ML20212D101
| ML20212D101 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 10/22/1997 |
| From: | Cruse C BALTIMORE GAS & ELECTRIC CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9710310001 | |
| Download: ML20212D101 (164) | |
Text
{{#Wiki_filter:, Curuu:s II. Case Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant Nuclear Energy 1650 Calven Cliffs Parkway Lusby, Maryland 20657 410 495-4455 October 22,1997 1 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk l
SUBJECT:
Calvert Cliffs Nuclear Power P! ant l Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 i Request for Review and Approval of System and Commodity Reports for License Renewal
REFERENCES:
(a) Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated August 18,1993, Integrated Plant Assessment Methodology (b) Letter from Mr. D. M. Crutchfield (NRC) to Mr. C. H. Cruse (BGE), dated, April 8,1996, Final Safety Evaluation (FSE) Concerning The Baltimore Gas and Electric Company Report entitled, Integrated Plant Assessment Methodology (c) Letter from Mr. S. C. Flanders (NRC), dated March 4,1997, " Summary of Meeting with Baltimore Gas and Electrb Company (BGE) on BGE Licen;c Renewal Activities" This letter forwards the attached Integrated Plant Assessment (IPA) System and Commodity Reports for review and approval in accordance with 10 CFR Part 54, the license renewal rule. Should we apply for License Renewal, we will reference IPA System and Commodity Reports as meeting the requirements of 10 CFR 54.21(a), " Contents of application-technical information," and the demonstration required by 10 CFR 54.29(a)(1)," Standards for issuance of a rer.ewed license." Tne information in this report is accurate as of the dates of the references listed therein. Per 10 CFR 54.21(b), an amendment or amendments will be submitted that identify any changes to the current licensing basis that materially affect the content of the license renewal application. - , f\D N,,I
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Document Control Desk October 22,1997 Page 2 In Reference (a), Baltimore Gas and Electric Company submitted the IPA Methodology for review and approval. In Reference (b), the Nuclear Regulatory Commission (NRC) concluded that the IPA Methodology if acceptable for meeting 10 CFR 54.21(a)(2) of the license renewal rule, and if implemented, provides icasonable assurance that all structures and components subject to an aging management review purruant to 10 CFR 54.21(a)(1) will be identified. Additionally, the NRC concluded that the methodology provides processes for demonstrating that the effects of aging will be adequately u maged pursuant to 10 CFR 54.21(a)(3) that are conceptually sound and consistent with the intent of the Ib ense renewal rule. In Reference (c), the NRC stated that if the format and content of these reports met the requirements of the template developed by BGE, the NRC could begin the technical review. This report has been produced and fonnatted in accordance with these guidance documents. We look forward to your comments on the reports as they are submitted and your continued cooperation with our license renewal efforts. I _ _ . . . u
Docum:nt Control Desk October 22,1997 Page 3 - Should you have questions regarding this matter, we will be pleased to discuss them with you. Very truly yours,
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STATE OF MARYLAND :
- TO WIT:
COUNTY OF CALVERT : I, Charles H. Cruse, being duly sworn, state that I am Vice President, Nuclear Energy Division, Baltimore Gas and Electric Company (BGE), and that I am duly authorized to execute and file this response on behalf of BGE. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other BGE employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it t be reliable.
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Suhscribed and sworn before me, a Notary P bl'c ig and for the State of Maryland and County of U(LLLLAKL .this d2 day of 64)(qA1997. WITNESS my Hand and Notarial Scal: AuAf > b. 4ttl As Notary Public My Commission Expires: b Date CHC/DLS/ dim Attachments: (1) 3,1 Component Supports (2) 3.2 Fuel Handling Equipment and Other Heavy Load Handling Cranes (3) 5.1 Auxiliary Feedwater System (4) 5.12 Main Steam, Steam Generator Blowdown, Extraction Steam, and Nitrogen and Hydrogen Systems cc: R. S. Fleishman, Esquire H. J. Mil'er, NRC J. E. Silberg, Esquire Resident Inspector, NRC , Director, Project Directorate I-1, NRC R. I. McLean, DNR ' A. W. Dromerick, NRC J. H. Walter, PSC D. L. Solorio, NRC
g: ATTACHMENT (1) 1 I i l APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant October 22,1997
A'ITACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS 3.1 Component Supports This is a section of the Baltimore Gas and Electric Company (BGE) License Renewal Application (LRA), addressing Component Supports. Component Supports have been evaluated as a " commodity" in j accordance with the Calvert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. These sections are prepared independently end will, collectively, comprise the entire BGE LRA. 4 l 3.1.1 Scoping 1 3.1.1.1 Componen t Supports Commodity Scoping Component supports are associated with equipment in almost every plant system. They perform the same basic function, regardless of the system with which they are associated. For this reason, it was determined that . commodity evaluation of component supports would be more efficient to address these supports than evaluating them as part of each system aging management review (AMR). [Re^- nce 1, Page 69] A " component support" is defined as the connection between a system, or component within a system, and a plant structural member (e.g.,the concrete floor or wall, structural beam or column, or ground outside the plant buildings). [ Reference 2, Page 1-2] Supports for structural components are not
" component supports in this sense because any support for a structural component is itself a structural component.
Commodity Descriotion/Concentual Boundaries As discussed in the CCNPP IPA Methodology section on commodity evaluations (Section 7.2), component supports are scoped using a process similar to the scoping process for structures, as follows. A generic list of component support types was developed by reviewing industry and plant-specific information, including Seismic Qualification Utility Group (SQUG) gaidance, American Society of Mechanical Engineers (ASME) Section XI component support inspection documentation, and the CCNPP System Level Scoping Results. All component support types that provide support to plant components that are within the scope of license renewal are identified, and these component support types are listed as being within the scope oflicense renewal. [ Reference 1. Page 69] Systems having component supports addressed in this section are identified in Table 3.1-1. [ Reference 2, Page 3-19] Component supports interface with the components they support in the listed systems, and they interface with the structural component to which they are attached. At this interface, if anchor bolts are used, there is overlap between the AMR for the component support and the AMR for the structural component. The structures AMR considered the effects of aging caused by the surrounding environment, while the component supports AMR considered the effects of aging caused by the supported equipment (thermal expansion, rotating equipment, etc.) as well as the surrounding environment. [ Reference 2, Page 1-3] The evaluation for the aging effects of structures is found in the Structures Commodity Evaluation in Section 3.3 of the BGE LRA. Supports for both the distributive portion: of systems, such as piping and cable raceways, and system s equipment items, are included in the scope of this section. The total population of component supports at : grouped into four categories based on the items they support (piping; cable raceways; heating, Application for License Renewal 3.1-1 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1) oed APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS ventilation and air conditioning [HVAC] ducting; and equipment) and then into 20 component support types. Component support types are based on similarities of physical characteristics, loading condition, and environment. All categories and types are shown in Table 3.1-2. [ Reference 2, Pages 12,1-4, and ' 2-1] Supports for the steam generators (other than snubbers) and reactor vessel are not included in this commodity evaluation but are addressed in Sections 4.1 and 4.2 of the BGE License Renewal Application, respectively. Supports for the spent fuel pool cooling demineralizer and filter vessels are unique and are also addressed separately in Section 5.18 of the BGE LRA. Supports for tubing are included in Section 6.4 of the BGE LRA. Jet impingement barriers and whip restraints that are relied upon in the CCNPP high eneigy line break analysis (Updated Final Safety Analysis Report [UFSAR] Chapter 10A) are evaluated for the effect of aging as part of the structure that houses these components, in Section 3.3. [ Reference 2, Page 1-2] w Basic design basis information for certain supports is discussed in UFSAR Chapters 1 (Principal Architectural and Engineering Criteria for Design), 5 (Containment Structure, Design Criteria), 5A(Structural Design Basis),6 (Engineered Safety Features Design Basis), and 10 (Steam and Power Conversion Systems). Application for License Renewal 3.1-2 Calvert ClitTs Nuclear Power Plant
ATTACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS TABLE 3.1-1 SYSTEMS WITHIN THE SCOPE OF LICENSE RENEWAL CONTAINING SUPPORTS WITHIN THE COMMODITY EVALUATION _, (CCNPP system numbers are shown in parentheses) (002) Electrical 125 Volt DC Distribution (042) Circulating Water (004) Electrical 4 kV Transformers and Busses (044) Condensate (005) Electrical 489 Volt Transformers and (045) Feedwater Busses (046) Extraction Steam l (006) Electrical 480 Volt Motor Control (048) Emergency Safety Features Actuation ! Centers (051) Plant Water (008) Well and Pretreated Water (052) SafetyInjection (011) Service Water Cooling (053) Plant Drains (012) Saltwater Cooling (055) Control Rod Drive Mechanisms and (013) Fire Protection Electrical (015) Component Cooling (CC) (057) Technical Support Center Computer (017) Instrument AC (058) Reactor Protection I (018)VitalInstrument AC (060) Primary Containment (Heating & (0l9) Compressed Air Ventilation) (020) Data Acquisition Computer (061) Containment Spray (023) Diesel Fuel Oil (062) Control Boards (024) Emergency Diesel Generators (064) Reactor Coolant (026) . Annunciation (067) Spent Fuel Pool Cooling (029) Plant Heating (069) Waste Gas (030) HVAC (071) Liquid Waste (032) Auxiliary Building and Radwaste Heating (073) Hydrogen Recombiner and Ventilation System (074) Nitrogen and Hydrogen (036) Auxiliary Feedwater (077/79) Area and Process Radiation Monitoring (037) Demineralized Wr.ter and Condi nsate (078) Nuclear Instrumentation Storage (083) Main Steam (038) Sampling System (Nuclear Steam Supply (097) Lighting and Power Receptacles System) (041) Cbcmical and Volume Control Sconed Structures and Comoonents and Their 1ntended Functions Because the component supports within the scope of license renewal support components that provide functions meeting Q54.4(a)(1),(2), and (3), the supports were determined to have the followin3 i ntended functions, that directly correlate: Provide structural support for systems and components required to remain functional during and following design basis events to ensure the integrity of the reactor coolant pressure boundary, the capability to shut down the reactor and maintain it in a safe shutdown condition, and the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the 10 CFR Part 100 guidelines. I Application for License Renewal 3.1-3 Calvert Cliffs Nuclear Power Plant
ATTACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS e Provide structural support for systems and componei.ts whose failure could prevent satisfactory accomplishment of safety functions for items identified in Part a above. Provide structural support for systems and components that are required for fire protection, environmental qualification, pressurized thermal shock, anticipated transients without scram, and station blackout, if the component is credited in the plant-specific analysis for these events included in the current licensing basis (CLB). [ Reference 2, Page 1-3] ne design loading conditions for component supports include factors such as dead loeds, thermal loads, seismic loads, etc, Supporting information for loading conditions of specific supports is maintained onsite. [ Reference 3, Appendix SA; Reference 4] I Passive Intended Functions / Comoonent Suonort Tvocs Reauiring AMR Because the intended functions listed above are provided without moving parts or without a change in configuration or properties, they are passive intended functions. Therefore, all component supports within the scope oflicense renewal are also subject to AMR [except snubbers, which were excluded as active equipment by l54.21(a)(1)(i)]. [ Reference 1, Pages 39 and 69] However, the snubber subcomponents that mont the snubber to the pipe or component and to the structural component are referred to as snubber supports, and are included within the scope of license renewal. The " snubber i support" includes the subcomponents from the snubber pin connections to the structural component (wall, floor, beam), and from the other snubber pin connection to the pipe c. component being supported. Table 3.1-2 provides the population of component support types requiring AMR. [ Reference 2, Page 12, Table 3-1, Table 3-2] Application for License Renewal 3.1-4 Calvert Cliffs Nuclear Power Plant i
ATTACIIMENT (1i APPENDIX A - TECHNICAL INFORMATION 3,1 - COMPONENT SUPPORTS TABLE 3,1-2 COMPONENT SUPPORT TYPES REQUIRING AN AMR Component Support Group ~ > Associated Systems (see Table 3,1-1 fer system title)- Piping Supports Spring llangers, Constant Load Supports, Sway Struts, Rod llangers, 008,011,012.013,015,019,023,024,029 and Snubber Supports (Note 1) Outside Containment 036, 037, 038, 041, 044, 045, 052, 053, M1 067.083 Spring llangers, Coastant Load Supports, Sway Struts, Rod lisngers, 011,013,019,036,038,041,045,052,061, and Snubber Supports (Note 1) Int ?de Centainment 064,067,074,083 Piping Frames and Stanchions Outside Containment 008,011,012,013,015,019,023,024,029, 036,037,038,041,044,045,046,051,052, 053.061,067,071,074,033 Piping Frames and Stanchions inside Containment 011,013,019,036,037,038,041,045,046, 051,052.061,064.067.071,074,023 Cable Raceway Supports Trapeze, Canulever, and Other Supporting Styles Outside Cables ara evaluated as commodity and not Containment assigned to specific systems, Trapeze, Cantilever, and Other Supporting Styles inside Containment flVAC Ducting Supports
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Rod llanger Trapeze Supports Outside Contrdnment 030 032 Rod llanger Trapeze Supports inside Containment 060 Equipment Supports Elastomer Vibration Isolators ( 030 032 Electrical Cabinet Anchorage Outside Coatainment 002 004 005 006 011 012 017 018 019 020 024 026 030 032 036 038 041 048 052 055 057 058 060 062 064 073 074 077/79 078 097 Electncal Cabinet Anchorage inside Containment 077/079 Equipmetu Frames and Stanchions (Instruments / Batteries) Outside 002 008 011 012 013 015 019 023 Containment 024 029 030 032 036 G38 041 042 044 045 052 060 061 067 069 083 Equipment Frames and Stanchions (Instruments) inside Containment 013 038 041 045
~ 052 064 073 033 Frames and Saddles (Tanks and lleat Exchangers) Outside 011 012 013 015 019 023 024 029 036 Containment 038 041 052 061 064 067 069 083 Frames and Saddles (Tanks and llcat Exchangers) Inside 041 052 064 073 Containment Metal Spring isolators and Fixed Bases Outside Containment 008 011 612 Ola 015 019 023 024 029 032 036 041 044 052 061 067 Metal Spring Isolators and Fixed Bases inside Containment 060 Loss-of-Coolant Accident (LOCA) Restraints 064 Ring Foundations for Flat-Bottom Vertical Tanks 008 023 036 037 052 Note 1: Snubber supports include the hardware from the wall and piping / equipment to the snubber pin connections. The snubber itselfis not subject to AMR.
