of sprinklers in accordance with NFPA 25, Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems, and submitting the samples to a testing laboratory prior to the sprinklers being in service 50 years. Subsequent testing is at intervals that do not exceed every 10 years.

Enhancements will be implemented prior to the period of extended operation, except sprinkler head inspections that will begin prior to sprinklers being in service 50 years.

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Appendix B - Aging Management Programs Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that the loss of material due to general, pitting, crevice and microbiologically influenced corrosion, and fouling are being adequately managed. The following examples of operating experience provide objective evidence that the Fire Water System program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. Following a test run and shut down of the diesel-driven river fire pump in 2005, fire service system pressure lowered until the motor-driven river fire pump auto-started on low fire service header pressure. An investigation indicated an underground piping leak that was successfully isolated and scheduled for repair. The cause of the leak was determined to be environmental mechanical damage (rock bearing on the underground pipe) and subsequently repaired.

This example provides objective evidence that detected degradation is entered into the corrective action process for evaluation and repair prior to loss of intended function, and that the corrective action process effectively determines the cause of the degradation.

2. During performance of fire protection system operations surveillance in 2005, a leak was identified on a threaded elbow. The leak was quantified, evaluated for cause (MIC), and determined to not impact FSAR-described or Technical Specification functions, and to not be reportable. The condition was subsequently repaired. This example provides objective evidence that the program provides for detection of degradation, that degradation is entered into the corrective action process for evaluation and repair prior to loss of intended function, and that the corrective action process effectively determines the cause of the degradation.

3. During performance of a TMI Fire Safe Shutdown Self-Assessment in 2002, a single pendant sprinkler head in the Engineered Safeguards Actuation Systems (ESAS) room was found not to be listed or approved for use in a dry pipe system application. The condition was evaluated and determined to be acceptable, and was identified for documentation as a code deviation. The condition evaluation found that while the head was installed per design in order to direct water away from potential obstructions, subsequent conversion of the system from a wet pipe to a dry pipe system to avoid the possibility of inadvertent actuation did not evaluate acceptability of this one sprinkler head for use in a dry system. The installation was determined to be acceptable, and a code deviation was documented. This example provides objective evidence that deficiencies discovered during periodic self-assessments performed in accordance with the program are entered into the corrective action process for evaluation and repair. It also demonstrates that the corrective action process effectively evaluates and dispositions deficiencies prior to any loss of intended function.

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Appendix B - Aging Management Programs

4. In 2007, a fire service valve previously closed to isolate an underground leak could not be opened due to valve operator resistance. An evaluation was performed which determined that multiple alternate flow paths existed such that operability of the fire system was not adversely affected. A flow test confirmed that required fire service flow was available to all areas of the plant at flow rates consistent with previous tests. The valve was subsequently replaced. This example provides objective evidence that detected degradation is entered into the corrective action process for evaluation and repair prior to any loss of intended system function.

In October 2002 and December 2005, two NRC-conducted triennial fire protection inspections were performed at TMI-1. The objective of these inspections was to assess whether TMI-1 has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained. A total of only three findings were cited (two in 2002 and one in 2005), each with a classification of very low safety significance and treated as a non-cited violation.

Conclusion The enhanced Fire Water System aging management program will provide reasonable assurance that the aging effects are adequately managed so that the intended functions of fire water system components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.15 ABOVEGROUND STEEL TANKS Program Description The Aboveground Steel Tanks aging management program is an existing program that will provide for management of loss of material aging effects for outdoor carbon steel tanks. The program credits the application of paint as a corrosion preventive measure and performs periodic visual inspections to monitor degradation of the paint and any resulting metal degradation for the carbon steel tanks. One-time internal UT inspections will be performed on the bottom of the Condensate Storage Tanks, which are supported by concrete foundations. The Fire Service Head Tank (Altitude Tank) and Sodium Hydroxide Tank are not directly supported by an earthen or concrete foundation and will undergo external visual inspections without the necessity of bottom surface UT inspections.

The Condensate Storage Tanks are supported by concrete foundations and have sealant at the tank-foundation interfaces which will be periodically inspected for degradation. The Altitude Tank and Sodium Hydroxide Tank are raised tanks not directly supported by earthen or concrete foundations, and inspection of the sealant at the tank-foundation interface does not apply.

The Aboveground Steel Tanks aging management program is an existing program. Enhancements will be implemented prior to the period of extended operation.

NUREG-1801 Consistency The Aboveground Steel Tanks aging management program is consistent with the ten elements of aging management program XI.M29, Aboveground Steel Tanks, specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 states that periodic plant system walkdowns each outage are used to monitor degradation. The TMI-1 program utilizes tank inspections at least every five years in place of periodic system walkdowns each outage.

Tank components subject to outdoor air are constructed from carbon steel.

The carbon steel tanks are protected by a protective coating. Industry guidance and experience indicate that monitoring of exterior surfaces of components made of this material and protective coating on a frequency of at least every five years provides reasonable assurance that loss of material will be detected before an intended function is affected.

Enhancements The existing TMI-1 Aboveground Steel Tanks program implementing procedures will be enhanced to include one-time thickness measurements of the bottom of the Condensate Storage Tanks, which are supported on concrete foundations. Measurements will be taken to ensure that significant degradation Three Mile Island Nuclear Station Unit 1 Page B-57 License Renewal Application

Appendix B - Aging Management Programs is not occurring and the component intended function will be maintained during the extended period of operation.

The program will also be enhanced to inspect the condition of the sealant between CSTs and the concrete foundations.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that aging effects/mechanisms are being adequately managed. Coating degradation, such as flaking and peeling, has occurred in safety-related systems and structures. Corrosion damage near the concrete-metal interface and sand-metal interface has been reported in metal containments. Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of material due to general, pitting, and crevice corrosion is being adequately managed. The following examples of operating experience provide objective evidence that the Aboveground Steel Tanks program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. In 2005, the annual external inspection of the Fire Service Head tank discovered minor blistering and chipped paint. The condition, which was discovered prior to tank degradation (i.e., no rust or leaks), was entered into the TMI-1 Corrective Action Process.

Although the tank had been repainted four years earlier, this was the first time this condition had been noted on the painted surfaces.

The condition was evaluated and a predictive maintenance action tracking item was created to monitor and trend the condition.

2. In 2007, the annual external inspection of the Fire Service Head tank did not identify any new conditions. No evidence of leaks or structural damage was noted. Insulation was removed during the previous annual inspection and not entirely replaced. The repair of the insulation was entered into the Corrective Action Process.

3. In 2007, the five-year external inspection of the Sodium Hydroxide Tank found no discrepancies with regard to the tank inspection criteria. This operating experience shows that there are no aging effects on the external surface of this tank, and the condition of the tank external surface will support the tank intended functions.

Conclusion The enhanced Aboveground Steel Tanks aging management program will provide reasonable assurance that the aging effects of loss of material are adequately managed so that the intended functions of outdoor aboveground tanks within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation. Enhancements will be implemented prior to the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.16 FUEL OIL CHEMISTRY Program Description The Fuel Oil Chemistry aging management program is an existing program that includes preventive activities to provide assurance that contaminants are maintained at acceptable levels in fuel oil for systems and components within the scope of Licensing Renewal. The fuel oil tanks within the scope of the program are maintained by monitoring and controlling fuel oil contaminants in accordance with the guidelines of the American Society for Testing and Materials (ASTM). Fuel oil sampling activities meet the requirements of ASTM D 4057-95 (2000), or, provide a more conservative sample for the detection of contaminants and water and sediment. Fuel oil will be periodically sampled and analyzed for particulate in accordance with modified ASTM Standard D 2276-00 Method A and for the presence of water and sediment in accordance with ASTM Standard D 1796-97. Fuel oil sampling and analysis is performed in accordance with approved procedures for new fuel and stored fuel. Fuel oil tanks are periodically drained of accumulated water and sediment and periodically drained, cleaned, and internally inspected. These activities effectively manage the effects of aging by providing reasonable assurance that potentially harmful contaminants are maintained at low concentrations.

NUREG-1801 Consistency The Fuel Oil Chemistry aging management program is consistent with the ten elements of aging management program XI.M30, "Fuel Oil Chemistry,"

specified in NUREG-1801 with the following exceptions:

Exceptions to NUREG-1801

• NUREG-1801 states in XI.M30 that the fuel oil aging management program is focused on managing the conditions that cause general, pitting, and microbiologically influenced corrosion (MIC). The TMI-1 aging mechanisms in fuel oil also include the loss of material due to crevice corrosion and biological fouling. The contaminants that cause crevice corrosion and biological fouling are similar to those that cause general, pitting and microbiologically influenced corrosion (MIC). Therefore, the monitoring and inspection techniques used to manage the conditions that cause general, pitting, and microbiologically influenced corrosion (MIC) will be effective in managing the loss of material due to crevice corrosion and biological fouling.

• NUREG-1801 states in XI.M30 that the fuel oil aging management program is in part based on the fuel oil purity and testing requirements of the plants Technical Specifications that are based on the Standard Technical Specifications of NUREG-1430 through NUREG-1433. TMI-1 has not adopted the Standard Technical Specifications as described in these NUREGs; however, the TMI-1 fuel oil specifications and procedures invoke equivalent requirements for fuel oil purity and fuel oil testing as described by the Standard Technical Specifications.

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Appendix B - Aging Management Programs

• NUREG-1801 states that the program serves to reduce the potential of exposure of the tank internal surface to fuel oil contaminated with water and biological organisms. This is accomplished by analyzing multilevel samples for water and sediment, biological activity, and particulate on a periodic basis (at least quarterly). Fuel oil tanks should also be periodically drained of accumulated water and sediment, and, periodically drained, cleaned, and internally inspected. The following are exceptions to these requirements:

• Multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 7.3 gallon Station Blackout Diesel Clean Fuel Tank is not periodically performed at TMI-1. This tank is integral to the routine operation of the Station Blackout Diesel and collects excess clean fuel oil from the diesel engine that has been previously analyzed within its managed source tank, the Station Blackout Diesel Fuel Storage Tank.

The Clean Fuel Tank is small in size and experiences a turnover of the fuel collected within as a result of routine engine operation. Therefore, the periodic draining of water and sediment from the bottom of the Clean Fuel Tank, and, the periodic draining, cleaning, and internal inspections are not necessary. To confirm the absence of any significant aging effects, a one-time inspection of the Station Blackout Diesel Clean Fuel Tank will be performed as part of the TMI-1 Fuel Oil Chemistry aging management program. Should the one-time inspection reveal evidence of aging effects, this condition will be entered into the corrective action process for resolution.

• Multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 550 gallon Station Blackout Diesel Fuel Day Tank is not periodically performed at TMI-1. This tank is integral to the routine operation of the Station Blackout Diesel and is filled with fuel oil that has been previously analyzed within its managed source tank, the Station Blackout Diesel Fuel Storage Tank. The fuel oil within the Day Tank is recirculated to the Station Blackout Diesel Fuel Storage Tank quarterly to prevent the accumulation of contaminants and water and sediment.

Therefore, the periodic draining of water and sediment from the bottom of the Day Tank, and, the periodic draining, cleaning, and internal inspections are not necessary. To confirm the absence of any significant aging effects, a one-time inspection of the Station Blackout Diesel Day Tank will be performed as part of the TMI-1 Fuel Oil Chemistry aging management program. Should the one-time inspection reveal evidence of aging effects, this condition will be entered into the corrective action process for resolution.

• NUREG-1801 requires periodic multilevel sampling of tanks in accordance with the manual sampling standards of ASTM D 4057-95 (2000). TMI-1 has not committed to ASTM D 4057-95 (2000) for manual sampling standards:

• The Diesel Fire Pump 350 gallon fuel oil storage tank and the Emergency Diesel Generator 550 gallon fuel oil day tank samples are single point samples obtained from the tank drain line located off of the bottom of the tank. This sample is not considered a multilevel sample as described in ASTM D 4057. Although the actual sample location is a Three Mile Island Nuclear Station Unit 1 Page B-60 License Renewal Application

Appendix B - Aging Management Programs single point taken from the tank bottom, the lower sample elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this a conservative and effective sampling location for fuel oil contaminants. Operating experience from January 2000 through June 2007 has shown that this sample method has yielded consistently acceptable sample results.

• The 50,000 gallon fuel oil storage tank samples are obtained from an in-line sample connection located off of the tank outlet piping. This sample is not considered a multilevel sample as described in ASTM D 4057.

Sampling of the tank is performed after recirculating the tank contents which promotes tank mixing and purging of the recirculation and sample piping. Although the actual sample draw off location is off of the tank outlet which is towards the bottom of the tank, the lower sample elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this a conservative and effective sampling location for fuel oil contaminants. Operating experience from January 2005 through July 2007 has shown that this sample method has yielded consistently acceptable sample results.

Enhancements The TMI-1 Fuel Oil Chemistry aging management program will be enhanced to include:

• The completion of full spectrum fuel oil analysis within 31 days following the addition of new fuel oil into fuel storage tanks.

• The determination of water and sediment in accordance with ASTM D1796-97.

• The analysis for particulate contamination in new and stored fuel oil in accordance with modified ASTM D2276, Method A.

• The analysis for bacteria in new and stored fuel oil.

• The addition of biocides, stabilizers, or corrosion inhibitors as determined by fuel oil analysis activities.

• Activities to periodically drain, clean, and inspect the 50,000 gallon fuel oil storage tank, the 550 gallon diesel generator day tanks, the 25,000 gallon station blackout diesel fuel storage tank, and the Diesel Fire Pump 350 gallon fuel oil storage tanks.

• Activities to periodically drain water and sediment from tank bottoms for the 50,000 gallon fuel oil storage tank, the 30,000 gallon diesel generator fuel storage tank, and the Diesel Fire Pump 350 gallon fuel oil storage tanks.

• The analysis of new oil for specific or API gravity, kinematic viscosity, and water and sediment prior to filling the 50,000 gallon fuel oil storage tank and the Diesel Fire Pump 350 gallon fuel oil storage tanks.

• Quarterly sampling for the 550 gallon diesel generator day tanks.

• Sampling of new fuel oil deliveries in accordance with ASTM D 4057-95 (2000).

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Appendix B - Aging Management Programs

• Multilevel sampling of the Emergency Diesel Generator 30,000 gallon fuel oil storage tank and the SBO Diesel Generator 25,000 gallon fuel oil storage tank in accordance with ASTM D 4057.

• The use of ultrasonic techniques for determining tank bottom thicknesses should there be any evidence of loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, and fouling found during visual inspection activities.

Enhancements will be implemented prior to entering the period of extended operation.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, and fouling are being adequately managed. The following examples of operating experience provide objective evidence that the Fuel Oil Chemistry aging management program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. In January 2005, a review of the quarterly diesel fuel oil samples taken from the fire service pump diesel fuel oil tank indicated an increasing trend for total insolubles. Following consultation with the fuel oil vendor, it was determined that the total insoluble contaminant increase was caused by oxidation of the fuel (aging).

The usability of the fuel oil was evaluated and determined acceptable in the short term. In order to return the fuel oil to within specification in order to maintain the long-term health of the fuel storage tank, the fuel oil was drained, the tank flushed, and new fuel oil added. Following these activities, sampling was performed which verified the effectiveness of this corrective action. Additional corrective actions included re-evaluation and improvements to TMI-1 monitoring activities for all site fuel oil storage tanks. This example provides objective evidence that a) fuel oil monitoring activities identify fuel oil contaminants that can lead to aging effects, b) deficiencies found during fuel oil monitoring activities are documented in the corrective action process, and c) fuel oil monitoring activity deficiencies are evaluated and corrective actions implemented to maintain system intended functions.

2. In January 2004, the TMI-1 fuel oil sampling program was reviewed against standard Exelon fuel oil sampling practices and the improved Technical Specifications in use at Limerick and Peach Bottom. As a result of this review, improvements were made to the sampling activities including changes to sampling frequencies, sampling techniques, and tested parameters. Preventative actions to preclude the accumulation of water and sediment were also incorporated into the site fuel oil monitoring activities. This example provides objective evidence that a) assessments are performed proactively to identify potential program improvements, b)

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Appendix B - Aging Management Programs improvements identified during assessments are captured in the corrective action process, and c) improvements are evaluated and implemented as required to enhance program effectiveness.

3. In October 2005, fuel oil sample analysis from the fire diesel fuel oil tank indicated an elevated level of total insolubles. Confirmatory testing was performed on this tank for total insolubles with satisfactory results. As a result of this discrepancy, sample reports for 2005 were reviewed to identify total insoluble trends. Based on this review, it was concluded that the results of the October 2005 sample were inaccurate, or, the sample was contaminated. This example provides objective evidence that a) fuel oil monitoring activities identify fuel oil contaminants that can lead to aging effects, b) deficiencies found during fuel oil monitoring activities are documented in the corrective action process, and c) fuel oil monitoring activity deficiencies are evaluated and corrective actions implemented to maintain system intended functions.

4. The 50,000 gallon fuel oil storage tank samples are obtained from an in-line sample connection located off of the tank outlet piping.

This sample is not considered a multilevel sample as described in ASTM D 4057. Sampling of the tank is performed after recirculating the tank contents which promotes tank mixing and purging of the recirculation and sample piping. Operating experience from January 2005 through July 2007 has shown that this sample method has yielded consistently acceptable sample results.

5. The Diesel Fire Pump 350 gallon fuel oil storage tank and Emergency Diesel Generator 550 gallon fuel oil day tank samples are single point samples obtained from the tank drain line located off of the bottom of the tank. This sample is not considered a multilevel sample as described in ASTM D 4057. Operating experience from January 2000 through June 2007 has shown that this sample method has yielded consistently acceptable sample results.

The operating experience of the Fuel Oil Chemistry aging management program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Fuel Oil Chemistry aging management program will effectively identify degradation prior to failure.

Conclusion The enhanced TMI-1 Fuel Oil Chemistry aging management program will provide reasonable assurance that the loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, and fouling will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.17 REACTOR VESSEL SURVEILLANCE Program Description The TMI-1 Reactor Vessel Surveillance program is an existing program that manages the reduction of fracture toughness of the reactor vessel beltline materials due to neutron embrittlement. The program fulfills the intent and scope of 10 CFR 50, Appendix H. The program provides for evaluation of neutron embrittlement by projecting upper-shelf energy (USE) for all reactor materials with projected neutron exposure greater than 1017 n/cm2 (E >1MeV) during 60 years of operation and with the development of pressure-temperature limit curves. Embrittlement information is obtained in accordance with RG 1.99, Rev. 2 chemistry tables.

TMI-1 participates in the Pressurized Water Reactor Owners Group (PWROG)

Master Integrated Reactor Vessel Surveillance Program (MIRVSP), which monitors TMI-1 reactor vessel beltline materials that are projected to exceed a cumulative neutron fluence of 1017 n/cm2 (E >1MeV) during 60 years of service. The MIRVSP includes all seven operating B&W 177-fuel assembly (FA) plants and six participating Westinghouse-designed plants having B&W-fabricated reactor vessels. The purpose of the MIRSVP is to augment the existing Reactor Vessel Surveillance Programs for the participating units and to provide a basis for sharing information between plants. The integrated program is feasible because of the similarity of the design and operating characteristics of the affected plants, as required by 10 CFR Part 50, Appendix H, paragraph II.C. The integrated program provides sufficient material data to meet the ASTM E-185-82 capsule program requirement for monitoring embrittlement.

The program consists of two parts - the first is the plant-specific program, which is the continued irradiation of the surveillance capsules transferred from those reactors in which the capsule holder tubes were damaged to host reactors with intact upgraded capsule holders. The TMI-1 capsules were placed in the Crystal River-3 reactor for irradiation. Those that have been irradiated and tested fulfill the ASTM E-185-82 Capsule Program Requirement for TMI-1. The second part of the program is made up of special research capsules designed to provide fracture toughness data on Linde 80 weld metals predicted to exhibit high sensitivity to irradiation damage. The irradiation schedules for the MIRVSP include the plant-specific capsules, supplementary weld metal surveillance capsules and higher fluence supplementary weld metal surveillance capsules for the Linde 80 materials. The capsule withdrawal schedule for limiting Linde 80 weld metal heats will result in neutron fluence exposures corresponding to 60 and 80 years of operation.

The program manages the steps taken if reactor vessel exposure conditions are altered; such as the review and updating of 60-year fluence projections to support the preparation of new pressurized shock reference temperature calculations, Charpy upper shelf energy calculations and pressure-temperature limit curves.

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Appendix B - Aging Management Programs TMI-1 does not have surveillance capsules remaining inside the reactor vessel, but uses ex-vessel cavity dosimetry to monitor neutron fluence. The cavity dosimetry program was developed and implemented to make it possible to continuously monitor the neutron fluence on each reactor vessel, as described in NRC-approved topical report BAW-1875-A. This will continue during the period of extended operation as part of the aging management program for reactor vessel neutron embrittlement.

NUREG-1801 Consistency The TMI-1 Reactor Vessel Surveillance program is an existing program that is consistent with NUREG-1801 aging management program XI.M31, Reactor Vessel Surveillance.

Exceptions to NUREG-1801 None.

Enhancements The TMI-1 Reactor Vessel Surveillance program will be enhanced to address maintenance of the TMI-1 cavity dosimetry exchange schedule. The program will also be enhanced to clarify that, if future plant operations exceed the limitations or bounds specified in Regulatory Position 1.3 of RG 1.99, Rev. 2, the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. Enhancements will be implemented prior to the period of extended operation.

Operating Experience

1. The integrated reactor vessel material surveillance program was designed when the surveillance capsule holder tubes in a number of B&W reactors were damaged and could not be repaired without a complex and expensive repair program and considerable radiation exposure to personnel. For these plants, including TMI-1, the original Reactor Vessel Surveillance Program could not provide sufficient material data and dosimetry to monitor embrittlement; therefore, the integrated program was developed. The purpose of the MIRSVP is to augment the existing Reactor Vessel Surveillance Programs for the participating units and to provide a basis for sharing information between plants. The integrated program is feasible because of the similarity of the design and operating characteristics of the affected plants, as required by 10 CFR Part 50, Appendix H, paragraph II.C. The integrated program provides sufficient material data to meet the ASTM E-185-82 capsule program requirement for monitoring embrittlement.

2. The NRC staff evaluated the basis for the integrated program concept, determined the MIRVSP to be acceptable, and approved TR BAW-1543 (NP), Revision 3, by letter dated June 11, 1991. This letter concluded that the program met the applicable criteria from 10 Three Mile Island Nuclear Station Unit 1 Page B-65 License Renewal Application

Appendix B - Aging Management Programs CFR 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements.

3. TR BAW-1543 (NP), Revision 4, issued in February 1993, updated some of the units withdrawal schedules. TR BAW-1543 (NP),

Revision 4, Supplement 1 reflected revised fluence values for some units and revised some withdrawal schedules to comply with the 1973 Edition of American Society for Testing and Materials (ASTM)

Standard E 185, Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels (ASTM E 185-73). It was anticipated that future updates to TR BAW-1543 (NP) would only involve changes to the Revision 4 Supplement. Supplement 2, issued in June 1996, reflected revised fluence values and the revised withdrawal schedules. Supplement 3, issued in February 1999, deleted Rancho Seco, R. E. Ginna, and Zion, Units 1 and 2, from the program. In addition, it updated the capsule status and the peak end-of-license fluences for several plants. Supplement 4, issued in May 2002, incorporated the disposal plan for stored capsules, updated the status for various capsules, and incorporated current fluence levels.

4. Supplement 5 was issued in December 2003 because the previous supplement included a commitment regarding Capsules OC1-D and OC3-F; however, that commitment could not be met because these capsules could not be removed from Crystal River, Unit 3. The NRC staff approved the revised withdrawal schedules for Oconee, Units 1, 2, and 3, and Three Mile Island, Unit 1 (TMI-1), in Supplement 5-A in May 2005. The NRC staff found that each of these plants met the capsule withdrawal schedule requirements of the 1982 Edition of ASTM Standard E185 (ASTM E 185-82), even though the original capsules were not going to be withdrawn and tested for Oconee, Units 2 and 3, and TMI-1, because there were other capsules within the MIRVSP that contained the same limiting material for the subject plants that would be withdrawn and tested and, therefore, would satisfy the requirements of ASTM Standard E185-82.

5. Supplement 6 was submitted in December 2005 to provide updates to fluence values and to the surveillance capsule insertion and withdrawal schedules. The NRC issued Draft Safety Evaluation Report for Supplement 6 in May 2007 for comment, and in it indicated that the revised capsule insertion and withdrawal schedules are acceptable. Therefore, the MIRVSP continues to meet the requirements of 10 CFR 50, Appendix H and the capsule withdrawal schedule requirements of ASTM E-185-82.

The operating experience of the Reactor Vessel Surveillance Program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. Periodic self-assessments of the program are performed to identify the areas that need improvement to maintain the quality performance of the program.

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Appendix B - Aging Management Programs Conclusion The enhanced TMI-1 Reactor Vessel Surveillance aging management program will provide sufficient material data and dosimetry to meet the ASTM E-185-82 capsule program requirement for monitoring embrittlement of the TMI-1 reactor vessel. The continued implementation of the enhanced TMI-1 Reactor Vessel Surveillance aging management program will provide reasonable assurance that neutron irradiation embrittlement will be adequately managed so that the intended functions of the reactor vessel will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.18 ONE-TIME INSPECTION Program Description The TMI-1 One-Time Inspection aging management program is a new program that will provide reasonable assurance that an aging effect is not occurring, or that the aging effect is occurring slowly enough to not affect a components intended function during the period of extended operation, and therefore will not require additional aging management. The program will be credited for cases where either (a) an aging effect is not expected to occur but there is insufficient data to completely rule it out, (b) an aging effect is expected to progress very slowly in the specified environment, but the local environment may be more adverse than that generally expected, or (c) the characteristics of the aging effect include a long incubation period.

The One-Time Inspection program will be used for the following:

• To confirm the effectiveness of the Water Chemistry program to manage the loss of material, cracking, and the reduction of heat transfer aging effects for steel, stainless steel, copper alloy, nickel alloy, and aluminum alloy in treated water, steam, and reactor coolant environments.

• To confirm the effectiveness of the Fuel Oil Chemistry program to manage the loss of material aging effect for steel, stainless steel, and copper alloy in a fuel oil environment.

• To confirm the effectiveness of the Lubricating Oil Analysis program to manage the loss of material and the reduction of heat transfer aging effects for steel, stainless steel, copper alloy, and aluminum alloy in a lubricating oil environment.

• To confirm the loss of material aging effect is insignificant for stainless steel and copper alloy in an air/gas - wetted environment.

The new program elements include (a) determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects/mechanisms, and operating experience; (b) identification of the inspection locations in the system or component based on the aging effect; (c) determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined; and (d) evaluation of the need for follow-up examinations to monitor the progression of aging if age-related degradation is found that could jeopardize an intended function before the end of the period of extended operation. When evidence of an aging effect is revealed by a one-time inspection, the engineering evaluation of the inspection results would identify appropriate corrective actions.

The inspection sample includes worse case one-time inspection of more susceptible materials in potentially more aggressive environments (e.g., low or stagnant flow areas) to manage the effects of aging. Examination methods will include visual examination, VT-1 or VT-3, or equivalent, as appropriate, or Three Mile Island Nuclear Station Unit 1 Page B-68 License Renewal Application

Appendix B - Aging Management Programs volumetric examinations. Acceptance criteria are in accordance with industry guidelines, codes, and standards.

The One-Time Inspection aging management program will be implemented prior to the period of extended operation.

NUREG-1801 Consistency The One-Time Inspection aging management program is consistent with the ten elements of aging management program XI.M32, One-Time Inspection, specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 specifies in XI.M32 the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD.

The TMI-1 ISI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda.

The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that aging effects/mechanisms are being adequately managed. The One-Time Inspection program applies to potential aging effects for which there are currently no operating experience indicating the need for an aging management program. Nevertheless, the elements that comprise these inspections (e.g., the scope of the inspections and inspection techniques) are consistent with industry practice. Specific Operating Experience and objective evidence does exist for attributes in which this program covers, such as the effectiveness of NDE techniques at identifying, confirming, and/or quantifying aging effects. The following examples of operating experience provide objective evidence that NDE is effective in assuring that intended function(s) would be maintained consistent with the CLB for the period of extended operation. These examples also demonstrate how the corrective action process is used to document and evaluate unacceptable NDE results.

1. In October 2004, while performing UT pipe thickness inspections, it was discovered that the wall thickness was below the nominal manufacturing tolerance of 87%. Engineering performed a review for operability and concluded that the as-found wall thickness exceeded the minimum wall thickness required by the B31.1 Code.

Engineering also concluded that based on the maximum predicted corrosion rate, the minimum wall thickness required by the B31.1 Three Mile Island Nuclear Station Unit 1 Page B-69 License Renewal Application

Appendix B - Aging Management Programs Code would not be exceeded for several fuel cycles. Based on remaining life, engineering recommended future re-inspection to ensure a conservative design margin prior to reaching predicted failure. This example provides objective evidence that a) the NDE program identifies aging effects prior to the loss of intended function, b) deficiencies found during NDE are documented and evaluated for impact on system operability and intended functions, and c) follow-up inspections are specified when necessary to confirm remaining design margin assumptions.

2. In November 2005, while performing UT pipe thickness inspections on 3/4 pipe, it was discovered that the wall thickness had been reduced. Engineering performed a review for operability and concluded that the as-found wall thickness provided a safety factor of 10 and an adequate corrosion margin until the next refueling outage, at which time the thinned piping would be replaced. This example provides objective evidence that a) the NDE program identifies aging effects prior to the loss of intended function, b) deficiencies found during NDE are documented and evaluated for impact on system operability and intended functions, and c) replacement activities are specified when necessary to maintain system intended functions.

3. In November 2001, while performing scheduled augmented ISI visual (VT-1) examinations, cracking was discovered on the High Pressure Injection/Makeup nozzle thermal sleeve. Engineering performed a review for operability and concluded that it was highly improbable that the identified crack in the thermal sleeve would propagate such that a significant loose part (e.g., inboard end of the thermal sleeve) would be generated during the next 24-month fuel cycle. The evaluation also concluded that in the unlikely event that the end of the thermal sleeve was lost early in the fuel cycle the loose part would not cause any structural or operational problems.

Additionally, the effects on the nozzle of operating for a full fuel cycle without the end of the thermal sleeve were evaluated and were shown to be within code requirements. This example provides objective evidence that a) the NDE program identifies aging effects prior to the loss of intended function and b) deficiencies found during NDE are documented and evaluated for impact on system operability and intended functions.

Conclusion The new One-Time Inspection program will provide reasonable assurance that either an aging effect is not occurring, or the aging effect is occurring so slowly that the intended function of the component or structure consistent with the current licensing basis is not affected. In either case there would be no need to manage an aging related degradation for the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.19 SELECTIVE LEACHING OF MATERIALS Program Description The Selective Leaching of Materials aging management program is a new program that will consist of one-time inspections to determine if loss of material due to selective leaching is occurring. The scope of the program will include components made of susceptible materials and located in potentially aggressive environments. Susceptible materials at TMI-1 are gray cast iron, copper alloy with greater than 15% zinc. Envrionments include raw water, closed cooling water, treated water, and soil.

The Selective Leaching of Materials aging management program will be implemented prior to the period of extended operation. The program will provide for visual inspections, hardness tests, and other appropriate examinations, as required, to identify and confirm existence of the loss of material due to selective leaching. If degradation is found, the condition of affected components will evaluated to determine the impact on their ability to perform intended functions during the period of extended operation. Condition monitoring and expanded sampling will be utilized, as required, to ensure the components perform as designed.

NUREG-1801 Consistency The Selective Leaching of Materials aging management program is consistent with NUREG-1801 Section XI.M33, Selective Leaching of Materials.

Exceptions to NUREG-1801 None Enhancements None Operating Experience The Selective Leaching of Materials aging management program is new.

Therefore, no programmatic operating experience is currently available.

However, the review of TMI-1 operating experience identified the dezincification of copper alloys containing greater than 15% zinc in treated water environments. Specifically, in December 2004, dezincification occurred in a tubing cap of a test tee for a pressure gauge in the main steam system.

This condition contributed to the failure of the tubing cap. The failed tubing cap was replaced with a stainless steel cap. Subsequently, the tubing cap on the test tee for a companion gage was inspected. No markings indicating material grade could be identified, therefore this cap was also replaced with one made of austenitic steel in accordance with the plant design. A preliminary extent-of-condition walkdown was conducted on similar test connections in the immediate area of the failed test cap. Included were components of the main Three Mile Island Nuclear Station Unit 1 Page B-71 License Renewal Application

Appendix B - Aging Management Programs steam and emergency feedwater systems. No other discrepancies were identified.

Conclusion The new Selective Leaching of Materials aging management program inspections will provide reasonable assurance that loss of material aging effects due to selective leaching are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.20 BURIED PIPING AND TANKS INSPECTION Program Description The Buried Piping and Tanks Inspection aging management program is an existing program that includes preventive measures to mitigate corrosion and periodic inspection of external surfaces for loss of material to manage the effects of corrosion on the pressure-retaining capacity of piping and components in a soil (external) environment. Preventive measures are in accordance with standard industry practices for maintaining external coatings and wrappings.

External inspections of buried components will occur opportunistically when they are excavated during maintenance. Inspection of buried cast iron, carbon steel, concrete-coated steel, and stainless steel piping and components will have been performed in the ten years prior to the period of extended operation.

Upon entering the period of extended operation, a focused inspection of an example of each of the above materials shall be performed within ten years, unless an opportunistic inspection occurs within this ten-year period. There have been several yard excavation activities to date that have uncovered buried piping and components and inspections of the buried piping and components. A cast iron fire protection component was excavated in 2005 and carbon steel condensate piping was excavated in 2006. During the 2007 outage, the concrete coated carbon steel Secondary River Water piping was excavated. Therefore, inspections of buried cast iron, carbon steel, and concrete-coated carbon steel piping or components have occurred in the ten years prior to the period of extended operation. Inspections will be performed on at least one stainless steel pipe or component prior to the period of extended operation. Inspection of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank both within the ten-year period prior to the period of extended operation, and within ten years of entering the period of extended operation will be performed as described below.