ApplicatioEfor License Renewal 3.1-5 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1)
. APPENDIX A - TECHNICAL INFORMATION 3,1 - COMPONENT SUPPORTS 3.1.2 Aging Mansgement The potential age-related degradation mechanisms (ARDMs) for component suppcrts are identified in Table 3.13. Those ARDMs identined as plausible for a group of supports are noted by a check mark
(/) in the appropriate column. Those ARDMs that were evaluated, but determined to be not plausible for a particular group of supports, are marked "not plausible." Those ARDMs that were not evaluated for a group of supports, because they are not applicable to the group, are marked N/A [ Reference 2, Table 2-1) For efficiency in presenting the results of these evaluations in this report, component /ARDM combinations were grouped together where there are similar characteristics and the discussion is
- applicable to all components within that group. Exceptions are noted where appropriate. The following seven groups have been selected for component supports. Table 3,1-3 also identifies the group assigned l to each suppor1/ARDM combination.
Group 1 - Pining Supoorts: general corrosion of steel, loading due to hydraulic vibration or water hammer, and loading due to thermal expansion of piping / component Group 2 - Cable Raceway Sunoorts. HVAC Ducting Sunoog Eauioment Sunocrts'. general corrosion ofsteel Group 3 - Elastomer Vibration Isolators: elastomer hardening Group 4 - Metal Spring Isolators and Fived Bases (outside containmentVLOCA Restraints: loading due I to rotating / reciprocating equipraent Group 5 - Frames and Saddles /LOCA Restraints: loading due to hydraulic vibration or water hammer ' Group 6 - Frames and Saddles /Bjng Foundation for Flat-Bottom Vertical Tanks: loading due to thermal expansion of piping / component Group 7 - Frames and Saddles (inside containmentVLOCA . Restraints: stress corrosion cracking of high strength bolts For the component supports AMR, where ARDMs were determined to be plausible, an aging management strategy was selected that involves both methodeto mitigate the effects of the plausible ARDMs and methods to discover their effects. For component supports, discovery methods involve two , separate but complementary sets of activities. The first set of activities consists of baseline walkdowns ' or inspections that are conducted one time to determine whether the plausible ARDMs are actually occurring for the supports potentially affected. The second set of activities involves follow-on actions that occur repetitively. The nature of the follow-on actions is dictated by the results of the baseline inspection or walkdowns. For example, if no evidence is found that the plausible ARDM is occurring during the baseline inspection, the follow-on actions credited may consist of periodic, documented walkdowns by system engineers to ensure that this condition continues. If evidence of significant aging is found for certair. groups during the baseline activities, follow-on actions consist of aging management activities that are formulated to address the condition discovered during the baseline inspection. Baseline and follow-on activities are discussed in more detail under each component support group heading. [ Reference 2, Pages 6-1 through 6-3]
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Application for License Renewal 3.1-6 Calve.rt Cliffs Nuclear Power Plant
ATTACHMENT (1) APPENDIX A - TECIINICAL INFORMATION 3.1 - COMPONENT SUPPORTS { i To serve as an adequate baseline activity, the entire population of supports in a given group does not i ' have to be subject to baselice inspection. If those supports that were not inspected are similar in design, material, and environment to those that went inspected, the conclusion can be reached that an :.dequate baseline was conducted, if loading conditions, environmental conditions, or equipment design differ significantly from the supports that were included in the baseline activity, focused baseline inspections for aging will be conducted to adequately baseline conditions of such supports. [ Reference 2, Page 6-4] I 1 l l i 4 Application for License Renewal 3.1-7 Calvert Cliffs Nuclear Power Plant
ATTACHMENT m
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APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS TA.BLE 3.1-3 POTENTIAL AND PLAUSIBLE ARDMs FOR COMPONENT SUPPORTS i Piping Supports Cable Raceway Supports HVAC Doctng Supports Spnng Hangers, Spnng hangers, Constant Lot 3 Constant Load Piping Frames Piping Frames Trapeze- Trapeze. Rod Hanger, Rod Hanger, Potential ARDMs Supports Sway Cantilever, and Supports. Sway and Stanctuons and Stanchens Cantilever, and Trapeze Supports Trapeze Supports Struts. Rod Hangers Outside inside Other Supportog Struts Rod Hans,ers, Other SW Outssde inside h and Snubber and Snubber Containment Containment DD Outs _ @ Styles Inside Contamment
' upports Outside Supports inside Containment Containment Containment l General Corrosen of y (g) y (9) y (g) y g) y g)
Steet
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Elastorner Hardenmg MA N/A N/A MA MA MA MA N/A Loadtng Due to N/A N/A N/A N/A N/A MA N/A MA j Rotating /
)
Peciprocating ' Machinery Loading : Due to not plausible not plausible MA Hydsaulic Vibration or
/ (1) / (1) N/A N/A N/A Waiar Hammer Losomg Due to not plausible MA Thermal Expansion of
/ (1) . / (1) not plaussble N/A N/A N/A Piping / Component Stress Corrosen not plausible not plausible not plausible not plausible not plausible not plausible not plausible not plausible Cracking of High Strength Bolts Radiaton MA not plausible N/A not plausible N/A not plausible N/A not plausible embnttlement of steel Thermal effects on not plausble not plausible not ptsusbie not plausible not plausible not plausible not pm ne' plausible steel Grout /concre*.e local not plausible not plausible not plausible not plausible not plausible not plausible not plausible not plausible dete ioration ,,
Lead aW creep l not plaussbie not plausible not plausible not plausible not plausible , not plausible not plausbie not plausible
< -Indicates plausible ARDM determination (#) - Indicates the group in which this structures and w...pvimulVARDM comtwnabon is evaluated
- Not plausible for snubbers supports N/A- Not Applicable Application for License Renewal 3.1-8 Calvert CUfTs Nuclear Power Plant
ATTACHMENT (1)
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APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS TABLE 3.1-3 (continued) POTENTIAL AND PLAUSIBLE ARDMs FOR COMPONENT SUPPORTS Equipment Supports Equipment Frames and Frames and Elastomer Elecinca! Electncal Equ W Saddles Saddles Metal Spring Metal Spring i Ring Frames and Potential ARDMs Vbration Cabmet Cabinet ggg Frames and gg g . F2& Wm& h& LOCA lF m isolators Anchorage Anchorage Sta h Heat Heat Fixed Bases Fixed Bases Restracts for Inside Onstr'm Exchangers) Exchangers) Mde Ins W Flath Outside Outs * & Battenes) Containment Containment Containment 3 'Id* Outs de inside Containment Containment Vertical 1 Outsde "* Containment Containment Co.6 - . 44 Tanks General /(2) /(2) / (2) /(2) /(2) /(2) /(2) /(2) /(2) / (2) /(2) Corrosion of Steel , Elastwner / (3) MA NA MA MA N/A NA NA MA MA MA 'l
~ Hardening Loading Due to not plauseie WA N/A MA NA N/A MA /(4) not / (4) MA l Rotating / plausele Recprocating Machmery Loading Due to N/A N/A MA N/A N/A / (5) / (5) MA MA /(5) MA Hydraulic Vibration or Water Hammer Loading Due to N/A N/A N/A MA N/A /(6) /(6) MA MA not /(6)
Thermal plausible Expansion of Piping / Component Stress Corrosion not plausele not plausele not plausele not psausele not plausene not pausele /(7) not plauP*)ie not plauseie /(7) not p>usele Cracking of High Strength Bolts Radiaton N/A NA not plausrble N/A not ple'adele MA not plausete MA not plauseie not N/A embr@ement of plausible steel Thermal effects not plausele not plausele not plausene not plausele not plausele not plauseio not plaust$e not plausele not plausele not not plauseie on steel plausbie Grout / concrete not plausene not plausene not plausoe not plausele not plausele not plauseie not plauseie not plausele not plausele not not plauseie local deterioration plausbie Lead anchor not plauseie not plausele not plausene not plauses not plausele not plausele not plauseie not plauseie not plauseie not not plauseie creep p!ausbie
/-Indicates plausible ARDM determinatson (#)- Indicates the group in which this structures and cuinpuisddARDM i., vie uon is evaluated N/A - Not Applicable Application for License Renewal 3.1-9 Calvert Cliffs Nuclear Power Plant
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_. . _ . _ ~ _ . - _ _ _ . _ . _ ATTACIIMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Group 1 - Piping Supports:- general corrosion of steel, loading due to hydraulic vibration or water hammer, and loading due to thermal expansion of piping / component A wide variety of piping support types are installed in systen.s within the scope of license renewal dependirg on the design requirements of individuai piping, configurations. During the AMR, those piping supports that contain threaded fasteners in their load bearing path were evaluat,;d separately from those without such fasteners because those with fasteners are potentia!!y fatigue-damaged or loosened due to thermal expansion (except sr:ubber cupports) and vibration. Within each of these types, supports inside containment were evaluated separately from those outside since the environment in containment is typically more severe for aging and. provides fewer opportunities for routine discovery of degraded conditions. Tables 3.1-2 and 3.1-3 show the resulting four groups of piping supports. [ Reference 2, Pages 2-1 and 2-2] Piping supp'rts are subject to general corrosion, loadicg due to hydradiic vibration c': water hammer, and loading due to thermal expansion. Although these are different aging mechanisms, with different effects, , they can be discovered in the same manner, i.e., by visual examination. Therefore, piping suppor:s of all types are addressed in this section, and any discussion that applies only to a particular type is noted as such. [ Reference 2, Page 2 6] Group 1 - (Piping Supports - Geners.1 Corrosion of Steel, Loading Due to Hydraulle Vibration or Water Hammer, and Loading Due to Thermal Expansion of Piping / Component) . Materials and Environment Piping supports are constructed of structural steel. Piping supports are located inside the Containment Build,ings and inside other climate-controlled buildings. [ Reference 2, Page 2-1] inside Containment: The maximum design ambient air temperature is 120 F for normal conditions. The design ambient air relative humidity during normal plant operatbn is 50% at 120*F and 14.7 psia. [ Reference 5, Page 19] In the other buildirigs: Ambient temperatures are controlled by plant ventilation systems, as specified in UFSAR Chapte 3 The plant ventilation systems are designed to provide minimum (winter) and maximum (rec.ca building air temperatures, as specified in UFSAR, Table 9-18. Certain areas are maintained by safety-related ventilation systems. The remaining areas are ventilated by non-safety related ventilation systems and are maintained at or below the maximum design te.nperatures.
- There are no design humidity requirements for the plant areas outside containment.
[ Reference 5, Pages 22 and 24] 1 l Application for License Renewal 3.1-10 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Radioactivity Levels: The maximum fluence for component supp" orts 2 at CCNPP, other than perhaps the reactc; vessel supports, is significantly lower than 6 x 10 n/cm . Note that the reactor vessel supports are not included in the Component Siipports Commodity Evaluation. (Based on recent industry reports, significant fluences less thanradiation 6 x 10" n/cm[ .neutron)2) embrittlement degradation will not occur for steels [ Reference 2, Page 210, Note 7] Group 1 - (Piping Supports - General Corrosion of Steel, Loading Due to Hydraulle Vibration or Water Hammer, and Loading Due to Thermal Expansion of Piping / Component) - Aging Mechanism Effects i As shown in Table 3.1-3, general corrosion, loading due to hydraulic vibration or wa:er hammer, and loading due to thermal expansion are the ARDMs considered to be plausible for piping supports. [ Reference 2, Page 2 6] General corrosion is plausible for all piping supports because humidity levels in the plant could result in moisture coming into contact with the structural steel supports. During the plausibility determination, no credit is taken for the protective coating applied to these supports; however, this protective coating plays an important role in the aging management approach for piping supports. [ Reference 2, Page 2-10, Note 1] Loading due to hydraulic vibration or water hammer and thermal expansion is considered plausible for spring hangers, constant load supports, sway struts, and rod hangers because these types of supports have threaded fasteners in the load bearing path that could be loosened by such loading. Piping supports are designed to accommodate a broad range ofloading conditions. However, over time, loading could result in degraded support conditions. [ Reference 2, Pages 2-5 and 2-6] For snubber supports, loading due to thermal expansion was determined to be not plausible because, by design, snubbers do not restrict movement due to thermal expansion. Loading due to hydraulic vibration or water hammer was determined to be plausible for snubber supports because snubbers do restrict these types of movement. [ Reference 2, Page 2-11, Note 13] 5- Piping frames and stanchions are utilized in applications where loadings due to hydraulic vibration or water hammer and thermal expansion are known to exist. These loads occur due to system ope ations and are included in the design of the affected suppons. While these ARDMs are known to occur, the aging effects are not expected to prevent the piping frames from performing their intended support function. However, piping frames are also utilized in applications where hydraulic vibration or water hammer are not normally expected to occur. These loads are generally attributed to som? sort infrequent system transient. Calvert Cliffs' operating experience, with respect to piping frame damage due to water hammer, includes an occurrence, in March 1989, in the Unit 1 Low Pressure Safety injection (LPSI) piping due to a check valve slam transient. Although this water hammer event caused piping frume Application for License Renewal 3.1-11 Calvert Clif fs Nuclear Power Plant
ATTACHMENT (1) APPENDIX A - TECIINICAL INFORMATION 3.1 - COMPONENT SUPPORTS support damage, analysis showed that piping integrity was not compromised. This event is .leseribed in more detail below. [ References 6 and 7] Therefore, while hydraulic vibration or water hammer and thermal expansion have been observed, the aging effects are not expected to prevent the piping frames from performing their intended support function and these ARDMs are considered to be not plausible for this type of support. [lwierence 2, Page 2 6] The effects of general corrosion on piping supports would be a loss of support material and reduction in component support strength if the ARDM were allowed to progress unmanaged. The effects ofloading due to hydraulic vibration, water hammer, and thermal expansion could initially be loosening of bolted or pinned connections, weld crack initiation and growth, component displacement or misalignment concrete daninge, and/or hanger setting drift if these mechanisms were left unmanaged, the effects could progress to the point of reducing the amount of support afforded to the piping and/or allowing excessive motion of the supported piping. This failure of the piping supports' intended function could, in turn, lead to failure of the piping pressure boundary under CLB conditions. [ Reference 2, Pages 2-3,2-54 and 5-4] Operating experience, with respect to water hammer events at CCNPP that have caused damage to piping i supports, includes the following: l e On May 13,1975, the Unit I reactor tripped on loss of main feedwater. Approximately 40 minutes after the trip, three water hammers were experienced h the feedwater piping as main feedwater was being re-established to the steam generators. [ Reference 8] e On May 19,1976, a preoperational test was performed on Unit 2 to determine the effectiveness of the addition of standpipes to the new main feedring. With the reactor in Mode 3, steam generator level was decreased via the blowdown system. Thirteen minutes after securing blowdown, feedwater was introduced into the steam generator at 5% of rated flow via the main feedring. As the water level reached the feedring, water hammer occurred. [ Reference 8] e On March 17,1989, while performing a test on a containment spray pump, a bent vertical support on the shutdown cooling portion of the LPSI suction piping was identified. The support damage was determined to be a result of piping loads due to water hammer. The root cause of the water hammer was traced to check valve slam of one of the LPSI pump discharge check valves. [ References 6 and 7] A review of the 1975 and 1976 events indicated that water hammer could occur following the initiation of Mam Fexdwater System flow when the steam generator level is below the feedring following a loss of main feedwater flow. In late 1978 for Unit 2 and mid-1979 for Unit 1, the steam generators were modified by installing non-reducing J tubes on the top of the feedrings and covering the bottom exit nozzl,:.;. This reducci the possibility of a feedwater watec hammer event by extending the period of time required for the feedring to drain once it is uncovered. In addition, operating procedures were changed to reduce the potential for water hammer. [ References 8 and 9] For the 1989 check valve slam water hammer event, corrective actions included establishment of a check valve siam evaluation prefect. The check valve slam project identified the LPSI System and the I CC System as the systems most susceptible to check valve slam transients based on similarities in system k Application for License Renewal 3.1-12 Calvert Cliffs Nuclear Power Plant
ATTACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS conGguration and system operating ~ experience. Testing to determine traasient pressure loads and detailed structural modeling and analysis of the LPSI and CC piping systems was performed to determine the adequacy of the supports and the piping. His analysis concluded that transient loads may exceed the support capacity for a number of supports since the original design did not account for check valve slam. The 22 most limiting supports (12 LPSI supports and 10 CC supports) were identi0ed and subjectea to extensive testing. From this sample, three Unit i LPSI supports and one Unit 2 LPSI support were determined to have damage attributable to check valve slam. No damage attributable to check valve slam was found on the CC System supports. Corrective actions for the affected supports { included design analysis of piping stresses, to determine sy> tem operability, and an evaluation to determine the appropriate repairs and modincations to the affected pipe supports. The results of the l J piping stress analysis showed that piping integrity was not compromised. Design actions to address damage caused by water hammer included strengthening of these supports to withstand the re-evaluated ' l forces from water hammer. [ References 6 and 7] ! In summary, CCNPP operating experience with respect to water hammer is that it has occurred in the past and these events have been evaluated as appropriate. Design modiGeations were made and operating procedures were changed to reduce the potential for water hammer or damage due to water hammer in the future. Group 1 -(Pipir.g Supports - General Corrosion of Steel, Loading Due to Ilydraulie Vibration or Water Hammer, and Loading Due to Thermal Expansion of Piping / Component) - Methods to Manage Aging Effects Mitination-To mitigate the effects of general corrosion, the conditions on the external surfaces of the component support must te controlled. Significant rates of corrosion only occurs when the component support comes in contact with moisture. Preventing direct and prolonged contact between metal surfaces and moisture is an effective mitigation technique for general cor osion. Therefore, to mitigate general corrosion, protective coatings ensure that the external metal surfaces of the component supports are not in contact with a moist, aggressive environment for extended periods of time. In addition, plant housekeeping practices that identify conditions such as degraded paint can be used to mitigate the effects of general corrosion. [ Reference 2, Page 2-10, Note 1] The effects of loading due to h. 'raulic vibration and thermal expansion have been minimized through proper support design. The etTects of loading due to hydraulic vibration r.nd water hammer are minimized through proper system operation. Loading due to hydraulic vibration or water hammer is only a concern due to the potential for off-normal operation and transients. Therefore, no additional specific measures to mitigate these ARDMs are needed.
- Discoverv: t, The effects of general corrosion are detectable by visual inspection. The external metal surfaces of the component supports are covered by a protective coating, and observing that signincant degradation has not occurred to this coating is an effective method to ensure that corrosion has not affected the intended function of the component support. Coatings degrade slowly over time, allowing visual detection during normal operations. Since the coating does not contribute to the intended function of the supports, Application for License Renewal 3.1-13 Calvert Cliffs Nuclear Power Plant
ATTAC21 MENT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS observing the coating for degradation provides an alert condition that triggers conective action prior to degradation that affects the support's ability to perform its intended function. The degradation of the protective coating or any actual corrosion that does occur can be discovered and monitered by periodically inspecting the supports and by carrying out corrective action as necessary. The effects ofloading due to hydraulle vibration, water hammer, and thermal expansion are detectable by visual observation of external conditions. The effects of excessive loading from hydraulic vibration, water hammer, and thermal expansion are observable in the form of loosening of bolted or pinned connections, weld crack initiation and growth, component displacement or misalignment, concrete damage, and hanger setting drift. Rese conditions would be readily observable during a visual inspection. (Reference 2, Page 5-4] Therefore, adequate discovery techniques for component support aging need to include both a visual observation of the general condition of the protective coating of the supports, and examination for loose i parts, loosened fasteners, deteriorated welds, componem displacement or misalignment, concrete
- damage, and hanger setting drift.
1 Group 1 - (Piping Supports - General Corrosion of Steel, Loading Due to Hydraulic Vibration or Water Hammer, and Loading Due to Thermal Expansion of Piping / Component) - Aging Management Program (s) Mitigation: The external metal surfaces of the component supports are covered by a protective coatin5 that mitigates the effects of general corrosion. He discovery programs discussed below ensure that the protective coatings of component supports are maintained. Discoverv: For discovery, the level of aging management activity needed for each category of component supports is determined based on the condition observed during a baseline walkdown of a representative sample of supports of each category. Herefore, discovery activities are discussed in two categories, baseline activities and follow-on aging management activities. The as-found condition during the baseline walkdown dictates the level of follow-on aging management needed for the support type. [ Reference 2,- Pages 6-1 through 6-5] The CCNPP Inservice Inspection (ISI) Program is based on References 3, and 10 through 15. Calvert Cliffs Technical Specification Surveillance Requirement 4.0.5.a requires that ISI of ASME Code Cisss 1, 2, and 3 components be performed in accordance with Section XI of the ASME Code. The CCNPP ISI Program Plan describes the inspections performed to satisfy these requirements. Requirements are provided for parts to be examined, examination frequency, methods, acceptance standards, and additional examinations. [ Reference 2, Page 5-1] Component support examinations are performed in accordance with a CCNPP procedare that fulfills the requirements of Section XI. The result of each inspection is documented in an outage report. (Reference 2, Page 5-3] Application for License Renewal ' 3.1-14 Calvert Cliffs Nuclear Power Plant
4 ATTACHMFNT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS ne ASME Section XI Isis for component suppoits include a visual examination of a prescribed sampling of the systems covered by this program. The visual examination contains the following elements that would detect the effects of aging related degradation in a timely manner: [ Reference 2, Page 5-2] e A visual examination to determina the general mechanical and structural condition of the support; and A check for loose parts, debris, abnormal corrosion products, wear, erosion, corrosion, and loss of integrity of bolted or welded connections. The ASME Section XI ISI examination methods include the following elements, which are performed during the visual examination, that ensure that excessive loading, regardless of its cause, is discovered in j a timely manner: (Reference 2, Page 5-2]
- Measurement of clearances; e Detection of physical displacement; e
Structural adequacy of supporting elements; Connections between load-carrying structural members; .md I
- Tightne::s of bolting.