The program will be enhanced as described below to provide reasonable assurance that buried piping and components will perform their intended function during the period of extended operation.

NUREG-1801 Consistency The Buried Piping and Tanks Inspection aging management program is consistent with the ten elements of aging management program XI.M34, "Buried Piping and Tanks Inspection," specified in NUREG-1801 with the following exceptions:

Exceptions to NUREG-1801

• NUREG-1801,Section XI.M34 Buried Piping and Tanks Inspection aging management program scope only includes buried steel piping and components. However TMI-1 also includes stainless steel in their buried piping program that will be managed as part of this aging management program.

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Appendix B - Aging Management Programs

• NUREG-1801,Section XI.M34 Buried Piping and Tanks Inspection aging management program relies on preventive measures such as coatings and wrappings. However portions of buried stainless steel piping may not be coated or wrapped. Inspections of buried piping that is not wrapped will inspect for loss of material due to general, pitting, crevice, and microbiologically influenced corrosion.

• NUREG-1801,Section XI.M34 Buried Piping and Tanks Inspection aging management program recommends that opportunistic or focused inspections of the external surfaces of buried components be performed.

Internal inspection and UT of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank wall will be used in lieu of inspection of the external surface of this tank. This internal surface visual inspection and UT examination of the tank wall will provide an alternate means to monitor the tanks pressure retaining ability.

Enhancements The Buried Piping and Tanks Inspection aging management program will be enhanced to include at least one opportunistic or focused excavation and inspection of stainless steel piping and components prior to entering the period of extended operation. (Inspection activities of buried piping and components for cast iron, carbon steel, and concrete-coated carbon steel materials have occurred in the ten years prior to the beginning of the period of extended operation.) Upon entering the period of extended operation, a focused inspection of an example of each of the above materials shall be performed within ten years, unless an opportunistic inspection occurs within this ten-year period.

An internal inspection and UT of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank wall will be used in lieu of inspection of the external surface of this tank. This inspection will be performed within the ten-year period prior to the period of extended operation, and within ten years of entering the period of extended operation.

Operating Experience Operating experience shows that the program described here is effective in managing corrosion of external surfaces of buried steel piping and tanks.

However, because the inspection frequency is plant-specific and depends on the plant operating experience, the applicants plant-specific operating experience is further evaluated for the extended period of operation.

Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of material due to general, pitting, crevice, and microbiologically influenced corrosion are being adequately managed. The following examples of operating experience provide objective evidence that the Buried Piping and Tanks Inspection program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

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Appendix B - Aging Management Programs

1. In August 2005, a water leak on a fire service piping valve was discovered. During required packing repair, the nearby piping was exposed during the excavation. The piping was inspected and found the external coating was in good condition, as was the interior of the piping.

2. In December 2006, a fire service valve was replaced. During the replacement, coatings were removed and re-applied where the freeze seal had been applied for valve replacement. Following completion of the work, it was discovered that the coating application steps did not include the appropriate inspection testing.

The coating procedures and specifications were revised to include appropriate inspection testing. There was no indication that the as-found coating was degraded.

3. In June 2006, it was determined that a leak occurred in the Condensate Storage Tank (CST) A de-ice line between the Turbine Building and CST A. When the piping was excavated, the coating was deteriorated and corrosion was present on the outside surface of the piping. The piping was cut out and replaced. The cause of the failure was the use of improper backfill material around the piping, which resulted in ballast-type rock contacting and damaging the outer pipe coating. This resulted in the localized corrosion which eventually led to a through-wall leak. Other underground piping locations were selected and excavated. In each case, the correct backfill material had been present. A comprehensive underground piping inspection program was developed, considering location, design, protection, coating, consequences of failure and type of inspections to be performed. In April 2007, an underground leak in the same piping line was detected. Investigation determined that this leak developed in a mechanical joint (flange), which was inadvertently damaged during the earlier repair. The leak was repaired in June 2007, and the underground piping line was subsequently redesigned and replaced.

This example provides objective evidence that deficiencies in the program are identified and entered into the corrective action process and that the program is updated as necessary to ensure that it remains effective for condition monitoring of piping and components within the scope of license renewal.

The operating experience of the Buried Piping and Tanks Inspection program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Buried Piping and Tanks Inspection program, as enhanced for license renewal, will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the Buried Piping and Tanks Inspection program are performed to identify the areas that need improvement to maintain the quality performance of the program.

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Appendix B - Aging Management Programs Conclusion The enhanced Buried Piping and Tanks Inspection aging management program will provide reasonable assurance that the aging effects on the external surfaces of buried piping and components are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.21 EXTERNAL SURFACES MONITORING Program Description The External Surfaces Monitoring aging management program is a new program that directs visual inspections that are performed during system walkdowns. The program consists of periodic visual inspection of components such as piping, piping components, ducting, and other components within the scope of license renewal. The program provides for management of aging effects through visual inspection of external surfaces for evidence hardening and loss of strength and loss of material. Visual inspections may be augmented by physical manipulation to detect hardening and loss of strength of elastomers. Loss of material due to boric acid corrosion is managed by the Boric Acid Corrosion program. The external surfaces of components that are buried and those of above ground tanks are inspected via the Buried Piping and Tanks Inspection program and the Aboveground Steel Tanks program, respectively. This program does not provide for managing aging of internal surfaces.

NUREG-1801 Consistency The TMI-1 External Surfaces Monitoring aging management program is a new program that is consistent with NUREG-1801 aging management program XI.M36, External Surfaces Monitoring with the following exceptions.

Exceptions to NUREG-1801 The NUREG-1801 aging management program XI.M36, External Surfaces Monitoring program is based on system inspections and walkdowns. This program consists of periodic visual inspections of steel components such as piping, piping components, ducting, and other components within the scope of license renewal and subject to AMR in order to manage aging effects. The program manages aging effects through visual inspection of external surfaces for evidence of material loss. Exceptions to NUREG-1801 are:

• An increase to the scope of the materials inspected (i.e., aluminum alloy, asbestos cloth, copper alloy, elastomers, and stainless steel)

• An increase to the scope of aging effects (i.e., hardening and loss of strength).

Enhancements None.

Operating Experience Corrosion of external surfaces, particularly steel components where paint damage has exposed bare metal, can result in significant material degradation if left unnoticed.

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Appendix B - Aging Management Programs

1. During the December 2004 system walkdown, engineering noticed an uncoated/painted Circulating Water System valve. Similar valves are painted to prevent external corrosion of the valve and valve operator. The valve was painted to prevent external corrosion.

2. In February 2006, the Control Building Chiller was found to have minor surface corrosion on the condenser shell. The areas of the chiller that were found to have corrosion were cleaned and repainted to prevent further degradation.

3. The Altitude Tank fill check valve was found to be rusting during a June 2005 walkdown. The corrosion was due to condensation forming on the external surfaces of the fill line and aging paint.

Corrective action was taken to clean and repaint the valve to prevent further degradation.

Conclusion The new External Surfaces Monitoring aging management program will provide reasonable assurance that the identified aging effects are adequately managed so that the intended functions of structures and components within the scope license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.22 INSPECTION OF INTERNAL SURFACES IN MISCELLANEOUS PIPING AND DUCTING COMPONENTS Program Description The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components aging management program is a new program that provides for managing cracking due to stress corrosion cracking; hardening and loss of strength due to elastomer degradation; loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, cracking, and fouling; and reduction of heat transfer due to fouling. The program includes provisions for visual inspections of the internal surfaces and volumetric testing of components not managed under any other aging management program and initiate corrective action. The program also includes inspection of the external surfaces of expansion joints in ducting.

NUREG-1801 Consistency The TMI-1 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components aging management program is a new program that is consistent with NUREG-1801 aging management program XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components with the following exceptions.

Exceptions to NUREG-1801 The NUREG-1801 aging management program XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components consists of inspections of the internal surfaces of steel piping, piping components, ducting, and other components that are not covered by other aging management programs. These internal inspections are performed during the periodic system and component surveillances or during the performance of maintenance activities when the surfaces are made accessible for visual inspection. The program includes visual inspections to assure that existing environmental conditions are not causing material degradation that could result in a loss of component intended functions. Exceptions to NUREG-1801 are:

• An increase of the component material types within the scope of this program (i.e., asbestos, copper alloy with 15% zinc or more, copper alloy with less than 15% zinc, neoprene, nickel alloy, rubber, stainless steel, and titanium alloy).

• An increase of the aging effects within the scope of this program (i.e.,

cracking, reduction of heat transfer, and hardening and loss of strength).

• Volumetric testing will be used to detect SCC of stainless steel components

• Physical manipulation may be used to detect hardening and loss of strength of elastomers both internally and externally.

Enhancements None.

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Appendix B - Aging Management Programs Operating Experience Industry operating experience indicates that internal degradation can cause significant degradation to susceptible plant components. Existing plant procedures that direct visual inspections of internal surfaces of piping and ducting have identified minimal instances of internal degradation. Continued implementation of these procedures plus a new procedure to expand the systems and components inspected will be adequate to manage degradation during the period of extended operation. Examples of degradation identified by these procedures include:

1. Every refueling outage Engineering performs an internal inspection of the Reactor Building Cooling Units upstream of the normal cooling coils, down stream of the emergency coils, and the fan inlets and fan outlets. During the 2003 outage, samples of boric acid were taken from the bottom section of the inlet of each normal cooling coil bank. Boron deposits coating less than 5% of the total surface area of the normal cooling coils were found. Generally, the Reactor Building Cooling Units have less than 5% surface area fouling overall. There was an increase in the amount of boron deposition since the last refueling outage visual inspection, but it was expected due to an ongoing reactor coolant leak rate. The consequence of the boron fouling of the Reactor Building Recirculation Fan &

Coolers is a reduction in heat transfer. The fans and coolers were cleaned of the boron deposits in accordance with the Corrective Action Process. The reactor coolant leak has since been fixed.

2. In 2005, leak testing of the Auxiliary Boiler Sump identified leakage from the Blowdown Tank drain line to the sump. Boroscope inspection of the drain line identified corrosion in the horizontal run.

Operation of the boilers requires use of the blowdown tank and associated drain line. Repair to the blowdown tank drain was needed to prevent further release of water from the Condensate System. The drain line was repaired in accordance with the Corrective Action Program.

3. During a 2004 visual inspection of internal surfaces of Condensate Storage Tank A, damaged coatings and corrosion was discovered in the inner diameter of a drain line. A technical evaluation concluded excessive corrosion in the localized degraded coating area would not occur prior to recoating in 2009.

Conclusion The new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components aging management program will provide reasonable assurance that the identified aging effects are adequately managed so that the intended functions of structures and components within the scope license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.23 LUBRICATING OIL ANALYSIS Program Description The TMI-1 Lubricating Oil Analysis aging management program is an existing program that provides oil condition monitoring activities to manage the loss of material and the reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and tanks within the scope of license renewal exposed to a lubricating oil environment. Sampling and condition monitoring activities identify specific wear products, contamination and the physical properties of lubricating oil within operating machinery to ensure that intended functions are maintained.

NUREG-1801 Consistency The Lubricating Oil Analysis aging management program is consistent with the ten elements of aging management program XI.M39, Lubricating Oil Analysis Program, specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 recommends that flash point be determined for lubricating oil.

Flash point will not be measured for all lubricating oil in service. The determination of flash point in lubricating oil is used to indicate the presence of highly volatile or flammable materials in a relatively nonvolatile or nonflammable material, such as found with fuel contamination in lubricating oil.

The TMI-1 oil analysis guidelines only include the measurement of flash point for diesel engine lubricating oil where there is the potential for the contamination of lubricating oil with fuel. Flash point is not measured for other lubricating oils where there is no potential for the contamination of lubricating oil with fuel. For all lubricating oils, flash point is used as a quality control measurement when receiving new oil. Flash point is not a primary measurement to determine the presence of water or contaminants in lubricating oil, which are the environmental parameters necessary for the loss of material and reduction of heat transfer aging effects.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that aging effects/mechanisms are being adequately managed. The following examples of operating experience provide objective evidence that the Lubricating Oil Analysis aging management program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

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Appendix B - Aging Management Programs

1. Analysis and review of the monthly oil sample data in January 2004 for the main turbine oil reservoir and feedwater pump/turbine oil reservoirs indicated an increasing particle count. A large sudden injection of particles into the systems from abnormal bearing wear, mechanical shock to the system, or failure of the bowser filter units was considered. This failure mode would drive the particle count extremely high in a short period of time. The trend of particle increase since January of 2003 was a slow, steady trend with the exception of June. Based on this continued trend, the theory of a large injection into the turbine oil system was rejected. A review of the other physical properties of the oil: viscosity, TAN and Spectrochemical analysis was performed and it was concluded that this data did not support abnormal bearing wear. Review of the vibration monitoring system data also concluded no bearing degradation issues.

Confirmatory sampling activities were performed in order to determine bowser filter efficiency. As a result if this testing, it was concluded that the bowser filter units required replacement, even though differential pressure thresholds for filter replacement were not exceeded. Additional reviews of the sample results on the main oil reservoir revealed evidence of variances in cleanliness with the suspected cause being technique. To eliminate these sampling variances, a new sample point was installed to achieve consistent sample results. This example provides objective evidence that a) lubricating oil monitoring activities identify lubricating oil contaminants that can lead to aging effects, b) deficiencies found during lubricating oil monitoring activities are documented in the corrective action process, and c) lubricating oil monitoring activity deficiencies are evaluated and corrective actions implemented to maintain system intended functions.

2. A Self-Assessment of the Emergency Diesel Generator crankcase lubricating oil program was performed by corporate engineering in September 2005. The program was assessed against Exelon procedures and the applicable Owners Group recommendations for Fairbanks Morse Emergency Diesel Generators. The overall conclusion was that the Emergency Diesel Generator lubricating oil program is being executed in a generally satisfactory manner.

Several program deficiencies were noted at TMI. One of these deficiencies was attributed to a known oil contamination issue (see OE item below). A deficiency in magnesium level was identified that had not been previously identified by the plant staff. This was entered into the corrective action process for evaluation and determination of root cause. The third deficiency identified was associated with inadequate sampling techniques and was also entered into the corrective action process. This example provides objective evidence that a) assessments are performed to verify the effectiveness of program execution, b) deficiencies found during assessments are documented in the corrective action process, and Three Mile Island Nuclear Station Unit 1 Page B-82 License Renewal Application

Appendix B - Aging Management Programs c) assessment deficiencies are evaluated and corrective actions implemented to maintain program effectiveness.

3. Contaminated lubricating oil has remained in TMI A Emergency Diesel Generator since 1999. In April 1999, 10 gallons of the wrong lubricating oil was accidentally introduced into the engine sump due to an operator error. This oil has a different additive package than the lubricating oil normally used at TMI. Review of the oil analysis reports showed that this error has caused persistently high levels of zinc in the engine oil, which is normally a sign of oil contamination.

Review of the corrective action evaluation, which dispositioned the issue, provided no technical basis for the long-term acceptability of this condition. This deficiency was identified during a September 2005 corporate Check-In assessment of the Emergency Diesel Generator crankcase lubricating oil program (see OE item above) and entered into the corrective action process. The follow-up evaluation of this condition concluded that the elevated zinc level was not a result of contamination; it was inherent to the lubricating oil inadvertently added in 1999. Additionally, it was also concluded that there were no wear parts of the diesel engine in contact with the oil that would contribute to the elevated zinc concentrations. As an interim corrective action, revised alert/fault values were established based on the elevated zinc levels in accordance with the guidance specified for zinc for Emergency Diesel Generator lubricating oil.

The zinc values obtained during routine oil analysis activities following implementation of the increased alert/fault guidelines did not exceed the alert/fault values established.

Zinc concentration above the reference value did not affect the function of the engine as evidenced by major inspections conducted in April 2006. No adverse findings were identified during this inspection. A complete lubricating oil change was performed as a final disposition to this issue. This example provides objective evidence that a) deficiencies found during lubricating oil monitoring activities are documented in the corrective action process, and b) lubricating oil monitoring activity deficiencies are evaluated and corrective actions implemented to maintain system intended functions.

The operating experience of the Lubricating Oil Analysis aging management program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Lubricating Oil Analysis aging management program will effectively identify degradation prior to failure.

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Appendix B - Aging Management Programs Conclusion The Lubricating Oil Analysis aging management program provides reasonable assurance that the loss of material and the reduction of heat transfer aging effects are adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.24 ASME SECTION XI, SUBSECTION IWE Program Description The ASME Section XI, Subsection IWE aging management program provides for inspection of Reactor Building liner plate, including its integral attachments, penetration sleeves, pressure retaining bolting, personnel airlock and equipment hatch, seals, gaskets, and moisture barrier, and other pressure retaining components. It is implemented through procedures that implement ASME Section XI, Subsection IWE requirements for detecting loss of material (general, pitting, and crevice corrosion), loss of pressure retaining bolting preload, cracking due to cyclic loading, loss of sealing, leakage through containment/deterioration of seals, gaskets, and moisture barriers (caulking, flashing, and other sealants).

TMI-1 has completed ASME Section XI Subsection IWE General Visual Examinations for the first and the second periods of the first 10-year interval.

The second period examinations were completed in 2007. The required VT-3 examinations will be performed during the third period of this 10-year interval.

Areas of the reactor building liner adjacent to the moisture barrier (i.e., between liner and concrete) and the moisture barrier are subject to augmented examination (VT-1, ultrasonic test (UT)).

The TMI-1 aging management program complies with Subsection IWE for metallic shell and penetration liners of Class CC pressure retaining components and their integral attachments of ASME Section XI, 1992 Edition including 1992 Addenda in accordance with the provisions of 10 CFR 50.55a.

TMI-1 is committed to replacing the existing steam generators with new Once Through Steam Generators (OTSGs) prior to entering the period of extended operation. Repair/replacement of Reactor Building liner plate, removed for access purposes, will be done in accordance with ASME Section XI, Subsection IWE.

NUREG-1801 Consistency The TMI-1 ASME Section XI, Subsection IWE aging management program is consistent with the ten elements of aging management program XI.S1, "ASME Section XI, Subsection IWE," specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 evaluation is based on ASME Section XI, 2001 Edition including 2002 and 2003 Addenda. The current TMI-1 ASME Section XI, Subsection IWE program plan for the First 10-Year Inspection Interval effective from September 9, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on ASME Section XI, 1992 Edition including 1992 addenda. The next 10-Year Inspection Interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a 12 months before the start of the inspection interval.

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Appendix B - Aging Management Programs Enhancements None.

Operating Experience Industry Operating Experience:

1. In 2000 while performing visual inspection of the containment surfaces prior to the Type A Leak Test, Braidwood Unit 2 identified corrosion of the liner plate in the areas adjacent to the moisture barrier. Loss of material of the 1/4 liner was characterized as due to pitting corrosion. Most of the degraded areas had a reduction in thickness of 1/64 to 1/32. The maximum pit depth measured was approximately 3/32.

2. In 2004, NRC issued Information Notice 2004-09, Corrosion of Steel Containment and Containment Liner, which summarized industry identified corrosion of freestanding metallic containments (Mark I) and corrosion of containment liner plate. Corrosion of the liner plate in the area adjacent to the moisture barrier was reported by several plants and was attributed to the degraded moisture barrier (caulk) or in some cases the moisture barrier was not installed during construction.

As noted in the IN 2004-09, implementation of ASME Section XI, Subsection IWE identified that over time, the existing floor-to-containment seal can degrade, allowing moisture into the crevice between the containment liner plate and floor. Small amounts of stagnant water behind the floor seal area promote pitting corrosion. This is consistent with TMI-1 operating experience as described below.

TMI-1 Operating Experience:

1. In 1993, visual inspections of the TMI-1 reactor building liner plate coating identified local areas of degraded coating and surface corrosion of the liner. UT measurements taken in the areas where corrosion was observed showed that the lowest reading is 0.390, which is greater than the nominal plate thickness of 0.375.

2. In 1997, visual inspection of containment identified degradation of the coating and local liner corrosion at elevations 346, 308, and 281. Corrosion observed at elevations 346, and 308 was limited to surface rust. Examination of the corroded area at elevation 281 revealed local shallow round bottom pits with depths estimated to be ranging from 1/32 to 1/16. The results of these inspections were entered into the corrective action process. Engineering evaluation concluded the liner intended function is not affected by the local corrosion.

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Appendix B - Aging Management Programs

3. In 1999, 100% of the accessible portions of the reactor building liner and moisture barrier were examined in accordance with ASME XI, Subsection IWE. Examination results identified areas of degraded coating and local corrosion of the liner plate at several elevations and degradation of the moisture barrier. Six (6) locations adjacent to the moisture barrier at elevation 281 and 279 6 were observed to have loss of material due to corrosion. Other areas were observed to have only surface rust. One location at elevation 374 was noted to have a depression of 1/16 in diameter, 1/16 deep; but the depression was not due to corrosion.

UT measurements were taken at the six locations to quantify the reduced liner thickness. Where corrosion appeared to extend into the liner below the concrete floor at elevation 281, the moisture barrier and the gap filler material were removed to allow for UT measurements of the corroded area. The minimum measured thickness was 0.310 on the 0.375 nominal thickness liner and 0.651 on the 0.75 nominal thickness liner. The results of these examinations were entered into the corrective action process and evaluated by engineering. The evaluation concluded that the reduced thickness of the liner does not impact its intended function.

Additionally UT thickness measurements were taken at six 12 x 12 grid locations identified for augmented examination during each ISI Period in accordance with IWE-1240. These grids were previously marked on the liner, above the interface of the concrete floor and the moisture barrier, to allow repetitive examination. Each grid was scanned using a D-meter to determine the minimum liner thicknesses. The minimum measured thickness in each grid was greater than the nominal liner thickness of 0.375; except for one grid where the minimum measurement was 0.354. Engineering evaluation of the 0.354 thickness concluded that the reduction is acceptable based on provisions of IWE-3122.4, which allows a 10%

reduction in the nominal liner thickness or 0.338 for the 0.375 thick liner.

4. In 2003, visual examination in accordance with ASME Section XI, Subsection IWE of liner plate identified local areas of degraded coating, surface corrosion of the liner adjacent to the moisture barrier, and degraded or loss of seal of the moisture barrier. UT thickness measurements were taken at four (4) locations where surface corrosion was observed. The minimum measured thickness was 0.308 as compared to the nominal design plate thickness of 0.375. Engineering evaluation concluded that the reduced thickness is acceptable and does not impact the intended function of the liner.

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Appendix B - Aging Management Programs

5. In 2005, visual inspection of the reactor building observed that the moisture barrier had separated from liner at several locations.

Typically, the separation is less than about 1/32 inch. Several instances are between about 1/32 inch and 1/16 inch and are short in length (1 to 2 inches). No significant liner corrosion was observed. As a result of the observed condition, inspection frequency of the moisture barrier was increased to every refueling outage (2 years). Previously the moisture barrier was scheduled for inspection during each IWE examination period (3 years, 4 years, 3 years).

6. In 2007 TMI-1 conducted the 2nd ISI period examinations of the reactor building liner in accordance with ASME Section XI, Subsection IWE. 100% of accessible areas of the liner were visually inspected. The results of the inspection were acceptable and were similar to findings in previous outages. In addition, augmented UT examinations were performed which resulted from previous inspections in 1999 and 2003. The results of the inspection were acceptable and confirmed that sufficient containment liner thickness remains.

Also in 2007, the entire Reactor Building moisture barrier was replaced during the refueling outage and a 100 percent VT-3 inspection was performed on the excavated region of the liner. The VT-3 examinations indicated some localized corrosion in the exposed area. UT examinations of the liner were performed in these regions. After replacement of the moisture barrier was complete the adjoining service level 1 coating system was repaired. The results of the inspections were acceptable and confirmed that sufficient containment liner thickness remains.

During the 2007 refueling outage, primary system water was discovered between the Reactor Building sump stainless steel liner and the lowest point of the carbon steel containment liner. This space is filled with concrete. Based on radiological analysis the water was determined to have resulted from primary system leakage about 15 years ago. The cause of the water intrusion was most likely due to previous leakage past a degraded moisture barrier between the Reactor Building reinforced concrete floor and the carbon steel containment liner. Corrosion of the stainless steel sump liner and carbon steel containment liner due to continued exposure to the water was determined not to be an applicable aging mechanism because the pH of the water was greater than 11.5.

Future augmented inspections under the IWE program will include inspection of previously corroded areas behind the moisture barrier in accordance with IWE (or other alternative approved by the NRC).

In addition, a one time inspection will be performed of the liner in the area of the cork down to the horizontal plate. The entire moisture barrier will continue to be visually inspected each refueling outage.

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Appendix B - Aging Management Programs Conclusion The continued implementation of the TMI-1 ASME Section XI, Subsection IWE aging management program provides reasonable assurance that the aging effects of loss of material (general, pitting, and crevice corrosion), loss of pressure retaining bolting preload, cracking due to cyclic loading, loss of sealing, leakage through containment/deterioration of seals, gaskets, and moisture barriers (caulking, flashing, and other sealants) will be adequately managed so that the intended functions of the Reactor Building will be maintained, consistent with the current licensing basis, during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.25 ASME SECTION XI, SUBSECTION IWL Program Description The TMI-1 ASME Section XI, Subsection IWL aging management program is an existing program which implements examination requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,Section XI, Subsection IWL for reinforced and prestressed concrete containments (Class CC), 1992 Edition with the 1992 Addenda, as mandated by 10 CFR 50.55a. The program requires periodic inspection of accessible reactor building (containment) reinforced concrete, and inspection and testing of a sample of unbonded post-tensioning system as specified by ASME Section XI, Subsection IWL.

Inspection methods are in accordance with ASME Section XI, Subsection IWL.

Accessible concrete surfaces of containment walls and tendon gallery are subject to visual (VT-3C) inspection each examination period to detect loss of material, cracking, and loss of bond. Reinforced concrete surfaces are inspected for loss of material, cracking, cracking and expansion, increase in porosity and permeability, and loss of bond. Concrete surfaces that are suspect of degradations and those extending 2 from the bearing plate of tendons examined during the period are subject to VT-1C examination. A sample of each tendon wire type (vertical, hoop, dome) for the post-tensioning system is subject to physical testing (lift-off force) each examination period to determine if the post-tensioning system tendon wires are experiencing loss of prestress.

One tendon wire of each type is detensioned each examination period and visually (VT-1) inspected for loss of material. Samples from the detensioned wires are tested for yield strength, ultimate tensile strength, and elongation.

The end anchorage for the post-tensioning system is inspected for loss of material. Tendon corrosion protection medium (grease) is tested for alkalinity, water content, water-soluble chlorides, nitrates, and sulfides.

Acceptance criteria specified in the program is in accordance with ASME Section XI, Subsection IWL. The prestressing forces (lift-off) measured for each tendon is compared to the Base Values predicted for the specific tendon at the specific time of the test as described in Regulatory Guide 1.35, Revision

3. Conditions that do not meet acceptance criteria result in a scope expansion to determine the extent of the condition, evaluated for acceptability in accordance with ASME requirements, and entered in corrective action process.

The TMI-1 aging management program compiles with ASME Section XI, Subsection IWL, 1992 Edition including 1992 Addenda, as approved by 10 CFR 50.55a. In accordance with 10 CFR 50.55a(g)(4)(ii), the TMI-1 ISI program is updated each successive 120-month inspection interval to comply with the requirements of the latest edition of the ASME Code specified twelve months before the start of the inspection interval.

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Appendix B - Aging Management Programs TMI-1 is committed to replacing the existing steam generators with new Once Through Steam Generators (OTSGs) prior to entering the period of extended operation. Repair/replacement of Reactor Building concrete and prestressing system, removed for access purposes, will be done in accordance with ASME Section XI, Subsection IWL.

NUREG-1801 Consistency The TMI-1 ASME Section XI, Subsection IWL aging management program is consistent with the ten elements of aging management program XI.S2, "ASME Section XI, Subsection IWL," specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

Operating Experience TMI-1 completed reactor building (containment) 30th and 25th year ISI examinations (Periods 8 and 7) in 2005 and in 2000 respectively.

Examinations for these two periods were conducted in accordance with ASME Section XI, Subsection IWL. Prior to the 25th year ISI, examinations were conducted based on the requirement of Regulatory Guide 1.35, Revision 3 as specified in the plant Technical Specifications and the UFSAR. The results of the 30th year examinations and corrective actions for prestressing tendon wires, end anchorage, corrosion protection medium, and concrete surfaces are summarized below.

1. Prestressing Tendon wires All tendon forces were above 95% of the predicted values.

Vertical, hoop and dome tendon normalized group mean forces were all above the minimum required levels.

Vertical and hoop tendon force trends projected to the latest date for completion of the 35th year ISI were above the minimum required levels for those groups. The unadjusted dome tendon projection was below the minimum required level; the result of a small sample statistical anomaly. A projection using forces adjusted for the mean normalization factor met the acceptance criterion. The dome tendon projection was accepted by evaluation.

Elongations measured during re-tensioning of de-tensioned dome and hoop tendons were within 10% of previously measured values.

The elongation of V-140 exceeded the 10% limit, a condition attributed to anchor head rotation observed during the re-tensioning process. As a result, tendons V-137 and V-141 (like V-140, these Three Mile Island Nuclear Station Unit 1 Page B-91 License Renewal Application

Appendix B - Aging Management Programs curve around the equipment opening) were added to the surveillance sample, de-tensioned, and re-tensioned. Elongation of the two tendons met the 10% acceptance criteria and elongation of tendon V-140 also met the acceptance criteria during the second re-tensioning. On this basis engineering evaluation concluded the initial excess elongation of V-140 is acceptable.

The tensile strength and elongation (at failure) of all wire test samples were above the minimum required values.

2. End Anchorage End anchorage hardware was free of active corrosion, cracking and distortion. With two exceptions, button head condition was as documented during construction. One exception was a single button head protruding about 0.1 inch that was not previously documented.

Since such a small protrusion could have been easily missed by the construction examinations, this was accepted without further question. Four button heads protruded from the lower anchor head of V-140 both before de-tensioning and after re-tensioning. Since the vertical tendons are tensioned at the top end only, it was concluded that protruding button heads at the lower end could have been overlooked at the time of construction. On this basis, the condition was accepted by evaluation.

Coating degradation was observed in large areas of several vertical tendon upper end-bearing plates. Some of these areas were rusted.

The areas were cleaned to bright metal, primed and painted to prevent further corrosion.

3. Corrosion Protection Medium:

Water content, corrosive ion concentration and reserve alkalinity of all corrosion protection medium samples selected for testing during this period met acceptance criteria. The follow-up testing of the corrosion protection medium for lower ends of tendons V-86 and V-164, which was recommended during 25th year surveillance, was done and the test results met acceptance criteria. No free water was found at tendon anchorages. Concrete adjacent to end anchorages was free of cracks over 0.01 inches wide. End anchorage covers (grease caps) were free of damage; only a few showed any signs of corrosion protection medium leakage and the leakage observed were deemed to be insignificant.

Leakage of the corrosion protection medium (grease) has been observed over the years. The leakage is through small cracks in concrete and through the grease end cap seals. The end caps of a sample of tendons with significant grease leakage were removed and inspected. No corrosion was observed on the anchor head, base plate or button heads. The affected seals were replaced and Three Mile Island Nuclear Station Unit 1 Page B-92 License Renewal Application

Appendix B - Aging Management Programs the leaked grease was replaced. Grease leakage is being addressed under the Repetitive Task program.

4. Concrete Surfaces Concrete surfaces were free of damage, deterioration other than that previously documented; except for the following:

Water seeping under three embedded plates on the dome has resulted in some minor leaching of the concrete. These plates extend out from a point close to the dome apex toward the general area of the vent stack on the west side of the containment. This condition was corrected by sealing the concrete to embed interface area with a caulking compound to prevent further entry of water.

Grout patches have detached from dome surface at two locations leaving depressions that can accumulate water. One location is alongside an embed on the west side of the dome. The other is on the west side of the dome close to the crane rail. These depressions were filled with epoxy grout to prevent ponding and the consequent possibility of progressive freeze-thaw damage.

Concrete surface areas with previously documented damage and deterioration were re-examined. In all cases, the conditions previously recorded were found to be effectively stable. However, in several of these areas it was determined that repair/restoration work is necessary to ensure against further deterioration. The repair and restoration work was completed in 2006. With one exception, the repaired areas consist of minor restorative work on the concrete surface or sealing against water intrusion. These are not subject to ASME Section XI Repair/ Replacement requirements. The exception is the application of protective coating in the areas where reinforcing steel is exposed on the vertical face of the ring girder.

This work falls under the purview of ASME Section XI since the first layer of reinforcing is exposed. The repaired areas will be re-examined during the next ISI examination, Period 9 (2009)

Conclusion The continued implementation of the TMI-1 ASME Section XI, Subsection IWL aging management program provides reasonable assurance that the aging effects of loss of material, cracking, cracking and expansion, increase in porosity and permeability, and loss of bond in reinforce concrete, loss of prestress of the tendons, and loss of material for tendon wires and end anchorage will be adequately managed so that the intended functions of the Reactor Building (containment) components within the scope of License Renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.26 ASME SECTION XI, SUBSECTION IWF Program Description The ASME Section XI, Subsection IWF aging management program is an existing program that consists of periodic visual examination of ASME Section XI Class 1, 2, and 3 piping and component support members for loss of mechanical function, lock-up due to wear, and loss of material. Bolting is also included with these components and inspected for loss of material and for loss of preload by inspecting for missing, detached, or loosened bolts. The program also relies on the design change procedures that are based on EPRI TR-104213 guidance to ensure proper specification of bolting material, lubricant, and installation torque.

The program is implemented through corporate and station procedures, which provide inspection and acceptance criteria consistent with the requirements of ASME Section XI, Subsection IWF 1995 Edition with 1996 Addenda as approved by 10 CFR 50.55(a).

In accordance with 10 CFR 50.55a(g)(4)(ii), the TMI-1 ISI program is updated each successive 120 month inspection interval to comply with the requirements of the latest edition of the ASME Code specified twelve months before the start of the inspection interval.

NUREG-1801 Consistency The TMI-1 ASME Section XI, Subsection IWF aging management program is an existing program that is consistent with NUREG-1801 aging management program XI.S3, ASME Section XI, Subsection IWF with the exception described below.