American Society of Mechanical Engineers Section XI ISI requires inspections of piping supports at periodic intervals such that all piping supports of code class systems are inspected on a sampling basis once per inspection interval. Inspection intervals are established based on the requirements of an established industry code (i.e., ASME Section XI). He current inspection interval for CCNPP is 10 years. [ Reference 2, Page 5 3] The CCNPP ISI Program is adequate to manage the effects of aging in component supports within the program scope for the following reasons: [ Reference 2, Pages 5-3,5-4, and 5-5] The examination procedure requires that the component supports be checked for the etTects of the following potential ARDMs: general corrosion of steel, and vibration or thermal expansion cycles (loosening of bolted or pinned connections, weld crack initiation and growth, component displacement or misalignment, concrete damage, and hanger setting drin), e Inspections performed to date have identified deficiencies like those associated with aging degradation. The program requires that each support within the ISI Program be inspected at regular intervals; as evidenced by the relatively small number of support deficiencies found to date, it appears that the inspection interval (10 years) is adequate for detecting degradation. The program requires expansion of the inspection secpe in the event that degradation of component supports is observed; this reduces the I;kelihood that widespread degradation is occurring without being noticed in other supports in the affected system or other systems with like supports, e The outage reports prepared aner each inspection period provide historical information for supports. Application for License Renewal 3.1-15 Calvert Cliffs Nuclear Power Plant l l t
ATTACHMENT m APPENDIX A - TECFINICAL INFORMATION 3.1 - COMPONENT SUPPORTS De ISI Program is subject to internal assessment activity both within the Materials Engineering and Inspection Unit and through the Site Performance Assessment Group. The ISI Program is recognized through these assessments as performing highly effective examinations and aggressively pursuing continuous improvements through monitoring industry initiatives and trends in the area of non-destructive examination. Additionally, the program is subject to frequent external assessments by the NRC, authorized Nuclear Inservice Inspector, and others. Operating experience relative to the CCNPP ISI Program has been such that no site-specific problems or events have occurred that required changes or adjustments to the program. Changes that may have been made over the program's history have been in response to developments by the NRC or within the industry. Specifically for component supports, operating experience relative to the ISI Program has revealed that it is effective in discovering age-related debradation and/or other conditions that, if unmar. aged, could potentially compromise the intended function of the affxted supports. For example, during the 1995 Unit 2 spring refueling outage,428 components and their supports were examined. The ISI visual examinations revealed 13 supports with inservice or construction / installation deficiencies that included: l 9 supports with missing or loosened fasteners; I support with improper clearance; and 3 supports with missing sight holes on sway struts. During the 1996 Unit I spring refueling outage,491 components and their supports were examined. The ISI visual etaminations revealed 16 supports with inservice or construction / installation deficiencies that included: 4 supports with missing or loosened items; I support with improper spring settings; I support with improper clearance; I support with a cracked weld; 2 supports with a missing sight hole; I support with a misaligned sauboer; and 6 supports where the as-found condition did not agree with the component support sketch. Deficiencies found during the ISI visual examinations were either accepted by evaluation or repaired / replaced ta bring them into conformance with their original design. [ References 16 and 17] Brseline Walkdowns Table 3.1-2 shows there are 25 systems within the scope of license renewal that contain piping supports. The aging management approach for the piping supports in these systems included a baseline walkdown to establish if there are active ARDMs within each system. [ Reference 2, Table 3-1] Twelve of the systems within the scope oflicense renewal that contain piping supports are subject to ASME Section XI Isis. Completed ISI activities serve as an adequate baseline activity to document the condition of pipin;; supports for these 12 systems within the scope of license renewal that contain piping supports. [ Reference 2, Table 3-1] The ISIS occasionally find loose bolts in hangers, which indicates that ARDMs of loading due to hyuraulic vibration or due to thermal expansion are active in some systems. [ Reference 2, Pages 6-6 and 6-7] In the event that degradation of component supports is observed, the ISI Program requires that the deficiency be corrected and that additional supports be inspected. [ Reference 2, Pages 5-3,5-4, and 5 5] Application for License Renewal 3.1-16 Calvert Cliffs Nuclear Power Plant
ATTACHMENT m APPENDIX A - TECHNICAL INFGAMATION 3.1 - COMPONENT SUPPORTS Thirteen of the systems within the scope oflicense renewal that contain piping supports are not subject to ASME Section XI Isis. [ Reference 2, Table 3-1] Therefore, additional sampling baseline walkdowns l will be performed. [ Reference 2 Page 6-6] nese systems are: Well and Pretreated Water Plant lie 6g l Fire Protection Demineralized Water and Condensate Storage Compressed Air Nuclear Steam Supply System Sampling System Diesel Fuel Oil Condensate System Extraction Steam Liquid Waste Plant Water Nitrogen and Hydrogen Plant Drains These walkdowns will consist of a sampling of the supports within the scope of license renewal for the 13 systems. The sample approach will be comparable to the approach required by ASME Section XI for piping supports of ASME Class 3 systems. The walkdown scope will include inspection on a sampling basis for corrosion and loose bolts, and will be documented using means such as field notes and photographs. Dese walkdowns will document the condition of the piping supports within the scope of license renewal for all piping support types except piping frames outside containment. If an active corrosion mechanism is found during the additional sampling baseline walkdowns for pipe hangers outside containment, then the inspection scope for that system would be expanded to piping frame supports outside containment. Once these additional walkdowns are completed, an adequate baseline condition assessment will have been completed. [ Reference 2, Pages 6-6 and 6-7] Ahhough there is nuclear industry experience with respect to loose piping support concrete expansion ) anchor bolts (e.g., NRC Inspection and Enforcement [lE] Bulletin 79-02), additional baseline inspections specifically for anchor bolts are not considered necessary. The existing baseline activities are considered adequate and, as described below, failure of concrete expansien anchors is more of a design / installation issue rather than an aging issue. To support the SQUG effort in the mid-1980s, the Electric Power Research Institute (EPRI) sponsored a research program to develop procedures and guidelines to demonstrate the adequacy of equipment anchorages for older nuclear plants. This work is documented in EPRI report NP-5223-SL, Revision 1. Electric Power Research Institute report NP-5228-SL documents the compilation and analysis of extensive test data available on concrete expansion anchors. The report identifies three types of failure mechanisms associated with tension failures of concrete expansion anchors: (1) concrete cone failure, (2) anchor tension failure, and (3) anchor s!ip. These mechanisms are discussed as follows: Concrete Cone Failure - Concrete expansion anchors with deep embedment depth, adequate spacing between anchors, and adequate distance between the anchor and a free concrete edge do not exhibit this failure mode. Anchor Tension Failure - Anchor tension failure occurs when the tensile load exceeds the ultimate tensile strength of the anchor material prior to a concrete cone failure or the anchor slipping out of the hole. Anrnor Slip - Anchor slip failures occur when the lateral pressure that the anchor exerts on the sidee of the drilled hole crushes the concrete and opens the ring or sleeve sufficiently to allow the Application for License Renewal 3.1-17 Calvert Cliffs Nuclear Power Plant
ATTACHMFXT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS end of the cone expander to slip through the ring or sleeve. Note that concrete strength (which increases with time as a function of shrinkage, and according to American Concrete Institute standard 209R-82,91% of the shrinkage occurs during the Orst year,98% in 5 years, and 100% in 20 years) is an important consideration in the 'IPRl/SQUG guidelines for assessing anchorage , adequacy. Concrete expansion snchors fail under shear loadings either by a shear failure of the anche ooit material or formation of a crack in the concrete. All of these failure mechanisms are associated with the quality, including design, of the initial installation and/or the size of the load on the anchor. None of the failure modes is expected to be a!Tected by age-related effects, such as anchor bolt relaxation or concrete shrinkage because: Dolt preload in the anchor is not counted on for anchor function. Once an anchor is " set" by torque, anchor function is maintained by the irreversible expansion of the anchor expansion ring or cone into the concrete. l
- Anchor expansion into the concrete results in considerably larger displacements than would be expected for any credible concrete shrinkage, even over a long period of time.
e Loss of preload due to relaxation of the steel parts of the anchor is not expected at ambient temperatures. Based on the above, the follow-on activities described below are deemed adequate to ensure that the anchor bolts will continue to perform their structural support function under CLB conditions during the period of extended operation. An Age Related Degradation inspection (ARDI) Program, as described in the BGE IPA Methodology, will be implemented to address 24 specific inaccessible piping supports outside containment. These supports cannot rely on walkdowns for ongoiag aging management for the effects of general corrosion, loading due to hydraulic vibration, or loading due to thermal expansion. These supports are included in the ARDI Program for inaccessible structural steel. Development of the ARDI Program includes the following steps: [ Reference 2, Pages 6-6 and 6-7; Reference 18]
- Identification of inaccessible structural steel locations; l e
Selection of representative components for inspection; e Development of an inspection sample size; e Selection of appropriate inspection techniques; and Development of requirements for reporting results and corrective actions if aging concerns are identified. The inaccessible piping supports discussed above were originally identified as being inaccessible as part of the activities associated with NRC 111 Bulletin 79-14 as described in a BGE letter to the NRC dated October 19, 1984. [ Reference 18]. The letter stated that there were 24 piping supports outside containment inaccessible for inspection and testing, and p.ovided information as to the location of those supports. One of the 24 supports identified in the letter, associated with the Unit 2 Service Water Application fne License Renewal 3.1-18 Calvert Cliffs 1:uclear Power Plant
. - . - .= - - - _ _ -.
ATTACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT St'.PPORTS . System, has been abandoned in place and replaced functionally with an accessible support. The abandoned suppor: is located inside a concrete wall, the replacement support is located outside of that wall. Additionally, the letter stated that there were seven inaccessible supports located undenvater in the Unit 1 Spent Fuel Pool. De current as-built design reflects that 11... are actually 11 inaccessible supports located underwater in the Unit 1 Spent Fuel Pool. However, there is a piping modification i planned that will reduce this number to eight. Upon completion of this modification, there will be a total of 24 inaccessible supports, as originally reported. i These supports are 'naccessible either because they are located underwater (in spent fuel pools or refueling water storage tanks), or because they are located in high radiation areas. It may not b . possible to perform a visual walkdown of these supports, as was concluded by the IE Bulletin 79-14 efforts. However, other inspection techniques (e.g., remote video) may be recommended under the ARDI Program if they are vieble. The ARDI Program will specifically eithei sample some of these supports (possibly using the remote inspection techniques), sample other accessible supports that are similar in design / environment, or will provide an analysis that will document why any inspection is not required. The ARDI Program will ensure that age-related degradation is managed such that inaccessible
- component supports will be capable of performing their intended functions under all CLB conditions.
Fol ow-on Activities Based on the results of baseline inspections completed per the existing ISI Program requirements, it was determined that continuing ASME Section XI ISIS into the period of extended operations will also sene as an adequate follow-on activity for those piping systems subject to that program. [ Reference 2, Page 5-4] For piping supports not covered by ISI requirements, the results of the additional baseline walkdowns
- described above will determine the extent of aging management practices needed for these supports. If the baseline v'alkdowns reveal no significant effects of aging from generul corrosion, loading due to hydraulic vibration or water hammer, or loading due to thermal expansion, then the follow-on activities for aging management of these piping supports will be by system engineer walkdowns, CCNPP Administrative procedure," Control of Shift Activities,"(NO-1-200), and " Ownership of Plant Operating Spaces" Program (NO-l 107), discussed below. [ Reference 2, Pages 4-2 and 6-6]
Calvert Cliffs Plant Engineering Guideline (PEG)-7, " System Walkdowns," provides for discovery of the
. effects of component supports ARDMs by providing for visual inspection of component supports during .
i system walkdowns, reporting the walkdown results, and initiating corrective action. The program applies to mechanical and electrical systems; and includes visual inspections of mechanical, electrical, and instrumentation components, within each respective system. Under this program, inspection items typically re!ated to aging management include identifying poor housekeeping conditions (such as ! degraded paint), and identifying system and equipment stress or abuse (such as thermal insulation damage, bent or damaged hangers, etc.). Excessive vibration, unusual noise, and excessive temperatures are some other symptoms of potential equipment stress that are considered. Conditions identified as adverse to quality are documented on issue Reports in accordance with procedure QL-2-100, " Issue ) Reporting and Assessment." [ Reference 19] l Application for License Renewal 3.1-19 Calvert Cliffs Nucl[ar Power Plant
ATTACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Under PEG 7, the system engineer performs periodic walkdowns; walkdowns before, during, and after outages; and walkdowns related to a specific plant modification (s). [Referenes 19, Section 5.0] These walkdowns have the following general characteristics: e Walkdowns are conducted at periodic intervals, as set by the PEG, based on system performance, operating conditions, etc. Walkdowns are performed by the assigned system engineer, who is familiar with the system and its condition. Signs of corrosion or effects of excessive loading would be detected by this individual. Conditions adverse to functionality, indications of system or equipment stress or abuse, safety or fire hazards, and housekeeping deficiencies are documented and an issue Report is generated as required. Specifically for piping supports, PEG-7 contains the following characteristics:
- Plant Engineering Guideline-7 contains a mechanical system walkdown checklist that contains items related to the condition of piping supports (in addition to other components, such as valves and pumps), on which to document adverse conditions observed during the walkdown.
A CCNPP Engineering Standard, ES-002," Pipe Support Inspections," has been prepared to detail
- acceptable and unacceptable conditions of piping supports. Excerpts from this standard are included in the system walkdown guideline as an attachment to PEG-7. [ References 19 and 20]
e Plant Engineering Guideline-7 requires that any unusual condition observed during the system engineer's walkdown of piping supports be recorded on the walkdown sheet and assistance obtained from design engineering in evaluating the impact of the unusual condition. Conditions that warrant further action are documented on an issue report and the site corrective action program tracks the status of corrective actions. [ Reference 19] Plant Engineering Guideline-7 promotes familiarity with the systems by the system engineers and provides extended attention to plant material condition beyond that aiTorded by Operations and Maintenance alone. As a result of experience gained, PEG-7 has been improved over time to provide guidance regarding specific standard activities that should be included in walkdowms. The Control of Shift Activities and Ownership of Plant Operating : paces Programs ensure that aggressive conditions, such as pooled water, are not allowed to remain for extended time periods. [ References 21 and 22] Calvert Cliffs procedure NO-1-200 (based on References 3,10, and 23 through 35) ensures that shift operations are conducted in a safe and reliable manner and within the scope of the operator's license, procedures, and applicable regulatory requirements. During normal operation, NO-1-200 uirects plant operators to inspect operating spaces each shift and to report any deficiency. When shutdowm, the conta.'nment is also inspected. The procedure lists detailed inspection guidelines, including discovery of items such as oil / water leakage, irregular noise and vibration levels, irregular temperature, and humidity for the area, etc. [ Reference 21, Section 5.8.B] Site deficiencies are documented in accordance with QL-2-100 issue reporting and assessment procedure to ensure appropriate corrective action is taken. . Operator rounds have been historically effective in identifying plant deficiencies. The documented Application for License Renewal 3.140 Calvert Cliffs Nuclear Power Plant
A*ITACllMEN'r i1) APPENDIX A TECHNICAL INFORMATION i 3.1 COMPONENT SUPPORTS guidance and expectations have been impr9ved over the years as a result of lessons learned and the site
; emphasis on continual quality improvement.
l Calvert Cliffs procedure NO l.107 (based on Reference 36) provideo requirements and guidance on personnel accountability for the correction of housekeeping, material and radiological deficiencies. This
) procedure assigns plant areas to an " owner." These owners are identified within each space and provide i ; a point of contact for any individual who finds deficiencies or any concem with the space. Owners are , required to periodically inspect their space for deficicacies defined in the procedure, including checking for leaks; loose or unbrscketed pipes; loose, stripped, or missing fasteners; and corrosion, rust, or inadequate paint. Spaces subject to inspection include areas such as Containment, Turbine Hullding, < Auxiliary Building, intake Structure and outside areas. [ Reference 22) The Ownershlp of Plant Operating Spaces Program is relatively new and no major changes to this program have been necessary to this point. Siti 'Wiencies are documented in accordance with QL 2100 to ensure appropriate , corrective action is %n. [ Reference 22, Section 5.2]
Official assessnents of programs such as these that contribute to the plant's " housekeeping" (including NRC comments) have been historic 4lly noted as effective in identifying deficiencies in plant areas. [ Reference 37] e a For snubber supports, the Snubber Visual Inspection Surveillances are credited as an additional follow-on aging management activity. Although the snubbers, themselves, are determined to be active i components in the License Renewal Pule, the snubber supports that connect the smtbber to the pipe / component and to the structural member are considere.1 passive. Plant Technical Specifications i' require periodic surveillance of snubbers to ensure functionality. The periodicity b Sased on past results and is in accordar.cc with a table in th< Technical Specifications. Many of the steps of this surveillance address the functionality of the active snubber and are not credited as aging management activities in the co text of the License Renewal Rule. Ilowever, several steps of the surveillance also addreas the passive . snubber supports. The surveillance requires the following:
- Verification that snubber installation exhibits no signs of detachment from foundation or supporting structures, including clamps, welds, concrete anchor bolts, and general condition of concrete; and
- Verify that the pipe clamp / rod eye bracket is in satisfactory condition and that the snubber is aligned properly.
Any abnormal condlNn discovered during this sun cillance must be reported and resolved in accordance
- with the site issu: eporting and corrective action process. [ Reference 2. Pages 12, S 4, and 5 5; and References 38 thrwch 41] The snubber suncillances have been effective in performing visual inspections of snubbers, and changes to the approach to performing these surveillances have not been necessary.
i Application for License Renewal 3.1 21 Calvert Cliffs Nuclear Power Plant
NITACilMENT (1) APPENDIX A . TECHNICAL INFORMATION 3.1 COMPONENT SUPPORTS Group 1 (Piping Supports . General Corrosion of Steel, Loading 1)ue to liydraulic Vibration d Watn llammer, and Loading Due to Thermal Espansion of Piping / Component) . Demonstration of Aging Management Based on the information presented above, the fallowing conclusions can be reached with respect to general corrosion of steel, lotibg due to hydraulic vibration or water hammer, and loading due to thermal expansion of piping / component for piping supports. e piping supports associated with piping within the scope of license renewal are themselves considered to be within the scope of license renewal because failure of these suppris could lead to failure of the supported component. General corrosion, loading due to hydraulic vibration er water hammer, and loading due to thermal expansion were determined to be plausible ARDMs for piping supports. The effects of there ARDMs are loss of support material, reduction of component support strength, loosening of bolted or pinned connections, weld crack initiation and growth, component displacement or misalignment, concrete damage, and hanger setting drin. These effects, if len unmanaged, could lead to loss of the intended function of the piping supports and ultimately to failure of the supported piping under CLB conditions. General corrosion is mitigated by applying coatings to component supports, periodically examining the supports for degradation of that coating or conditions that could aceelerate degradation, and by maintaining the coatings, e Baseline discovery programs include elements that would enable these activities to discover the effect of all plausible aging mechanisms (including degradation of coatings that prevent specific ARDMs) and to determine the appropriate level of follow on aging management activitle:. Follow-on discovery activities include Isis, system engineer walkdowns, the control of shin activities, the ownership of plant operating spaces, Snubber Surveillance inspectiens, and the ARDI sampling inspections. These activities include elements that would ensurt discovery of the effects of all plausible aging mechanisms (including degradation of coatings that prevent specific ARDMs) and require corrective action and actions to prevent recurrence of problem conditions as appropriate. Piping supports within the scope of license renewal a e subject to follow on discovery activities. The discovery aging mansgement activities (Isis, additional baseline walkdowns of selected piping systems, system engineer walkdowns, control of shin activities, ownership of plant operating spaces, snubber surveillances, and the ARDI Program) detect ad correct any adverse effects of g(aral corrosion, loading due to hydraulic vibration or water hammer, and loading due to thermal expansion. Th:refore, there is reasonable assurance that the effects of aging will be adequately managed such that the piping supports will be capable of performing their structural support function consistent with the CLB during the period of extended operation.
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Application for License Renewal 3.1 22 Calvert Clifts Nuclear Power Plant
ATTACHMFNT (H APPENDIX A TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Group 2 Cable Raceway Supports, HVAC Ducting Supports, and Equipment Supportet general corrosion of steel Group 2 includes all 15 cor.iponent support types within the 3 component support groupe cable raceway supports, llVAC ducting supports, and equipment supports. These type of supports are all subject to age related degradation due to general corrosion. iiroup 2 -(Cable Raceway Supports, HVAC D(eting Supports, and Equipment Supports - General Corrosion of Steel)- Materials and Environment Cable raceway supports, ilVAC ducting supports, arid equipment supports are constructed of structural l steel and are located inside the Containment Buildings and other climate controlled buildings (except for some ring foundations for flat bottom vertical tanks, as described below). Environmental conditions inside the plant for cable raceway supports, ilVAC ducting supports, and equipment supports, are identical to those described above, for " Piping Supports." Ring foundations for flat bottom vertical tr.nks are concrete and are located both inside climate-controlled buildings and outdoors. Environmental conditions for ring foundations inside climate-controlled buildings are identical to those described above, for " Piping Support." Ring foundations that may be outdoors are subject to changing atmospheric conditions. The site and environment of CCNPP are described in Chapter 2 of the UFSAR. Group 2 - (Cable Raceway Supports, HVAC Ducting Supports, and Equipment Supports - General Corrosion of Steel)- Aging Mechanism Effects as shown on Table 3.13, general corrosion of steel is an ARDM considered to be plausible for cable raceway supports, ilVAC ducting supports and equipment supports (Group 2). General corrosion of steel is plausible for Group 2 supports because humidity levels in the plant could result in moisture coming in contact with the suppoit members. During the plausibility determination, no credit is taken for the protective coating applied to these supports; however, this protective coating plays an important role in the aging management approach for component supports. General corrosion is considered to be plausible for Group 2 supports both inside and outside containment. [ Reference 2, Page 2 7 and Reference 2, Dage 210, Note 1) The effects of general corrosion on Group 2 supports would be a loss of support material and reduction in component support rtrength if the ARDM .,ere allowed to progress unmanaged. If these mechanisms were left unmanaged, the effects could progress to the point ofinsufficient support being afforded to the component and/or allowing excessive motion of the supporteJ component. This failure of the component supports' intended function could, in turn, lead to loss of component intended function under CLB conditions. [ Reference 2, Page 2 3] Application for License Renewal 3.1-23 Calvert Cliffs Nuclear Power Plant
A*ITACllMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 COMPONENT SUPPORTS Group 2 -(Cable Raceway Supports, HVAC Dueting Supports, and Equipment Supports - General Corrosion of Steel) Methods to Manage Aglag Effects Mitlaation To mitigate the effects of general corrosion, the conditions on the external surfaces of the component support must be controlled. Significant rates of corrosion only occurs when the component support comes in cont,ct with moisture. Preventing direct and prolonged contact between metal surfaces and moisture is an effective mitigation technique for general corrosion. Therefo e, to mitigate general corrosion, protective coatings ensure that the external metal surfaces of the component supports are not in contact with a moist, aggressive environment for extended periods of time. In addition, plant housekeeping practices, which identify conditions such as degraded paint, can be used to mitigate the effects of general corrosion. [ Reference 2, Page 2 10, Note 1) Discoverv The effects of general corrosion are detectable by visual techniques. Because the external metal surfaces of the component supports are covered by a protective coating, observing that significant degradation has not occurred to this coating is an effective method to ensure that conesion has not affected the intended function of the component support. Coatings degrade slowly over !!me, allowing visual detection during normal operations. Since the coating does not contribute to the intended function of the supports, observing the coating for degradation provides an alert condition, which triggers corrective action prior to the occurrence of degradation that would affect the support's ability to perform its intended function.
'the degradation of the protective coating or any actual corrosion that does occur can be discovered and conected by periodically inspecting the supports and by carrying out corrective actions as necessary.
Group 2 -(Cable Raceway Supports, HVAC Dueting Supports, and Equipment Supports - General Corrosion of Steel)- Aging Managemen* Program (s) Mitifation The external metal surfaces of the component suppor's are covered by a protective coating that mitigates the efTects of general corrosion. The discovery programs discussed below ensure that the protective coatingt of component supports are maintalacd. Discoverv For discovery, the level of aging manaFement activity needed for each category of component supports is determined based on the condition observed during a baseline walkdown of a representative sample of supports of each category. Therefore, discovery activities are discussed in two categories, baseline activities and follow-on aging management activities. The as found condition during the baseline walkdown dictates the level of f3l low-on aging management needed for the support type. (Reference 2, Pages 61 through 6 5] The Seismic Verification Project (SVP) was established at CCNPP to resolve the NRC's Unresolved Safety issue A-46 on the seismic adequacy of older nuclear power plants. The SVP used the NRC approved Generic Implementation Procedure (Reference 42) to verify the seismic adequacy of mechanical and electrical equipment required for safe shutdown following a seismic event. The SVP Application for License Renewal 3.124 Calvert Cliffs Nuclear Power Plant
NITACllMENT (1) APPENDIX A TECHNICAL INFORMATiON 3.1 - COMPONENT SUPPORTS used the SQUG methodology whose acceptance criteria was based on the review of as-found conditions of plant equipment at a large number of industrial facilities worldwide that had experienced strong motion seismic events. (Reference 2, Page 4 1) A requirement of the SQUG methodology is that walkdown evaluations and inspections be conducted by "Scismic Capability Engineers." These engineers must complete the SQUG developed Welkdown Training Course for Seismic Capability Engineers. He course includes reviews of the Generic Implementation Procedure walkdown evaluation criteria, including criteria for evaluating the condition of equipment anchorages for the variety of anchor types used in the nuclear industry. [ Reference 2, Page 41] One area of seismic vulnerability that was found to apply to many types of equipment in the SQUG database was inadequate anchorage. [ Reference 2. Page 41] Herefore, the Generic implementation Procedure methodology emphasizes the inspection of the structural adequacy of the as found condition of equipment support load paths and anchorages. Generic implementation Procedure anchorage evaluation requirements include the following actions, perfonned by the Seismic Capability Engineers. [ Reference 2, Page 4 2]
- Documentation of plant inspections on a checklist that was standardized for each generic class of equipment; e Calculations of the anchorage capacity vs. seismic loading (demand);
- Photographic documentation of equipment anchorages; and e Evaluation to identify overhead equipment or components with the potential to collapse under a seismic event, consistent with the Class 11 over I conceptual concern.
Although the majority of the SQUG cvaluation methodology is based on visual inspections, there is one part of the anchorage evaluation criteria that requires a " hands-on" inspection. His hands-on inspection applies to concrete expansion anchors, which are used extensively in power plants to anchor equipment such as cabinets, instrument / battery racks, and stanchions. The inspection (called the " anchor tightness check" in Section C.2.3 of the Generic Implementation Procedure) requires applying a small torque to the anchor to conHrm the bolt is tight and adequately installed. These checks were performed by CCNPP craft personnel on a sampling of anchor bolts selected by the Seismic Capability Engineers. [ Reference 2, Page 4 2] Because the SVP was a one time occurrence, h2seline activity, its use as an aging management program for component supports is supplemented by the ongoing walkdowns by system engineers and other plant personnel. [ Reference 2, Page 4 2] ne combination of the SVP Program and the ongoing walkdowns by system engineers and other plant personnel are deemed adequate to manage the efTects of aging in component supports for the following reasons: [ Reference 2, Section 4.3] e The SVP walkdowns, which were credited as baseline inspections for many component support types, were conducted approximately 20 years into the life of both CCNPP units if there were active ARDMs for a component support, it would be reasonable to assume they would have initiated within the Hrst 20 years of the component support's life. Therefore, the SVP walkdowns Application for I1ense Renewal 3.1 25 Calvert Cliffs Nuclear Power Plant
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gITACIIMI:NT f1) APPENDIX A - TECilNICAL INFORMATION 3.1. COMPDNENT SUPPORTS can be und to determine whether or not ARDMs are active for a component support. Based on this determination, an appropriate assumption about the future condition of the support can be made, unless plant conditions were to change some time in the future (e.g., degraded coating on a l suppon, pooled water or leaks, irregular humidity for an area). Changes in plant conditions ' would be identified by the ongoing walkdowns by system engineers and other plant personnel. ne visual inspections performed by the SVP Program included checks for the following potential ARDMs: 0 Grout / concrete local deterioration; and 0 Steel load path and concrete pad degradation potentially caused by loadings from rotating / reciprocating machinery, hydraulic vibration or water hammer, and thermal expansion of piping / component. e ne visual inspections performed by the SVP Program and the system engineer walkdowns include (d) checks for the following additiona! potential ARDMs: 0 General corrosion of steel; and l 0 Elastomer hardening. The ongoing walkdowns by system engineers and other plant personnel are judged adequate to continue monitoring of the ARDMs listed above on the basis that: 0 The guidelines for these walkdowns (i.e., PEG 7, NO 1200, and NO-1 107) require the system engineers and other plant personnel to look for component support condition and other plant conditions that could potentially affect the component supports; 0 N system engineers and other plant personnel are required to document deficiencies in accordance with QL 2100; O System engineers and other plant personnel occasionally find component support deficiencies like those that would occur due to aging, which indicates that component support aging is being managed; and 0 Additionally, because CCNPP commits to SQUG methodology as an alternative method for the verification of the seismic adequacy of new and replacement equipment, Seismic Capability Engineers will be available to assist the system engineers, as required, in evaluating cases of questionable support condition. Dagline Walkdowns ne aging management approach for cable raceway supports, ilVAC ducting supports, and equipment suppons relies on baseline walkdown activities. The activities for these suppons include one or more of the following: e Inspections performed by the SVP; e inspections performed by the ISI Program;
- Additional sampling baseline walkdowns; or Determination that walkdowns performed on similar types of supports in similar environments were sufficient such that no baseline walkdowns were required (e.g., for llVAC ducting supports Application for License Renewal 3.1 26 Calvert Cliffs Nuclear Power Plant
NITACitMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 COMPONENT SUPPORTS 1 outside containment, credit was taken for the SVP inspections of cable raceway supports outside containment). l For cc:nponent supports subject to baseline inspection under the SVP, the inspections were conducted in accordance with the criteria stated above, nese completed SVP inspections serve as an adequate l baseline activity to document the condition of component supports and the results of the SVP inspecthns are maintained at CCNPP. [ Reference 2, Page 6 5) The component supports inspected by the SVP l included the supports for the mechanical and electrical equipment on the CCNPP Safe Shutdomi l Equipment List, and included the following types of supports: [ Reference 2, Table 3 1] Trapeze, cantilever, and other cable raceway support styles (outside and inside containment);
- Elastomer vibration isolators outside containment; e Electrical cabinet anchorage outside containment; e
Equipment frames and stanchions for instmments and batteries outside containment; e Equipment frames and stanchlons for instruments inside containment; e Frames and saddles for tanks and heat exchangers (outside and inside containment); e Metal spring isolators and fixed bases (outside and inside containment); and
- Ring foundations for flat bottom vertical tanks.