Exceptions to NUREG-1801 NUREG-1801 evaluation covers the 2001 edition including the 2002 and 2003 Addenda, as approved in 10 CFR 50.55a. The current TMI-1 ISI Program Plan for the Third Ten-Year Inspection Interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

Enhancements None.

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Appendix B - Aging Management Programs Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of mechanical function, lock-up due to wear, loss of material and loss of bolting function (which includes loss of material and loss of preload by inspecting for missing, detached, or loosened bolts) are being adequately managed. The following examples of operating experience provide objective evidence that the TMI-1 ASME Section XI, Subsection IWF program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. Visual examinations conducted in 1999 in accordance with ASME Section XI, Subsection IWF identified non-recordable and recordable indications. Non-recordable indications consist of minor surface rust, loose bolts or nuts, and out of tolerance hot or cold settings for piping and component supports. A total of 166 piping and component supports (40 Class 1, 96 Class 2, 30 Class 3) were examined. Six (6) of the Class 1 supports, 19 of the Class 2 supports, and 2 Class 3 supports required engineering evaluation.

Engineering found the 6 Class 1 supports acceptable. Nineteen (19) Class 2 supports required engineering evaluation; 16 of which were found acceptable and 3 were found unacceptable and required repair. The unacceptable condition was due to loose, missing bolts or nuts. As a result of unacceptable conditions, the scope of inspection was expanded 3 times to include additional supports in order to determine the extent of the condition. The scope expansions were in the Main Steam system where, due to the dynamics of the system, many nuts and/or bolts were either loose or missing. Deficiencies identified in all Class 1, 2, or 3 supports were documented, and either accepted by evaluation or repaired to meet design requirements.

2. Visual examinations conducted in 2001, 2003, 2005, in accordance with ASME Section XI, Subsection IWF identified non-recordable indications that consist of minor surface rust, loose bolts or nuts, and out of tolerance hot or cold settings for piping and component supports. The loose bolts and nuts were tightened and the out tolerance settings were restored to meet design requirements. The surface rust was evaluated and determined not to impact the structural integrity of the supports.

3. A nuclear oversight assessment of non-destructive examination (NDE) procedures governed by the ISI program discovered an inspection procedure that was not updated to reflect the currently applicable ASME Code and Addenda editions as referenced in the ISI program. A review was performed to determine any effect from citing the earlier code, and an extent of condition review was performed to ascertain the existence of any similar incorrect code date use. This example provides objective evidence that deficiencies are identified and entered into the corrective action process and that the program is updated as necessary to ensure Three Mile Island Nuclear Station Unit 1 Page B-95 License Renewal Application

Appendix B - Aging Management Programs that it remains effective for condition monitoring of piping and components within the scope of license renewal.

4. A focused-area self assessment of the TMI-1 ISI program identified improvement items for completeness of program documentation including referencing an NRC issued SER for a weld repair in the program, referencing an NRC issued SER addressing certification of VT-2 examiners in the program, and including information from the repair and replacement program in the work order used as the repair plan. These changes were made in revisions to the program documents and implemented by the work planners. This example provides objective evidence that deficiencies are identified and entered into the corrective action process and that the program is updated as necessary to ensure that it remains effective for condition monitoring of piping and components within the scope of license renewal.

The operating experience of the ASME Section XI, Subsection IWF program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the ASME Section XI, Subsection IWF program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of ASME Section XI, Subsection IWF program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The continued implementation of the TMI-1 ASME Section XI, Subsection IWF aging management program provides reasonable assurance that the aging effects of loss of mechanical function, lock-up due to wear, loss of material and loss of bolting function (which includes loss of material and loss of preload) will be adequately managed so that the intended functions of piping and component supports within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.27 10 CFR PART 50, APPENDIX J Program Description The 10 CFR Part 50, Appendix J aging management program is an existing program that provides for detection of age related pressure boundary degradation and loss of leak tightness due to aging effects such as loss of material, loss of sealing, cracking, or loss of preload in the containment and various systems penetrating primary containment. The program also provides for detection of age related degradation in material properties of gaskets, o-rings, and packing materials for the primary containment pressure boundary access points.

The program consists of tests performed in accordance with the regulations and guidance provided in 10 CFR 50 Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B, Regulatory Guide 1.163, Performance-Based Containment Leak-Testing Program, NEI 94-01, Industry Guideline for Implementing Performance-Based Options of 10 CFR Part 50, Appendix J, and ANSI/ANS 56.8, Containment System Leakage Testing Requirements.

Containment leak rate tests are performed to assure that leakage through the containment and systems and components penetrating primary containment does not exceed allowable leakage limits specified in the Technical Specifications. An integrated leak rate test (ILRT) is performed during a period of reactor shutdown at the frequency specified in 10 CFR Part 50, Appendix J, Option B. Local leak rate tests (LLRT) are performed on isolation valves and containment access penetrations at frequencies that comply with the requirements of 10 CFR 50 Appendix J, Option B.

NUREG-1801 Consistency The 10 CFR Part 50, Appendix J aging management program is consistent with the ten elements of aging management program XI.S4, "10 CFR Part 50, Appendix J," specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

Operating Experience The industry has found that the 10 CFR Part 50, Appendix J testing program has been effective in maintaining the pressure integrity of the containment boundaries, including identification of leakage within the various systems pressure boundaries.

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Appendix B - Aging Management Programs The Three Mile Island Unit 1 facility has demonstrated experience in effectively maintaining the integrity of the containment boundaries. The operating experience of the 10 CFR 50, Appendix J program has shown a positive trend in performance. This operating experience shows that individual valves on occasion exceed the leakage acceptance test values and repairs are made in accordance with the program, however, the overall leakage total has been generally trending down. Leakage test data in standard cubic centimeters per minute (SCCM) is as follows: 40,247 SCCM in 2001, 23,687 SCCM in 2003, 21,712 SCCM in 2005 and 22,159 SCCM in 2007.

The allowable limit for the maximum leakage is 104,846 SCCM and the latest values represent approximately 20 percent of this value. Based on this data, there is sufficient confidence that the implementation of the 10 CFR 50, Appendix J program will effectively identify degradation prior to failure.

Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the 10 CFR 50, Appendix J program are performed to identify the areas that need improvement and to identify enhancements to maintain the quality performance of the program.

Conclusion The 10 CFR Part 50, Appendix J aging management program provides reasonable assurance that the loss of material and changes in material properties aging effects are adequately managed so that containment components within the scope of license renewal will continue to perform their intended functions consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.28 STRUCTURES MONITORING PROGRAM Program Description The Structures Monitoring Program is an existing program that provides for aging management of structures and structural components, including structural bolting, within the scope of license renewal. The program was developed based on guidance in Regulatory Guide 1.160 Revision 2, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, and NUMARC 93 01 Revision 2, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, to satisfy the requirement of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, The scope of the program also includes condition monitoring of masonry walls and water-control structures as described in the Masonry Wall Program and in the RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants, aging management program. As a result, the program elements incorporate the requirements of NRC IEB 80-11, Masonry Wall Design, the guidance in NRC IN 87-67, Lessons learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11, and the requirements of NRC Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants.

The program consists of periodic visual inspections by qualified personnel to monitor structures and components for applicable aging effects. Specifically, concrete structures are inspected for loss of material, cracking, and a loss of bond. Steel components are inspected for loss of material due to corrosion.

Masonry walls are inspected for cracking, and elastomers will be monitored for a loss of sealing. Earthen structures associated with water-control structures will be inspected for loss of material and loss of form. Component supports will be inspected for loss of material, reduction or loss of isolation function, and reduction in anchor capacity due to local concrete degradation. Exposed surfaces of bolting are monitored for loss of material, due to corrosion, loose nuts, missing bolts, or other indications of loss of preload. The program also relies on the design change procedures that are based on EPRI TR-104213 guidance to ensure proper specification of bolting material, lubricant, and installation torque.

The scope of the program will be enhanced to include structures that are not monitored under the current term but require monitoring during the period of extended operation. Details of the enhancements are discussed below.

Inspection frequency is every 5 years maximum, with provisions for more frequent inspections to ensure that observed conditions that have the potential for impacting an intended function are evaluated or corrected in accordance with the corrective action process.

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Appendix B - Aging Management Programs NUREG-1801 Consistency The Structures Monitoring Program is consistent with the ten elements of aging management program XI.S6,"Structures Monitoring Program," specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements

• Include Service Building, UPS Diesel Building, Mechanical Draft Cooling Tower Structures, Miscellaneous Yard Structures (Foundation for condensate storage tank, borated water storage tank, diesel fuel storage tank, altitude tank, duct banks, and manholes)

• Monitor penetration seals that perform flood barrier, shelter, protection, and pressure boundary intended functions.

• Monitor the Intake Canal for loss of material and loss of form

• Monitor electrical panels, junction boxes, instrument panels, and conduits for loss of material due to corrosion

• Monitor ground water chemistry by periodically sampling, testing, and analysis of ground water to confirm that the environment remains non-aggressive for buried reinforced concrete.

• Monitor reinforced concrete submerged in raw water associated with Intake Screen and Pumphouse, Circulating Water Pump House, Mechanical Draft Cooling Tower Structures, Natural Draft Cooling Tower Basins

• Monitor vibration isolators, associated with component supports other than those covered by ASME XI, Subsection IWF, for reduction or loss of isolation function.

• Parameters monitored will be enhanced to include plausible aging mechanisms.

• Monitor concrete structures for a reduction in anchor capacity due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling

• Revise acceptance criteria to provide details specified in ACI 349.3R-96.

The enhancements will be implemented prior to entering the period of extended operation.

Operating Experience The TMI-1 Structures Monitoring Program was implemented on the schedule mandated by 10 CFR 50.65(a). Baseline inspections of all structures in the scope of Maintenance Rule were completed in 1999. An additional inspection was completed in 2004 consistent with the program 5-year frequency.

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Appendix B - Aging Management Programs

1. The 2004 Inspection of 22 structures in the scope of Maintenance Rule identified no significant degradations that impact the intended function of structures and structural components. Hairline cracks, minor spalling and leaching of calcium hydroxide was observed on concrete surfaces in 2004. The inspectors also observed small cracks in the mortar joints of Turbine Building airshaft masonry wall above elevation 355. The cracks were also noted in Baseline Inspections completed in 1999 and appear not to have changed since that time.

2. The Flood Dike inspection identified no indication of settlement or slope instability. The riprap is well settled, with no signs of movement or degradation. Three areas of local washout were observed and attributed to occasional high-level river water runoffs rather than by the normal river flow. The areas were evaluated and determined not to pose an immediate threat to the dike integrity.

The size and location of the washout areas were entered into the corrective action process and scheduled for visual examination during the dike semi-annual inspection.

3. Silt accumulation was observed at the discharge of the 48-inch diameter Emergency River Water Dump line. The silt covered approximately half the diameter of the pipe outlet, a condition also observed in 1999, during the Baseline inspections. Engineering evaluation concluded that the discharge line remains capable of performing its intended function. The pipe outlet is under Operations Surveillance and is inspected on annual basis to ensure that the discharge line is capable of performing its intended function.

4. Equipment supports including anchorages and equipment foundations have no indications of damage or deterioration that would jeopardize equipment integrity. A missing anchor bolt at the condensate booster pump discharge header support, and a degraded grout pad at the base of the auxiliary boiler stack were observed. The conditions were entered into the corrective action for evaluation and repair.

5. Ground water intrusion was identified in the Air Intake Tunnel. The in-leakage, estimated at 1-2 gpm during wet weather, is attributed to a degraded expansion joint seal. Evaluation of the condition concluded that the sump pumps are capable of removing the inflow water, thus flooding of the tunnel is not a concern. Visual inspection of concrete floor at the expansion joint did not show signs of degradation (leaching, rust stains). Repairs to some of the seal were completed in 2006; with additional repairs to be done in 2007.

Additional water leaks were observed through small cracks on the tunnel walls and the roof. Minor leaching of calcium hydroxide and minor rust stains were noted at some of the cracks. Engineering evaluation concluded that the observed leaching and rust stains are not an indication of significant concrete degradation or rebar Three Mile Island Nuclear Station Unit 1 Page B-101 License Renewal Application

Appendix B - Aging Management Programs corrosion. The Air Intake Tunnel ground water in-leakage poses no safety concern and its impact on concrete and reinforcement is not significant. The condition was entered into the corrective action process for repair of the seal.

Conclusion The enhanced TMI-1 Structures Monitoring Program provides reasonable assurance that loss of material, cracking, loss of bond, reduction in anchor capacity due to local degradation of concrete, reduction or loss of isolation function, loss of sealing, loss of preload, and loss of form will be adequately managed so that the intended functions of structures and structural components within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.29 PROTECTIVE COATING MONITORING AND MAINTENANCE PROGRAM Program Description The Protective Coating Monitoring and Maintenance Program is an existing program that provides for aging management of Service Level I coatings inside the containment. Service Level I coatings are used in areas where corrosion protection may be required and where coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown.

TMI-1 was not originally committed to Regulatory Guide 1.54 for Service Level I coatings because the plant was licensed prior to the issuance of this Regulatory Guide in 1973. Currently, TMI-1 is committed to a modified version of this Regulatory Guide, as described in the response to GL 98-04, and, as detailed in the Exelon Quality Assurance Topical Report. The Protective Coating Monitoring and Maintenance Program provides for inspections, assessment, and repairs for any condition that adversely affects the ability of Service Level I coatings to function as intended.

NUREG-1801 Consistency The Protective Coating Monitoring and Maintenance Program is consistent with the ten elements of aging management program XI.S8, Protective Coating Monitoring and Maintenance Program, specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that degradation of Service Level I protective coatings are being adequately managed. The following examples of operating experience provide objective evidence that the Protective Coating Monitoring and Maintenance Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. During inspection of containment coatings in 1997, peeling and delamination was observed on the containment liner in an area approximately 15 wide by 10 high. The failure of the coating was attributed to limited inadequate surface preparation during previous liner coating repair work performed during the mid 1980s. No notable degradation of the liner was observed. Numerous other small areas of surface rusting and coating degradation were observed on the liner. Additionally, the 6 Emergency Feedwater line exhibited significant coating degradation (delamination). The Three Mile Island Nuclear Station Unit 1 Page B-103 License Renewal Application

Appendix B - Aging Management Programs degraded coating was either immediately repaired or evaluated for repair during the next refueling outage. Where coating repair was deferred, the degraded coating was evaluated and documented in the unqualified coatings list in accordance with engineering procedures. This example provides objective evidence that a) the coatings program identifies aging effects prior to the loss of intended function, b) deficiencies found during containment coatings inspections are documented in the corrective action program and evaluated for impact on system operability and intended functions, and c) repair activities are specified when necessary to maintain system intended functions.

2. Refueling outage coating inspections were performed in 2003 on the steel containment liner, concrete containment surfaces, and equipment/piping within the containment. Coating deficiencies such as blistering, chipping, cracking, peeling, rusting, mechanical damage, and missing topcoat were photographically recorded and documented in a Coating Inspection Topical Report and several engineering technical evaluations. Coating deficiencies were evaluated by engineering in accordance with engineering procedures and prioritized as requiring immediate repair or deferred repair. Engineering evaluation was also used to determine coating deficiencies that were acceptable as-is with continued monitoring.

Coating deficiencies that were not repaired were evaluated to determine their impact on potential liner degradation and on the containment sump debris analysis. Evaluations were documented in the corrective action program and in engineering technical evaluations. This example provides objective evidence that a) the coatings program identifies aging effects prior to the loss of intended function, b) deficiencies found during containment coatings inspections are documented in the corrective action program and evaluated for impact on system operability and intended functions, and c) repair activities are specified when necessary to maintain system intended functions.

3. Refueling outage coating inspections were performed in 2005 on the steel containment liner, concrete containment surfaces, and equipment/piping within the containment. Coating deficiencies such as blistering, chipping, cracking, peeling, rusting, mechanical damage, and missing topcoat were photographically recorded and documented in engineering technical evaluations. Coating deficiencies were evaluated by engineering in accordance with engineering procedures and prioritized as requiring immediate repair or deferred repair. Engineering evaluation was also used to determine coating deficiencies that were acceptable as-is with continued monitoring. Coating deficiencies that were not repaired were evaluated to determine their impact on potential liner degradation and on the containment sump debris analysis.

Evaluations were documented in the corrective action program and in engineering technical evaluations. This example provides objective evidence that a) the coatings program identifies aging Three Mile Island Nuclear Station Unit 1 Page B-104 License Renewal Application

Appendix B - Aging Management Programs effects prior to the loss of intended function, b) deficiencies found during containment coatings inspections are documented in the corrective action program and evaluated for impact on system operability and intended functions, and c) repair activities are specified when necessary to maintain system intended functions.

4. During the design walkdowns in 2006 for the Reactor Building Sump modification, a small amount of coating was found separated from the steel deck under the concrete floor at the 308 and 347 elevations in the Reactor Building. Further inspection revealed that the steel decking had a zinc coating beneath the DBA qualified Carboline 368 primer and Phenoline 368 topcoat protective coating from original construction. Although the protective coating system is DBA qualified, it had not been qualified with the zinc present on the floor decking. Eight samples were shipped to the Keeler and Long DBA Testing facility for analysis. The results of the testing concluded that the coating system was not qualified when applied over the zinc coating on the steel decking. As a result of the testing, a portion of the coating is being tracked as unqualified coating as determined by engineering evaluation. An operability review was performed that indicated that this condition did not adversely impact applicable safety functions. This example provides objective evidence that deficiencies found during containment coatings inspections are documented in the corrective action program and evaluated for impact on system operability and intended functions.

The operating experience of the Protective Coating Monitoring and Maintenance Program provides objective evidence that problems identified would not cause significant impact to the safe operation of the plant and that adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the Protective Coating Monitoring and Maintenance Program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found.

Conclusion The existing Protective Coating Monitoring and Maintenance Program provides reasonable assurance that aging effects are adequately managed so that the intended functions of Service Level I coatings inside containment are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.30 ELECTRICAL CABLES AND CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS Program Description The Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a new program that will be used to manage non-EQ cables and connections within the scope of license renewal that are subject to adverse localized environments. An adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the cable or connection.

Cables and connections subject to an adverse environment are managed by visual inspection of the insulation. A sample of accessible electrical cables and connections installed in adverse environments will be visually inspected for signs of accelerated age-related degradation such as embrittlement, discoloration, cracking, or surface contamination. Additional inspections, repair or replacement are initiated as appropriate under the Corrective Action Process.

A sample of accessible cables and connections found to be located in adverse environments will be inspected prior to the period of extended operation, with an inspection frequency of at least once every 10 years. The scope of this program includes inspections of power, control and instrumentation cables and connections located in adverse localized areas.

NUREG-1801 Consistency The aging management program for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements is a new program. The program will be implemented prior to the period of extended operation. Program activities are consistent with the ten elements of aging program XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements, specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

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Appendix B - Aging Management Programs Operating Experience As noted in NUREG-1801, industry operating experience has shown that adverse localized environments caused by heat or radiation for electrical cables and connections may exist next to or above steam generators, pressurizers or hot process pipes, such as feedwater lines. These adverse localized environments have been found to cause degradation of the insulating materials on electrical cables and connections that is visually observable, such as color changes or surface cracking. These visual indications can be used as indications of degradation.

In response to the cable insulation degradation experienced in an adverse localized environment at Turkey Point, TMI-1 evaluated its configurations for the potential of heat damage to cable insulations. It was determined that TMI-1 did not have the subject design configuration at Turkey Point. Additionally, a few instances of potentially age-related degradation of cables have been identified during the conduct of routine maintenance activities and dispositioned using the corrective action process. In each case, engineering evaluations determined the cause of the apparent degradation, the effect on operability and appropriate corrective action, providing TMI-1 specific operating experience that provides objective evidence demonstrating effectiveness of the corrective action process in identifying and resolving potential age related cable and connection insulation degradation issues. These cases were not significant with respect to current licensing basis or plant safety.

This aging management program is new. Therefore, no programmatic operating experience is available.

Conclusion The aging management program for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements provides reasonable assurance that aging effects will be adequately managed so that the intended functions of these types of cables and connections are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.31 ELECTRICAL CABLES AND CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS USED IN INSTRUMENTATION CIRCUITS Program Description The Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits aging management program is an existing program that will be enhanced to manage the aging of the cable and connection insulation of the in scope radiation monitoring and nuclear instrumentation circuits in the License Renewal Radiation Monitoring and Nuclear Instrumentation and Incore Monitoring Systems. The in scope radiation monitoring and nuclear instrumentation circuits are sensitive instrumentation circuits with low-level signals and are located in areas where the cables and connections could be exposed to adverse localized environments caused by heat, radiation, or moisture. These adverse localized environments can result in reduced insulation resistance causing increases in leakage currents. Calibration testing and system performance monitoring are currently being performed for in scope radiation monitoring circuits. The current radiation monitoring circuit calibrations will be performed at least once every two years during the period of extended operation. Direct cable testing will be performed as an enhancement to ensure that the cable and connection insulation resistance is adequate for the in scope nuclear instrumentation circuits to perform their intended functions. Nuclear instrumentation direct cable testing will be performed once every 10 years. Based on acceptance criteria related to instrumentation loop performance and cable testing set forth in the calibration and testing procedures, evaluation of unacceptable results is performed under the Corrective Action Process. The in scope radiation monitoring calibration results will be assessed as part of system performance monitoring, for cable aging degradation, once every 10 years, as recommended by NUREG-1801 Section XI.E2. This enhanced aging management program will be implemented prior to the period of extended operation.

NUREG-1801 Consistency The TMI-1 Electrical Cables and Connections Not Subject to 10 CR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits aging management program is an existing aging management program that is consistent with NUREG-1801 aging management program XI.E2, Electrical Cables and Connections Not Subject to 10 CR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

Exceptions to NUREG-1801 None.

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Appendix B - Aging Management Programs Enhancements The TMI-1 Electrical Cables and Connections Not Subject to 10 CFR 50.59 Environmental Qualification Requirements Used In Instrumentation Circuits aging management program is an existing program that will be enhanced. In scope radiation monitoring circuits are currently tested in alignment with NUREG-1801 aging management program XI.E2, Electrical Cables and Connections Not Subject to 10 CR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. Existing testing practices will be enhanced by performing direct cable testing for in scope nuclear instrument circuits.

Operating Experience Industry operating experience has identified occurrences of cable and connection insulation degradation in high voltage, low level instrumentation circuits performing radiation monitoring and nuclear instrumentation functions.

The majority of occurrences are related to cable and connection insulation degradation inside of containment near the reactor vessel or to a change in an instrument readout associated with a proximate change in temperature inside the containment.

TMI-1 currently implements instrument circuit calibrations for the in scope radiation monitoring circuits as part of surveillance testing and preventive maintenance. Review of operating experience for these circuits and associated calibrations did not identify significant events attributable to insulation degradation nor a trend indicating age degradation is occurring. Therefore, this operating experience offers objective evidence that current calibration practices are effective in assuring that these circuits will be able to perform their intended functions throughout the period of extended operation.

As an enhancement, TMI-1 will implement direct cable tests for the in scope nuclear instrumentation circuits. This testing is to be added as an enhancement to existing practices which include periodic electronic component calibrations and heat balance computations. Recent TMI-1 operating experience with nuclear instrumentation circuits has resulted in a planned plant change for the replacement of the penetration for the NI-12 Source/Wide Range Nuclear Instrument to correct degraded penetration triaxial connectors.

This issue is documented, evaluated and corrected via the Corrective Action Program. The associated issue reports and corrective actions provide objective evidence of proper implementation and effectiveness of the TMI-1 corrective action process in capturing issues, resolving problems and preventing significant occurrences.

The Corrective Action Program documents occurrences when nuclear instruments did not meet test acceptance criteria. Calibrations were subsequently performed, demonstrating appropriate use of the Corrective Action Program and appropriate implementation of corrective actions.

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Appendix B - Aging Management Programs The direct cable testing of in scope nuclear instrumentation circuits is being added as an enhancement and is therefore a new portion to this program.

Therefore, no programmatic operating experience is available.

Conclusion This aging management program Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrument Circuits provides reasonable assurance that aging effects are adequately managed so that the intended functions of these types of cables and connections are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.32 INACCESSIBLE MEDIUM VOLTAGE CABLES NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS Program Description The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program manages inaccessible medium voltage cables that are exposed to significant moisture simultaneously with significant voltage.

Significant moisture is defined as periodic exposures to moisture that last more than a few days (e.g., cable in standing water). Periodic exposures to moisture that last less than a few days (i.e., normal rain and drain) are not significant.

Significant voltage exposure is defined as being subjected to system voltage for more than twenty-five percent of the time.

TMI-1s in scope, non-EQ, inaccessible medium voltage cables subject to significant moisture and voltage will be tested as part of this aging management program. These medium voltage cables will be tested using a proven test for detecting deterioration of the insulation system due to wetting, such as power factor, partial discharge, or polarization index, as described in EPRI TR-103834-P1-2, or other testing that is state-of-the-art at the time the test is performed. Cable testing will be performed at least once every 10 years.

The first tests will be completed prior to the period of the extended operation.

This aging management program will also inspect manholes associated with the in scope, non-EQ, inaccessible cables subject to significant moisture and voltage, so that draining or other corrective actions can be taken. Inspections for water collection will be performed at a frequency of twice per year, in accordance with existing practices. The first inspections will be completed prior to the period of extended operation.

NUREG-1801 Consistency The TMI-1 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a new aging management program that is consistent with NUREG-1801 aging management program XI.E3, Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

Exceptions to NUREG-1801 None.

Enhancements None.

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Appendix B - Aging Management Programs Operating Experience Industry operating experience has shown that cross linked polyethylene or high molecular weight polyethylene insulation materials, exposed to significant moisture and voltage, are most susceptible to water tree formation. Formation and growth of water trees varies directly with operating voltage. TMI-1 has not had an inaccessible medium voltage cable failure. Meggering is the cable testing currently performed. A different test methodology will be used for the implementation of this aging management program. TMI-1 does have operating experience with standing water in its electrical vaults, manways and manholes. Current preventive maintenance practices include twice per year inspections of manholes. If standing water is identified during these inspections, it is removed by pumping.

A NUREG-1801,Section XI.E3 compliant cable testing/condition monitoring aging management program will be implemented prior to the period of extended operation. The current manhole inspection program will remain in effect as a preventative measure to preclude the aging effect.

The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program is a new program.

Therefore, no programmatic operating experience is available.

Conclusion The implementation of the TMI-1 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program provides reasonable assurance that the inaccessible medium voltage cables exposed to significant moisture and significant voltage will be adequately managed so that the intended functions of these cables are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.33 METAL ENCLOSED BUS Program Description The Metal Enclosed Bus aging management program is an existing program that will be enhanced to manage the aging of metal enclosed busses at TMI-1.

A sample of accessible bolted connections will be checked for loose connections via thermography. Thermography of metal enclosed busses is an existing TMI-1 predictive maintenance activity. A sample of in scope metal enclosed bus internals are currently visually inspected.

This program, including its enhancements, will be implemented prior to the period of extended operation so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation.

NUREG-1801 Consistency The Metal Enclosed Bus, when enhanced, is consistent with the ten elements of aging management program XI.E4, Metal Enclosed Bus, specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements Thermography of metal enclosed busses is an existing TMI-1 predictive maintenance activity. A sample of in scope metal enclosed bus internals is currently visually inspected. These inspection activities will be enhanced to specify the following inspection criteria:

• Internal portion of the metal enclosed bus will be visually inspected for cracks, corrosion, foreign debris, excessive dust build-up and evidence of moisture intrusion.

• The bus insulation will be visually inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation.

• The internal bus supports will be visually inspected for structural integrity and signs of cracks.

As an additional enhancement, existing metal enclosed bus internal visual inspections will be expanded to include the 480V Metal Enclosed Bus and the Station Black Out Metal Enclosed Bus. This program, including its enhancements, will be implemented prior to the period of extended operation so that the intended functions of components within the scope of License Renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs Operating Experience Industry experience has shown that failures have occurred on Metal Enclosed Buses caused by cracked insulation and moisture or debris buildup internal to the Metal Enclosed Bus. Experience has also shown that bus connections in the Metal Enclosed Buses exposed to appreciable ohmic heating during operation may experience loosening due to repeated cycling of connected loads. NRC Information Notice IN 2000-14: Non Vital Bus Fault Leads to Fire and Loss of Offsite Power and LER 324-06001: Manual Scram Following a Loss of Startup Auxiliary Transformer are examples of non-segregated bus duct failures.

A specific review of the thermography results from Preventive Maintenance (PM) repetitive tasks and 1A Aux Transformer bus duct internal inspections did not identify a trend related to aging degradation. A search of the corrective action database has revealed no failures of Metal Enclosed Bus at TMI-1. This TMI-1 specific operating experience offers objective evidence demonstrating effectiveness of current practices, including the Corrective Action Program.

Conclusion The implementation of the TMI-1 Metal Enclosed Bus aging management program provides reasonable assurance that the loosening of bolted connections due to thermal cycling and ohmic heating; and embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced insulation resistance and electrical failure due to degradation, radiolysis and photolysis of organics; radiation-induced oxidation and moisture intrusion will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.2.1.34 ELECTRICAL CABLE CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS Program Description The Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a new aging management program that will be used to manage the aging effects of metallic parts of cable connections.

The aging effect/mechanism of concern is as follows:

• Loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation.

A representative sample of cable connections within the scope of License Renewal will be selected for one-time testing prior to the period of extended operation to confirm that there is no age related degradation of the electrical connection metallic parts, and if occurring, to determine the extent of any such degradation. The scope of this sampling program will consider application (medium and low voltage), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc). The technical basis for the sample selection will be documented.

The specific type of test performed will be a proven test for detecting loose connections, such as thermography or contact resistance measurement, as appropriate to the application.

NUREG-1801 Consistency The Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is consistent with the ten elements of aging management program XI.E6, " Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," specified in NUREG-1801, with exceptions described below.

Exceptions to NUREG-1801 NUREG-1801 describes an aging management program for electrical cable connections in Chapter XI: XI.E6 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. An NRC and industry effort is in progress, working towards the issuance of a revision to XI.E6, via the Interim Staff Guidance (ISG) process. The latest draft revision of this ISG was presented for public comment in the September 6, 2007, Vol. 72, No. 172 issue of the Federal Register as: Proposed License Renewal Interim Staff Guidance LR-ISG-2007-02: Changes to Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.E6, Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Solicitation of Public Comment. The exception for this aging management program is that the TMI-1 Electrical Cable Connections Not Three Mile Island Nuclear Station Unit 1 Page B-115 License Renewal Application

Appendix B - Aging Management Programs Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is consistent with NUREG-1801 as it is modified by the September 6, 2007 draft revision of LR-ISG-2007-02.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation are being adequately managed. The following examples of operating experience provide objective evidence that the TMI-1 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. In April 2002, a phase terminal hot spot was discovered by an operator on rounds. It appears the connections loosened due to heating and or vibration. After this event TMI-1 implemented the Exelon corporate Thermography Program Guide MA-AA-716-230-1003 as part of the corrective action.

2. In March of 2003, thermography revealed a hot spot on a breaker load side connection existed. The B phase connection was 9 degrees C hotter than the A and C phases due to a slightly loose lug. This demonstrates effective use of the Thermography Program to detect degraded connections and take appropriate maintenance actions before component failure.

3. In December of 2004, thermography revealed the line side connection was 11 degrees C hotter than the A and B phases as a result of a loosely crimped lug. This demonstrates effective use of the Thermography Program to detect degraded connections and take appropriate maintenance actions before component failure.

The Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements is a new program. Operating experience has demonstrated that TMI-1 has successfully identified loose connections through the effective use of thermography. There is sufficient confidence that the implementation of the TMI-1 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program will provide confirmation that supports industry operating experience that electrical connections have not experienced a high degree of failures and that existing TMI-1 installation and maintenance practices are effective.

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Appendix B - Aging Management Programs Conclusion The new Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program provides confirmation that the loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation aging effects is either not occurring or being precluded by an effective existing preventive maintenance program. A periodic inspection is therefore not required to assure that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.2.2 PLANT SPECIFIC AGING MANAGEMENT PROGRAMS This section provides summaries of the plant specific programs credited for managing the effects of aging.

B.2.2.1 NICKEL ALLOY AGING MANAGEMENT PROGRAM Program Description The TMI-1 Nickel Alloy Aging Management program is an existing program that provides for managing cracking due to primary water stress corrosion cracking (PWSCC) for nickel alloy components. The Nickel Alloy Aging Management program uses a number of inspection techniques to detect cracking due to PWSCC, including surface examinations, volumetric examinations and bare metal visual examinations. The Nickel Alloy Aging Management program implements the inspection of components through an augmented In-service Inspection (ISI) program. The augmented program administers component evaluations, examination methods, scheduling, and site documentation as required to comply with regulatory, code or industry commitments related to Nickel Alloy issues. The Nickel Alloy Aging Management program includes mitigation and repair activities and strategies to ensure the long-term operability of nickel alloy components. The Nickel Alloy Aging Management program implements applicable Bulletins and Generic Letters and staff-accepted industry guidelines.

Aging Management Program Elements The results of an evaluation of each element against the 10 elements described in Appendix A of the Standard Review Plan of License Renewal Applications for Nuclear Power Plants, NUREG-1800, are provided below.

Scope of Program - Element 1 The TMI-1 Nickel Alloy Aging Management Program manages cracking due to primary water stress corrosion cracking for nickel alloy components located in the Steam Generator, Reactor Vessel, Reactor Coolant, and Core Flooding system. The components do not include steam generator tubes or secondary side components (included in the Steam Generator Tube Integrity program (B.2.1.8)), reactor vessel internals (included in the PWR Vessel Internals program as described in Table A.5 item 36), or control rod drive mechanism nozzles (included in the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program (B.2.1.5)). The specific locations included are described by the Alloy 600 plan for TMI-1.

Currently, the Core Flooding locations are exempt from examination, however, a VT-2 examination is performed in accordance with IWC-2500-1 for these locations. However, future industry events or station evaluations may increase the population of components or allow the exclusion of some components from the scope of the program.