For these component support types, no active general corrosion was discovered except on certain electrical cabinet anchorages outside containment. Corrosion was found on the cabinet anchorage for sampling system hoods, and additional walkdowns will be conducted to determine the condition of the anchorage of similar cabinets. For all other component support types subject to SVP inspection, no additional action for general corrosion is required and the follow-on activities discussed below are adequate for continued aging management. [ Reference 2, Pages 6 7 through 612] For component supports subject to baseline inspection under the ISI Program, the inspections were conducted in accordance with the criteria stated above in the subsection, Group 1 Aging Management Programs. %ese completed Isis serve as an adequate baseline activity to document the condition of component supports, and the results of the Isis are maintained at CCNPP. [ Reference 2 Page 6 5] The component suppoit types subject to inspection under the ISI Program are equipment supports (frames and saddles for tanks and heat exchangers outside containment, frames and saddles for tanks and heat exchangers inside containment, and LOCA restraints). [ Reference 2. Pages 6 7 through 6-12] For component supports that were not covered or only partially covered by the SVP or the ISI Program, and environmental or other differences prevented extrapolation of results to cover these component supports, additional sampling walkdown are needed. The walkdown scope will include inspection, on a sampling basis, for corrosion, and will be documented using ineans such as field notes and photographs. These walkdowns will document the condition of the component supports within the scope of license renewal. Once these additional walkdowns are completed, an adequate baseline condition assessment will have been completed. [ Reference 2, Page 6-4, Table 6-l] The component support types subject to additional sampling walkdowns are rod hanger trapezc supports for HVAC ducting inside containment; Application for License Renewal 3.1-27 Calvert Cliffs Nuclear Power Plant
ATTACilMI'NT (1) APPENDIX A - TECilNICAL INFORMATION 3.1 COMPONENT SUPPORTS electrical cabinet anchorage outside containment (anchorage Sr sampling system hoods only), and electrical cabinet anchorage inside containment (for six radiation monitors). [ Reference 2, Table 61] Follow-on Activities Because the SVP was a one-time occurrence, the commodity approach for component supports also relles on the ongoing site activities for managing aging of component supports. [ Reference 2, Page 12) For component supports covered by the SVP, the follow on activities for aging management of these component supports will be system engineer walkdowns, the Control of Shin Activities Program, and the Ownership of Plant Operating Spaces Program. [ Reference 2, Section 4.2) The purpose, scope, bases, etc., for these programs are described above in the subsection, Group 1 Aging Management Programs. Although the containment air cooler fans (metal spring isolators and 0xed bases inside containment) received an adequate baseline inspection as part of the SVP and no aging was discovered, these supports are not accessible for system engineer walkdowns since the spring isolator supports are located internal to the fan. %crefore, the preventive maintenance checklists (MPM 09150 and MPM 09151), which open and inspect other components internal to the fan housing, will be modified to also inspect these spring isolator supports for signs of general corrosion. [ Reference 2, Page 612] Based on the results of baseline inspections completed per the existing ISI Program requirements, it was determined that continuing ASME Section XI Isis into the period of extended operations will also serve as an adequate follow-on activity for those component supports subject to that program. [ Reference 2, Page 5-4) The purpose, scope, bases, etc., for the ISI Program are described above in the subsection, Group 1 Aging Management Programs. For those component supports that require additional baseline walkdowns, the results of those walkdowns will determine the extent of aging management practices needed for these supports, if the baseline walkdowns reveal no signincant efTects of aging from general corrosion, then the follow-on activities for aging management of these component supports wiP be system engineer walkdowns, the Control of Shin Activities Program, and the Ownership of Plant Operating Spaces Program. [ Reference 2, Page 5 4t and Reference 2 Page 4 2) Group 2 -(Cable Raceway Supports,IIVAC Dueting Supports, and Equipment Supports - General Corrosion of Steel)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to general corrosion of steel for cable raceway supports, IIVAC ducting supports, and equipment supports. l e Group 2 supports associsted with components within the scope ofI cense renewal are themselves considered to be within the scope oflicense renewal because failure of these supports could lead to failure of the supported plant component.
- General corrosion was detennined to be a plausible ARDM for Group 2 supports. The effects of the ARDM are a loss of support material and reduction of component support strength. These effects, ifleft unmanaged, could lead to loss of the intended function of the component supports and ultimately to failure of the supported plant component under CLB conditions.
Application for License Renewal 3.1 28 Calvert Cliffs Nuclear Power Plant
ATTACHMMT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS e General corrosion is mitigated by applying coatings to component supports, periodically examining the supports for degradation of that coating or conditions that could accelerate degradation, and by maintaining the coatings.
- Baseline discovery programs include elements that would enable these activities to discover the effect of all plausible aging mechanisms (including degradation of coatings that prevent specific l ARDMs) and to determine the appropriate level of follow-on aging management activities.
Follow on discovery activities include Isis, system engineer walkdowns, the control of shiR activities, the ownership of plant operating spaces, and preventive maintenance checklists (for containment air cooler fans). Rese activities include elements that would ensure discovery of the efTeets of all plausible aging mechanisms (including degradation of coatings that prevent specific ARDMs) and require corrective action and actions to prevent recurrence of problem conditions, as appropriate. Group 2 supports within the scope of license renewal are subject to follow-on discovery activities, e The discovery aging management activities (Isis, SVP inspections, additional baseline walkdowns, system engineer walkdowns, the control of shift activities, and the ownership of plant operating spaces) detect and correct any adverse effects of general corrosion. Therefore, there is reasonable assurance that the effects of aging will be adequately managed such that the cable raceway supports,11VAC ducting supports, and equipment support types will be capable of performing their structural support function consistent with the CLB durin;; the period of extended operation. Group 3 - Elastomer Vibration Isolaton: Elastomer Hardening Vibrations resulting from rotating equipment or other sources are, in general, transmitted to the surrounding structure. Elastomer materials are used in the anchorage load path of some rotating equipment to reduce the vibration transmitted to the supporting structures. Group 3 includes elastomer vibration isolators for equipment such as fans and compressors. in addition to general corrosion discussed in Group 2, these type of supports are subject to age-related degradation due to hardening of the clastomer material. Group 3 - (Elastomer Vibration isolators - Elastomer Hardening)- Materials and Environment Elastomer is the generic term used to describe a variety of natural and synthetic rubber products. Elastomer substantially recovers its original shape and size after removal of a deforming force. [ Reference 43, Page 16) Environmental conditions for Group 3 component supports inside the plant are identical to those described above, for " Piping Supports." llowever, some Group 3 supports may be subject to temperatere conditions higher than ambient conditions due to their close proximity to heat generating equipment. Mlication for License Renewal 3.1-29 Calvert Cliffs Nuclear Power Plant t
ATTACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Group 3 -(Elastomer Vibration Isolators . Elastomer Hardening) Aging Mechanism Effects As shown on Table 3.13, clastomer hardening is an ARDM considered to be plausible for elastomer vibration isolatora (Group 3) (Referenos 2, Pages 2 7 and 2 8] Extended exposure to light, heat, oxygen, ozone, water, or radiation can cause scission or cross linking of the polymer chains forming the clastomer material. Chain scission (the breaking of chemical bonds) lowers the elastomer tensile strength and clastic modulus. Cross linking (undesirable linking of adjacent polymer strings at susceptible sites) causes the elastomer to become more brittle and promotes surface cracking, which may lead to loss of strength and subsequent failure. [ Reference 2 Section 2.2.3] Elastomers used to dampen vibration are subject to age hardening, even in mild environments [ Reference 2. Table 21, Note 11]. This aging mechanism, if unmanaged, could eventually lead to loss of the clastomer vibration dampening function. Loss of this function could, in turn, lead to a loss of function of the supported equipment under CLB conditions. Therefore, elastomer hardening was determined to be a plausible ARDM for which the aging effects must be managed for elastomer vibration isolators. Group 3 - (Elastomer Vibration Isolators - Elastomer Hardening) - Methods to Manage Aging Effects Mitigation Since elastomer hardening is affected by exposure to environmental conditions that are not feasible to control (e.g., light, heat, oxygen, ozone, water, radiation), there are no practical methods to mitigate its effects. Discovery The effects of elastomer hardening for elastomer vibration isolators are detectable by visual inspection techniques. Therefore, adequate discovery techniques to detect the effects of aging must include a visual observation of the external condition of the clastomer material on elastomer vibration isolators. [ Reference 2, Page 6-8] Group 3 . (Elastomer Vibration Isolator - Elastomer Hardening) - Aging Managernent Program (s) Mitigation Here are no CCNPP programs credited for mitigation of elastomer hardening. Discoven For discovery, the level of aging management activity needed for each category of component supports is detemined based on the condition observed during a baseline walkdown of a representative sample of supports of each category. Therefore, discovery activities are discussed in two categories, baseline activities and follow-on aging management activities. The as found condition during the baseline Application for License Renewal 3.1 30 Calvert Cli!Ts Nuclear Power Plant
- _- - - _ _ _ . - - - _ . - - ~ . - . . -.
ATTACilMENT (1) APPENDIX A - TECilNICAL INFORMATION 3.1 - COMPONENT SUPPORTS walkdown dictates the level of follow-on aging management needed for the support type. [ Reference 2, Pages 61 through 6 5) Baseline Walkdowns l Some elastomer vibration isolators were subject to sampling baseline walkdown activities under the
- SVP.
Completed SVP inspections serve as an adequate baseline activity to document the condition of component supports and the results of the SVP inspections are maintained at CCNPP. [ Reference 2, Page 6 5) The purpase, scope, bases, etc., for the SVP are described above in the subsection, Group 2 Aging Management Programs. 'Ihe SVP found the current condition of vibration isolators inspected to be acceptable, except for those that support the Control Room IIVAC air handler. Prior to the SVP walkdown, these supports had been identified by the system engineer as requiring replacement, and a modification had been planned to replace the elastomer isolators with spring type isolators. After these isolators are replaced, the follow-on activities described below are judged to be adequate to manage aging of clastomer vibration isolator component supports for other equipment. [ Reference 2, Page 6 8) Follow-on Activities Because the SVP was a one-time occurrence, the commodity approach for component supports also relies on the ongoing site activities for managing aging of component supports. [ Reference 2, Page 1-2] The follow-on activities for aging management of the elastomer vibration isolator component supports will be system engineer walkdowns, the Control of Shill Activities Program, and the Ownership of Plant Operating Spaces Program. The purpose, scope, bases, etc., for these programs are described above in the subsection, Group 1 - Aging Management Programs. The system engineer walkdown inspection technique with respect to clastomer vibration isolators has typically included pushing on the isolator to assess its pliability and a visual inspection to detect signs of cracking. This technique has been shown in the past to be effective in identifying elastomer hardening prior to loss of the CLB function. Group 3 - (Elastomer Vibration Isolaton - Elastomer Hardening) - Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to elastomer hardening for elastomer vibration isolators, e Group 3 supports associated with components in the scope of license renewal are themselves considered to be within the scope oflicense renewal because failure of these supports could lead to failure of the supported plant component.
- Elastomer hardening was determined to be a plausible ARDM for Group 3 supports. This aging mechanism, if unmanaged, could eventually lead to loss of the elastomer vibration dampening function. Loss of this function could, in turn, lead to a loss of function of the supported equipment under CLB conditions. A modification had been planned, for the Control Room HVAC air handler supports, to replace the elastomer isolators with spring type isolators.
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Application for License Renewal 3.1 31 Calvert Cliffs Nuclear Power Plant
q ATTACHMENT (1) , APPENDIX A - TECHNICAL INFORMATION ' 3.1 - COMPONENT SUPPORTS
- Baseline discovery programs include elements that would enable these activities to discover the effect of all plausible aging mechanisms, and to determine the appropriate level of follow on aging management activities.
- Follow-on discovery activities include system engineer walkdowns, the control oi shift activities, and the ownership of plant operating spaces for elastomer vibration isolators. nese activities include elements that would ensure discovery of the effects of all plausible aging mechanisms and require corrective action and actions to prevent recurrence of problem conditions, as appropriate.
Group 3 elastomer vibration isolators within the scope oflicense renewal, are subject to follow on . discovery activities.
- De discovery aging management activities (SVP inspections, system engineer walkdowns, the control of shift activities, and the ownership of plant operating spaces) detect and correct any adverse effects of clastomer hardening for clastomer vibration isolators.