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Appendix B - Aging Management Programs Preventive Actions - Element 2 The Nickel Alloy Aging Management program includes mitigation activities and strategies to ensure the long-term operability of nickel alloy components.

Some of the currently available mitigation techniques include weld overlay, replacement with Alloy 690/52/152 and half nozzle repair. The program lists recommended mitigation strategies that are available and considerations to include when selecting a mitigation strategy. The Nickel Alloy Aging Management program is not a performance monitoring program.

Parameters Monitored/Inspected - Element 3 The Nickel Alloy Aging Management program implements the inspection of components through an augmented In-service Inspection (ISI) program. The augmented program administers component evaluations, examination methods, scheduling, and site documentation as required to comply with regulatory, code or industry commitments related to Nickel Alloy issues.

The Nickel Alloy Aging Management program uses a number of inspection techniques to detect cracking due to PWSCC. These include surface examinations, volumetric examinations and bare metal visual examinations.

The schedule for the examinations is described in the augmented ISI plan.

The Nickel Alloy Aging Management program is not a performance monitoring program. The Nickel Alloy Aging Management program includes mitigation activities and strategies to ensure the long-term operability of nickel alloy components. Some of the currently available mitigation techniques include weld overlay, replacement with Alloy 690/52/152 and half nozzle repair. The program lists recommended mitigation strategies that are available and considerations to include when selecting a mitigation strategy.

Detection of Aging Effects - Element 4 The Nickel Alloy Aging Management program uses a number of inspection techniques to detect cracking due to PWSCC. These include surface examinations, volumetric examinations and bare metal visual examinations.

Bare metal visual examinations are similar to VT-2 examinations but require removal of insulation to allow direct access to the metal surface while pressurized or not pressurized. The nickel alloy components have been ranked based on susceptibility, safety, and economic consequences of degradation/failure. Where applicable, MRP-139 PWSCC susceptibility categories have been assigned to the components.

Detection of cracking due to PWSCC is used to ensure that nickel alloy components meet required design attributes and maintain their availability to perform their intended function as designed when called upon. This program will detect age-related degradation prior to component failure. When required, repair or mitigation is used to ensure that components will meet the design requirements required to perform their intended function.

Nickel Alloy components are inspected in accordance with the augmented In-service Inspection (ISI) plan. The location of the inspection population is Three Mile Island Nuclear Station Unit 1 Page B-119 License Renewal Application

Appendix B - Aging Management Programs detailed in the augmented ISI plan. The schedule for the examinations is described in the augmented ISI plan.

The TMI-1 Nickel Alloy Aging Management program is based on the recommendations of NEI and the EPRI Materials Reliability Program (MRP).

Industry experience and research has resulted in recommended techniques and frequencies for inspection to detect cracking prior to component failure.

The TMI-1 Nickel Alloy Aging Management program ranks components based on susceptibility in accordance with MRP guidelines. Inspection population and sample size are in accordance with MRP guidelines.

Monitoring and Trending - Element 5 The TMI-1 Nickel Alloy Aging Management program ranks components based on susceptibility in accordance with MRP guidelines. Inspection frequencies are in accordance with MRP guidelines. Contingencies for repairs are evaluated prior to each inspection outage. Monitoring of industry-operating experience is performed to incorporate any required changes to the Nickel Alloy Aging Management plan as a result of industry experience.

The TMI-1 Nickel Alloy Aging Management inspections are performed as part of an augmented ISI inspection plan. The Nickel Alloy Aging Management program uses a number of inspection techniques to detect cracking due to PWSCC. These include surface examinations, volumetric examinations and bare metal visual examinations. Examination results are evaluated according to regulatory requirements and MRP guidance. Initiation of an issue report to evaluate the examination results is required when acceptance criteria is not met.

Acceptance Criteria - Element 6 Acceptance criteria are specified in the implementing procedure or work order in accordance with the applicable regulatory or industry requirements.

Any acceptance criteria not currently defined in the FSAR will be defined by engineering and accepted based on procedures, regulatory requirements and accepted industry practices.

All qualitative inspections will be performed to the same predetermined criteria as quantitative inspections in accordance with ASME code and approved site procedures.

Corrective Actions - Element 7 Examination results are evaluated according to regulatory requirements and MRP guidance. Initiation of an issue report to evaluate the examination results is required when acceptance criteria is not met.

If the examination results do not meet acceptance criteria, initiation of an issue report to evaluate the examination results is required. Engineering analysis of identified degradation will confirm that the component intended function will be Three Mile Island Nuclear Station Unit 1 Page B-120 License Renewal Application

Appendix B - Aging Management Programs maintained consistent with the current licensing basis, or the component will be repaired or replaced.

Confirmation Process - Element 8 Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B.

The Nickel Alloy Aging Management program includes mitigation activities and strategies to ensure the long-term operability of nickel alloy components.

Follow-up inspections of mitigated components are included in the Nickel Alloy Aging Management program.

When corrective actions are necessary, the corrective action process assures that the cause of the adverse condition is determined and corrective actions are effective in precluding repetition. This process defines how the effectiveness of corrective actions are monitored to prevent recurrence.

Administrative Controls - Element 9 The procedures used to implement the Nickel Alloy Aging Management program are included in the TMI-1 quality assurance program that provides for formal reviews and approvals. Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B.

The Nickel Alloy Aging Management program consists of administratively controlled procedures, which are controlled as stated in item above. This aging management program is included in the TMI-1 license renewal FSAR supplement.

Operating Experience - Element 10 Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking due to PWSCC is being adequately managed. The following examples of operating experience provide objective evidence that the Nickel Alloy Aging Management Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. During refueling outage 15 (Fall 2003), a recordable indication attributed to primary water stress corrosion cracking was identified in the weld that joins the 10 diameter pipe safe-end to the surge nozzle attached to the 36 diameter hot leg. The weld material is Inconel 182. The weld was repaired with a weld overlay during the Fall of 2003, which was approved by the NRC in a safety evaluation.

The weld was re-examined during refueling outage 16 (Fall 2005) and found to be acceptable.

2. During refueling outage 15 (Fall 2003), boron was found near the lower Pressurizer Heater Bundles. Further inspections and a root Three Mile Island Nuclear Station Unit 1 Page B-121 License Renewal Application

Appendix B - Aging Management Programs cause analysis determined that the root cause of the leakage was PWSCC of the Alloy 600 heater bundle diaphragm. The diaphragm was replaced with a stainless steel diaphragm plate.

3. During refueling outage 16 (Fall 2005), a proactive mitigation of the Alloy 600 material on the Pressurizer vent nozzle was performed.

For the vent nozzle, a half nozzle repair was performed. The lower portion of the original nozzle was left in the Pressurizer. The new upper portion of the nozzle as well as the weld pad on the outside surface of the Pressurizer was changed to stainless steel. Proactive mitigation of three pressurizer relief valve nozzles is planned for refueling outage 17 during the Fall of 2007, level sensing, one sample and one thermowell are planned for 2009 mitigation. In addition, the pressurizer surge nozzle (at the pressurizer) and the decay heat drop line alloy 82/182 welds will be mitigated with a weld overlay during refueling outage 17 in the Fall of 2007. TMI-1 has considered industry issues with mitigation for the pressurizer nozzles. Experience at McGuire with weld overlay design issues has been factored into the TMI-1 planned work for refueling outage

17. TMI-1 has committed to complete inspection or mitigation of the Pressurizer surge, spray, safety and relief valve nozzle welds containing Alloy 82/182 by December 31, 2007.

4. On August 21, 2003, the NRC issued Bulletin 2003-02, requesting that licensees of pressurized-water nuclear power reactors (PWRs) provide information related to the inspections that have been performed on RPV lower head penetrations. TMI-1 responded indicating that VT-2 examinations with the insulation in place had been performed during startup from each refueling outage since at least 1991. TMI-1 also stated that a bare metal visual examination would be performed during refueling outage 15 in the Fall of 2003.

TMI-1 performed a remote visual inspection of the 52 bottom mounted instrumentation nozzles and the RPV lower head in the Fall of 2003. There was no indication of bottom mounted instrumentation nozzle leakage, no lower RPV boric acid leakage, and no RPV base metal wastage observed.

The operating experience of the Nickel Alloy Aging Management Program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient confidence that the implementation of the program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the program are performed to identify the areas that need improvement to maintain the quality performance of the program.

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Appendix B - Aging Management Programs NUREG-1800 Consistency The TMI-1 Nickel Alloy Aging Management program is a plant-specific program that meets all of the elements of an aging management program as defined in NUREG-1800.

Exceptions to NUREG-1800 None.

Enhancements to NUREG-1800 None.

Conclusion The Nickel Alloy Aging Management program provides reasonable assurance that cracking due to PWSCC will be adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

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Appendix B - Aging Management Programs B.3 NUREG-1801 CHAPTER X AGING MANAGEMENT PROGRAMS B.3.1.1 METAL FATIGUE OF REACTOR COOLANT PRESSURE BOUNDARY Program Description The TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary program is an existing program credited for managing fatigue of reactor coolant pressure boundary components and other components. The program tracks the number of occurrences of significant thermal and pressure transients and compares the cumulative cycles to the number of design cycles, which are considered limits.

Several categories of transients are monitored, including reactor trips, heatups and cooldowns, power changes, secondary side temperature changes, hydrostatic tests, and high-pressure injection cycles. Corrective actions are required if the cumulative cycle count approaches 80 percent of a transient cycle design limit or transient cycle administrative limit to assure the limit is not exceeded.

The effect of the reactor coolant environment on TMI-1 fatigue usage has been evaluated for the sample components identified in NUREG/CR-6260 applicable for TMI-1 as a Babcock and Wilcox plant. The method for adjusting fatigue usage to address reactor water environmental effects was to multiply the current Cumulative Usage Factor (CUF) by 1.5 (60/40) to account for 60 years and to further multiply it by an environmental fatigue correction factor applicable for the material type using methodology from NUREG/CR-6583 for carbon and low-alloy steel and NUREG/CR-5704 for stainless steel. This resulted in fatigue usage values greater than 1.0 for certain components, which is unacceptable. Therefore, fatigue will be managed for these components using the Metal Fatigue of Reactor Coolant Pressure Boundary aging management program to assure fatigue usage is not permitted to exceed 1.0 during the period of extended operation. Calculations were prepared to determine how many transient cycles these components could experience without having environmentally adjusted fatigue usage exceeding 1.0, and these reduced numbers of cycles will be imposed as transient cycle administrative limits in the program prior to the period of extended operation.

Prior to the period of extended operation, the program will also be enhanced to add the statement: Acceptable corrective actions include: reanalysis of the component to demonstrate that the design code limit will not be exceeded prior to or during the period of extended operation, repair of the component, replacement of the component, or other methods approved by the NRC.

The program will be further enhanced to require consideration of environmental fatigue for additional reactor coolant pressure boundary locations if the cumulative usage factor for one of the environmental fatigue sample locations approaches the design limit of 1.0.

The continued implementation of the TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary aging management program provides reasonable assurance that fatigue of reactor coolant pressure boundary components will Three Mile Island Nuclear Station Unit 1 Page B-124 License Renewal Application

Appendix B - Aging Management Programs be managed so that the intended functions of the components within the scope of License Renewal will be maintained during the period of extended operation.

NUREG-1801 Consistency The TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary program is an existing program that, when enhanced, is consistent with NUREG-1801 aging management program X.M1, Metal Fatigue of Reactor Coolant Pressure Boundary.

Exceptions to NUREG-1801 None.

Enhancements The TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary program will be enhanced to add the statement: Acceptable corrective actions include:

reanalysis of the component to demonstrate that the design code limit will not be exceeded prior to or during the period of extended operation; repair of the component; replacement of the component, or other methods approved by the NRC. In addition, the program will be enhanced to require a review of additional reactor coolant pressure boundary locations if the usage factor for one of the environmental fatigue sample locations approaches its design limit.

Operating Experience The Transient Cycle Logbook has been satisfactorily maintained in the TMI-1 control room, and appropriate entries have been made when transients have occurred throughout plant operational periods. Additional data has been recorded for future use in characterizing each transient if a more rigorous analysis is ever needed. No transient limits have been approached or exceeded. Therefore, the program has been effective in assuring that the reactor coolant pressure boundary components have not been exposed to more transient cycles than they are analyzed for in the applicable fatigue analyses. The operating experience regarding this program is related to updating the transient cycle limits when revisions have been made to fatigue analyses that changed the number of acceptable cycles. The following examples demonstrate that the program has been appropriately reviewed when these changes occurred and updates were made when required.

Fatigue analyses have been revised when necessary to account for unanticipated transients that have been discovered in operating plants.

Two examples are pressurizer surge line thermal stratification transients and pressurizer insurge/outsurge transients that were not addressed in the original design analyses. Once they were identified, additional monitoring was performed at Oconee Unit 1 to characterize the transients, and a revised analysis was prepared that accounted for them. The revised analyses increased the fatigue usage associated with certain transients but no changes were made to the numbers of cycles, so no changes were required to the cycle limits in the monitoring program.

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Appendix B - Aging Management Programs

5. The HPI nozzle analyses were revised to account for a modification in the piping arrangement, resulting in revised numbers of cycles, which were incorporated into the monitoring program as revised limits.

Conclusion The enhanced TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary program manages cumulative fatigue damage of reactor coolant pressure boundary components by assuring that the associated Time-Limited Aging Analyses remain valid through the period of extended operation. This is accomplished by tracking the number of occurrences of plant transients that are significant contributors to fatigue usage for these components, including the transient types listed in UFSAR Table 4.1-1. The cumulative cycle counts are compared to the design cycle limits to assure they are not exceeded.

Corrective actions are required if the cumulative cycle count approaches 80 percent of a transient cycle design limit or transient cycle administrative limit to assure the limit is not exceeded. Acceptable corrective actions include reanalysis, repair or replacement of the component. This will assure that the design fatigue analyses will remain valid through the period of extended operation.

The effect of the reactor water environment upon fatigue has been evaluated on a sample of components listed in NUREG/CR-6260 for Babcock and Wilcox plants. Each of these environmental fatigue analyses were shown to have an environmentally adjusted Cumulative Usage Factor less than 1.0 for 60 years of operation based upon reduced numbers of transients that will be imposed as transient cycle administrative limits prior to the period of extended operation.

This will assure that the environmental fatigue analyses will also remain valid through the period of extended operation.

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Appendix B - Aging Management Programs B.3.1.2 CONCRETE CONTAINMENT TENDON PRESTRESS Program Description The TMI-1 Concrete Containment Tendon Prestress aging management program is an existing program that is part of the TMI-1 ASME Section XI, Subsection IWL Program. The program is based on the 1992 Edition, with 1992 Addenda, of the ASME Boiler and Pressure Vessel Code,Section XI and includes confirmatory actions that monitor loss of containment tendon prestressing forces during the current term and will continue through the period of extended operation.

The program requires measurement of prestressing forces in a 2% sample of each tendon group (vertical, hoop, dome) every five years. One tendon in each group sample is identified as a common, or control, tendon and is tested during each successive inspection. The remaining tendons in the sample are obtained by randomly selecting tendons from among all of those that have not been previously examined. The initial sample size, which may be expanded if unacceptable conditions are found, is established as specified in Table IWL-2521-1.

Assessments of the results of the tendon prestressing force measurements are performed in accordance with ASME Section XI, Subsection IWL to confirm adequacy of the prestressing forces. The assessment consists of the establishment of (a) acceptance criteria, and (b) trend lines. The acceptance criteria consist of lower limits on the forces in individual tendons and the minimum required prestressing force or value (MRV). The lower limit on the force in an individual tendon is, as specified in Section IWL 3221.1(b), 95% of the force predicted for the tendon at the time of the test. The predicted value for individual tendons is developed consistent with the guidance presented in NRC Regulatory Guide 1.35.1. As long as individual tendon forces remain above 95% of predicted values, there is definitive evidence that actual pre-stressing force loss is not significantly greater than that allowed for in the original design calculations.

Trend lines, one for each tendon group, are constructed using the measured tendon forces and represent the changes in mean vertical, hoop and dome prestressing forces with time. Trend line regression analysis is consistent with NRC Information Notice 99-10, Attachment 3. As long as the trend lines do not fall below the MRVs, the tendon prestress force is acceptable. In accordance with the requirements of 10 CFR 50.55a(b)(2)(viii)(B), an evaluation will be performed if the trend lines predict the prestressing forces in the containment to be below the MRV before the next scheduled inspection.

TMI-1 performed a new analysis based on actual measured forces to establish the trend of prestressing forces through the end of the period of extended operation. The analysis evaluates force trends by group (vertical, hoop and dome) and shows that group mean forces will not fall below applicable Minimum Required Values (MRVs) prior to the March 2010 deadline for the completion of the 35 Year Surveillance, a requirement of 10 CFR 50.55a Par.

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Appendix B - Aging Management Programs (b)(2)(viii)(B). However, as tendon force trends may vary with time, the conclusions regarding long-term (beyond March 2010) performance of the post-tensioning system are subject to change as the analysis is periodically updated to account for data acquired during future surveillances. Analysis of individual tendon forces against predicted values shows that there is, on average, a substantial margin between measured force levels and the acceptance limits (95% of predicted values) established in ASME Section XI, Sub-Section IWL, Par. 3221.1(b).

Loss of containment tendon prestressing forces is a Time-Limited Aging Analysis (TLAA) evaluated in accordance with 10 CFR 54.21(c)(1)(iii) as described in Section 4.7. This program is credited for managing loss of containment tendon prestressing forces through the period of extended of operation.

The TMI-1 tendons are ungrouted, thus a plant specific program or a case-by-case evaluation is not required.

TMI-1 is committed to replacing the existing steam generators with new Once Through Steam Generators (OTSGs) prior to entering the period of extended operation. Repair/replacement and testing of the Reactor Building prestressing system, removed for access purposes, will be done in accordance with ASME Section XI, Subsection IWL.

NUREG-1801 Consistency The TMI-1 Concrete Containment Tendon Prestress aging management program is consistent with the ten elements of aging management program X.S1, "Concrete Containment Tendon Prestress" specified in NUREG-1801 with the exception below.

Exceptions to NUREG-1801 NUREG-1801 evaluation specifies that acceptance criteria will normally consist of prescribed lower limit (PLL) and the minimum required value (MRV) calculated based on NRC Regulatory Guide 1.35.1 guidance. TMI-1 takes exception to using PLL as acceptance criteria. TMI-1 revised its program to comply with ASME Section XI, Subsection IWL, as mandated by 10 CFR 50.55a. Subsection IWL specifies that acceptance criteria be based on the actual design basis (or base value) forces and not the PLL or the base value forces less the upper bound losses. Therefore, IWL requires measured tendon force to be at least 95% of the base value rather than 95% of the significantly smaller PLL specified in Regulatory Guide 1.35. Thus TMI-1 acceptance criteria are more conservative than NUREG-1801 acceptance criteria.

Enhancements None.

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Appendix B - Aging Management Programs Operating Experience The operating experience of the Concrete Containment Tendon Prestress program did not show any adverse trend in performance. Forces were measured, in 1999 and 2004, on the required 2% sample of the total tendons population, as required by TMI-1 Technical Specification surveillance for the Reactor Building prestressing system. The 2% sample, or 12 tendons consist of 3 control tendons (1 vertical, 1 hoop, and 1 dome). The remaining 9 tendons (3 vertical, 4 hoop, and 2 dome) were obtained by randomly selecting tendons from among all of those that have not been previously measured. The measured force in each individual tendon met established acceptance criteria of not less than 95% of the predicted force and MRV for each tendon. Two additional tendons were added to the scope of testing in 2004 because elongation of the adjacent original sample tendon, measured during re-tensioning of tendons de-tensioned for removal of sample wires for testing, exceeded the acceptance limit. The measured forces for the two additional tendons also met acceptance criteria.

For control tendons, the average of all normalized tendon measured forces, was greater than the required minimum average tendon force specified in the UFSAR. Plots of the measured forces, measured force trend line data, and the predicted force trend line exhibit three consistent features.

1. Trend lines fitted to the measured forces all have flatter slopes than the predicted force trend lines and, as expected, all fitted trend lines have a negative slope.

2. 30th year surveillance measured forces and fitted trend line ordinates equal 30.6 years are all above predicted force line ordinates.

These plots provide a positive indication that tendon forces are currently decreasing at a lower than expected rate and, support the conclusion that mean tendon forces will remain above the minimum required value at least until the 35th year surveillance.

Conclusion The continued implementation of the TMI-1 Concrete Containment Tendon Prestress aging management program provides reasonable assurance that the aging effects of loss of containment tendon prestressing forces will be adequately managed so that the intended functions of reactor building (containment) components within the scope of license renewal will be maintained during the period of extended operation.

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Appendix B - Aging Management Programs B.3.1.3 ENVIRONMENTAL QUALIFICATION (EQ) OF ELECTRICAL COMPONENTS Program Description The Environmental Qualification (EQ) of Electric Components program is an existing program implemented through station procedures and preventive maintenance tasks. The TMI-1 Environmental Qualification (EQ) of Electric Components program complies with 10 CFR 50.49, Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants. All EQ equipment is included within the scope of License Renewal.

The program provides for maintenance of the qualified life for electrical equipment important to safety within the scope of 10 CFR 50.49. Program activities establish, demonstrate, and document the level of qualification, qualified configuration, maintenance, surveillance and replacement requirements necessary to meet 10 CFR 50.49. Reanalysis addresses attributes of analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, corrective actions if acceptance criteria are not met, and the period of time prior to the end of qualified life when the reanalysis will be completed. Qualified life is determined for equipment within the scope of the Environmental Qualification (EQ) of Electric Components program and appropriate actions such as replacement or refurbishment are taken prior to or at the end of the qualified life of the equipment so that the aging limit is not exceeded.

The Environmental Qualification (EQ) of Electric Components program addresses the low voltage I&C cable issues, consistent with those described in the closure of Generic Safety Issue 168 (GSI 168), Environmental Qualification of Electrical Equipment.

NUREG-1801 Consistency The Environmental Qualification (EQ) of Electric Components program is an existing program that is consistent with the ten elements of aging management program X.E1, Environmental Qualification (EQ) of Electrical Components, specified in NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements None.

Operating Experience Demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that the TMI-1 Environmental Qualification (EQ) of Electric Components program is adequately managing EQ components. The following examples of operating experience provide objective Three Mile Island Nuclear Station Unit 1 Page B-130 License Renewal Application

Appendix B - Aging Management Programs evidence that the TMI-1 Environmental Qualification (EQ) of Electric Components program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation:

1. On 9/15/2005 and 3/13/2006, elevated building area temperatures were observed due to an increase in outside ambient temperatures and equipment failure. Proper evaluation of these conditions through the corrective action program demonstrate that the TMI-1 Environmental Qualification (EQ) of Electric Components program is ensuring that EQ profiles are being met and immediate actions are taken to ensure that the elevated building area temperatures had not caused any components to exceed their qualified life.

2. During the performance of maintenance activities, conditions potentially adverse to maintaining the EQ qualification of components need to be identified and corrected. On 1/6/2004, a degraded EQ motor splice was identified through the corrective action system. It was promptly evaluated for operability impact, specifically to ensure it met the requirements of the EQ file.

3. During procurement activities, EQ qualification of components must be demonstrated prior to being installed in the plant. On 5/18/2004, a component being supplied by a vendor had less than adequate EQ documentation. The installation of the component in the plant was delayed until the proper EQ paperwork was obtained.

The operating experience of the TMI-1 Environmental Qualification (EQ) of Electric Components program did not show any adverse trend in performance.

Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence.

The key elements of the Environmental Qualification (EQ) of Electric Components program are being monitored and effectively implemented. There is sufficient confidence that the implementation of the TMI-1 Environmental Qualification (EQ) of Electric Components program will effectively identify degradation prior to failure. Appropriate guidance for re-evaluation, repair, or replacement is provided for locations where degradation is found. Periodic self-assessments of the TMI-1 Environmental Qualification (EQ) of Electric Components program are performed to identify the areas that need improvement to maintain the quality performance of the program.

Conclusion The Environmental Qualification (EQ) of Electric Components program provides reasonable assurance that aging effects are adequately managed so that the intended functions of components within the scope of 10 CFR 50.49 are maintained consistent with the current licensing basis during the period of extended operation.

Three Mile Island Nuclear Station Unit 1 Page B-131 License Renewal Application

Appendix C- Commodity Group Evaluations APPENDIX C Commodity Group Evaluations (This Appendix is not used).

Three Mile Island Nuclear Station Unit 1 Page C-1 License Renewal Application

Appendix D- Technical Specification Changes APPENDIX D Technical Specification Changes 10 CFR 54.22 requires that an application for license renewal include any Technical Specification changes or additions necessary to manage the effects of aging during the period of extended operation.

As part of the TMI-1 aging management review, Amergen identified and committed to the replacement of both Once Through Steam Generators (OTSGs) prior to the period of extended operation. In association with this replacement, a separate Technical Specification Change Request will be submitted.

No Technical Specification changes or additions were identified as necessary to manage the effects of aging during the period of extended operation and as such no Technical Specification changes or additions are included with this License Renewal Application.

Three Mile Island Nuclear Station Unit 1 Page D-1 License Renewal Application

Applicants Environmental Report -

Operating License Renewal Stage Three Mile Island Nuclear Station Unit 1 AmerGen Energy Company, LLC Docket No. 50-289 License No. DPR-50

Environmental Report TABLE OF CONTENTS Table of Contents Section Page Acronyms and Abbreviations ............................................................................................. AA-1 Chapter 1 Introduction....................................................................................................... 1-1 1.1 Purpose of and Need for Action ............................................................. 1-3 1.2 Environmental Report Scope and Methodology ..................................... 1-4 1.3 Three Mile Island Nuclear Station Unit 1 Licensee and Ownership........ 1-5 1.4 References ............................................................................................. 1-8 Chapter 2 Site and Environmental Interfaces ................................................................... 2-1 2.1 Location and Features ............................................................................ 2-3 2.2 Aquatic Ecology ...................................................................................... 2-4 2.2.1 Hydology ..................................................................................... 2-4 2.2.2 Water Quality .............................................................................. 2-4 2.2.3 Aquatic Communities .................................................................. 2-6 2.2.3.1 Macroinvertebrates ..................................................... 2-7 2.2.3.2 Adult Fish .................................................................... 2-7 2.3 Groundwater Resources......................................................................... 2-12 2.3.1 Water Bearing Units .................................................................... 2-12 2.3.2 Water Supply Wells ..................................................................... 2-12 2.3.3 Groundwater Monitoring.............................................................. 2-13 2.4 Critical and Important Terrestrial Habitats .............................................. 2-16 2.5 Threatened or Endangered Species....................................................... 2-17 2.6 Demography ........................................................................................... 2-19 2.6.1 Regional Demography................................................................. 2-19 2.6.2 Minority and Low-Income Populations ........................................ 2-21 2.6.2.1 Minority Populations.................................................... 2-21 2.6.2.2 Low-Income Populations............................................. 2-22 2.7 Taxes ...................................................................................................... 2-24 2.8 Land Use Planning ................................................................................. 2-25 2.9 Social Services and Public Facilities ...................................................... 2-28 2.9.1 Public Water Supply .................................................................... 2-28 2.9.2 Transportation ............................................................................. 2-29 2.10 Meteorology and Air Quality ................................................................... 2-31 2.11 Historic and Archaeological Resources .................................................. 2-32 2.11.1 Area History in Brief .................................................................... 2-32 2.11.2 Initial Construction and Operation ............................................... 2-33 2.11.3 Other Cultural Resource Activities in the Area ............................ 2-34 2.11.4 Current Status ............................................................................. 2-34 2.12 Known or Reasonably Foreseeable Projects in Site Vicinity .................. 2-36 2.13 References ............................................................................................. 2-63 Chapter 3 The Proposed Action........................................................................................ 3-1 3.1 General Plant Information....................................................................... 3-4 3.1.1 Reactor and Containment Systems............................................. 3-4 3.1.2 Cooling and Auxiliary Water Systems ......................................... 3-5 3.1.2.1 Surface Water ............................................................. 3-5 3.1.2.2 Circulating Water System............................................ 3-5 3.1.2.3 Groundwater Resources ............................................. 3-5 Three Mile Island Nuclear Station Unit 1 Page iii License Renewal Application

Environmental Report TABLE OF CONTENTS Table of Contents (Continued)

Section Page 3.1.3 Transmission Facilities ................................................................ 3-6 3.1.4 Waste Management and Effluent Control Systems..................... 3-7 3.1.4.1 Radioactive Waste ...................................................... 3-9 3.1.4.2 Nonradioactive Waste ................................................. 3-9 3.2 Refurbishment Activities ......................................................................... 3-10 3.3 Programs and Activities for Managing the Effects of Aging.................... 3-14 3.4 Employment............................................................................................ 3-15 3.5 References ............................................................................................. 3-20 Chapter 4 Environmental Consequences of the Proposed Action and Mitigating Actions 4-1 4.1 Water Use Conflicts ................................................................................ 4-7 4.2 Entrainment of Fish and Shellfish in Early Life Stages ........................... 4-9 4.3 Impingement of Fish and Shellfish.......................................................... 4-10 4.4 Heat Shock ............................................................................................. 4-11 4.5 Groundwater Use Conflicts (Plants Using > 100 GPM of Groundwater) 4-12 4.6 Groundwater Use Conflicts (Plants Using Cooling Towers Withdrawing Makeup Water From a Small River) ....................................................... 4-13 4.7 Groundwater Use Conflicts (Plants Using Ranney Wells) ...................... 4-15 4.8 Degradation of Groundwater Quality ...................................................... 4-16 4.9 Impacts of Refurbishment on Terrestrial Resources .............................. 4-17 4.10 Threatened or Endangered Species....................................................... 4-19 4.11 Air Quality During Refurbishment (Non-Attainment or Maintenance Areas) ..................................................................................................... 4-21 4.12 Microbiological Organisms...................................................................... 4-23 4.13 Electric Shock from Transmission-Line-Induced Currents...................... 4-25 4.14 Housing Impacts ..................................................................................... 4-28 4.14.1 Housing - Refurbishment............................................................ 4-28 4.14.2 Housing - License Renewal Term .............................................. 4-31 4.15 Public Water Supply ............................................................................... 4-31 4.15.1 Public Water Supply - Refurbishment......................................... 4-31 4.15.2 Public Water Supply - License Renewal Term ........................... 4-33 4.16 Education................................................................................................ 4-35 4.16.1 Education - Refurbishment ......................................................... 4-35 4.16.2 Education - License Renewal Term............................................ 4-35 4.17 Offsite Land Use ..................................................................................... 4-36 4.17.1 Offsite Land Use - Refurbishment .............................................. 4-36 4.17.2 Offsite Land Use - License Renewal Term................................. 4-37 4.18 Transportation ........................................................................................ 4-40 4.18.1 Transportation - Refurbishment.................................................. 4-40 4.18.2 Transportation - License Renewal Term .................................... 4-42 4.19 Historic and Archaeological Resources .................................................. 4-44 4.19.1 Historic and Archaeological Resources - Refurbishment ........... 4-44 4.19.2 Historic and Archaeological Resources - License Renewal Term 4-46 4.20 Severe Accident Mitigation Alternatives (SAMA).................................... 4-48 4.21 References ............................................................................................. 4-51 Page iv Three Mile Island Nuclear Station unit 1 License Renewal Application

Environmental Report TABLE OF CONTENTS Table of Contents (Continued)

Section Page Chapter 5 Assessment of New and Significant Information .............................................. 5-1 5.1 Discussion .............................................................................................. 5-3 5.2 References ............................................................................................. 5-5 Chapter 6 Summary of License Renewal Impacts and Mitigating Actions........................ 6-1 6.1 License Renewal Impacts....................................................................... 6-3 6.2 Mitigation ................................................................................................ 6-4 6.3 Unavoidable Adverse Impacts ................................................................ 6-5 6.4 Irreversible and Irretrievable Resource Commitments ........................... 6-6 6.5 Short-Term Use Versus Long-Term Productivity of the Environment..... 6-7 6.6 References ............................................................................................. 6-10 Chapter 7 Alternatives to the Proposed Action ................................................................. 7-1 7.1 No-Action Alternative .............................................................................. 7-5 7.2 Alternatives that Meet System Generating Needs.................................. 7-7 7.2.1 Alternatives Considered .............................................................. 7-7 7.2.1.1 Construct and Operate Fossil-Fuel-Fired Generation . 7-9 7.2.1.2 Purchase Power.......................................................... 7-10 7.2.1.3 Demand Side Management ........................................ 7-10 7.2.1.4 Other Alternatives ....................................................... 7-11 7.2.2 Environmental Impacts of Alternatives ........................................ 7-16 7.2.2.1 Gas-Fired Generation ................................................. 7-16 7.2.2.2 Coal-Fired Generation................................................. 7-18 7.2.2.3 Purchased Power........................................................ 7-20 7.3 References ............................................................................................. 7-25 Chapter 8 Comparison of Environmental Impact of License Renewal with the Alternatives....................................................................................................... 8-1 8.1 References ............................................................................................. 8-13 Chapter 9 Status of Compliance ....................................................................................... 9-1 9.1 Proposed Action ..................................................................................... 9-3 9.1.1 General ....................................................................................... 9-3 9.1.2 Threatened or Endangered Species ........................................... 9-3 9.1.3 Historic Preservation ................................................................... 9-4 9.1.4 Water Quality (401) Certification ................................................. 9-4 9.2 Alternatives ............................................................................................. 9-5 9.3 References ............................................................................................. 9-15 Appendices A - NRC NEPA Issues for License Renewal of Nuclear Power Plants B - Clean Water Act Documentation C - Special-Status Species Correspondence D - State Historic Preservation Officer Correspondence E - Severe Accident Mitigation Alternatives Analysis Three Mile Island Nuclear Station Unit 1 Page v License Renewal Application

Environmental Report TABLE OF CONTENTS Table of Contents (Continued)