Herefore, there is reasonable assurance that the effects of aging will be adequately managed such that the clastomer vibration isolators will be capable of performing their structural support function consistent with the CLB during the period of extended operation. Group 4 - Metal Spring Isolaton and Fixed Bases (outside containment) / LOCA Restraints: Loading Due to Rotating / Reciprocating Equipment Group 4 includes metal spring isolators and fixed bases for rotating / reciprocating equipment, such as pumps and fans. Group 4 also includes LOCA restraints for the reactor coolant pumps. In addition to general corrosion discussed in Group 2, these type of supports are subject to age-related degradation due to vibration transmitted from the rotating / reciprocating equipment Group 4 - (Metai Sprlag Isolators and Fixed Braes (outside containment) / LOCA Restralats - Loading Due to Rotating / Reciprocating Machinery)- Materials and Environment Metal spring isolators and LOCA restraints are constructed of structural steel. Metal spring isolators and fixed bases subject to loading due to rotating / reciprocating machinery are located outside of the Containment Buildings. Loss-of coolant accident restraints subject to loading due to rotating / reciprocating machinery are locmed inside the Containment Buildings. Environmental conditions for metal spring isolators and LOCA restraints are identical to those described above, for
" Piping Supports." [ Reference 2, Page 612]
Group 4 - (Metal Spring Isolators and Fixed Bases (outside containment) / LOCA Restraints - Loading Due to Rotating / Reciprocating Machinery) . Aging Mechanism Effects As shown in Table 3.1-3, loading due to rotating / reciprocating machinery is the ARDM considered to be plausible for metal spring isolators, fixed bases, and LOCA restraints (Group 4) that are anchored to concrete; [ Reference 2, Pages 2-9; and 2-10, Note 8] Loading due to rotating / reciprocating machinery is plausible for supports in Group 4 because the machinery supported by these metal spring isolators, fixed bases, and LOCA restraints is subject to vibration from rotation and/or reciprocat'on while in operation. Application for License Renewal 3.1-32 Calvert Cliffs Nuclear Power Plant
ATTACllMENT H) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS ne etiects ofloading due to rotating / reciprocating macidnery are steel 10 4 path degradation, concrete pad degradation, and concrete cracking in the vicinity of the equipment anchorage, and consequently a l reduction in component support strength if the ARDM were allowed to progress unmanaged, if these mechanisms were left unmanaged, the effects could progress to the point of reducing the amount of support afforded to the component and/or allowing excessive motion of the supported component. This failure of the component supports' intended function could, in turn, lead to loss of function of the wpported equipment under CLB conditions. [ Reference 2. Pages 210 and 4 4] For the metal spring isolators, fatigue cracking of the springs is not considered plausible. Springs are designed for infinite cycles of design loadings, and unless improperly des 4ned, would fall only during an overload (l.c., non-design) condition. Therefore, the ARDM " loading due to rotating / reciprocating machinery " focuses on other signs of degradation, e.g., cracking of adjacent concrete.
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Group 4 - (Metal Spring Isolators and Fixed Bases (outside containment) / LOCA Restraints - Leading Due to, Rotating /Reelprocating Machinery) . Methods to Manage Aging Effects hiitlantion ne effects of the ARDM loading due to rotating / reciprocating machinery for component supports have been minimized through proper support design and through proper system operation. Therefore, no additional specific measures to mitigate this ARDM are needed. Discovery Methods to discover the effects of loading due to rotating / reciprocating machinery are a visual observation of the support and/or the surrounding concrete. [ Reference 2, Pages 4 4 and 612] Group 4 - (Metal Spring Isolators and Fixed Bases (outside containment) / LOCA Restraints - Londing Due to Rotating / Reciprocating Machinery)- Aging Management Program (s) Mitination There are no CCNPP programs credit:d for mitigation of loading due to rotating / reciprocating machinery. Discovery For discovery the level of aging management activity needed for each category of component supports is determined based on the condition observed during a baseline walkdown of a representative s:mple of supports of uch category. Herefore, discovery activities are discussed in two categories, baseline activities and follow-on aging management activities. The as found condition during the baseline walkdown dictates the level of follow-or: aging management needed for the support type. [ Reference 2, Pages 6-1 through 6-5] Baseline Walkdowns Some metal spring isolators and fixed bases outside containment were subject to baseline inspection under the SVP. These completed SVP inspections serve as an adequate baseline activity to document the Application for License Renewal 3.1 33 Calvert Cliffs Nuclear Power Plant
ATTACllMENT (1) Al>PENDIX A TECHNICAL INFORMATION ' 3.1 - COMPONENT SUPPORTS condition of component supports, and the results of the SVP inspections are maintained at CCNPP. [ Reference 2, Page 6 $) ne results of the SVP baseline did not identify any active ARDMs for metal spring isolators and Axed bases. Therefore, the follow on activities described below are adequate for continued aging management. [ Reference 2, Page 612] The purpose, scope, bases, etc., for the SVP are described above in the subsection, Group 2 Aging Management Programs. Loss-of coolant accident restraints are subject to baseline inspection under the ISI Program. Dese completed ISIS serve as an adequate baseline activity to document the condition of component supports, and the results of the Isis are maintained at CCNPP. (Reference 2, Pages 6 5 3nd 612] ne purpose, scope, bases, etc., for the ISI are described above in the subsection, Group I Aging Management Programs. i Follow-on Activitics Because the SVP was a one time occurrence, the commodity approach for component supports also , telles on the ongoing site activities for managing aging of component supports that were baselined under I the SVP. { Reference 2, Page 12] l l The follow-on activities for aging management of the metal spring isolators and fixed bases component - supports will be system engineer walkdowns, the Control of Shift Activities Program, and the Ownership of Plant Operating Spaces Program. [ Reference 2, Pages 4 2 and 6-12] The purpose, scope, bases, etc., for these programs are described above in the subsection, Group 1 - Aging Management Programs, Based on the results of baseline inspections completed per the existing ISI Program requirements, it was determined that continuing ASME Section XI Isis into the period of extended operation will also sen'e as an adequate follow on activity for LOCA restraints subject to that program. [ Reference 2, Page 5 4] Group 4 - (Metal Spring isolators and Fixed Bases (outside containment) / LOCA Restraints - Loading Due to Rotating / Reciprocating Machinery)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to loading due to rotating / reciprocating machinery for metal spring isolators and fixed bases /LOCA restraints. e Group 4 supports associated with components in the scope of license renewal are themselves considered to be within the scope oflicense renewal because failure of these supports could lead ; to failure of the supported plant component. e Loading due to rotating / reciprocating machinery was determined to be a plausible ARDM for Group 4 supports. The effects of the ARDM are steel load path degradction,, concrete pad j degradation, and concrete cracking in the viciMty of the equipment anchorage and subsequent loss of strength of the component support. Rese efTects, iflefl unmanaged, could lead to loss of the intended function of the component supports and ultimately to failure of the supported component under CLB conditions, e Baseline discovery programs include elements that would enable these activities to discover the effect of this plausible aging mechanism and to determint the appropriate level of follow-on aging management activities.
~
Applicatic,n for License Renewal 3.1-34 Calvert Cliffs Nuclear Power Plant
4 ATTACilMENT (1) APPENDIX A TECilNICAL INFORMATION 3.1 - COMPONENT SUPPORTS
- Follow-on discovery activities include Isis, system engineer walkdowns, the control of shlR activities, and the cwnership of plant operating spaces. 'these activities include elements that would ensure discovery of the effects of this plausible aging mechanism and require corrective action and actions to prevent recurrence of problem conditions, as appropriate. Group 4 supports within the scope oflicense renewal are subject to follow on discovery activities, e The discovery aging management activities (Isis, SVP inspections, system engineer walkdowns, the control of shift activities, and the ownership of plant operating spaces) detect and correct any adverse effects ofloading due to rotating / reciprocating equipment.
Therefora Gere is reasonable assurance that the effects of aging will be adequately managed such that the metai f ngi isolators, fixed bases, and LOCA restraints will be capable of performing their structural support function consistent with the CLB during the period of extended operation. Group 5 - Frames and Sadd!es / LOCA Restraints: Londing due to Ilydraulle Vibration or Water llammer Group 5 includes frames and saddles for tanks and heat exchangers. Group 5 also includes LOCA restraints for the pressurizer and the reactor coolant pumps. In addition to general corrosion discussed in Group 2, these type of supports are subject to age rela'ed degradation due to hydraulic loadings (e.g., and 612,flow Tat e 21) in,{luced vibration, flashing flove, or steam bubble collapse). [ Re Group 5. (Frames and Saddles / LOCA Restraints - Loading due to Ilydraulle Vibration or Water llammer)- Materials and Environment Frames and saddles are constructed of structural steel. Frames and saddles are located inside the Containment Buildings and inside other climate-controlled buildings. Environmental canditions for frames and saddles are identical to those described above, for " Piping Supports" [ Reference 2, Page 611) Loss of-coolant accident restraints are constructed of structural steel and are only located inside the Containment Buildings. Environment 1 conditions for LOCA restraints are identical to those described above, for " Piping Supports." (Reference 2, Page 6-12] Group 5. (Frames and Saddles / LOCA Restraints - Loading due to llydraulic Vibration or Water llammer). Aging Mechanism Effects As shown in Table 3,13, loading due to hydraulic vibration or water hammer is considered to be plausible for frames, saddles, and LOCA restraints. (Reference 2, Pages 2 8 and 2 9) Loading due to hydraulic vibration or water hammer is plausible for supports in Group 5 because the plant equipment supported by these equipment supports could be subject to hydraulic vibration or water hammer during plant operation. The aging effects due to this ARDM would be loosening of bolted connections, loss of weld integrity, and component displacement or misalignment. If this aging mechanism were left unmanaged, the effects Application for License Renewal 3.1 35 Calvert Cliffs Nuclear Power Plant >
- - .,.w,, ,, - y . -- - .-. -
ATTACllMrNT (1) APPENDIX A . TECHNICAL INFORMATION 3.1 COMPONENT SUPPORTS could progress to the point ofinsuflicient support afforded to the components and/or allowing excessive movement of the equipment or component. His failure of the equipment supports' intended function could, in tum, lead to failure of the supported equipment under CLil conditions. (Reference 2, Page 5 4] Group 5. (Frames and Saddles / LOCA Restraints . Loading due to Hydraulic Vibration or Water Hammer) . Methods to Manage Aging Effects Mitloatlnn ne effects of the ARDM loading due to hydraulle vibration or water hammer for component supports have been minimized through proper support design and through proper system operation. Loading due to hydraulle vibration or water hammer is only a concern due to the potential for off normal operation and transients. %erefore, no additional specific inessures to mitigate this ARDM are needed. Discovery The effects ofloading due to hydraulic vibration or water hammer are detectable by visual observation of external conditions. The effects of excessive loading from hydraulle vibration or water hammer are observable initially in the form ofloosening of bolted connections, loss of weld integrity, and component displacement or misalignment. These conditions would be readily observable during a visual inspection. (Reference 2, Page 5 4) Group 5. (Frames and Saddles / LOCA Mestraints . Loading due to Hydraulic Vibration or Water Hammer). Aging Management Program (s) Mitlantion There are .so CCNPP programs credited for mitigation of loading due to hydraulu. 'ibration or water hammer. Discoverv For discovery, the level of aging management activity needed for each category of component supports is determined based on the condition observed during a baseline walkdown of a representative sample of supports of each category. Therefore, discovery activities are discussed in two categories, baseline activities and follow-on aging management activities, ne as-found condition during the baseline walxdown dictates the level of follow on aging management needed for the support type. [ Reference 2, Pages 61 through 6 5] Baseline Walkdowns Several programs are credited with discovery methods for identifying degradation from loading due to hydraulle vibration or water hammer. Frames, saddles, and LOCA restraints are included within the scope of the SVp and the 151 Program sampling baseline walkdowns. [ Reference 2, Tables 31 and 61] (Note that supports for the spent fuel pool cooling dcmineralizer and ion exchanger vessels are addressed in the AMR for that system and are not covered by this commodity evaluation.) Some frames and saddles were subject to baseline inspection under the SVP. Completed SVP inspections serve as an adequate baseline activity to document the condition of frames and saddles, and Application for License Renewal 3.1 36 Calvert Cliffs Nuclear Power Plant
NITACllMENT (1) APPENDIX A TECilNICAL INFORMATION 3.1 COMPONENT SUPPORTS the results of the SVP inspections are maintained at CCNPP. [ Reference 2 Page 6 5] The results of the SVP baseline did not identify any active ARDMs for the component supports inspected, and the
- follow on activities discussed below are adequate for continued aging management. [ Reference 2, Page 611] The purpose, scope, bases, etc., for the SVP are described above in the subsection, Group 2 Aging Management Programs. .
Frames and saddles are also subject to baseline inspection und:r the 151 Program. These completed Isis , L serve as an adequate baseline activity to document the condition of component supports, and the results , of the ISIS are maintained at CCNPP. [ Reference 2, Pages 611 and 5 4) He purpose, scope, bases, etc., for the ISI are described above in the subsection, Group I Aging Management Programs.
- Loss-of coolant accident restraints are subject to baseline inspection under the 151 Program. These completed ISIS serve as an adequate baseline activity to document the condition of component supports, and the results of the ISin are maintained at CCNPP [ Reference 2, Page 612] The purpose, scope, i
bases, etc., for the ISI are described above in the subsection, Group 1 Aging Management Programs. The results of the SVP baseline and the continual ISIS concluded that no additional actions, other than i follow on activities discussed below, are needed. [ Reference 2, Page 6-11] i bliow-on Activiiles Since the SVP was a one time occurrence, the commodity approach for component supports also telles on the ongoing site activities for managing aging of component supports. [ Reference 2, Page 1 2) ? j The follow on activities for aging management of the framu and saddles component supports will be
- system engineer walkdowns, the Control of Shift Activities Program, and the Ownership of Plant Operating Spaces Program. [ Reference 2, Pages 4 2 and 6-11] The purpose, scope, bases, etc., for these programs are described above in the subsection, Group I - Aging M> nagement Programs.