List of Tables Table Page 1.2-1 Environmental Report Responses to License Renewal Environmental Regulatory Requirements ................................................................................... 1-6 2.2-1 Monthly average, minimum, and maximum T (degrees F) based on automatic temperature sensors at the intake screen pumphouse and at the discharge monitoring pit...................................................................................... 2-39 2.2-2 Passage of American shad, walleye, smallmouth bass, and gizzard shad at the York Haven fishway since it became operational in 2000 ............................ 2-39 2.5-1 Endangered and Threatened Species that could Occur in the Vicinity of TMI-1 or in Counties Crossed by TMI-1 Transmission Lines.............................. 2-40 2.6-1 Residential Distribution of TMI-1 Employees ...................................................... 2-43 2.6-2 Decennial Populations and Growth Rates .......................................................... 2-44 2.6-3 Environmental Justice Summary ........................................................................ 2-45 2.7-1 TMI-1 Tax Information 2000-2005 ...................................................................... 2-47 2.9-1 Major Dauphin County Public Water Suppliers................................................... 2-48 2.9-2 Major Lancaster County Public Water Suppliers ................................................ 2-48 2.9-3 Roadway Information (Dauphin and Lancaster Counties) .................................. 2-49 2.11-1 Sites Listed in the National Register of Historic Places and Sites Determined Eligible for Listing that fall within a 6-mile Radius of TMI-1 ................................ 2-50 3.1-1 List of Radioactive Waste Systems at TMI-1 ...................................................... 3-17 4.13-1 Results of Induced Current Analysis................................................................... 4-49 6.1-1 Environmental Impacts Related to License Renewal at TMI-1 ........................... 6-8 7.2-1 Gas-Fired Alternative.......................................................................................... 7-21 7.2-2 Coal-Fired Alternative ......................................................................................... 7-22 8.0-1 Impacts Comparison Summary .......................................................................... 8-4 8.0-2 Impacts Comparison Detail................................................................................. 8-5 9.1-1 Environmental Authorizations for Current TMI Operations ................................. 9-6 9.1-2 Environmental Authorizations for TMI-1 License Renewal ................................. 9-10 9.1-3 Environmental Authorizations Potentially Needed for TMI-1 Refurbishment Activities.............................................................................................................. 9-11 Page vi Three Mile Island Nuclear Station unit 1 License Renewal Application

Environmental Report TABLE OF CONTENTS Table of Contents (Continued)

List of Figures Figure Page 2.1-1 50-Mile Vicinity Map ............................................................................................ 2-52 2.1-2 6-Mile Vicinity Map .............................................................................................. 2-53 2.1-3 Site Boundary Map.............................................................................................. 2-54 2.2-1 Susquehanna River Subbasins ........................................................................... 2-55 2.2-2 TMI-1 Inlet and Discharge Temperatures............................................................ 2-56 2.3-1 Radiological Groundwater Protection Program ................................................... 2-57 2.6-1 Black Races Minority Populations ....................................................................... 2-58 2.6-2 Other Races Minority Populations....................................................................... 2-59 2.6-3 Aggregate Minority Populations .......................................................................... 2-60 2.6-4 Hispanic Ethnicity Populations ............................................................................ 2-61 2.6-5 Low-Income Populations ..................................................................................... 2-62 3.1-1 General Plant Layout........................................................................................... 3-18 3.1-2 TMI Transmission System................................................................................... 3-19 7.2-1 PJM Regional Generating Capacity (2005)......................................................... 7-23 7.2-2 PJM Regional Energy Output by Fuel Type (2005)............................................. 7-24 Three Mile Island Nuclear Station Unit 1 Page vii License Renewal Application

Environmental Report ACRONYMS AND ABBREVIATIONS ACRONYMS AND ABBREVIATIONS AADT Annual Average Daily Traffic AEC [U.S.] Atomic Energy Commission AEPS Alternative Energy Portfolio Standards Act AmerGen AmerGen Energy Company, LLC AWEA American Wind Energy Association BTU British Thermal Unit

°C degrees Celsius CAIR Clean Air Interstate Rule CEQ Council on Environmental Quality CFR Code of Federal Regulations cfs cubic feet per second CWA Clean Water Act DSM Demand-side management EPA [U.S.] Environmental Protection Agency ESA Endangered Species Act

°F degrees Fahrenheit FERC Federal Energy Regulatory Commission FES Final Environmental Statement fps feet per second FSAR Final Safety Analysis Report FWS [U.S.] Fish and Wildlife Service GEIS Generic Environmental Impact Statement for License Renewal of Nuclear Plants gpd gallons per day gpm gallons per minute IPA integrated plant assessment ISFSI Independent Spent Fuel Storage Installation ISPH Intake Screen and Pumphouse km kilometers kV kiloVolt KW kilowatt kwh kilowatt hours LDSD Lower Dauphin School District LOS level of service m meters MGD million gallons per day MSA Metropolitan Statistical Area MW megawatt MWe megawatts-electric Three Mile Island Nuclear Station Unit 1 Page AA-1 License Renewal Application

Environmental Report ACRONYMS AND ABBREVIATIONS MWt megawatt - thermal NA not applicable NAAQS National Ambient Air Quality Standards NAES Naval Air Engineering Station NESC National Electrical Safety Code NMFS National Marine Fisheries Service NOAA National Oceanic and Atmospheric Administration NOx nitrogen oxides NPDES National Pollutant Discharge Elimination System NRC Nuclear Regulatory Commission OSG original steam generator pCi/l pico-curies per liter psig pounds per square inch gauge PADEP Pennsylvania Department of Environmental Protection PDMS Post Defueling Monitored Storage PENNDOT Pennsylvania Department of Transportation PHMC Pennsylvania Historic and Museum Commission PJM Pennsylvania, New Jersey, Maryland [power pool]

PM2.5 particulates with diameters less than 2.5 microns PM10 particulates with diameters less than 10 microns PNHP Pennsylvania Natural Heritage Program PPUC Pennsylvania Public Utility Commission PURTA Pennsylvania Utility Realty Tax Act PWR pressurized water reactor RSG replacement steam generator SAMA Severe Accident Mitigation Alternatives SCR selective catalytic reduction SH State Highway SHPO State Historic Preservation Officer SIP State Implementation Plan SMITTR surveillance, monitoring, inspections, testing, trending, and recordkeeping SO2 sulfur dioxide SOx sulfur oxides SRBC Susquehanna River Basin Commission TMI Three Mile Island Nuclear Station Unit 1 tpy tons per year TSP total suspended particulates twh terawatt hours USCB [U.S.] Census Bureau USGS [U.S.] Geological Survey VOC volatile organic compounds Page AA-2 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report ACRONYMS AND ABBREVIATIONS WHC Wildlife Habitat Council Three Mile Island Nuclear Station Unit 1 Page AA-3 License Renewal Application

Chapter 1 INTRODUCTION Three Mile Island Nuclear Station Unit 1 Environmental Report

Environmental Report Section 1.1 PURPOSE OF AND NEED FOR ACTION 1.1 PURPOSE OF AND Licenses for Nuclear Power Plants, Section 54.23, Contents of Application-NEED FOR ACTION Environmental Information (10 CFR 54.23) and The U.S. Nuclear Regulatory Commission (NRC) licenses the operation of domestic Title 10, Energy, CFR, Part 51, nuclear power plants in accordance with the Environmental Protection Requirements Atomic Energy Act of 1954, as amended, for Domestic Licensing and Related and NRC implementing regulations. Regulatory Functions, Section 51.53, AmerGen Energy Company, LLC Postconstruction Environmental (AmerGen) operates the Three Mile Island Reports, Subsection 51.53(c), Operating Nuclear Station Unit 1 (TMI-1), pursuant to License Renewal Stage [10 CFR NRC Operating License DPR-50. The 51.53(c)].

license for Unit 1 will expire on April 19, 2014. TMI Unit 2, which is owned by NRC has defined the purpose and need for FirstEnergy Corporation, has been the proposed action, the renewal of the permanently shut down and is now in a safe operating license for a nuclear power plant storage mode called Post Defueling such as TMI-1, as follows:

Monitored Storage. The only TMI Unit 2 systems, structures or components that are ...The purpose and need for the relied upon for the operation of TMI-1 are proposed action (renewal of an the Station Blackout Diesel Generator operating license) is to provide an option Building and the TMI Unit 2 Fuel Handling that allows for power generation Building. No TMI Unit 2 activities are within capability beyond the term of a current the scope of the TMI-1 license renewal nuclear power plant operating license to application. meet future system generating needs, as such needs may be determined by AmerGen has prepared this environmental State, utility, and, where authorized, report in conjunction with its application to Federal (other than NRC) decision NRC to renew the TMI-1 operating license, makers. (NRC 1996a) as provided by the following NRC regulations: The renewed operating license would allow an additional 20 years of plant operation Title 10, Energy, Code of Federal beyond the current TMI-1 licensed operating Regulations (CFR), Part 54, period of approximately 40 years.

Requirements for Renewal of Operating Three Mile Island Nuclear Station Unit 1 Page 1-3 License Renewal Application

Environmental Report Section 1.2 ENVIRONMENTAL REPORT SCOPE AND METHODOLOGY 1.2 ENVIRONMENTAL (GEIS) (NRC 1996d and 1999b); Regulatory Analysis for Amendments to Regulations for REPORT SCOPE AND the Environmental Review for Renewal of Nuclear Power Plant Operating Licenses METHODOLOGY (NRC 1996e);

NRC regulations for domestic licensing of Public Comments on the Proposed 10 CFR nuclear power plants require environmental Part 51 Rule for Renewal of Nuclear Power review of applications to renew operating Plant Operating Licenses and Supporting licenses. The NRC regulation 10 CFR Documents: Review of Concerns and NRC 51.53(c) requires that an applicant for Staff Response (NRC 1996f); and license renewal submit with its application a separate document entitled Applicants Supplement 1 to Regulatory Guide 4.2, Environmental Report - Operating License Preparation of Supplemental Environmental Renewal Stage. In determining what Report for Applications to Renew Nuclear information to include in the TMI-1 Power Plant Operating Licenses (NRC Environmental Report, AmerGen has relied 2000).

on NRC regulations and the following supporting documents that provide AmerGen has prepared Table 1.2-1 to verify additional insight into the regulatory conformance with regulatory requirements.

requirements: Table 1.2-1 indicates where the environmental report responds to each NRC supplemental information in the requirement of 10 CFR 51.53(c). In Federal Register (NRC 1996a, 1996b, addition, each responsive section is 1996c, and 1999a); prefaced by a boxed quote of the regulatory language and applicable supporting Generic Environmental Impact Statement document language.

for License Renewal of Nuclear Plants Page 1-4 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 1.3 THREE MILE ISLAND NUCLEAR STATION UNIT 1 LICENSEE AND OWNERSHIP 1.3 THREE MILE ISLAND a corporation formed under the laws of the Commonwealth of Pennsylvania and NUCLEAR STATION headquartered in Chicago, Illinois. Exelon Corporation is one of the nations largest UNIT 1 LICENSEE AND electric utilities, distributing electricity to OWNERSHIP approximately 5.2 million customers in Illinois and Pennsylvania. AmerGen, which TMI-1 is owned by AmerGen Energy acquires and operates nuclear plants as an Company, LLC, which is a wholly owned independent power producer in North subsidiary of Exelon Corporation, America, is the licensed operator of TMI-1.

Three Mile Island Nuclear Station Unit 1 Page 1-5 License Renewal Application

Environmental Report Section 1.2 TABLES Table 1.2-1. Environmental Report Responses to License Renewal Environmental Regulatory Requirements Regulatory Requirement Responsive Environmental Report Section(s) 10 CFR 51.53(c)(1) Entire Document 10 CFR 51.53(c)(2), Sentences 1 and 2 3.0 Proposed Action 10 CFR 51.53(c)(2), Sentence 3 7.2.2 Environmental Impacts of Alternatives 10 CFR 51.53(c)(2) and 10 CFR 4.0 Environmental Consequences of the Proposed 51.45(b)(1) Action and Mitigating Actions 10 CFR 51.53(c)(2) and 10 CFR 6.3 Unavoidable Adverse Impacts 51.45(b)(2) 10 CFR 51.53(c)(2) and 10 CFR 7.0 Alternatives to the Proposed Action 51.45(b)(3) 10 CFR 51.53(c)(2) and 10 CFR 8.0 Comparison of Environmental Impacts of License 51.45(b)(3) Renewal with the Alternatives 10 CFR 51.53(c)(2) and 10 CFR 6.5 Short-Term Use Versus Long-Term Productivity of 51.45(b)(4) the Environment 10 CFR 51.53(c)(2) and 10 CFR 6.4 Irreversible and Irretrievable Resource 51.45(b)(5) Commitments 10 CFR 51.53(c)(2) and 10 CFR 51.45(c) 4.0 Environmental Consequences of the Proposed Action and Mitigating Actions 10 CFR 51.53(c)(2) and 10 CFR 51.45(c) 6.2 Mitigation 7.2.2 Environmental Impacts of Alternatives 8.0 Comparison of Environmental Impacts of License Renewal with the Alternatives 10 CFR 51.53(c)(2) and 10 CFR 51.45(d) 9.0 Status of Compliance 10 CFR 51.53(c)(2) and 10 CFR 51.45(e) 4.0 Environmental Consequences of the Proposed Action and Mitigating Actions 10 CFR 51.53(c)(2) and 10 CFR 6.3 Unavoidable Adverse Impacts 51.45(b)(2) 10 CFR 51.53(c)(3)(ii)(A) 4.1 Water Use Conflicts (Plants with Cooling Ponds or Cooling Towers Using Makeup Water from a Small River with Low Flow) 10 CFR 51.53(c)(3)(ii)(A) 4.6 Groundwater Use Conflicts (Plants Using Cooling Water Towers or Cooling Ponds and Withdrawing Makeup Water from a Small River) 10 CFR 51.53(c)(3)(ii)(B) 4.2 Entrainment of Fish and Shellfish in Early Life Stages 10 CFR 51.53(c)(3)(ii)(B) 4.3 Impingement of Fish and Shellfish 10 CFR 51.53(c)(3)(ii)(B) 4.4 Heat Shock 10 CFR 51.53(c)(3)(ii)(C) 4.5 Groundwater Use Conflicts (Plants Using >100 gpm of Groundwater) 10 CFR 51.53(c)(3)(ii)(C) 4.7 Groundwater Use Conflicts (Plants Using Ranney Wells)

Page 1-6 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 1.2 TABLES Table 1.2-1. Environmental Report Responses to License Renewal Environmental Regulatory Requirements (Continued)

Regulatory Requirement Responsive Environmental Report Section(s) 10 CFR 51.53(c)(3)(ii)(D) 4.8 Degradation of Groundwater Quality 10 CFR 51.53(c)(3)(ii)(E) 4.9 Impacts of Refurbishment on Terrestrial Resources 4.10 Threatened or Endangered Species 10 CFR 51.53(c)(3)(ii)(F) 4.11 Air Quality During Refurbishment (Non-Attainment Areas) 10 CFR 51.53(c)(3)(ii)(G) 4.12 Microbiological Organisms 10 CFR 51.53(c)(3)(ii)(H) 4.13 Electric Shock from Transmission-Line-Induced Currents 10 CFR 51.53(c)(3)(ii)(I) 4.14 Housing Impacts 10 CFR 51.53(c)(3)(ii)(I) 4.15 Public Utilities: Public Water Supply Availability 10 CFR 51.53(c)(3)(ii)(I) 4.16 Education Impacts from Refurbishment 10 CFR 51.53(c)(3)(ii)(I) 4.17 Offsite Land Use 10 CFR 51.53(c)(3)(ii)(J) 4.18 Transportation 10 CFR 51.53(c)(3)(ii)(K) 4.19 Historic and Archaeological Resources 10 CFR 51.53(c)(3)(ii)(L) 4.20 Severe Accident Mitigation Alternatives 10 CFR 51.53(c)(3)(iii) 4.0 Environmental Consequences of the Proposed Action and Mitigating Actions 10 CFR 51.53(c)(3)(iii) 6.2 Mitigation 10 CFR 51.53(c)(3)(iv) 5.0 Assessment of New and Significant Information 10 CFR 51, Appendix B, Table B-1, 2.6.2 Minority and Low-Income Populations Footnote 6 Three Mile Island Nuclear Station Unit 1 Page 1-7 License Renewal Application

Environmental Report Section

1.4 REFERENCES

Note to reader: Some web pages cited in this document are no longer available, or are no longer available through the original URL addresses. Hard copies of cited web pages are available in AmerGen files. Some sites, for example the census data, cannot be accessed through their given URLs. The only way to access these pages is to follow queries on previous web pages. The complete URLs used by AmerGen have been given for these pages, even though they may not be directly accessible. Also, all references are specific to the chapter in which they are cited.

NRC (U.S. Nuclear Regulatory Commission). 1996a. Environmental Review for Renewal of Nuclear Power Plant Operating Licenses. Federal Register. Vol. 61, No. 109. June 5.

NRC (U.S. Nuclear Regulatory Commission). 1996b. Environmental Review for Renewal of Nuclear Power Plant Operating Licenses; Correction. Federal Register. Vol. 61, No. 147.

July 30.

NRC (U.S. Nuclear Regulatory Commission). 1996c. Environmental Review for Renewal of Nuclear Power Plant Operating Licenses. Federal Register. Vol. 61, No. 244. December 18.

NRC (U.S. Nuclear Regulatory Commission). 1996d. Generic Environmental Impact Statement for License Renewal of Nuclear Plants. Volumes 1 and 2. NUREG-1437. Washington, DC. May.

NRC (U.S. Nuclear Regulatory Commission). 1996e. Regulatory Analysis for Amendments to Regulations for the Environmental Review for Renewal of Nuclear Power Plant Operating Licenses. NUREG-1440. Washington, DC. May.

NRC (U.S. Nuclear Regulatory Commission). 1996f. Public Comments on the Proposed 10 CFR Part 51 Rule for Renewal of Nuclear Power Plant Operating Licenses and Supporting Documents: Review of Concerns and NRC Staff Response. Volumes 1 and 2. NUREG-1529. Washington, DC. May.

NRC (U.S. Nuclear Regulatory Commission). 1999a. Changes to Requirements for Environmental Review for Renewal of Nuclear Power Plant Operating Licenses; Final Rule. Federal Register. Vol. 64, No. 171. September 3.

NRC (U.S. Nuclear Regulatory Commission). 1999b. Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS). Section 6.3, Transportation and Table 9-1, Summary of findings on NEPA issues for license renewal of nuclear power plants.

NUREG-1437. Volume 1, Addendum 1. Washington, DC. August.

NRC (U.S. Nuclear Regulatory Commission). 2000. Preparation of Supplemental Environmental Reports for Applications to Renew Nuclear Power Plant Operating Licenses; Supplement 1 to Regulatory Guide 4.2. Washington, DC. September.

Page 1-8 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Chapter 2 Site and Environmental Interfaces Three Mile Island Nuclear Station Unit 1 Environmental Report

Environmental Report Section 2.1 LOCATION AND FEATURES 2.1 LOCATION AND York Haven Dams, which transect the river on either side of the downstream end of FEATURES Three Mile Island creating a barrier for the purpose of hydroelectric generation.

Three Mile Island Nuclear Station Unit 1 (TMI-1) is located in Londonderry Township State Highway (SH)-441 parallels Three in Dauphin County, Pennsylvania, on the Mile Island to the east, and tracks of the northern end of Three Mile Island near the Norfolk Southern Railroad parallel the eastern shore of the Susquehanna River Susquehanna River on the eastern and (AEC 1972). The largest communities western banks. Shelley Island is located within 10 miles of the site are the borough of west of Three Mile Island in the middle of Middletown, Pennsylvania, approximately the river, and the borough of Goldsboro is three miles north of Three Mile Island, and located on the western bank of the river.

the borough of Goldsboro, Pennsylvania, The developed portion of the TMI-1 site is located in York County approximately 1.25 surrounded by a flood protection dike miles west of Three Mile Island across the system. Access to the northern portion of Susquehanna River. The nearest major Three Mile Island is by a bridge connecting metropolitan area is the City of Harrisburg, the main entrance to the TMI-1 site and the Pennsylvania, approximately 10 miles to the mainland near the junction of SH-441 and northwest (AmerGen 2006b). Figures 2.1-1 Geyers Church Road. Another bridge and 2.1-2 are the 50 mile and 6-mile vicinity connects the southern end of Three Mile maps, respectively. Island with the mainland near Falmouth on SH-441 in Lancaster County (AEC 1972).

The TMI-1 site encompasses several The southern bridge serves as TMI-1 site properties that total approximately 440 access for some station personnel, outage acres. Included are: Three Mile Island, and refurbishment workers, and which hosts TMI-1 on approximately 200 of construction equipment. It also provides an its 370 acres; St. Johns Island and alternate egress route.

Evergreen Island (also referred to as Sand Beach Island), which are situated north of TMI-1 is a pressurized water reactor utilizing Three Mile Island and together total once-through steam generators and approximately 31 acres; a 6.4-acre section licensed to operate at a power level of 2,568 of Shelley Island, which is part of the MWt (megawatt-thermal) (AmerGen 2006b).

western half of the TMI-1 Exclusion Area; Certain buildings and structures associated and a 32-acre strip of land east of Three with the Three Mile Island Nuclear Station Mile Island along the eastern shore of the Unit 2 (TMI-2), which is owned by Susquehanna River. Three Mile Island is FirstEnergy Corporation, are intermingled approximately 11,000 feet long and 1,700 with TMI-1 buildings and structures on the feet wide with the long axis aligned north- TMI-1 site. TMI-2 has been shut down south in the river. It lies approximately 900 since March 1979. Since December 1993, feet from the east bank of the Susquehanna it has been in a stable, safe storage mode River and approximately 6,500 feet from the called Post Defueling Monitored Storage west bank of the river (Figure 2.1-3). The (PDMS).

Susquehanna River makes a sharp change in directional flow from southeasterly to Section 3.1 describes key features of TMI-1, nearly due south just north of Three Mile including reactor and containment systems, Island where the river widens to cooling water system, and transmission approximately 1.5 miles wide. This system.

widening resulted from the Red Hill and Three Mile Island Nuclear Station Unit 1 Page 2-3 License Renewal Application

Environmental Report Section 2.2 AQUATIC ECOLOGY 2.2 AQUATIC ECOLOGY undated; Smithsonian Environmental Research Center 2003).

Metropolitan Edison Company and GPU The United States Geological Survey Nuclear Corporation [former owners and (USGS) monitors Susquehanna River flows operators of TMI-1 and TMI-2 prior to at Harrisburg, Pennsylvania (station AmerGen Energy Company, LLC 01570500). In water year 2004 (October (AmerGen) purchasing TMI-1] monitored 2003 thru September 2004) the annual water quality and aquatic organisms in the mean flow was 56,400 cubic feet per Susquehanna River up- and down-stream of second (cfs) (compared to the historic Three Mile Island from 1974 through 1982 annual mean of 34,450 cfs). During that to coincide with startup and operation of year, the Susquehanna River flow was TMI-1. The monitoring was intended to above average every month except develop a baseline and thereby identify any February, June and July (Durlin and significant biological alterations within the Schaffstall 2005). Water year 2004 was a study area resulting from TMI-1 operations. year with above average precipitation This monitoring program allowed the primarily caused by the remnants of four owners to monitor the overall health of the hurricanes passing through the Susquehanna River and its aquatic Susquehanna River drainage. Daily mean communities in the vicinity of Three Mile flow ranged from 9,600 cfs (July 6) to Island and to identify any chronic or 500,000 cfs (September 19) (Durlin and recurring water quality problems or obvious Schaffstall 2005).

impacts to aquatic communities that might be identified with operation of the Three 2.2.2 WATER QUALITY Mile Island Nuclear Station (Ichthyological Associates 1983).

As stated in Section 2.2.1, Metropolitan In addition to the comprehensive Edison and GPU Nuclear conducted environmental monitoring conducted from ecological studies in the vicinity of Three 1974 through 1982, the owners of TMI-1 Mile Island from 1974 - 1982 (Ichthyological continued annual environmental monitoring Associates, 1983). These studies were through 1990. However, over time the conducted to assess impacts of station programs and specifications changed as to operations on local aquatic communities.

frequency, sampling stations, parameters, Data were collected on water chemistry, and target aquatic community (Normandeau macroinvertebrates, and larval and adult 2007). fishes. In addition, thermal plume mapping was conducted. During 1978 (last year of operation prior to the TMI-2 accident in 2.2.1 HYDROLOGY March 1979) both reactors were operating.

TMI-1 had achieved criticality in June 1974 The Susquehanna River flows south more and TMI-2 on April 21, 1978; therefore, than 440 miles from its source, Lake Otsego 1978 was the last year of data for two-unit in south-central New York, to Havre de operation (Ichthyological Associates, 1979).

Grace, Maryland, where it empties into the Chesapeake Bay. The Susquehanna River Water quality parameters analyzed included Basin (Figure 2.2-1) drains an area of about turbidity, alkalinity, sulfate, total dissolved 27,500 square miles and supplies solids, total and dissolved copper, and total approximately 19 million gallons of fresh and dissolved zinc at stations located water per minute to the Chesapeake Bay, upstream, near the discharge structure, and about half of the Bays total freshwater downstream of the discharge structure. In inflow (Alliance for the Chesapeake Bay addition, water temperature, pH, and Page 2-4 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.2 AQUATIC ECOLOGY dissolved oxygen were determined in the (December 19) to 81.5 °F (July 24).

field at all sampling locations. Temperatures taken in an area near the discharge structure ranged from 33.8 °F Mean values for dissolved oxygen, turbidity, (December 19) to 81.5°F (July 24) while total copper, and total zinc were highest in temperatures approximately 262.5 feet April while water temperature, alkalinity, downstream of the discharge structure sulfate, and total dissolved solids were ranged from 33.8°F (December 19) to 85.1°F highest in July; dissolved zinc was highest (July 24) (Ichthyological Associates 1979).

in November. Values for alkalinity, sulfate, These data indicate that the thermal effluent dissolved copper, and total zinc were higher did not cause water temperatures in the at the upstream stations in most months. Susquehanna River to exceed applicable Values for water temperature, dissolved State water quality criteria for maximum oxygen, turbidity, total dissolved solids, and temperature (25 PA Code §93.7) and did dissolved zinc were generally higher at the not increase the temperature between downstream stations most months. Water upstream and downstream sampling points quality values (including water temperature) in the river by more than 5 °F.

did not exceed state water quality criteria (Ichthyological Associates 1979).

during the period when TMI-1 and TMI-2 were both operating (Ichthyological AmerGen continues to collect water Associates, 1979). temperature data with an automatic temperature sensor at the intake screen Water temperatures were measured in the pump house and at the discharge Susquehanna River as a component of monitoring pit (before the water is mixed ecological studies conducted by with the Susquehanna River water). Figure Metropolitan Edison and GPU Nuclear from 2.2-2 presents recent representative data 1974 - 1982 (Ichthyological Associates from August 2005 through September 2007.

1983). During this period, the Susquehanna The 24-hour maximum discharge River in the vicinity of Three Mile Island temperature detected in 2006 occurred on shows a predictable annual pattern of August 4 (100.2°F), and in 2007 it occurred temperatures, with lowest temperatures in on September 11 (101.1°F). The winter and highest temperatures in late differences between the intake and summer. Also during this period, the TMI-1 discharge temperatures (i.e., T) have also and TMI-2 reactors achieved criticality on been calculated on a monthly basis for the June 5, 1974 and April 21, 1978, same time period and are presented in respectively. Hence, the data collected Table 2.2-1. During this two year period, from Spring 1978 through Spring 1979 the maximum T occurred in April 2006 reflect water temperatures with both TMI-1 and TMI-2 operating, which would be a (30.16°F) (AmerGen 2007b).

conservative scenario. Water temperature Based on monitoring from 1974 through data collected in the Susquehanna River 1990, river flow has been one of the most from March 1979 through 1982 represent influential factors for both biological and ambient river conditions because both water quality parameters in the reactors were shut down after an accident Susquehanna River (Normandeau 2007).

occurred at TMI-2. TMI-1 resumed During this period, mean river flow varied operation in 1985.

widely and was influenced by snow melt, During the sampling period from April to spring runoff, rain events, and drought.

December 1978 (i.e., conservative Based on analysis of 17 years of data for conditions), temperatures taken in the water temperature, pH, and dissolved Susquehanna River at locations above the oxygen, and 13 years for TDS (total dissolved solids), no evidence of significant discharge structure ranged from 33.8°F Three Mile Island Nuclear Station Unit 1 Page 2-5 License Renewal Application

Environmental Report Section 2.2 AQUATIC ECOLOGY influence of TMI-1 discharge on these Susquehanna River contains fairly good parameters was identified. Temporal and water quality (Hoffman 2006),

spatial trends in these parameters appear to be related more to meteorological cycles 2.2.3 AQUATIC COMMUNITIES and river flow than to TMI-1 operations (Normandeau 2007). They also reflect the As noted previously, Metropolitan Edison influences of the varied geological, land, and GPU Nuclear monitored the ecological and water use practices throughout the communities of the Susquehanna River in Susquehanna River basin (Normandeau the vicinity of Three Mile Island from 1974 to 2007). 1982. Three Mile Island is adjacent to a small reservoir formed by York Haven and Water quality in the Lower Susquehanna Red Hill Dams (Figure 2.1-3). This River Basin has improved steadily since the reservoir, known as York Haven Pond (Lake early 1970s. This improvement has been Frederick) extends about 3.5 miles attributed to a reduction in mine drainage upstream and formed the area for the pollutants from upstream sources, aquatic studies. Normal full pool elevation improvements in sewage-treatment plants, of Lake Frederick is 277 feet above mean a ban on phosphate detergents, and sea level and mean depth is about 9 feet implementation of agricultural best- (Ichthyological Associates 1983; RMC 1990; management practices. However, when RMC 1991).

looking at the entire Lower Susquehanna River Basin, nitrate (a component of total York Haven Dam was completed in 1904 nitrogen) showed an upward trend at the and is a low head, run-of-the-river dam and uppermost (Lewisburg, Pennsylvania) hydroelectric plant. The main dam is 5,000 monitoring station (Lindsay et al. 1998, feet long and connects the mainland on the USGS Survey Circular 1168). western side of the river to Three Mile Island; a smaller dam (Red Hill) connects In 2002, the Susquehanna River Basin Three Mile Island to the mainland on the Commission (SRBC) conducted a pilot eastern side of the river (Normandeau study to determine appropriate methods for 2007). The York Haven hydroelectric plant assessing the biology of the large rivers in generates 19-20 megawatts (MW) of power the Susquehanna River Basin (Hoffman and has 13 horizontal generators that 2006). Biological and water chemistry data produce up to 1,000 kilowatts (KW) each were collected at 25 stations during August and 7 vertical generators that generate through October 2005 on the mainstem between 1,200 and 1,600 KW each. Four of Susquehanna River and at the mouths of the vertical units use Kaplan turbines. The the three major tributaries: the West Branch plant uses one of the first Kaplan turbines Susquehanna River, the Juniata River, and installed in the United States, and the plant the Chemung River. Ten macroinvertebrate is listed as a National Historic Engineering samples were collected at each station, Landmark (ASME Undated).

using five rock baskets and five kick nets, when possible. A total of 102 rock basket At Three Mile Island, the Susquehanna samples and 125 kick net samples were River is about 7,000 feet wide and divided collected during the survey. Six of the by islands into three channels (west, center, stations were designated moderately and east). The intake and discharge impaired, while 19 of the stations were structures for TMI-1 are located along the designated slightly impaired. Only 79 out of west shore of Three Mile Island, and the 950 laboratory and field water quality data intake withdraws water from the center points exceeded standards or levels of channel (Ichthyological Associates 1983 tolerance for aquatic life, indicating that the RMC 1990; RMC 1991).

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Environmental Report Section 2.2 AQUATIC ECOLOGY 2.2.3.1 Macroinvertebrates 1983). In addition, the drought of 1980 influenced the distribution and abundance of Between 1974 and 1982, macroinvertebrates during the latter part of macroinvertebrates were typically collected the study (Ichthyological Associates 1983).

once in January and then twice per month starting in March; February samples in The area in the vicinity of the TMI-1 some years were not collected due to ice discharge was continuously studied during cover at most stations (Ichthyological the period from 1986 through 1990 (i.e.,

Associates 1983. during a time when TMI-1 was operational after having been shut down until 1985 A total of 66,048 specimens representing following an accident at Unit 2 in March 165 taxa were collected in 1982, the largest 1979) (Normandeau 2007). Annual number of taxa collected over the 1974 - macroinvertebrate sampling during the 1982 period. However, total number of period identified variable numbers of taxa organisms, density, and biomass were the and species diversity, with no consistent lowest in 1982 since 1974; which continued trends in spatial or temporal abundance trends noted after the 1980 drought. The (Normandeau 2007). None of the station highest number of organisms was collected abundance data for benthic in 1977. Dominant taxa were Limnodrilus macroinvertebrate communities suggested hoffmeisteri (Oligochates - aquatic worms), the influence of TMI-1 (Normandeau 2007).

Chironomus decorus group sp. (Diptera - Fluctuations in environmental variables, midges), and Pisidium spp. (Molluscs). especially river flow and water temperature, Elimia virginica, C. decorus group sp. seemed to exert the predominant influence (snails), and L. hoffmeisteri had the greatest on the benthic communities in York Haven biomass. During the 1982 sampling, 15 Pond (Lake Frederick) (Normandeau 2007).

species were collected for the first time (Ichthyological Associates 1983). 2.2.3.2 Adult Fish Monthly measures of diversity varied A number of collection methods (trapnet, between upstream and downstream seine, electrofishing) were used to discharge stations during all years. characterize the adult fish community in the However, seasonal distribution was vicinity of Three Mile Island from 1974 generally the lowest in April and June at through 1982. In addition, population stations downstream of the discharge area estimates and creel surveys were and highest in March at stations upstream conducted to further characterize the fishery of the discharge. For example, in 1982 a and its usage by recreational fishermen total of 66 taxa were collected in March and (Ichthyological Associates 1983). During represented the highest monthly total the study period, a total of 58 species of fish collected during the study period and may were collected representing 13 families with be attributed in part to drift from high spring Ictaluridae (catfishes) and Centrarchidae flows (Ichthyological Associates 1983). The (sunfishes, bass, and crappie) dominating relative abundance, density, and biomass of the catches. The greatest species diversity Limnodrilus hoffmeisteri (aquatic worms) was exhibited by the Cyprinids (carp and exhibited a decline over the study period minnows) with 19 species (dominated by and this was attributed to the 1980 drought goldfish, carp, shiners, daces, and chubs) and subsequent repopulation of drought- followed by Centrarchids with 9 species affected areas by Chironomus decorus (primarily bass, lepomids, and crappie),

group sp. (midges). In summary, the Ictalurids with 5 species (dominated by differences between stations were generally channel and white catfish and bullheads),

attributed to habitat differences and not to Clupeids with 4 species (blueback herring, TMI-1 operation (Ichthyological Associates alewife, and American and gizzard shad)

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Environmental Report Section 2.2 AQUATIC ECOLOGY and Catostomids (suckers) with 4 species The mean number of fish per trapnet (quillback, redhorse, and white and northern collection over the 1974 - 1982 sampling hogsuckers). All the remaining families period was the lowest in 1976, with catches were represented by three or fewer species of less than five per collection. Collections (Ichthyological Associates 1983). at Station 3 downstream of the discharge were the lowest among the four sampling Studies of the fish community conducted in stations. Trends between years were 1989 and 1990 revealed a similar species similar to the total catch trend; catches at all composition to those observed during 1974 stations were greater in 1980 - 1982 than in through 1982 (RMC 1990; RMC 1991; 1974 - 1979. In general, Station 4 Normandeau 2007). The fish community (approximately one mile below the was sampled by multiple gear types. Both discharge) exhibited the greatest catches seine and electrofishing catches reflected (Ichthyological Associates 1983).

the effects of natural population cycles in this section of the Susquehanna River, with Seine Collections no consistent pattern of temporal or spatial abundance (RMC 1990; RMC 1991; Seine collections were taken at 10 stations Normandeau 2007). Several above, adjacent to, and below the discharge representatives of the sunfish family (e.g., from March through December during 1974 smallmouth bass, redbreast sunfish, rock through 1982. In some years, sampling at bass) and the minnow family (spotfin shiner, early dates and during December was spottail shiner) were consistently abundant hampered by ice cover and collections were over the study period (RMC 1990; RMC either not made or done over several days.

1991; Normandeau 2007). A total of 28 species were collected in 1982, the highest number of species collected Trapnet Collections during the study period. Spotfin shiners, spottail shiners, and white suckers Trapnet collections were taken at four dominated the annual catches from 1974 stations above, adjacent to, and below the through 1982 and constituted over 80 discharge from March or April through percent of the catch each year. Additional December during 1974 through 1982 species collected were dominated by other (Ichthyological Associates 1979, 1983). shiners, assorted sunfishes and bass, and Channel catfish, rock bass, pumpkinseed, various darters, with an occasional walleye.

white crappie, and black crappie dominated As expected, there was considerable the collections over the study period. variation between years due to river flow Channel catfish exhibited a significant conditions. Catches per seine haul varied decline over the study period, declining from from about 30 to over 124; however, the over 7 fish per unit of effort in 1974 to less range in yearly catches was relatively stable than one in 1982. Pumpkinseed showed an (Ichthyological Associates 1983). Spotfin opposite trend with catches increasing shiners exhibited a significant increase dramatically starting in 1980 to beginning in 1980, and by 1981 and 1982 approximately three times greater than catches were over 10 times those of 1974.

those of earlier years. The other species Spottail shiners exhibited a significant (rock bass, black crappie, white crappie) decline over the same period, but not as showed similar trends as pumpkinseed, but dramatic (Ichthyological Associates 1983).

their increases in 1980 - 1982 were The greatest diversity (number of species between 1 -and 2 times those observed in per seine haul) occurred at a station on the 1974 - 1979. (Ichthyological Associates western side of the river, while all other 1983). stations exhibited lower, but more uniform, catches over the study period (Ichthyological Associates 1983).

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Environmental Report Section 2.2 AQUATIC ECOLOGY Electrofishing The largest number of anglers, fish caught, fish kept, and hours fished in all areas Electrofishing (boat-mounted) was used to combined were reported in May. Channel sample 12 near-shore areas above, catfish, rock bass, smallmouth bass, and adjacent to, and below the discharge from walleye composed over 80 percent of the March or April through December during total catch. The smallmouth bass was the 1976 through 1982. In some years, March species most often caught and kept by sampling was not conducted due to ice anglers during April through November.

cover. During the sampling period; the Over 70 percent of the anglers interviewed number of species collected ranged from were residents of York or Dauphin Counties 25 to 31, with Centrarchids dominating the (Ichthyological Associates 1983).

catch each year. Five species -- the rock bass, redbreast sunfish, pumpkinseed, In 1990, a total of 39,953 angler hours were bluegill, and smallmouth bass -- accounted expended resulting in a total catch of 37,955 for over 60 percent of the catch each year. fish with the anglers keeping 7,158 fish In general, pumpkinseed sunfish were the (Normandeau 2007). Sport fishing catches most abundant each year. Spring and fall were dominated by smallmouth bass, sampling periods exhibited the largest channel catfish, rock bass, and walleye.

catches, while summer catches were the Catch and harvest fluctuated as fish smallest. Differences in species populations responded to angler composition and abundance among the preferences and variable year class sampling stations, sampling periods, and success (Normandeau 2007). A large years (1976 - 1982) were attributed to number of anglers throughout the 16 survey habitat differences, changes in river flow years indicated that they released or gave and water temperature, and natural away all, or at least a portion of their catch, fluctuations inherent in fish populations reflecting an interest in fishing primarily for rather than TMI-1 operations (Ichthyological recreation (Normandeau 2007).

Associates 1983).

The impact of the 1979 accident at TMI-2 on Electrofishing studies conducted in 1989 recreational fishing was assessed in and 1990 revealed similar results to those subsequent years by asking whether conducted during 1976 - 1982 (RMC 1990; anglers used their catch differently than they RMC 1991). The small differences in catch did in prior years. During 1980 (the year per unit of effort at stations above, near, and immediately after accident), 7.6 percent of adjacent to the TMI-1 discharge revealed no the anglers interviewed indicated that they evidence to suggest that the operation of had changed their use of catch due to the TMI-1 had any influence on the distribution accident. The proportion of anglers of fish populations in York Haven Pond expressing a change in catch usage steadily (Lake Frederick) (RMC 1990; RMC 1991). declined during the 1980s and no anglers reported changing their catch usage in Creel Surveys either 1989 or 1990 (RMC 1990; RMC 1991). As of 1990, most anglers reported Roving creel surveys were conducted for that they eat at least a portion of their catch over 16 continuous years on the (RMC, 1991).

Susquehanna River in the vicinity of Three Mile Island from January through December There are no updated creel survey data for during 1974 through 1990 (Ichthyological the Lake Frederick area of the Associates 1983; RMC 1990; RMC 1991, Susquehanna River. However, in 2007 a Normandeau, 2007). In 1982, an estimated creel survey overseen by the Pennsylvania 19,914 anglers caught 45,603 fish, kept Fish and Boat Commission is underway 12,546 fish, and fished for 34,053 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br />. (April through October 2007) that will Three Mile Island Nuclear Station Unit 1 Page 2-9 License Renewal Application

Environmental Report Section 2.2 AQUATIC ECOLOGY explore fishing use and anglers experience American Shad and Lower Susquehanna on 130 miles of the Susquehanna and River Basin Juniata Rivers from Sunbury to the Holtwood Dam near the Maryland border The American Shad is an important (Frederick 2007). anadromous fish that spawns in the Susquehanna River. Prior to 2000, access Recreational Fishing to the upper reaches of the river above York Haven Dam was limited to physical The Susquehanna River in the area of transport (Normandeau 2007) due to the Three Mile Island provides some of the best absence of fish passage facilities. Between smallmouth bass fishing in the eastern U.S. 1904 and 1930, four hydroelectric dams (Nicewonger 2002). The stretch of the river were built on the lower Susquehanna River:

from Harrisburg to Holtwood Dam, in York Haven (1904), Holtwood (1910),

particular, has benefited from the 1990 Conowingo (1928), and Safe Harbor (1930).

implementation of special fishing regulations (Pennsylvania Fish and Boat Commission designed to enhance the smallmouth bass Undated).

fishery (Jaworoski Undated 1). Since that time, the special regulations have become When the Conowingo Dam was built, state more protective of this fishery and now and federal fishery authorities conceded apply to nearly 90 miles of the that development of effective fish Susquehanna. In winter months, anglers passageways at high dams was not are allowed to keep two fish per day, 18- practical and the Susquehanna River shad inch minimum. During the spring spawning resource was lost (Pennsylvania Fish and period, Mid-April through mid-June, all bass Boat Commission Undated). However, by must be released. From mid-June through the 1950s, fish passage technology had October 1, anglers may keep four fish per improved and studies were undertaken to day, 15-inch minimum. These regulations assess the possibility of restoring shad runs have increased the number of smallmouth to the Susquehanna River. These state-bass in this stretch of the river and and utility-sponsored efforts included increased the average size of these fish determining the ability of shad to move (Jaworoski Undated1). Professional fishing upstream and reproduce, determining the guides tout the area's excellent smallmouth engineering and biological feasibility for fish bass habitat and the unique experience of passage at dams, and evaluating the fishing "in the shadow" of the Three Mile suitability of the river to support migratory Island cooling towers (McNally 1997; fishes. Results of the fish passage Backwoods Angler 2006). engineering and habitat suitability studies were favorable (Pennsylvania Fish and Boat Aside from smallmouth bass fishing, more Commission Undated).

placid sections of the Susquehanna River in the vicinity of Three Mile Island offer Pursuant to Federal Energy Regulatory excellent fishing for sunfish (rock bass, Commission (FERC) relicensing efforts for crappie, pumpkinseed, and redbreast York Haven Dam, the York Haven Power sunfish) and channel catfish (Jaworoski Company agreed to the design and Undated2). These waters also provide construction of fish passage facilities at outstanding fishing for muskie and walleye York Haven. In 2000, York Haven Power (Hartman 2000). Company completed a 500,000-fish-capacity fish ladder at Three Mile Island east channel dam (Red Hill Dam) at a cost of about $9 million (Pennsylvania Fish and Boat Commission Undated). The York Haven fishway consists Page 2-10 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.2 AQUATIC ECOLOGY of a 67-foot-wide notch in the 11-foot-high Over the period 2000 through 2006, a total east channel dam (Red Hill Dam). It allows of 28,870 American Shad were passed over downstream passage of fish if the the York Haven fishway (Table 2.2-2). The Susquehanna River is low during the annual number ranged from 219 (2004) to 16,200 migration period from April 1 to the end of (2001) (Pennsylvania Fish and Boat June. The flow of water through the notch Commission, Undated). In addition, over is controlled by a new upstream permanent 12,000 smallmouth bass, 42,000 walleye, structure that has two 20-foot wide gated and 480,000 gizzard shad were successfully openings. The water flowing through the passed at the York Haven fishway.

notch also provides attraction flow to help upstream migrating fish locate the The fish studies described in Section 2.2.3 staggered pool, vertical slot fish ladder, were conducted in the vicinity of Three Mile which is also part of the fishway. The fish Island over three distinct periods: (1) before ladder will allow fish to migrate upstream TMI-1 and TMI-2 began operating, (2) during periods of low river flow. The during peak operation with two reactors, fishway was hydraulically designed to also and (3) during operation with only TMI-1.

allow upstream passage through the dam Taken as a whole, the studies show that the notch and 20-foot gates during higher river Susquehanna River in the vicinity of Three flows as well. The York Haven fishway Mile Island supports a diverse assemblage became operational on April 1, 2000 of coolwater and warmwater fishes. Neither (Kleinschmidt Undated). York Haven Dam or the operation of TMI-1 impede the passage of migratory fish.

Completion of this fish passage facility There is no indication that pollution-tolerant meant that American Shad as well as other species or groups are predominant, or that migratory fish could ascend the sensitive or pollution-intolerant species are Susquehanna River as far as Binghamton, rare or absent. Water quality improvement New York, a distance of approximately 435 in the 1970s and 1980s brought fishermen miles (Pennsylvania Fish and Boat back to the river in increasing numbers as Commission, Undated). evidenced by creel surveys.

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Environmental Report Section 2.3 GROUNDWATER RESOURCES 2.3 GROUNDWATER shore would create induced infiltration (AmerGen 2006a).

RESOURCES The second water-bearing unit mentioned 2.3.1 WATER-BEARING UNITS above (i.e., the Gettysburg shale) is the primary aquifer in the vicinity of Three Mile TMI-1 is located on Three Mile Island in the Island. In this unit, groundwater is found Susquehanna River in a segment of the under artesian conditions in the bedrock.

river where the incised river channel is Groundwater in the bedrock is present wider than upstream and downstream along bedding plane separations, closely segments. spaced joints, and fractures. Hydraulic conductivity values vary from 2,126 Water-bearing units (aquifers) in the vicinity feet/year to 4,208 feet/year. Maximum include (1) a unit under water table drawdown occurs parallel to the bedding conditions located in the surficial alluvial, strike in response to pumping and glacial deposited materials (glacial (McLaren/Hart 1998a). Bedrock has been material directly overlies the bedrock) that encountered at depths of 19 to 28 feet compose the island and (2) the underlying throughout Three Mile Island during drilling sedimentary sequence under artesian operations. At the Three Mile Island conditions known as the Gettysburg shale, Nuclear Station, bedrock dips uniformly to which is part of the Newark group of the northwest at approximately 37 degrees.

Triassic Age. The first water-bearing unit Two prominent bedrock joints exist on the (i.e., the unit under water table conditions) is island. One dips approximately 72 degrees composed of silts, sands, and gravels, with to near vertical and strikes approximately varying amounts of clay. The surficial due north. The other dips 50 to 60 degrees deposits in this unit vary in thickness from southwest and has a northwest strike 7 to 19 feet, and the glacial material varies (McLaren/Hart 1998a).

from 12 to 21 feet. This unit, although capable of producing water, is not 2.3.2 WATER SUPPLY WELLS considered a major aquifer in the area.

Groundwater conditions in the alluvial A search of the Pennsylvania Groundwater material of the first unit are controlled by the Information System was performed to locate Susquehanna River. The water table off-site wells within 1 mile of the plant site.

reaches its maximum elevation at the This search indicated there are 47 water highest point in the center of the island, then supply wells not associated with the Three slopes toward both the eastern and western Mile Island Nuclear Station within the shores with a gradient of less than one specified 1-mile radius. Only 1 of these was percent. The groundwater flow eventually designated as a public drinking water supply enters the river, which acts as a natural well. The rest are primarily used for boundary. River flow to the rock of the domestic purposes (Conestoga-Rovers Gettysburg shale (i.e., the second water 2006).

bearing unit mentioned above) on either bank of the river is highly unlikely due to the There are seven water supply wells lower flow characteristics of the Gettysburg associated with the Three Mile Island shale when compared to those of the Nuclear Station. Five are located on Three alluvial materials and the higher Mile Island within the plant site groundwater levels on either shore with (Figure 2.3-1). The other two are located off hydraulic gradients toward the river. River the island at the Visitors Center and the flow to the Gettysburg shale might occur, Training Center/Simulator Building (Figure however, if very heavy pumping were to 3.1-1), as is further described below. Two occur on shore because heavy pumping on of the five wells on Three Mile Island supply Page 2-12 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.3 GROUNDWATER RESOURCES the on-site, non-community, public water 2.3.3 GROUNDWATER system. They are called the Operations MONITORING Support Facility/North Office Building (OSF) well and the Building 48 (48S) well. They Since 1980, numerous groundwater were installed to depths of 775 feet and monitoring wells have been installed at the 996 feet, respectively, and have maximum Three Mile Island Nuclear Station for design yields of 40 gallons per minute (gpm) various monitoring or investigative and 30 gpm, respectively. If it is not needed programs. Such wells have been sampled to supply drinking water, the OSF well also at varying frequencies and for a variety of may be used to augment the supply of parameters. Over time, some wells have service water, which is otherwise provided been closed. Historical knowledge and data by site production wells A, B, and C related to Station operations and

[Susquehanna River Basin Commission radionuclide analyses of groundwater (SRBC) Well numbers 1, 2, and 3, samples from such wells indicate tritium to respectively]. These three wells supply be the radionuclide most often detected industrial makeup water (including fire above background concentrations in the service, makeup to the demineralized water groundwater (Conestoga-Rovers 2006).

system, bearing lubrication for the screen Tritium is a radionuclide that decays by house pumps, and service for other emitting a low-energy beta particle that buildings and equipment) (McLaren/Hart cannot penetrate deeply into tissue or travel 1998b) and were installed to depths of far in air. It is created in the environment 400 feet, 500 feet, and 400 feet, from naturally occurring processes both respectively. Wells A, B, and C are cosmic and subterranean, as well as from permitted to pump a total of 225,000 gallons anthropogenic (i.e., man-made) sources.

per day (gpd) (156 gpm) of groundwater The background concentration for tritium in (SRBC 1999). groundwater at the Three Mile Island Nuclear Station has been estimated to be As previously mentioned, two of the seven approximately 200 pCi/L or lower water supply wells associated with the (Conestoga-Rovers 2006).

Three Mile Island Nuclear Station are located off the island at the Visitors Center In 2006, Exelon conducted a and the Training Center/Simulator Building. comprehensive initiative to evaluate the The well that supplies potable water to the radiological impacts of operations on Visitors Center was installed to a depth of groundwater and surface water in the 121 feet and has a maximum design yield of vicinities surrounding all Exelon-owned about 10 gpm. The well that provides nuclear power stations, including TMI-1. As potable water to the Training a result of this initiative, the groundwater Center/Simulator Building was installed to a monitoring network at the Three Mile Island depth of 100 feet and has a maximum Nuclear Station was expanded, and 31 new design yield of 30 gpm. permanent, on-site groundwater monitoring wells were installed. Also, the 2006 For the period from 2003 to 2005, groundwater monitoring effort at the Three groundwater production from the seven Mile Island Nuclear Station occurred in two water supply wells associated with the parallel phases. Phase 1, which occurred Three Mile Island Nuclear Station averaged during May, implemented the Exelon between approximately 95 to 115 gpm initiative at the Station. Phase 2 continued (AmerGen 2004, AmerGen 2005, AmerGen the groundwater monitoring program that 2006a).

had been ongoing at the Station for over 20 years.

Three Mile Island Nuclear Station Unit 1 Page 2-13 License Renewal Application

Environmental Report Section 2.3 GROUNDWATER RESOURCES During the May 2006, Phase 1 groundwater compared with the 2006 Phase 1 results, monitoring effort, 58 on-site wells were which have been designated as the sampled for tritium, strontium-90, and Baseline Monitoring Round for the TMI-1 gamma emitting radionuclides. Tritium was RGPP. Such comparison serves to not detected at concentrations greater than establish trends, identify potentially the EPA drinking water standard of 20,000 contaminated systems, and verify that pCi/L. Tritium was detected at radiological protection of groundwater is concentrations greater than background. maintained (Exelon 2006b). This process Such concentrations ranged from 223 +/- 114 identified significantly increased tritium pCi/L to 13,500 +/- 1,390 pCi/L. (Conestoga- concentrations in several wells during the Rovers 2006) period from May through July 2007. During this period, six samples from two monitoring During the 2006 Phase 2 groundwater wells exceeded the EPA drinking water monitoring effort, samples were collected standard of 20,000 pCi/L, with the highest from 76 locations, two of which were off-site being 29,600 pCi/L in July. By then, drinking water wells, and many of which however, Station personnel had identified were also sampled as part of Phase 1. the source of the leak, isolated and Sampling was conducted from January removed the leaking piping from service, through December 2006. No detectable and repaired the leak. Subsequently, tritium concentration of tritium was found in the off- concentrations decreased in all wells to site drinking water wells. Tritium was not levels far below the EPA drinking water detected in any of the other groundwater standard, which demonstrated the success samples at concentrations greater than the of the repair, and the utility of the RGPP for EPA drinking water standard of 20,000 protecting the quality of groundwater.

pCi/L. Tritium was detected at concentrations greater than background in In January 2007, Conestoga-Rovers &

46 on-site wells. Such concentrations Associates (Conestoga-Rovers) completed ranged from 201 + 111 pCi/L to 19,200 + calculations (using results from the 2006 1960 pCi/L. (AmerGen 2007a) Phase 1 investigation) to determine the estimated mass flux of tritiated groundwater In 2007, AmerGen implemented a revised to the Susquehanna River. The results long-term groundwater monitoring effort were reconfirmed following repair of the referred to as the Radiological Groundwater tritium leak in June 2007 (Conestoga-Protection Program (RGPP) at TMI-1, Rovers 2007). The following matrix replacing the previous groundwater summarizes the estimated rate of tritium monitoring program (AmerGen 2007a). A migration with and without pumping of the primary purpose of the RGPP is to provide on-site production wells A, B, and C and timely detection and effective response to with and without background.

radiological releases to groundwater (Exelon 2006b). A total of 59 on-site groundwater wells, which are shown on Total Mass Total Mass Background Figure 2.3-1, are included in the Three Mile Flux With Flux Without Island Nuclear Station RGPP (Exelon Contribution Background

Background

2007). These wells, 5 of which are the 5 (Ci/yr) (Ci/yr) (Ci/yr) on-site water supply wells described in No pumping 0.32 0.09 0.23 section 2.3.2, are sampled at various frequencies for tritium, strontium-90, and Tritium Captured by 0.20 0.013 0.18 gamma emitting radionuclides.

Pumping Under the RGPP, groundwater sampling With Pumping 0.12 0.074 0.05 conducted during 2007 has been regularly Source: Conestoga-Rovers (2006)

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Environmental Report Section 2.3 GROUNDWATER RESOURCES Based on these results and conditions at its Radiological Effluents Control Program, the Station with respect to pumping of the which is inspected by and reported to the production wells, Conestoga-Rovers NRC. Furthermore, even without pumping concluded that the cumulative migration of of the three production wells, the amount of tritium in groundwater to the river was tritium entering the river in groundwater was negligible compared to the Stations estimated to be minimal.

regulated tritium releases to the river under Three Mile Island Nuclear Station Unit 1 Page 2-15 License Renewal Application

Environmental Report Section 2.4 CRITICAL AND IMPORTANT TERRESTRIAL HABITATS 2.4 CRITICAL AND (WHC 2005). These particular three birds of interest are discussed further in Section IMPORTANT 2.5, Threatened and Endangered Species.

TERRESTRIAL Three Mile Island is located within the HABITATS Central Appalachian Broadleaf Forest -

Coniferous Forest - Meadow Province Three Mile Island covers approximately 370 (WHC 2005). Local differences in acres, of which about 200 are occupied by vegetation types and densities in this the TMI-1 and TMI-2 facilities (Figure 3.1-2). Province are a function of elevation and the AmerGen owns the entire island except soil fertility. Primarily in the southern and certain TMI-2 facilities. AmerGen also owns undeveloped portions of the island, open all or a portion of some of the smaller field habitat is dominated by foxtail grasses islands in the vicinity of Three Mile Island bordered by tree and shrub buffers. Plant and a portion of the eastern bank of the species in these buffer areas include Susquehanna River. TMI-1 is surrounded sycamore, sweetgum, blackberry, by fencing and contains few areas that have basswood, and locust trees. The riparian not been developed or previously disturbed. forest areas on Three Mile Island contain The undeveloped land on the island is found silver maple, alder, birch, and sycamore south of the TMI-1 and TMI-2 facilities (WHC 2005). These plants provide cover of (Figure 3.1-2). The majority of this varying degrees and a direct source of food undeveloped land lies under the ten- year for various reptiles, birds, and mammals.

flood level and is subject to seasonal Mammals commonly identified in the area variations in water level. The southern part include white-tailed deer, striped skunk, of the island contains a wetland that was raccoon, red fox, and grey squirrel.

formed when borrow pits created during construction of a flood dike system, which Transmission lines associated with TMI-1 surrounds the TMI-1 and TMI-2 facilities, extend into Dauphin, Lancaster, and York filled with water. The southern portion of Counties. Four 230-kilovolt (kV) the island also contains fallow field areas transmission lines associated with TMI-1 that are surrounded by a woodland buffer. cross these counties and terminate 0.7 to Riparian buffer areas are intact around the 4.1 miles from the plant (Figure 3.1-2). The perimeter of the entire island although primary land use type crossed by the forested riparian areas are isolated to the transmission lines is agricultural, but the southern part of the island (WHC 2005). lines also cross residential, urban, and forested areas. Land planning in Dauphin, The Susquehanna River is an important Lancaster, and York Counties emphasizes source of fresh water and nutrients that flow preservation of agricultural land use and into the Chesapeake Bay. The Chesapeake restriction of development to areas already Bay is vital to migratory waterfowl on the impacted. These counties also emphasize eastern flyway (DU 2006). The islands in the identification and protection of natural the Susquehanna River are important areas and incorporate this theme into their resting stops for migratory waterfowl and future land use policies (York County 2006; the borrow pits on Three Mile Island provide Dauphin County 2007; Lancaster County nesting and foraging habitat. The peregrine 2006). Plant and animal species in the falcon and osprey are known to nest on the areas near the transmission lines are island. The island has also been identified represented by those found on Three Mile as a potential nesting site for bald eagles Island.

although none are known to nest there now Page 2-16 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.5 THREATENED AND ENDANGERED SPECIES 2.5 THREATENED AND federally-listed as endangered, is known to occur in Lancaster County (PNHP 2007).

ENDANGERED AmerGen is not aware of any occurrences of the bog turtle, Northeastern bulrush, or SPECIES Dwarf wedgemussel on Three Mile Island or along the transmission lines associated with Animal and plant species that are state- or TMI-1. Bald eagles; (Haliaeetus federally-listed as endangered or threatened leucocephalus), have recently been and recorded in counties within which TMI-1 removed (August 2007) from the and its associated transmission lines are Endangered Species Act list of federally located are listed in Table 2.5-1. Counties protected species; however, they remain crossed by the transmission lines are protected by two other federal laws, The Dauphin (the location of TMI-1), Lancaster, Bald and Golden Eagle Protection Act and and York (Figure 3.1-2). The total length of the Migratory Bird Treaty Act (BLM 2007).

all four lines are less than 8 miles. The Bald eagles have become relatively species included in Table 2.5-1 are those common along the Susquehanna River and that meet at least one of the following are known to occur in Dauphin, Lancaster, conditions: and York counties. Occasionally, they have been observed on Three Mile Island, but no

• Records maintained by the U.S. Fish nests are known to be located there. There and Wildlife Service (FWS) indicate that is a nest located approximately 20 miles the species is known to occur in south, near the Holtwood Dam.

Dauphin, Lancaster or York counties, and the species is federally-listed as The Susquehanna River and the associated endangered, threatened, proposed for riparian and wetland areas in the vicinity of federal listing, or is a candidate for Three Mile Island are used by many federal listing (FWS 2006). migratory and resident bird species (NRC 1989). Osprey (Pandion haliaetus) and

• Records maintained by the peregrine falcon (Falco peregrinus) nests Pennsylvania Natural Heritage Program are known to occur on the TMI-1 property.

(PNHP) indicate that the species is Ospreys have nested on the meteorological known to occur in Dauphin, Lancaster or tower every year since 2004. A 55-foot York counties, and the species is state- nesting platform was erected near the listed as endangered or threatened tower, but the ospreys have not used it.

(PNHP 2006 and 2007). Peregrine falcons have nested on the TMI-1 Reactor Building every year since 2002. A

• The species has been observed in the nest box designed for peregrine falcons was vicinity of TMI-1 by Wildlife Habitat placed on the TMI-2 Reactor Building in Council biologists or TMI-1 employees 2002, but the birds have not used it (PADEP (WHC 2005), and is state- or federally- 2007). AmerGen cooperates with the listed. Pennsylvania Department of Environmental Protection (PADEP) in regularly monitoring Three species in Table 2.5-1 are federally- the osprey and peregrine falcon nests on listed as endangered or threatened. Bog the TMI-1 property.

turtles (Clemmys muhlenbergii), federally-listed as threatened, occur in York County. Other state-listed bird species identified in Populations of the Northeastern bulrush counties crossed by the transmission lines (Scirpus ancistrochaetus), federally-listed as include the upland sandpiper (Bartramia endangered, is known to be present in longicauda), American bittern (Botaurus Dauphin County (PNHP 2006). The Dwarf lentiginosus), great egret (Casmerodius wedgemussel (Alasmidonta heterodon), alba), sedge wren (Cistothorus platensis),

Three Mile Island Nuclear Station Unit 1 Page 2-17 License Renewal Application

Environmental Report Section 2.5 THREATENED AND ENDANGERED SPECIES bald eagle (Haliaeetus leucocephalus), state-listed as threatened, has been yellow-crowned night heron (Nyctanassa recorded on TMI-1 property (WHC 2005).

violacea), black-crowned night heron Other plants that are state-listed as (Nycticorax nycticorax) and king rail (Rallus threatened or endangered and known to elegans). Two state-listed mammals occur occur in Dauphin, Lancaster, and York in counties crossed by TMI-1 transmission counties are shown in Table 2.5-1. With the lines. The Allegheny woodrat (Neotoma exception of the bald eagle, peregrine magister) has been identified in Dauphin falcon, osprey, and American holly, County and the least shrew (Cryptotis AmerGen is not aware of occurrences of parva) has been identified in York County. species listed in Table 2.5-1 on Three Mile Two state-listed reptiles occur in counties Island or along transmission lines crossed by TMI-1 transmission lines. The associated with TMI-1.

redbelly turtle (Pseudemys rubriventris) has been identified in York County and the Appendix C includes copies of AmerGen rough green snake (Opheodrys aestivus) correspondence with FWS, the has been identified in Lancaster County. Pennsylvania Game Commission, One state-listed fish, the black bullhead Pennsylvania Department of Conservation (Ameiurus melas), has been recorded in and Natural Resources, and the Dauphin County (PNHP 2006 and PNHP Pennsylvania Fish and Boat Commission.

2007). The American holly (Ilex opaca),

Page 2-18 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.6 DEMOGRAPHY 2.6 DEMOGRAPHY Plants (GEIS) presents a population characterization method that is based on two factors: sparseness and proximity 2.6.1 REGIONAL DEMOGRAPHY (NRC 1996). Sparseness measures population density and city size within 20 The Generic Environmental Impact miles of a site and categorizes the Statement for License Renewal of Nuclear demographic information as follows:

Demographic Categories Based on Sparseness Category Most sparse 1. Less than 40 persons per square mile and no community with 25,000 or more persons within 20 miles

2. 40 to 60 persons per square mile and no community with 25,000 or more persons within 20 miles

3. 60 to 120 persons per square mile or less than 60 persons per square mile with at least one community with 25,000 or more persons within 20 miles Least sparse 4. Greater than or equal to 120 persons per square mile within 20 miles Source: NRC 1996 Proximity measures population density and city size within 50 miles and categorizes the demographic information as follows:

Demographic Categories Based on Proximity Category Not in close proximity 1. No city with 100,000 or more persons and less than 50 persons per square mile within 50 miles

2. No city with 100,000 or more persons and between 50 and 190 persons per square mile within 50 miles

3. One or more cities with 100,000 or more persons and less than 190 persons per square mile within 50 miles In close proximity 4. Greater than or equal to 190 persons per square mile within 50 miles Source: NRC 1996 Three Mile Island Nuclear Station Unit 1 Page 2-19 License Renewal Application

Environmental Report Section 2.6 DEMOGRAPHY The GEIS then uses the following matrix to medium, or high.

rank the population category as low, GEIS Sparseness and Proximity Matrix Proximity 1 2 3 4 Sparseness 1 1.1 1.2 1.3 1.4 2 2.1 2.2 2.3 2.4 3 3.1 3.2 3.3 3.4 4 4.1 4.2 4.3 4.4 Low Medium High Population Population Population Area Area Area Source: NRC 1996 AmerGen used 2000 census data from the located within 50 miles of TMI-1 U.S. Census Bureau (USCB) with (Figure 2.1-1). The MSAs nearest TMI-1 geographic information system software are (1) Harrisburg-Carlisle, PA, (2)

(ArcGIS) to determine most demographic Lancaster, PA, (3) Reading, PA, and characteristics in the TMI-1 vicinity. The (4) York-Hanover, PA, (USCB 2003). The calculations determined that 787,806 people nearest major city is Harrisburg, live within 20 miles of TMI-1, producing a Pennsylvania (12 miles northwest), with a population density of 627 persons per 2000 population of 48,950 (USCB 2000a).

square mile. Applying the GEIS sparseness Additional nearby population centers are measures results in the least sparse York (15 miles south) and Lancaster category, Category 4 (greater than or equal (25 miles southeast) where the 2000 to 120 persons per square mile within 20 populations were 40,862 and 56,348, miles). respectively. The municipality nearest TMI-1 is the Goldsboro Borough (1.25 miles To calculate the proximity measure, west, across the Susquehanna River) with a AmerGen determined that 2,546,479 people 2000 population of 939 (USCB 2000b).

live within 50 miles of TMI-1, which equates to a population density of 325 persons per From 1990 to 2000, the population of the square mile. Applying the GEIS proximity Harrisburg-Carlisle, PA MSA increased from measures, the TMI-1 region is classified as 474,242 to 509,074, an increase of Category 4 (greater than or equal to 190 7.3 percent. The population of the persons per square mile within 50 miles). Lancaster, PA MSA increased from 422,822 Therefore, according to the GEIS to 470,658, an increase of 11.3 percent.

sparseness and proximity matrix, the TMI-1 The population of the York-Hanover, PA region ranks of sparseness, Category 4, MSA increased from 339,574 to 381,751, an and proximity, Category 4, result in the increase of 12.4 percent. The population of conclusion that TMI-1 is located in a high the Reading, PA MSA increased from population area. 336,523 to 373,638, an increase of 11.0 percent (USCB 2003).

All or parts of 22 counties and a number of Metropolitan Statistical Areas (MSAs) are Page 2-20 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.6 DEMOGRAPHY Because approximately 71 percent of The 50-mile radius includes 1,931 block employees at TMI-1 reside in Dauphin and groups (Table 2.6-3).

Lancaster Counties, they are the counties with the greatest potential to be 2.6.2.1 Minority Populations socioeconomically affected by license renewal at TMI-1 (Table 2.6-1). Table 2.6-2 The NRC Procedural Guidance for shows population counts and growth rates Preparing Environmental Assessments and for these two counties. Values for the Considering Environmental Issues defines a Commonwealth of Pennsylvania are minority population as: American Indian or provided for comparison. The table is Alaskan Native; Asian; Native Hawaiian or based on USCB data for 1980, 1990, and other Pacific Islander; Black Races, and 2000. Hispanic Ethnicity (NRC 2001).

Additionally, NRCs guidance requires that Over the last two decades, Pennsylvania, (1) all other single minorities are to be as well as Dauphin and Lancaster Counties, treated as one population and analyzed, has experienced positive growth. From (2) multi-racial populations are to be 1980 to 1990, Dauphin and Lancaster analyzed, and (3) the aggregate of all Counties growth rates outpaced the minority populations are to be treated as Commonwealth of Pennsylvania. From one population and analyzed. The 1990 to 2000, the two counties population guidance indicates that a minority growth slowed, yet remained positive. Both population exists if either of the following counties continued to outpace two conditions exists:

Pennsylvania, which experienced an increase in growth. Overall, Lancaster

• The minority population in the census County has experienced the highest block group or environmental impact site percentage of growth. exceeds 50 percent.

2.6.2 MINORITY & LOW-INCOME

• The minority population percentage of POPULATIONS the environmental impact area is significantly greater (typically at least 20 The Nuclear Regulatory Commission (NRC) percentage points) than the minority performed environmental justice analyses population percentage in the geographic for previous license renewal applications area chosen for comparative analysis.

and concluded that a 50-mile radius (Figure 2.1-1) could reasonably be expected For each of the 1,931 block groups within to contain potential environmental impact the 50-mile radius, AmerGen calculated the sites and that the state was appropriate as percent of the block groups population the geographic area for comparative represented by each minority (Table 2.6-3).

analysis. AmerGen has adopted this If any block group minority percentage approach for identifying the minority and exceeded 50 percent, then the block group low-income populations that could be was identified as containing a minority affected by TMI-1 operations. population. AmerGen selected the entire Commonwealth of Pennsylvania as the AmerGen used 2000 census data from the geographic area for comparative analysis USCB with geographic information system for block groups located within the borders software (ArcGIS) to determine the of Pennsylvania, and calculated the minority characteristics by block group. percentages of each minority category in AmerGen included any block group with the Commonwealth. AmerGen selected the part of its area within 50 miles of TMI-1. entire State of Maryland as the geographic area for comparative analysis for block groups located within the borders of Three Mile Island Nuclear Station Unit 1 Page 2-21 License Renewal Application

Environmental Report Section 2.6 DEMOGRAPHY Maryland, and calculated the percentages Pennsylvania average by 20 percent or of each minority category in the State. If more. Of those 155 block groups, 100 have any block group percentage exceeded the Aggregate Minority populations of 50 corresponding State percentage by more percent or more. None of the Maryland than 20 percent, then a minority population census block groups that lie within the was determined to exist. 50-mile radius have Aggregate Minority populations that exceed the Maryland Census data for Pennsylvania characterizes average by 20 percent or more. One block 0.15 percent of the population as American group has Aggregate Minority populations of Indian or Alaskan Native; 1.79 percent 50 percent or more (see note at the bottom Asian; 0.03 percent Native Hawaiian or of Table 2.6-3).

other Pacific Islander; 9.97 percent Black races; 1.53 percent all other single One hundred and five census block groups minorities; 1.16 percent multi-racial; 14.63 within the 50-mile radius have Hispanic percent aggregate of minority races; and Ethnicity populations that exceed the 3.21 percent Hispanic ethnicity. Census average in their state by 20 percent or data for Maryland characterizes 0.29 more. Of those 105 block groups, 33 have percent of the population as American Hispanic Ethnicity populations of 50 percent Indian or Alaskan Native; 3.98 percent or more.

Asian; 0.04 percent Native Hawaiian or other Pacific Islander; 27.89 percent Black 2.6.2.2 Low-Income Populations races; 1.80 percent all other single minorities; 1.96 percent multi-racial; 35.97 NRC guidance defines low-income percent aggregate of minority races; and population based on statistical poverty 4.30 percent Hispanic ethnicity. thresholds (NRC 2001) if either of the following two conditions are met:

Table 2.6-3 presents the numbers of block groups in each county in the 50-mile radius

• The low-income population in the that exceed the threshold for minority census block group or the populations. Figures 2.6-1 through 2.6-5 environmental impact site exceeds 50 displays the minority block groups within the percent.

50-mile radius.

• The percentage of households below Seventy-eight census block groups within the poverty level in an environmental the 50-mile radius have Black races impact area is significantly greater populations that exceed the state average (typically at least 20 percentage points) by 20 percent or more. Of those 78 block than the low-income population groups, 38 have Black races populations of percentage in the geographic area 50 percent or more. chosen for comparative analysis.

Fifty-six census block groups within the 50- AmerGen divided USCB low-income mile radius have All Other Single Minority households in each census block group by populations that exceed the state average the total households for that block group to by 20 percent or more. Of those 56 block obtain the percentage of low-income groups, 2 have All Other Single Minority households per block group. Using the populations of 50 percent or more. Commonwealth of Pennsylvania as the geographical area chosen for comparative One hundred and fifty-five of the analysis for block groups within the borders Pennsylvania census block groups that lie of Pennsylvania, AmerGen determined that within the 50-mile radius have Aggregate 10.99 percent of Pennsylvania households Minority populations that exceed the are low-income. Using the State of Page 2-22 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.6 DEMOGRAPHY Maryland as the geographical area chosen Sixty-six of the 1,931 census block groups for comparative analysis for block groups within the 50-mile radius have low-income within the borders of Maryland, AmerGen households that exceed their state average determined that 8.32 percent of Maryland by 20 percent or more. Of those 66 block households are low-income. Table 2.6-3 groups, 14 have 50 percent or more low-identifies the low-income block groups in the income households.

region of interest, based on NRCs two criteria. Figure 2.6-5 displays the low-income block groups.

Three Mile Island Nuclear Station Unit 1 Page 2-23 License Renewal Application

Environmental Report Section 2.7 TAXES 2.7 TAXES Currently, AmerGen pays annual property taxes to Dauphin County, Londonderry Township, and the Lower Dauphin County In the past, the owners of TMI-1 paid real School District, so the focus of this analysis estate taxes to the Commonwealth of will be on those taxing entities.

Pennsylvania on their generating, transmission, and distribution facilities.

From 2000 through 2005, Dauphin County Under authority of the Pennsylvania Utility collected between $58 and $90 million Realty Tax Act (PURTA), real estate taxes annually in property tax revenues (see collected from all utilities (water, telephone, Table 2.7-1). Dauphin County property tax electric, and railroads) were redistributed to revenues fund, among other things, county the taxing jurisdictions within the operations, the judicial system, public Commonwealth. In Pennsylvania, these safety, public works, cultural and jurisdictions included all counties, cities, recreational programs, human services, and townships, boroughs, and school districts.

conservation and development programs.

The distribution of PURTA funds was Table 2.7-1 details the property tax determined by formula, and was not payments made by the owners of TMI-1 for necessarily based on the individual utilitys the same years. From 2000 to 2005, TMI-1 effect on a particular government entity.

property tax payments have represented 0.2 to 0.3 percent of Dauphin Countys total In 1996, Governor Tom Ridge signed into property tax revenues.

law the Electricity Generation Customer Choice and Competition Act, which allows From 2000 through 2005, Londonderry consumers to choose among competitive Township collected between $4 and $6.3 generation suppliers. As a result of utility million annually in property tax revenues restructuring, Act 4 of 1999 provided for a (see Table 2.7-1). Londonderry Township revision of the tax base assessment property tax revenues fund county methodology for utilities from the operations (which include libraries, depreciated book value to the market value hospitals, roads, etc.), school districts, and of utility property. Additionally, as of 2000, fire departments. Table 2.7-1 details the TMI-1 was required to begin paying real property tax payments made by the owners estate taxes directly to local taxing of TMI-1 for the same years. From 2000 to jurisdictions, ceasing payments to the 2005, TMI-1 property tax payments have Commonwealths PURTA fund. represented 0.3 to 0.7 percent of Periodically, the owner of TMI-1 negotiates Londonderry Townships total property tax with its local taxing jurisdictions regarding revenues.

market value assessments of the station and the resultant taxes that will be paid. From 2000 through 2005, the Lower AmerGen conducted the last negotiation in Dauphin School District (LDSD) collected 2005. AmerGen and the local taxing between $13 and $21 million annually in jurisdictions agreed that the assessed value property tax revenues (see Table 2.7-1).

of TMI-1 would be $20,000,000 in 2005 and Table 2.7-1 details the property tax

$18,250,000 each year from 2006 until payments made by the owners of TMI-1 for 2008. The assessed value for years the same years. From 2000 to 2005, TMI-1 beginning with 2009 will be negotiated at property tax payments have represented 1.7 appropriate times, in accordance with to 2.9 percent of LDSD total tax revenues.

applicable law.

Page 2-24 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.8 LAND USE PLANNING 2.8 LAND USE PLANNING Dauphin County Dauphin County is approximately 525 This section focuses on Dauphin and square miles in size and has 40 Lancaster counties because the majority of municipalities including the Pennsylvania the permanent TMI-1 workforce lives in state capital in Harrisburg (USCB 2005).

those counties (see Section 3.4). The TMI-The county is located in south-central 1 facility is located in southwestern Dauphin Pennsylvania, along the Susquehanna County. Lancaster County is located River. Dauphin Countys land use planning southeast of Dauphin County along the focuses on efficient use of land, and Susquehanna River. Lancaster Countys efficient expansion. The county planners population has increased 34.8 percent from are concerned about retaining enough area the years 1970 to 2005. Dauphin Countys for future population growth and making population has increased 11.9 percent for growth decisions that dont overburden the same 35-year period, an average taxpayers. The countys focus is on annual increase of 0.4 percent (USCB 1995 revitalization of old areas, and managed and USCB 2006). Regional and local growth that doesnt change rural character.

planning officials have shared goals of encouraging expansion and development in As part of the state capital region, the areas where public facilities, such as water county has been involved in regional and sewer systems, have been planned, planning since 1956. Dauphin County has and discouraging incompatible land use developed its future land use plan through mixes in agricultural or open spaces. the use of Planned Growth Areas. Dauphin County adopted the tool from the Regional The planning for both counties is driven in Growth Management Plan produced by the part by the Pennsylvania Municipalities Tri-County Regional Planning Commission, Planning Code Act of 1968 which promotes of which it is a member with neighboring the preservation of natural and historic Cumberland and Perry counties. Planned resources and prime agricultural land and Growth Areas serve to place most encourages the revitalization of established development in areas that are already urban centers through the use of served by public services and have Designated Growth Areas (Lancaster established infrastructure. The goal is to County 2006). The act requires focus development in and around comprehensive planning on the part of Community Service Areas where services counties. It is worth noting that due to the such as sewer, water, transit, highway autonomous nature of the local access, and community facilities exist to municipalities (townships, villages and maximize the investment in existing boroughs) in Pennsylvania that a county infrastructure (Dauphin County 2007) has limited legislative scope to implement the comprehensive plans. As a result, The Draft Dauphin County Comprehensive partnerships and coalitions of governing Plan describes the following land use.

bodies are needed to implement the plans.

Both Dauphin and Lancaster counties

• Residential use - 15 percent implement their comprehensive plans through townships and boroughs

• Public and Semi- Public Lands - 26 ordinances. Dauphin County is also percent (two thirds comprised of state involved in several regional comprehensive game lands and forest) plans as a result of historic and strategic goals.

• Agricultural and Undeveloped Lands -

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Environmental Report Section 2.8 LAND USE PLANNING

• Industrial - 2 percent designates only the land needed to accommodate the population projections

• Transportation - less than 1 percent through 2020. All other land is currently designated as Rural Reserve/Agriculture for

• Commercial/Service - less than 1 future evaluation and use (Dauphin County percent each 2007).

In 2000, 34.5 percent of the countys Lancaster County residents lived in Harrisburg and 16 boroughs while others made their homes in Lancaster County is approximately 949 townships and villages. As part of the square miles in size and has 60 Comprehensive Plan, the county has municipalities. The county is almost twice examined future land use by geographic the size of Dauphin County in acreage and planning sections designated by North population (USCB 2006). According to the Dauphin, Southeast Dauphin, Southwest Lancaster Farmland Trust, Lancaster Dauphin and the City of Harrisburg. The County holds the distinction of being the North section is characterized by low most productive non-irrigated farming density residential development. The county in the United States. The county Southeast section is characterized by and municipal planners are concerned medium density residential development. about preserving the farming The Southwest and the Harrisburg sections culture/heritage of the county, especially are characterized by high density mixed that of the Amish. Tourists visiting these urban development (Dauphin County 2007). areas add $1.6 billion annually to the countys economy. Farming plays a major Throughout the county, non-residential role in the county and planning focuses on development occurs in a scattered fashion preservation of agricultural areas. Farmland adjacent to roadways. The greatest in Lancaster County presently occupies 69 concentration of non-residential strip percent of the available land area. This development occurs between the City of planning goal differs from Dauphin County Harrisburg and Derry Township, adjacent to in that Lancaster wants to limit growth in U.S. Routes 83 and 322/422. Limited non- rural areas to locations that have already residential land use has occurred on limited been impacted by development. Lancaster access intersections of Interstates 81 and also has a goal of revitalizing old areas.

83 and the Pennsylvania Turnpike. The portions of the county located in the heart of Lancaster Countys land use planning is the Susquehanna Valley, contain the built on the foundation that it is in the best majority of the agricultural activity. The interest of the residents that its agricultural northeastern tier of the county is heritage be preserved. In 1993, the county mountainous and forested (Dauphin County adopted a Growth Management element to 2007). its Comprehensive Plan. Future growth would be directed to Designated Growth The Land Needs Concept is at the heart of Areas or areas already impacted by Dauphin Countys future land use planning. development to emphasize reinvestment in The concept forecasts land use needs by previously developed areas. The plan considering regional population growth defined two growth areas as Urban Growth trends, employment needs as a result of this Areas and Village Growth Areas to manage population growth, and real estate market future land use in the county (Lancaster projections. Previously, most planning did County 2006). The growth areas have not take into account the big picture and defined boundaries around a city, borough, relied solely on population projections. The or village and include the developed current county future land use plan map portions of surrounding townships and Page 2-26 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.8 LAND USE PLANNING enough buildable land to meet future land In addition to Designated Growth Areas, use needs over a 20 year period. Since Lancaster County has implemented 1993, 39 growth areas have been 11 multi-municipal plans. These planned established in the county. Further, between communities can work together to guide 1994 and 2002, residential land use outside growth and preserve farmland and open Designated Growth Areas occurred at a net space. Forty-one of the 60 county density of 0.8 dwellings per acre, while municipalities are involved in the multi-growth inside of Designated Growth Areas municipal planning efforts dating from 1993 occurred at a net density of 5.5 dwellings to the present (Lancaster County 2006).

per acre (Lancaster County 2006).

The Lancaster County Planning Currently, the largest residential, Commission has begun an update of the commercial and industrial development Growth Management Plan element of the concentrations are found in the City of Lancaster County Comprehensive Plan.

Lancaster and surrounding areas. The update will plan for growth thoroughout Development can also be found on the the county through 2030 and will be guided major road corridors heading north and by the Policy Element of the northwest (I-76, US 30, US 222, and Comprehensive Plan.

PA 283) through the county.

The Growth Management Plan Update will:

The recent trends in rural growth in Lancaster County have been limited to

• examine current and projected growth areas where development had already been patterns and infrastructure needs, established. County planners have a goal of growth in these areas of less than 15

• review Urban and Village Growth Areas, percent of total growth. Past trends show up to 27 percent growth outside developed

• address issues of concern within rural areas, which results in noticeable impacts. areas, and County planners are sensitive to this, and measures will be taken to ensure that

• provide recommendations to achieve development in rural areas will be limited to sustainable growth that balances additions that preserve the rural and development with the preservation of agricultural culture. They also are farmland and open space.

encouraging governmental and private institutions to locate in urban centers (Lancaster County 2006).

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Environmental Report Section 2.9 SOCIAL SERVICES AND PUBLIC FACILITIES 2.9 SOCIAL SERVICES Lancaster County AND PUBLIC Over the last several decades, Lancaster Countys population has grown at a faster FACILITIES rate than the Commonwealth of Pennsylvania (Section 2.6), reflecting an 2.9.1 PUBLIC WATER SUPPLY increase in demand for water and shelter.

In the early 1990s, the Lancaster County Because TMI-1 is in Londonderry Township Board of Commissioners adopted the (in Dauphin County) and most of the TMI-1 Lancaster County Water Resources Plan, employees reside in Dauphin and Lancaster which is the plan currently in use.

Counties, the discussion of public water According to the plan, approximately 64 supply systems will be limited to Dauphin percent of Lancaster County's households and Lancaster Counties. were served by public water suppliers and private wells served the remaining 36 Dauphin County percent. Both surface and groundwater sources are tapped. Total average daily Dauphin County is served by fourteen public water consumption for all uses in the water systems. The systems are owned by County was approximately 66 million various entities, including municipalities, gallons per day (MGD). Average daily authorities, investors and the state water use was anticipated to increase by government. In addition to the large public more than 18 MGD by 2010 (Lancaster systems, there are small private systems County 1996).

provided for some mobile home parks.

Public water systems serve approximately Lancaster County has more than 30 larger 240,000 persons with approximately 74,000 community water suppliers. Although these connections (Dauphin County 2007). The larger systems draw from both ground and largest populations served are those surface waters, they are increasingly receiving water from United Water dependent on groundwater to meet growing Pennsylvania (86,500 persons served), the public demand. To meet these increasing Harrisburg Municipal Water Authority demands, suppliers have made system (66,500 persons), and the Pennsylvania improvements, drilled new wells, and American Water Company-Hershey (38,000 extended service lines. In some cases, new persons) (PADEP 2005). The sources for authorities have been created and water these systems are primarily surface water systems have merged (Lancaster County (i.e. various creeks, streams and a 1996). Table 2.9-2 lists the largest reservoir), while the majority of the smaller municipal water suppliers (serving greater systems are dependent upon groundwater than 10,000 people) in Lancaster County.

sources (Dauphin County 2007).

Lancaster County has ample supply to meet County planners state that there is currently the Countys needs. However, County ample water to meet demand. However, planning officials are concerned about planners predict that future growth will future supplies. An analysis performed by require system expansions and upgrades to the County indicates that approximately assure adequate public water availability one-third of the large community water (Dauphin County 2007). Table 2.9-1 lists suppliers have sufficient water to meet 2010 the largest municipal water suppliers demands. One-third may lack sufficient (serving greater than 10,000 people) in water for this period, while the remaining Dauphin County. systems have an excess supply. Increased development has reduced the amount of land available for aquifer recharge. Also, Page 2-28 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.9 SOCIAL SERVICES AND PUBLIC FACILITIES water resources are impacted by pollutants services. The remaining three are general from high traffic transportation corridors and aviation airports available for public use industrial areas, excessive manure and (Lancaster County 2005).

sludge application, overuse of pesticides, urban and suburban runoff, and leaks, spills Dauphin County is served by three and dumps (Lancaster County 1996). passenger rail services. Harrisburg is the western terminus for Amtraks Keystone To address these issues, County planning Corridor trains, which provide service officials are encouraging a variety of between Harrisburg, Lancaster, mitigations including: zoning; compaction of Philadelphia, and New York. The county is communities; protection of wetlands, also served by two other Amtrak trains: the forests, parks, and agricultural lands to Pennsylvanian and the Three Rivers. The enable better groundwater recharge; Pennsylvanian runs between New York and reduction of pollutants through the adoption Pittsburgh and the Three Rivers runs of wellhead protection programs and the between New York and Chicago (Dauphin expansion of leak detection efforts; and the County 2007). Lancaster County is also interconnection of systems having served by the two passenger rail services.

insufficient water supplies with those having The Pennsylvania Department of excess supplies (Lancaster County 1996). Transportation and Amtrak are in the process of expanding and upgrading current 2.9.2 TRANSPORTATION rail services. Additionally, planning officials in the area are in the process of developing Dauphin and Lancaster Counties cover a regional rail system (Lancaster County approximately 525 and 949 square miles, 2005).

respectively (USCB 2006). TMI-1 is located in the southwest corner of Dauphin County Road access to TMI-1 is via State Highway (near the Lancaster County border), (SH-) 441, which has a north-south approximately 10 miles southeast of orientation. The plant has two access Harrisburg, Pennsylvania. Dauphin County roads, Liberty Lane to the north (North is traversed by four interstate highways, 81, Access Road), and Constitution Drive to the 83, 283, and 76. The nearest interstate, south (South Access Road) and they both I-76, can be accessed approximately 7 intersect with SH-441 (Figure 2.1-3). The miles north of TMI-1. See Figures 2.1-1 and majority of the plants operations workforce 2.1-2 for locations. uses the northern entrance, a limited number of employees working on the Two major airports serve Dauphin County; southern portion of the station and the the Harrisburg International Airport, in outage and refurbishment workforces use Lower Swatara Township, and the Capital the southern entrance. Approximately four City Airport in Fairview Township, York to five miles north of TMI-1, SH-441 County. The Harrisburg International intersects with I-76, which has an east-west Airport is a passenger and air freight facility. orientation (Figure 2.1-2). Employees The Capital City Airport is a public, general traveling from the north (Harrisburg, aviation airport. A second, but smaller, Hummelstown, and Middletown, etc.),

public general aviation airport is the northeast, and northwest of TMI-1 would Bendigo Airport which serves northern use I-76 and/or a variety of interstate, state, Dauphin County (Dauphin County 2007). and secondary roads to access SH-441 to Four airports serve Lancaster County. Two reach TMI-1. Employees traveling from the are in the central part of the county, and two south and southeast (Elizabethtown, Mount are in the western part of the county. The Joy, and Lancaster, etc.) would use a Lancaster Airport is the largest of the four variety of state highways and secondary and provides passenger and freight roads to access SH-441 to reach TMI-1.

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Environmental Report Section 2.9 SOCIAL SERVICES AND PUBLIC FACILITIES Employees traveling from the southwest E -- Operating conditions at or near capacity would travel north to I-76, cross the level causing low but uniform speeds and Susquehanna River, and access SH-441 to extremely difficult maneuvering that is reach TMI-1. Plant employees report no accomplished by forcing another vehicle to congestion on SH-441 near plant entrances. give way; small increases in flow or minor perturbations will cause breakdowns.

In determining the significance levels of transportation impacts for license renewal, F -- Defines forced or breakdown flow that NRC uses the Transportation Research occurs wherever the amount of traffic Boards level of service (LOS) definitions approaching a point exceeds the amount (NRC 1996). LOS is a qualitative measure which can traverse the point. This situation describing operational conditions within a causes the formation of queues traffic stream and their perception by characterized by stop-and-go waves and motorists. Traffic congestion conditions are extreme instability.

rated as A through F and are designated as follows: The Pennsylvania Department of Transportation (PENNDOT) makes LOS A -- Free flow of the traffic stream; users are determinations for roadways involved in unaffected by the presence of others. specific projects. However, there are no current PENNDOT-generated LOS B -- Stable flow in which the freedom to determinations for the roadways analyzed in select speed is unaffected but the freedom this document. Dauphin County has to maneuver is slightly diminished. provided LOS data for the portion of SH-441 within the borders of Dauphin County in its C -- Stable flow that marks the beginning of comprehensive plan. Lancaster County has the range of flow in which the operation of not included LOS data in its comprehensive individual users is significantly affected by plan. Therefore, annual average daily traffic interactions with the traffic stream. volumes are included for both counties and LOS data is included for Dauphin County.

D -- High-density, stable flow in which Table 2.9-3 lists roadways in the vicinity of speed and freedom to maneuver are TMI-1, the annual average number of severely restricted; small increases in traffic vehicles per day as determined by will generally cause operational problems. PENNDOT, and LOS information as determined by Dauphin County.

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Environmental Report Section 2.10 METEOROLOGY AND AIR QUALITY 2.10 METEOROLOGY AND that is worse than the NAAQS are designated by EPA as non-attainment AIR QUALITY areas. Those areas that were previously designated nonattainment and subsequently TMI-1 is located in Dauphin County in redesignated to attainment due to meeting south-central Pennsylvania. The area is the NAAQS are maintenance areas. States partially protected from severe weather by with maintenance areas are required to the Appalachian Mountains to the north. develop an air quality maintenance plan as The climate is characterized by cold an element of the State Implementation temperatures and frequent periods of snow Plan.

during the winter and relatively warm humid summers with precipitation distributed Dauphin County is part of the Harrisburg-evenly throughout the year (AmerGen Lebanon-Carlisle, Pennsylvania MSA. The 2006b). Meteorological information relevant EPA designated the entire MSA as a non-to the severe accident mitigation attainment area under the PM2.5 NAAQS alternatives analysis is provided in Section and a basic non-attainment area under the 4.20 and Appendix E. 8-hour ozone NAAQS. The Harrisburg-Lebanon-Carlisle MSA is designated as an Under the Clean Air Act, the U.S. attainment area for nitrogen dioxide, sulfur Environmental Protection Agency (EPA) has dioxide, carbon monoxide, PM10, and lead established National Ambient Air Quality (40 CFR 81.339).

Standards (NAAQS), which specify maximum concentrations for nitrogen The Clean Air Act, as amended, established dioxide, sulfur dioxide, carbon monoxide, 156 Mandatory Class I Federal Areas where particulate matter with aerodynamic visibility is an important issue. There are diameters of 10 microns or less (PM10), currently no Class I areas located within the particulate matter with aerodynamic state of Pennsylvania or within 100 miles of diameters of 2.5 microns or less (PM2.5), TMI-1 (40 CFR 81, Subpart D). The closest ozone, and lead. Areas of the United States Class I area to TMI-1 is the Brigantine having air quality as good as or better than National Wildlife Area, which is located the NAAQS are designated by EPA as approximately 189 miles to the southeast of attainment areas. Areas having air quality TMI-1 (Rand McNally 2006).

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Environmental Report Section 2.11 HISTORIC AND ARCHAEOLOGICAL RESOURCES 2.11 HISTORIC AND increase. It is subdivided into the Early, Middle, and Late periods, each lasting two ARCHAEOLOGICAL to three thousand years, and has several major cultural traditions - particularly the RESOURCES Laurentian, Lamoka, and Piedmont.

Warming and the retreat of glaciers led to 2.11.1 REGIONAL HISTORY IN the succession of vegetation zones, tundra-BRIEF spruce-fir-pine-mixed deciduous-oak-hickory, passing through Pennsylvania.

Prehistoric Tool forms changed and the culture showed stylistic changes and increased diversity of Aboriginal people migrated to Pennsylvania forms. As megafauna became extinct, so approximately 10,000 to 15,000 or more did the fluted lanceolate point. It was years ago. Three major cultural traditions replaced by forms more locally styled.

dominated the prehistory of Pennsylvania: Knives, scrapers, drills, and other chipped (1) the Paleo-Indian Tradition (15,000+ to stone tools, as well as bone tools continued 10,000 years ago); (2) the Archaic Tradition as important elements of Archaic (10,000 to 3,000 years ago); and (3) the assemblages.

Woodland Tradition (3,000 years ago to European contact). The Archaic period was followed by the Woodland period, which is also subdivided The Paleo-Indian period corresponds with into the Early, Middle, and Late periods.

the waning of the last glaciers. During The major trait delineating the Woodland glaciation, environmental zones were from the Archaic is the addition of ceramics.

shifted hundreds of miles to the south, and The practice of horticulture, the construction now-extinct megafauna roamed the of earthen mounds for burial of the dead landscapes. It is believed that nomadic and later, the introduction of the bow and Paleo-Indians hunted these large animals. arrow are also considered Woodland This period is characterized by the Clovis innovations. During this period, the point, a distinctive, fluted, lanceolate point Hopewell culture dominated much of the that is widely distributed throughout eastern United States. Traces of the Pennsylvania, especially in the Hopewell culture are present in Susquehanna and Delaware River Pennsylvania.

drainages. Pennsylvania Paleo-Indian sites also contain scrapers; spurred-end Historic scrapers; drills; cores; bifaces; microblades; and small uniface, biface, and flake knives. In the mid 17th century, when the first Europeans came to the area now known as As the glaciers retreated into Canada, Pennsylvania, they found Late Woodland environmental zones shifted northward, people, known as the Delaware, Shawnee, eventually assuming positions closely Iroquois, and Susquehannock. The approximating those of today. The largest Susquehannocks were an Iroquoian-fauna became extinct and humans adapted speaking tribe who lived along the to exploit modern flora and fauna, Susquehanna River in Pennsylvania and particularly deer, elk, rabbits, and squirrels, Maryland (PGA Undated). In fact, they and vegetable products of the forest, such inhabited an area about 20 miles as nuts and greens. The Archaic period downstream of TMI-1 in a town they called was concomitant with the retreat of the Sasquesahanaugh, on the east side of the glaciers and is characterized by the Susquehanna River at Washington Boro increasing use of a greater diversity of (AEC 1972). Living in Algonkian-speaking forest products and an apparent population tribes' territory, they engaged in many wars.

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Environmental Report Section 2.11 HISTORIC AND ARCHAEOLOGICAL RESOURCES In the end, they were victims of diseases it without first buying the claims of Native brought by European settlers, and attacks Americans who lived there. In this manner, by Marylanders and the Iroquois which all of Pennsylvania except the northwestern destroyed them as a nation by 1675. A few third was purchased by 1768. The descendants were among the Conestoga Commonwealth bought the claims to the Indians who were massacred in 1763 in remainder of the land by 1789 (PHMC Lancaster County (PGA Undated). Undated).

The rise of nation-states in Europe English Quakers were the dominant settlers, coincided with the gaining of lands in North although a substantial number were America. Wars in southern Germany Anglican. Thousands of Germans were caused many Germans to migrate to also attracted to the colony and, by the time Pennsylvania. The struggle in England of the American Revolution, they comprised between the Crown and Parliament and the a third of the population. Another immigrant quest for religious freedom brought group was the Scotch-Irish, who migrated Quakers, Puritans, and Catholics from from about 1717 until the American England, and Scots Calvinists via Ireland. Revolution in a series of waves caused by Huguenots left France for America (PGA hardships in Ireland (PHMC Undated).

Undated).

Other Quakers were Irish and Welsh. They, The first recorded European contact with together with the French Huguenots, Jewish present-day Pennsylvania was made by settlers, Dutch, Swedes, and other groups, Captain John Smith who journeyed from contributed in smaller numbers to the Virginia up the Susquehanna River in 1608, development of colonial Pennsylvania visiting the Susquehannock Indians. (PHMC Undated).

Between 1609 and 1681, the Dutch, Swedes, and English inhabited and fought Despite Quaker opposition to slavery, about over the region that would later become 4,000 slaves were brought to Pennsylvania eastern Pennsylvania. Ultimately, the by 1730, most of them owned by English, English prevailed and the area fell under Welsh, and Scots-Irish colonists. The English rule. census of 1790 showed that the number of African-Americans had increased to about William Penn was born in London on 10,000, of whom about 6,300 were free October 24, 1644. As a young man, he (PHMC Undated).

converted to the Society of Friends, or Quakers, then a persecuted sect. Seeking 2.11.2 INITIAL CONSTRUCTION a haven in the New World for persecuted AND OPERATION Friends, Penn asked the King to grant him land in the territory between Lord The Final Environmental Statement (FES)

Baltimore's province of Maryland and the for operation of Three Mile Island Nuclear Duke of York's province of New York. With Station listed three properties on the the Duke's support, Penn's petition was National Register of Historic Places granted. The King signed the Charter of (National Register) that were within 17 miles Pennsylvania on March 4, 1681, and it was of the site and two properties eligible for officially proclaimed on April 2. The King listing on the National Register that were named the new colony in honor of William within 5 miles of the site (AEC 1972). The Penn's father (PHMC Undated). National Register sites were: Walnut Street Bridge, 11 miles north of the station in Although William Penn was granted all the Harrisburg; Cornwall Iron Furnace, 17 miles land in Pennsylvania by the King, he and his northeast in Lebanon County; and Billmeyer heirs chose not to grant or settle any part of House in York, 14 miles south of the site.

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Environmental Report Section 2.11 HISTORIC AND ARCHAEOLOGICAL RESOURCES The sites eligible for listing on the National performing limited testing on the island.

Register were: St. Peters Evangelical Their investigation led to the conclusion that Lutheran Church, 3 miles north of the site; cultures from the prehistoric Early Archaic and a cemetery, slightly further north (AEC through the historic Susquehannock Indians 1972). have used the island and that much of the cultural data, stratigraphy, and features Additionally, the Atomic Energy Commission indicating human activity remain to be (AEC) reported that, in 1967, the applicants investigated.

for Three Mile Island Nuclear Station funded an archaeological survey and subsequent In 1988, the Curator of Archaeology from excavation of artifacts from the island prior the State Museum of Pennsylvania to construction. The survey and excavation performed an investigation of a burial site was conducted by the Pennsylvania discovered on the southern tip of the island Historical and Museum Commission (PHMC by a TMI-1 employee. The Curator 1977). More than 1,000 artifacts were concluded that the human burial was not the found and, from these artifacts, it was product of a recent homicide, but the deduced that the site had period remains of a 19th century island resident.

components ranging from 4,000 B.C. to The remains were collected and later 1000+ A.D. The artifacts having most reburied in a location near their original importance for understanding the way of life burial site. Associated cultural materials of an early people were from the Early and (i.e., clothing buttons, coffin nails, etc.) were Middle Woodland cultures, because these collected and donated to the State Museum are poorly known eras of Pennsylvania of Pennsylvania for perpetual curation.

prehistory.

In 1999, the Pennsylvania Historical and Comments included in the FES by the Museum Commission held a public history Advisory Council on Historic Preservation, symposium and erected a historical United States Department of the Interior, marker on SH-441, south of the Three Mile and Pennsylvania Historical and Museum Island Nuclear Station Visitor Center sign, Commission, indicated that the operation of commemorating the 20th anniversary of the Three Mile Island Nuclear Station would TMI-2 accident. The symposium was a have no significant adverse effect on cooperative effort of the Pennsylvania cultural resources in the area (AEC 1972) Department of Environmental Protection, the Pennsylvania Historical and Museum 2.11.3 OTHER CULTURAL Commission, Penn State Harrisburg, the RESOURCE ACTIVITIES IN NRC, GPU Nuclear Incorporated, Three Mile Island Alert, Middletown Borough, and THE AREA Londonderry Township (PHMC 1999).

In April, 1987, a paper was presented at the 2.11.4 CURRENT STATUS Mid Atlantic Archaeological Conference Annual Meeting in Lancaster, Pennsylvania As of 2006, the National Register of Historic by two archaeologists detailing work theyd Places listed 65 sites in Dauphin County, performed in relation to Three Mile Island 207 sites in Lancaster County, and 92 sites (Mangold and Grace 1987). The in York County, Pennsylvania (USDOI archaeologists wanted to more clearly 2006). Of these 364 sites, 19 fall within a define the cultural occupations of the island 6-mile radius of TMI-1.

by 1) inspecting extant private collections of those who have collected artifacts from As of 2006, the Department of the Interior Three Mile Island, 2) reviewing previous listed properties that are currently archaeological investigations, and 3) determined eligible for listing on the Page 2-34 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.11 HISTORIC AND ARCHAEOLOGICAL RESOURCES National Register of Historic Places within listing. Figure 2.1-2 depicts the area around the same three counties: 33 sites in TMI-1 bounded by the 6-mile radius.

Dauphin County, 13 sites in Lancaster County, and 14 sites in York County, The 200-acre area occupied by the TMI-1 Pennsylvania (USDOI 2006). Of these facilities on Three Mile Island consists 60 sites, 4 fall within a 6 mile radius of entirely of land disturbed by prior industrial TMI-1. Table 2.11-1 contains the sites activities. No properties listed or eligible for located within a six-mile radius of TMI-1 that listing on the National Register of Historic either are listed in the National Register of Places are known to be located within this Historic Places or have been determined by area.

the Department of Interior to be eligible for Three Mile Island Nuclear Station Unit 1 Page 2-35 License Renewal Application

Environmental Report Section 2.12 KNOWN OR REASONABLY FORESEEABLE PROJECTS IN SITE VICINITY 2.12 KNOWN OR negligible effects on the physical health of individuals or the environment (NRC 2005).

REASONABLY TMI-2, which is owned by FirstEnergy FORESEEABLE Corporation, has been permanently shut PROJECTS IN SITE down and is now in a safe storage mode called Post Defueling Monitored Storage VICINITY (PDMS). The only TMI-2 systems, structures or components that are relied As indicated on Figure 2.1-1, there are three upon for the operation of TMI-1 are the urban areas, Harrisburg, Lancaster, and Station Blackout Diesel Generator Building York, PA, within 25 miles of the TMI-1 plant and the TMI-2 Fuel Handling Building site. Within a six-mile radius (Figure 2.1-2) (Figure 3.1-1). No TMI-2 activities are of TMI-1, the nearest population centers are within the scope of the TMI-1 license Royalton and Middletown. Farms, renewal application.

residential neighborhoods consisting primarily of older single-family homes, and FirstEnergy Corporation has contracted with few commercial and/or industrial facilities AmerGen to perform maintenance and are located within the immediate vicinity. administration functions for TMI-2. It is anticipated that these maintenance and Three Mile Island Unit 2 administration functions would continue to be performed during TMI-1 license renewal On March 28, 1979, TMI-2 suffered a period.

severe accident that led to partial melting of the reactor core. Detailed studies of the Independent Spent Fuel Storage radiological consequences of the accident Installation have been conducted by the NRC, the EPA, the Department of Health, Education and AmerGen may construct an Independent Welfare (now Health and Human Services), Spent Fuel Storage Installation (ISFSI) at the Department of Energy, and the State of TMI-1, if a federal facility is not operational, Pennsylvania. Several independent studies to store additional spent fuel through the have also been conducted. Estimates are license renewal term. Construction of the that the average dose to about 2 million ISFSI would need to be completed by 2024.

people in the area was only about 1 millirem. The maximum dose to a person at Military Installations the site boundary would have been less than 100 millirem (NRC 2005). The Defense Distribution Depot Susquehanna, Pennsylvania (DDSP) was In the months following the accident, created in 1991 with the merger of the New thousands of environmental samples of air, Cumberland Army Depot (NCAD) and the water, milk, vegetation, soil, and foodstuffs Defense Logistics Agency (DLA) Defense were collected by various groups monitoring Depot Mechanicsburg. DDSP is the largest the area. Very low levels of radionuclides Department of Defense wholesale could be attributed to releases from the distribution depot in the United States accident. However, comprehensive (Global Security 2005).

investigations and assessments by several well-respected organizations have Comprised of over two thousand concluded that in spite of serious damage to employees, DDSP operates a campus at the reactor, most of the radiation was the Navy Inventory Control Point, contained and that the actual release had Mechanicsburg, and in New Cumberland at the NCAD site. The majority of employees Page 2-36 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.12 KNOWN OR REASONABLY FORESEEABLE PROJECTS IN SITE VICINITY are located at the New Cumberland site. pollutants, 140 facilities that have reported The remaining employees are located at the toxic releases, 926 facilities that have Mechanicsburg site, which is about 7 miles reported hazardous waste activities, and 11 from New Cumberland. The New potentially hazardous waste sites that are Cumberland installation encompasses 851 part of Superfund (USEPA 2006).

acres along the Susquehanna River in New Cumberland, Pennsylvania, about 5 miles Detailed information concerning these south of Harrisburg. Facilities within the facilities may be accessed through EPAs installation include over 200 buildings, 26 Envirofacts Warehouse.

miles of roads, and 18 miles of railroad (Global Security 2005). Electricity Generating Stations in the Vicinity of TMI-1 In its 2005 Base Realignment and Closure recommendations, the Department of York Haven Hydroelectric Station Defense recommended a realignment of DDSP. This recommendation was The York Haven Hydroelectric Station, predicted to result in a maximum loss of 31 completed in 1904, is approximately one jobs in the Harrisburg-Carlisle, PA, mile southwest of TMI-1. It is a low-head, Metropolitan Statistical Area over the 2006- run-of-the-river dam and hydroelectric plant 2011 time period (Global Security 2005). and is located on the Susquehanna River at Conewago Falls, where the river drops 19 EPA-Regulated Facilities in Dauphin, feet in 1/4 mile. The major axis of the 5,000 Lancaster, and York Counties foot diversion dam is north to south and connects to a 3,000 foot headrace which In its Envirofacts Warehouse online heads southeast. The dam and headrace database, EPA identifies permitted are layered out along natural rock dischargers to air, land, and water. A formations in the river. The southeastern search in Dauphin County revealed 137 end is on the western bank at the borough facilities that are permitted to discharge to of York Haven, Pennsylvania and the north the waters of the United States, 208 ends adjoins Three Mile Island. There is facilities that produce and release air another smaller dam (Red Hill) that pollutants, 37 facilities that have reported connects the eastern shore of Three Mile toxic releases, 547 facilities that have Island to the western mainland. The reported hazardous waste activities, and hydroelectric plant is located on the western five potentially hazardous waste sites that shoreline of the river. As discussed in are part of Superfund (USEPA 2006). Section 2.2.3, the plant is equipped with 13 horizontal and 7 vertical generators that A search in Lancaster County revealed produce 19-20 MW of electrical power.

330 facilities that are permitted to discharge York Haven Holdings, Inc., an affiliate of the to the waters of the United States, 317 privately-owned U.S. independent power facilities that produce and release air producer Olympus Power LLC owns the pollutants, 162 facilities that have reported facility.

toxic releases, 1,194 facilities that have reported hazardous waste activities, and Brunner Island Generating Station 16 potentially hazardous waste sites that are part of Superfund (USEPA 2006). Brunner Island is a three-unit, 1,483 MW, coal-fired plant located on the west bank of A search in York County revealed 223 the Susquehanna River in York County, facilities that are permitted to discharge to about 5 miles downstream from Three Mile the waters of the United States, 279 Island (Figure 2.1-2). Brunner Island Unit 1 facilities that produce and release air began commercial operation in 1961; it has Three Mile Island Nuclear Station Unit 1 Page 2-37 License Renewal Application

Environmental Report Section 2.12 KNOWN OR REASONABLY FORESEEABLE PROJECTS IN SITE VICINITY 334 MW of generating capacity. Unit 2, owned and operated by PPL Brunner which began commercial operation in 1965, Island, LLC which is a subsidiary of PPL has 390 MW of generating capacity. Unit 3 Corporation (Pennsylvania Power & Light came on-line in 1969 and has 759 MW of Undated).

generating capacity. Brunner Island is Page 2-38 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.2 TABLES Table 2.2-1. Monthly average, minimum, and maximum T (degrees F) based on automatic temperature sensors at the intake screen pumphouse and at the discharge monitoring pit.

Year Month Average T Minimum T Maximum T 2005 August 11.66 7.50 13.80 2005 September 11.04 2.76 16.46 2005 October 11.16 1.61 16.58 2005 November 5.98 0.78 14.67 2005 December 11.13 4.74 14.02 2006 January 9.47 6.30 10.77 2006 February 9.43 6.35 11.67 2006 March 12.23 5.32 17.04 2006 April 15.86 11.26 30.16 2006 May 16.10 7.13 20.61 2006 June 17.80 8.96 22.68 2006 July 16.59 9.72 21.17 2006 August 16.86 11.99 21.88 2006 September 18.84 10.26 21.56 2006 October 17.10 10.18 21.27 2006 November 16.04 4.83 22.41 2006 December 17.17 5.42 21.71 2007 January 16.88 11.35 20.22 2007 February 17.32 11.01 19.36 2007 March 17.35 9.64 24.37 2007 April 20.55 10.99 28.96 2007 May 21.01 15.97 27.08 2007 June 14.87 8.67 19.17 2007 July 15.01 11.62 18.04 2007 August 13.95 10.08 16.53 2007 September 15.56 8.74 20.95 Source: AmerGen (2007b).

Table 2.2-2. Passage of American shad, walleye, smallmouth bass, and gizzard shad at the York Haven fishway since it became operational in 2000 American Smallmouth Gizzard Year Shad Walleye Bass Shad 2000 4,675 4,581 1,916 79,972 2001 16,200 10,260 3,414 89,272 2002 1,555 14,415 4,403 100,779 2003 2,536 8,132 2,242 113,513 2004 219 1,178 159 84,234 2005 1,772 3,946 832 12,805 2006 1,913 NA NA NA Totals 28,870 42,512 12,966 480,575 Source: Pennsylvania Fish and Boat Commission (Undated).

NA = Not Available Three Mile Island Nuclear Station Unit 1 Page 2-39 License Renewal Application

Environmental Report Section 2.5 TABLES Table 2.5-1. Endangered and Threatened Species that could Occur in the Vicinity of TMI-1 or in Counties Crossed by TMI-1 Transmission Lines.

Scientific Name Common Name Federal Status State Status Mammals Cryptotis parva Least shrew - E Neotoma magister Allegheny woodrat - T Birds Bartramia longicauda Upland sandpiper - T Botaurus lentiginosus American bittern - E Casmerodius alba Great egret - E Cistothorus platensis Sedge wren - E Falco peregrinus Peregrine falcon - E Haliaeetus leucocephalus Bald eagle - T Nyctanassa violacea Yellow-crowned night heron - E Nycticorax nycticorax Black-crowned night heron - E Pandion haliaetus Osprey - T Rallus elegans King rail - E Reptiles Clemmys muhlenbergii Bog turtle T E Opheodrys aestivus Rough green snake - E Pseudemys rubriventris Redbelly turtle - T Fish Ameiurus melas Black bullhead - E Invertebrates Alasmidonta heterodon Dwarf wedgemussel E E Plants Agalinis auriculata Eared false- foxglove - E Ammannia coccinea Scarlet ammannia - E Arethusa bulbosa Swamp-pink - E Aristida purpurascens Arrow-feathered three awned - T Arnica acaulis Leopards-bane - E Asplenium bradleyi Bradleys speenwort - T Boltonia asteroids Aster-like boltonia - E Carex aquatilis Water sedge - T Carex bullatta Bull sedge - E Carex diandra Lesser panicled sedge - T Carex polymorpha Variable sedge - E Carex prairea Prairie sedge - T Carex sterilis Sterile sedge - T Carex tetanica Rigid sedge - T Carex typhina Cattail sedge - E Page 2-40 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.5 TABLES Table 2.5-1. Endangered and Threatened Species that could Occur in the Vicinity of TMI-1 or in Counties Crossed by TMI-1 Transmission Lines (continued)

Scientific Name Common Name Federal Status State Status Cirsium horridulum Horrible thistle - E Cladium mariscoides Twig rush - E Clitoria mariana Butterfly-pea - E Cynanchum laeve Smooth swallow-wort - E Cyperus diandrus Umbrella flatsedge - E Cyperus refractus Reflexed flatsedge - E Cyperus retrorsus Retrorse flatsedge - E Cypripedium reginae Showy ladys-slipper - T Dodecatheon radicatum Jeweled shooting-star - T Eleocharis compressa Flat-stemmed spike-rush - E Eleocharis intermedia Matted spike-rush - T Elephantopus carolinianus Elephants foot - E Ellisia nyctelea Ellisia - T Epilobium strictum Downy willow -herb - E Erigenia bulbosa Harbinger-of-spring - T Euphorbia purpurea Glade spurge - E Festuca paradoxa Cluster fescue - E Fimbristylis annua Annual fimbry - T Gaylussacia dumosa Dwarf huckleberry - E Gymnopogon ambiguus Broad-leaved beardgrass - E Helianthemum bicknellii Bicknells hoary rockrose - E Hypericum densiflorum Bushy Saint Johns-wort - T Ilex opaca American holly - T Iris cristata Crested dwarf iris - E Iris prismatica Slender blue Iris - E Iris verna Dwarf Iris - E Juncus articus var. littoralis Baltic rush - T Juncus brachycephalus Small-headed rush - T Juncus dichotomus Forked rush - E Juncus scirpoides Scirpus-like rush - E Linum intercursum Sandplain wild flax - E Linum sulcatum Grooved yellow flax - E Lipocarpha micrantha Common hemicarpa - E Lobelia kalmii Brook lobelia - E Lobelia puberula Downy lobelia - E Ludwigia polycarpa False loosestrife seedbox - E Lycopodiella appressa Southern bog clubmoss - T Lyonia mariana Stagger-bush - E Three Mile Island Nuclear Station Unit 1 Page 2-41 License Renewal Application

Environmental Report Section 2.5 TABLES Table 2.5-1. Endangered and Threatened Species that could Occur in the Vicinity of TMI-1 or in Counties Crossed by TMI-1 Transmission Lines (continued)

Scientific Name Common Name Federal Status State Status Magnolia tripetala Umbrella magnolia - T Magnolia virginiana Sweet Bay magnolia - T Matelea oblique Oblique milkvine - E Melica nitens Three-flowered melic-grass - T Myriophyllum sibiricum Northern water-milfoil - E Panicum scoparium Velvety panic grass - E Passiflora lutea Passion-flower - E Phemeranthus teretifolius Round-leaved fame flower - T Phlox ovata Mountain phlox - E Phyllanthus caroliniensis Carolina leaf-flower - E Poa paludigena Bog bluegrass - T Polygala cruciata Cross-leaved milkwort - E Polygala incarnata Pink milkwort - E Polygonum setaceum var. Swamp smartweed - E interjectum Potamogeton hillii Hills pondweed - E Potamogeton obtusifolius Blunt-leaved pondweed - E Potamogeton richardsonii Red-head pondweed - T Pycnanthemum torrei Torrys mountain-mint - E Quercus shumardii Shumards oak - E Ranunculus fascicularis Tufted buttercup - E Rhexia mariana Maryland meadow-beauty - E Rhododendron atlanticum Dwarf azalea - E Rhynchospora capillacea Capillary beaked-rush - E Ruellia strepens Limestone petunia - T Scheuchzeria palustris Pod-grass - E Schoenoplectus smithii Smiths bulrush - E Scirpus ancistrochaetus Northeastern bulrush E E Scleria pauciflora Few flowered nutrush - T Scleria verticillata Whorled nutrush - E Sericocarpus linifolius Narrow-leaved - E white-topped Aster Sida hermaphrodita Sida - E Sisyrinchium atlanticum Eastern blue-eyed grass - E Solidago simplex ssp. Randii Sticky golden-rod - E var. racemosa Solidago speciosa var. erecta Slender golden-rod - E Sparganium androcladum Branching bur-reed - E Spiranthes vernalis Spring ladies-tresses - E Page 2-42 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Sections 2.5 and 2.6 TABLES Table 2.5-1. Endangered and Threatened Species that could Occur in the Vicinity of TMI-1 or in Counties Crossed by TMI-1 Transmission Lines (continued)

Scientific Name Common Name Federal Status State Status Sporobolus clandestinus Rough dropseed - E Sporobolus heterolepis Prairie dropseed - E Symphyotrichum Serpentine aster - T depauperatum Thalictrum coriaceum Thick-leaved meadow-rue - E Triphora trianthophora Nodding pogonia - E Vernonia glauca Tawny ironweed - E Viburnum nudum Possum-haw - E Vittaria appalachiana Appalachian gametophyte fern - T Note: E = Endangered; T = Threatened; - = Not listed.

Source: FWS (2006), PNHP (2006) and PNHP (2007).

Table 2.6-1. Residential Distribution of TMI-1 Employees Number of Percent of County of Residence Employees Total Dauphin County, PA 196 37.3%

Lancaster County, PA 176 33.5%

Lebanon County, PA 57 10.9%

York County, PA 41 7.8%

Cumberland County, PA 26 5.0%

Perry County, PA 7 1.3%

Berks County, PA 6 1.1%

Chester County, PA 5 1.0%

Atlantic County, NJ 1 0.2%

Cambria County, PA 1 0.2%

Cobb County, GA 1 0.2%

Dupage County, IL 1 0.2%

Juniata County, PA 1 0.2%

McLean County, IL 1 0.2%

Montgomery County, PA 1 0.2%

Philadelphia County, PA 1 0.2%

Roseau County, MN 1 0.2%

Schuylkill County, PA 1 0.2%

Susquehanna County, PA 1 0.2%

TOTAL 525 100.0%

Source: AmerGen Three Mile Island Nuclear Station Unit 1 Page 2-43 License Renewal Application

Environmental Report Section 2.6 TABLES Table 2.6-2. Decennial Populations and Growth Rates Population and Decennial Growth Rate Dauphin County Lancaster County Pennsylvania Year Number Percent Number Percent Number Percent 1980 232,317 -- 362,346 -- 11,863,895 --

1990 237,813 2.4 422,822 16.7 11,881,643 0.2 2000 251,798 5.9 470,658 11.3 12,281,054 3.4 Note: The Commonwealth of Pennsylvania has not updated county projections using 2000 census data.

Source: USCB (1995) and USCB (2000)

Page 2-44 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Table 2.6-3. Environmental Justice Summary Three Mile Island Nuclear Station Unit 1 Block Groups where the Minority or Low-Income Population is 20% Greater than the State Percentage Number American Native Aggrega 2000 of Indian or Hawaiian or te Population Block Alaskan Other Pacific Other Multi- of Hispanic Low-Income within 50 State County Groups Black Native Asian Islander Race Racial Races* Ethnicity Households Miles Maryland Baltimore 91 0 0 0 0 0 0 0 0 1 129284.4 Maryland Carroll 69 0 0 0 0 0 0 0 0 1 101670.4 License Renewal Application Maryland Cecil 13 0 0 0 0 0 0 0 0 0 15809.2 Maryland Frederick 13 0 0 0 0 0 0 0 0 0 9795.5 Maryland Harford 74 0 0 0 0 0 0 0 0 0 109499.6 Maryland Washington 1 0 0 0 0 0 0 0 0 0 37.6 Pennsylvania Adams 54 0 0 0 0 0 0 0 0 1 91292.0 Pennsylvania Berks 221 1 0 0 0 34 0 42 51 16 289969.9 Pennsylvania Chester 55 10 0 0 0 1 0 9 2 3 76237.4 Pennsylvania Columbia 2 0 0 0 0 0 0 0 0 0 659.7 Pennsylvania Cumberland 137 1 0 0 0 0 0 1 0 5 213674.0 Pennsylvania Dauphin 191 48 0 0 0 1 0 52 6 12 251798.0 Pennsylvania Franklin 36 0 0 0 0 0 0 0 0 0 35529.0 Pennsylvania Juniata 19 0 0 0 0 0 0 0 0 0 20557.0 Pennsylvania Lancaster 317 1 0 0 0 16 0 25 31 11 470658.0 Pennsylvania Lebanon 85 0 0 0 0 0 0 0 5 2 120327.0 Pennsylvania Mifflin 1 0 0 0 0 0 0 0 0 0 347.2 Pennsylvania Northumberland 66 1 0 0 0 0 0 1 0 3 59964.7 Pennsylvania Perry 35 0 0 0 0 0 0 0 0 0 43576.3 Pennsylvania Schuylkill 94 1 0 0 0 0 0 0 0 2 92395.0 Pennsylvania Snyder 29 0 0 0 0 0 0 0 0 0 31646.1 Pennsylvania York 328 15 0 0 0 4 0 25 10 9 381751.0 TOTALS: 1931 78 0 0 0 56 0 155 105 66 2546478.9 Environmental Report Block Groups where the Minority or Low-Income Population is Greater than 50%

Maryland Baltimore 91 0 0 0 0 0 0 1 0 1 Maryland Carroll 69 0 0 0 0 0 0 0 0 0 Maryland Cecil 13 0 0 0 0 0 0 0 0 0 Page 2-45 Maryland Frederick 13 0 0 0 0 0 0 0 0 0 Section 2.6 TABLES Maryland Harford 74 0 0 0 0 0 0 0 0 0

Table 2.6-3. Environmental Justice Summary (continued)

Page 2-46 Environmental Report Number American Native Aggrega 2000 of Indian or Hawaiian or te Population Block Alaskan Other Pacific Other Multi- of Hispanic Low-Income within 50 State County Groups Black Native Asian Islander Race Racial Races* Ethnicity Households Miles Maryland Washington 1 0 0 0 0 0 0 0 0 0 Section 2.6 TABLES Pennsylvania Adams 54 0 0 0 0 0 0 0 0 0 Pennsylvania Berks 221 0 0 0 0 1 0 26 22 5 Pennsylvania Chester 55 8 0 0 0 0 0 9 0 1 Pennsylvania Columbia 2 0 0 0 0 0 0 0 0 0 Pennsylvania Cumberland 137 0 0 0 0 0 0 0 0 1 Pennsylvania Dauphin 191 28 0 0 0 0 0 37 0 3 Pennsylvania Franklin 36 0 0 0 0 0 0 0 0 0 Pennsylvania Juniata 19 0 0 0 0 0 0 0 0 0 Pennsylvania Lancaster 317 0 0 0 0 1 0 15 11 0 Pennsylvania Lebanon 85 0 0 0 0 0 0 0 0 0 Pennsylvania Mifflin 1 0 0 0 0 0 0 0 0 0 Pennsylvania Northumberland 66 0 0 0 0 0 0 0 0 1 Pennsylvania Perry 35 0 0 0 0 0 0 0 0 0 Pennsylvania Schuylkill 94 0 0 0 0 0 0 0 0 0 Pennsylvania Snyder 29 0 0 0 0 0 0 0 0 0 Pennsylvania York 328 2 0 0 0 0 0 13 0 2 TOTALS: 1931 38 0 0 0 2 0 101 33 14 Three Mile Island Nuclear Station Unit 1 State Percentages Number American Native Aggrega of Indian or Hawaiian or te Block Alaskan Other Pacific Other Multi- of Hispanic Low-Income State Groups Black Native Asian Islander Race Racial Races* Ethnicity Households Maryland 27.89 0.29 3.98 0.04 1.80 1.96 35.97 4.30 8.32 Pennsylvania 9.97 0.15 1.79 0.03 1.53 1.16 14.63 3.21 10.99 Note - For the Aggregate Category, the percentage of the Aggregate of Races for the state of Maryland is 35.97. Therefore, more block groups fall in the "Greater than 50%"

License Renewal Application category than "20% greater than the state average" (for Maryland only).

- Shaded areas are counties completely contained within the 50-mile radius of the TMI-1 site.

Source: USCB (2000)

Table 2.7-1. TMI-1 Tax Information 2000-2005 Three Mile Island Nuclear Station Unit 1 TMI-1 Property Percent of TMI-1 Lower Tax Paid to Lower Property Percent of TMI-1 Property Percent of Dauphin Lower Dauphin Dauphin Tax Paid to Dauphin Londonderry Tax Paid to Londonderry School Dauphin School County Tax Dauphin County Township Tax Londonderry Township District Tax School District Year Revenues County Revenues Revenues Township Revenues Revenues District Revenues 2000 58,000,000 $146,940 0.3 4,026,239 $30,000 0.7 13,750,583 $394,500 2.9 License Renewal Application 2000-2001 2001 60,050,000 $146, 940 0.2 4,768,643 $30,000 0.6 14,085,270 $394,500 2.8 2001-2002 2002 60,500,000 $146, 940 0.2 5,093,487 $30,000 0.6 15,836,551 $394,500 2.5 2002-2003 2003 61,500,000 $146, 940 0.2 5,602,437 $30,000 0.5 17,483,255 $394,500 2.3 2003-2004 2004 73,900,000 $146, 940 0.2 6,251,276 $30,000 0.5 18,572,668 $394,500 2.1 2004-2005 2005 89,300,000 $141,630 0.2 6,356,814 $20,972 0.3 20,095,292 $343,000 1.7 2005-2006 (budgeted)

Source: Exelon Environmental Report Page 2-47 Section 2.7 TABLES

Environmental Report Section 2.9 TABLES Table 2.9-1. Major Dauphin County Public Water Suppliers Average Maximum Design Storage Production Production Capacity Capacity Water Supplier (GPD) (GPD) (GPD) (GPD)

Harrisburg Municipal Water Authority 9,000,000 16,100,000 20,000,000 40,000,000 Pennsylvania American Water 6,000,000 8,000,000 9,000,000 8,240,000 Company-Hershey United Water Pennsylvania 11,003,000 12,000,000 15,800,000 8,050,000 GPD = Gallons per day Note: Municipal water suppliers serving populations greater than 10,000.

Source: PADEP (2005)

Table 2.9-2. Major Lancaster County Public Water Suppliers Average Maximum Design Storage Production Production Capacity Capacity Water Supplier (GPD) (GPD) (GPD) (GPD)

City of Lancaster 16,134,000 30,000,000 40,000,000 34,600,000 Columbia Water Company 1,934,238 2,240,000 3,000,000 8,450,000 Elizabethtown Area Water 1,015,000 1,506,000 1,667,000 1,625,000 Ephrata Area Joint Authority 1,763,347 2,762,000 4,096,000 4,873,000 East Hempfield Water Authority 1,500,000 2,370,000 2,854,000 5,380,000 GPD = Gallons per day Note: Municipal water suppliers serving populations greater than 10,000.

Source: PADEP (2005)

Page 2-48 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.9 TABLES Table 2.9-3. Roadway Information (Dauphin and Lancaster Counties)

Annual LOS Data Average (Dauphin Daily Traffic Roadway and Location County) (AADT)

SH-441, just north of Interstate 76 B 7,000 SH-441, south of Interstate 76, near Middletown B 6,900 SH-441, south of Interstate 76, near Royalton B 3,800 SH-441, near northern entrance to TMI-1 site A 3,800 SH-441, between Dauphin County border and intersection with SH-241 N/A 3,600 SH-441, between intersection with SH-241 and intersection with N/A 5,500 SH-743 to 6,000 SH-441, between intersection with SH-743 and intersection with N/A 12,000 SH-772 SH-441, between intersection with SH-772 and intersection with SH-23 N/A 16,000 SH-441, between intersection with SH-23 and intersection with U.S. N/A 17,000 Route 30 SH-441, between intersection with U.S. Route 30 and intersection with N/A 11,000 SH-462 Sources: PENNDOT (2004) and Dauphin County (2005)

LOS - Level of Service N/A - Information not available.

SH - State Highway Note: Locations are approximations derived from PENNDOT traffic count maps.

Three Mile Island Nuclear Station Unit 1 Page 2-49 License Renewal Application

Environmental Report Section 2.11 TABLES Table 2.11-1. Sites Listed in the National Register of Historic Places and Sites Determined Eligible for Listing that fall within a 6-mile Radius of TMI-1 Site Name Location National Register of Historic Places Sites Byers-Muma House 1402 Trout Run Road, East Donegal Lancaster County Donegal Presbyterian Church Complex Donegal Springs Road, East Donegal Lancaster County Kreider Shoe Manufacturing Company 155 South Poplar Street, Elizabethtown Lancaster County BNai Jacob Synagogue Nissley and Water Streets, Middletown Dauphin County Simon Cameron House and Bank 28 and 30 East Main Street, Middletown Dauphin County Henniger Farm Covered Bridge Northeast of Elizabethville Dauphin County Highspire High School 221 Penn Street, Highspire Dauphin County Charles and Joseph Raymond Houses 37 and 38 North Union Street, Middletown Dauphin County Henry Smith Farm 950 Swatara Creek Road, Middletown Dauphin County St. Peters Kierch 31 West High Street, Middletown Dauphin County Star Barn Complex Nissley Drive at PA 283, Lower Swatara Dauphin County Swatara Ferry House 400 Swatara Street, Middletown Dauphin County Michael and Magdealena Bixler Farmstead 400 Mundis Race Road, East Manchester York County Codorus Forge and Furnace Historic District Junction of River Farm and Furnace Roads, Hellam Township, Saginaw York County Goldsboro Historic District Roughly bounded by North, Third, Fraser, and Railroad Streets, Borough of Goldsboro York County Hammersly-Strominger House Northeast of Lewisberry on PA 177, Lewisberry York County Kise Mill Bridge LR 66003 over Bennett Run, Woodside York County Kise Mill Bridge Historic District Address Restricted, York Haven York County Page 2-50 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.11 TABLES Table 2.11-1. Sites Listed in the National Register of Historic Places and Sites Determined Eligible for Listing that fall within a 6-mile Radius of TMI-1 (continued)

Site Name Location Sinking Springs Farms Roughly bounded by Church Road, Sinking Springs Lane, North George Street, Locust Lane, Susquehanna Trail, and PA 238, Manchester York County Sites Determined Eligible for Listing Haldeman Mansion Township Road 839, Bainbridge Township Lancaster County Goldsboro Historic District Borough of Goldsboro, York County Lewisberry Historic District Roughly bounded by Lewis Street, City Unavailable York County Newberrytown Historic District Village of Newberrytown York County Source: USDOI (2006)

Three Mile Island Nuclear Station Unit 1 Page 2-51 License Renewal Application

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Page 2-56 120 Environmental Report Section 2.2 FIGURES 100 80 Temperature (degrees F) 60 40 Three Mile Island Nuclear Station Unit 1 20 0

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MW-TMI-10S .

! .

! Unit 2 MW-TMI-10I ! . OS-14

! Cooling Tower

.

.

!

MW-TMI-10D !.

MS-5

.

!

MS-4

.

!

.

! Main Stormwater Sewage MW-TMI-18D Outfall Treatment MW-TMI-19I

.

!

!

.

Plant MW-TMI-19D MW-TMI-8S

.

!

Main Station Discharge Structure Susquehanna River Unit 2 MW-TMI-9S MW-TMI-9I Cooling Tower  !

.

.

!

South Office MW-TMI-7S Building .

!

Legend Pennsylvania

.

! Monitoring Well Pennsylvania

.

! Supply Well Railroad

_

[ 0 100 200 400 600 800 Feet Secondary Road Three Mile Island Nuclear Station Unit 1 Water License Renewal Environmental Report Figure 2.3-1 Radiological Groundwater Protection Program Monitoring Well Locations Three Mile Island Nuclear Station Unit 1 Page 2-57 License Renewal Application

Environmental Report Section 2.6 FIGURES

Ü Montour Union Luzerne Centre Columbia Carbon a d i us l eR Mi State College -

50 Snyder Northumberland Mifflin ingdon Lehigh Schuylkill Juniata Berks Perry Dauphin Lebanon

• Harrisburg Reading M Cumberland _

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Lancaster Franklin Ph York Lancaster Adams York Su s Chester qu eh a nn aR Pennsylvania i ve r Washington Hagerstown Maryland Cecil Harford Carroll Frederick Baltimore New Castle Frederick Delaware Baltimore Jefferson Baltimore City Kent Howard Montgomery Legend

_

[ Three Mile Island Nuclear Station Unit 1 Pennsylvania Pennsylvania Black Races Minority Water

_

[ 0 5 10 20 30 Miles Urban Area State Boundary Three Mile Island Nuclear Station Unit 1 County Boundary License Renewal Environmental Report Figure 2.6-1 Black Races Minority Populations Page 2-58 Three Mile Island Nuclear Station Unit 1 License Renewal Application

Environmental Report Section 2.6 FIGURES

Ü Montour Union Luzerne Centre Columbia Carbon d i us Ra le Mi State College -

50 Snyder Northumberland Mifflin ingdon Lehigh Schuylkill Juniata Berks Perry Dauphin Lebanon Harrisburg ¿ Reading M

¿ Cumberland _

[

Lancaster Franklin York Ph

¿ Lancaster Adams York¿ Su s Chester qu eh a nn aR Pennsylvania i ve r Washington Hagerstown Maryland Cecil Harford Carroll Frederick Baltimore New Castle Frederick Delaware Baltimore Jefferson Baltimore City Kent Howard Montgomery Legend

_

[ Three Mile Island Nuclear Station Unit 1 Pennsylvania Pennsylvania Other Races Minority Water

_

[ 0 5 10 20 30 Miles Urban Area State Boundary Three Mile Island Nuclear Station Unit 1 County Boundary License Renewal Environmental Report Figure 2.6-2 Other Races Minority Populations Three Mile Island Nuclear Station Unit 1 Page 2-59 License Renewal Application