{ Based on the results of baseline inspections completed per the existing 61 Program requirements, it was determined that continuing ASME Section XI Isis into the period of extended operation will also serve as an adequate follow-on activity for frames, saddles, and LOCA restraints subject to that program. [ Reference 2, Page 5 4) Group 5 -(Frames and Saddles / LOCA Restraints - Loading due to Hydraulle Vibration or Water Hammer)- Demonstration of Aging Management Cased on the information presented above, the following conclusions can be reached with respect to loading due to 'nydraulle vibration or water hammer for frames, saddies, and LOCA restraints,
- Group 5 supports associated with components in the scope of license renewal are themselves considered to be within the scope oflicense renewal because failure of these supports could lead
- to failure of the supported plant component.
- Loading due to hydraulic vibration or water hammer was determincJ to be a plausible ARDM for Group 5 supports. The effects of the ARDM are loosening of bolted weetions, loss of weld
, integrity, and component displacement or misalignment that lead to loss of structural adequacy and subsequent loss of strength of the component support. This effect, ifleft unmanaged, could Application for License Renewal 3.1-37 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1) l APPENDIX A - TECilNICAL INFORMATION 3.1 COMPONENT SUPPORTS lead to loss of the intended function of the component supports and ultimately to failure of the supported plant component under CLB conditions.
- Baseline discovery programs include elements that would enable these activities to discover the cliect of this plausible aging mechanism and to determine the appropriate level of follow on aging management activities.
Follow on discovery activities include Isis, system engineer walkdowns, the control of shift activities, and the ownership of plant operating spaces. Rese activities include elements that
*vould ensure discovery of the effects of this plausible aging mechanism and require corrective action and actions to prevet securrence of problem conditions as appropriate. Group 5 supports within the scope oflicense renewal are subject to follow-on discovery activities.
The discovery aging management activities (Isis, SVP inspections, system engineer wattdowns, the control of shift activi'ies, the ownership of plant operating spaces) detect and correct any adverse effects ofloading due to hydraulle vibration or water hammer. Herefore, there is reasonable assurance that the effects of acing will be adequately managed such that the frames, saddles, and LOCA restraints will be capable of performing their structural support function consistem with the CLB during the period of extended operation. Group 6 - Frames and Saddles / Ring Foundation for Flat Bottom Vertical Tanks: Loading Due to Thermal Expansion Group 6 includes frames and saddles that are located inside and outside of the Containment Buildings, ; for equipment such as tanks and heat exchangers. Group 6 also includes ring foundations for flat bottom vertical tanks. In addition to general corrosion discussed in Group 2, these type of supports are subject to ! age-related degradation due to thermal expansion of piping or components.
~ Group 6 -(Frames and Saddles / Ring Foundation for Flat Bottom Vertical Tanks - Loading Due to Thermal Expansion)- Materials and Environment Flames and saddles are constructed of structural steel. Frames and saddles are located inside the Containment _ Buildings and inside other climate controlled buildings. Environmental conditions for frames and saddles are identical to those described above, for " Piping Supports."[ Reference 2, Page 2 8]
f Ring foundations for flat-bottom vertical tanks are concrete and are located both inside climate-controlled buildings and outdoors. Environmental conditions for ring foundations inside climate-cc ntrolled buildings are identical to those described above, for " Piping Supports." ing foundations that may be outdoors are subject to changing atmospheric conditions. The site and e..vironment of CCNPP are described in Chapter 2 of the UFSAR. [ Reference 2, Page 211, Note 19, Page 612] - Group 6 -(Frames and Saddles / Ring Foundation for Flat Bottom Vertical Tanks - Loading Due to Thermal Expansion) . Aging Mechanism Effects As shown in Table 3.13, loading due to thermal expant,lon is considered to be plausible for frames, caddles, and ring foundations. Loading due to thennal expansion is plausible for supports in Group 6 because these types of equipment supports are subject to thermal cycling while performing their intended Application for License Renewal 3.138 Calvert Cliffs Nuclear Power Plant
ATTACilMENT f1) APPENDIX A - TECHNICAL INFORMATION 3.1 COMPONENT SUPPORTS functions. %c concrete ring foundations of large, flat bottom vertical tanks are subject to thermal cycling, especially during periods of cold weather when tank contents are heated with flow frora warm sources, e.g., the main condenser. [ Reference 2 Pages 2 8,2-9, and 211] He aging effects due to this ARDM would be loosening of bolted connections, loss of weld integrity, component displacement or misalignment, and cracking of concrete. If this aging mechanism were left unmanaged, the effects could progress to the point of reducing the amount of support afforded to the components and/or allowing excessi/c movement of the equipment or component. His failure of the equipment supports' intended function could, in tum, lead to failure of the supponed equipment under CLB conditions. [ Reference 2, Pages 5 4 and 612] Group 6 -(Frames and Saddles / Ring Foundation for Flat Bottom Vertical Tanks Leading Due to Thermal Expansion)- Methods to Manage Aging Effects Mitigation , He effects of the ARDM loading due to thermal expansion for component suppons have been minim 8ted through proper support design and through proper system operation. Herefore, no additional
. specific rneasurcs to mitigate this ARDM are needed.
DhCACO' i The effects of loading due to thermal expansion are detectable by visual observation of external conditions. The effects of excessive loading from thermal expansion are observable initially in the form i of loosening of bolted connections, weld crack initiation and growth, component displacement or misalignment, and cracking of concrete. These conditions would be readily obse;vable during a visual inspection. [ Reference 2, Pages 5 4,611, and 612] Group 6 - (Frames and Saddles / Ring Foundation for Flat Bottom Vertical Tanks - Loading Due to Thermal Expansion)- Aging Management Program (s) Mitigation Here are no CCNPP programs credited for mitigation ofloading due to thermal expansion. Discoverv For discovery, the level of aging management activity needed for each category of component supports is determii,ed based on the condition observed during a baseline walkdown of a representative sample of supports of each category. Therefore, discovery activities are discussed in two categories, baseline activities and folicw-on aging management activities. The as found condition during the baseline walkdown dictates the level of follow-on aging management needed for the support type. [ Reference 2, Pages 6-1 through 6-5] Ilaseline Walkdowns Several programs are credited with discovery methods for identifying degradation from loading due to thermal expansion, Frames, saddles, and ring foundations for flat bottom vertical tanks are included Application for License Renewal 3.139 Calvert Cliffs Nuclear Power Plant
ATTACilMENT (1) APPENDIX A TECilNICAL INFORMATIGN 3.1 COMPONENT SUPPORTS within the acope of the SVP and the ISI Program sampling baseline walkdowns. [ Reference 2, Pai;es 314 and 611] Sonw hmes. saddles, and ring icuadations were subject to baseline inspection under the SVP. Comp!M SVP inspections serve as an adequate baseCne activity to document the condition of frames, saddles, s.nd rin; foundations, snd ebe results of the SVP inspections are maintained at CCNPP. [ Reference 2, Pkgs f4 %< results of the SVP baseline did not identi fy any active ARDMs for the frames and saddke invecig Nd tb follow-on activities are acequate for continued aging management. He SVP baseline for ring fovAtions found radial cracks in the concrete rhy a for some of the tanks that l were inspected, but the impact of these crukt on the structural adequacy of tne anchorage was judged to be insignificant in the SVP evaluations. Follow on activities are edequate for continued aging management for the ring foundations. [ Reference 2, Pages 611 and 612] He purpose, scope, bases, etc., for the SVP are described above in the subsection, Group 2 Aging Management Programs. Frames and rid?.les are also subject to baseline inspection under the ISI Program. Dese completed Isis
- serve as an adequate baseline activity to document the condition of component supports, and the results of the Isis are maintained at CCY'P. [ Reference 2, Pages 5 4 and 611] He purpose, scope, bases, etc.,
for the ISI are described above in the subsection, Group 1 Aging Management Programs. He results of the SVP baseline and the continual Isis concluded that no additional actions, other than follow on activities discussed below, are needed. [ Reference 2 Pages 6-1I and 612] Eollow on Activitien Because the SVP wes a one time occurrence, the commodity approach for component supports also relles on the ongoing site activities for managing aging of component supports. (Reference 2, Page 12] De follow-oa activities for aging management of the frames, saddics, and ring foundation component supports will be system engineer walkdowns, the Control cf Shin Activities Program, and the Ownership of Plant Operating Spaces Program. [ Reference 2, Page 4 2] He purpose, scope, bases, etc., for these programs are described above in the subsection, Group 1 Aging Management Programs. Based on the results of baseline inspections completed per the existing ISI Program requirements, it was determined that conf.1ulng ASME Section XI Isis into the period of extended operation will also serve as an adequate follow on activity for frames and saddles subject to that program. [ Reference 2, Page 5 4] Group 6 - (Frames and Sadttles II41ag FouMation for Flat-Bottom Vertical Tanks - Loading Due to Thermal Expansion) hmonstration of Aging Management Based on the infornation presented above, the following conclusions can be reached with respect to loading due to thermal expansion for frames, saddles, and ring foundations, e Group 6 supports associated with components in the scope of license renewal are themselves considered to be within the scope oflicense renewal because failure of these supports could lead to failure of the supported plant component. Application for License Renewal 3.1-40 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 COMPONENT SUPPORTS e
. Loading due to thermal expansion was determined to be a plausible ARDM for Group 6 suppons. i De effects of the ARDM are loosening of bolted connect.ons, weld crack initlatim and growth, I component displacement o misalignment, and cracking of concrete that lead to foss of structural adequacy and subsequent loss of strength of the component suppon. This effect, if len unmanaged, could lead to loss of the intended function of the component supports and ultimately to failure of the supponed plant component under CLB conditions.
- Baseline discovery programs include elements that would enable these activities to discover the l effect of this plausible aging mechanism and to determine the appropriate level of follow on aging management activities.
Follow on discovery activities include Isis, system engineer walkdowns, the control of shift activities, and the ownership of plant operating spaces. These activities include elements that would ensure discovery of the efTects of this plausible aging mechanism and require corrective action and actions to prevent recurrence of problem conditions, as appropriate. Group 6 supports j within the scope oflicense renewal are subject to follow on discovery activities. l
- The discovery aging management activities (Isis, SVP inspections, system engineer walkdowns, the control of shin activities, and the ownership of plant operating spaces) detect and correct any adverse effects of loading due thermal expansion.
Therefore, there is reasonable assurance that the effects of aging will be adequately managed such that l the frames, saddles, and ring foundations will be capable of performing their structural support function i consistent with the CLB during the period of extended operation. Group 7 - Frames and Saddles (inside containment) / LOCA Re traints: Stress Corrosion Cracking of High Strength Bolts Group 7 includes frames and saddles for safety injection !anks, and LOCA restraints for the pressurizer, in addition to general corrosion discussed in Group 2, these type of supports are subject to age-related degradation of anchor bolting due to stress corrosion cracking because of the bolting material in use for these suppons. [ Reference 2, Pages 2-4; 2 9; 210, Note 2; Pages 611 and 612] Group 7 - (Frames and Saddles (Inside containmeut) / LOCA Restraints - Stress Corrosion Cracking of High Strength Bolts) Materials and Environment Frames, saddles, and LOCA restraints are constructed of structural steel with anchor bolting of various grades of steel as specified for the particular design. Frames, saddles, and LOCA **straints for a limited number of tani.s, vessels, and heat exchangers contain relatively biph strength anchor bolting and are, therefore, subject to stress corrosion cracking. These ppen. are located inside the Containment Building. Environmental conditions for frames, saddles, and LOCA restraints are identical to those described above, for " Piping Supports."(Referenco 2, Pages 611 and 6-12) Application for License Renewal 3.1-41 Calvert Cliffs Nuclear Power Plant
f ATTACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SliPPORTS Group 7 - (Frames and Saddles (Inside containment) / LOCA Restraints - Stress Corrosion Cracking of High Strength Bolts) Asleg Mechanism Effects industry experience has shown that high strength bolting (i.e.,those with yield strength greater than 150 ksi) installed in some Nuclear Stcam Supply System applications could be subject to stress corrosion cracking in a humid environment. The only two types of high strength bolting that can be found in anchor bolt applications at CCNPP are A354 and A490. Specifically, A354 bolting was used in the I I reactor vessel, pressurizer, and safety injection tank anchor bolts; and A490 bolting was used in the steam generator supports. (Note that reactor vessel and steam generator supports were not included in the Component Supports Commodity Evaluation.) Therefore, stress corrosion cracking is only plausible for pressurizer and safety injection tank support botting since these supports are the only applications with high strength bolting in the scope of this commodity evaluation. [ Reference 2, Pages 2 4 and 2 10) Per UFSAR Section 5.1.2.3, pressurizer and safety injection tank support bolting is type A354 Grade BC. Per EPRI report NP 5769 Table 41, this type of bolting has failed in similar applications in nuclear power plants due to stress corrosion cracking. However, these failures occurred due to improper heat treatment of the bolting during manufacture, or improper material supplied for this specification. Therefore, it is unlikely that stress corrosion cracking will afTect these bolts installed at CCNPP. Additionally, if any such bolting were installed in improper applications, it would have failed due to stress corrosion cracking soon after installation rather than after many years. 'Ihese failures would have been detected by routine aad programmatic inspections, e.g., NRC IE Bulletins 79-02 and 7914, and 151. Ilowever, due to the industry experience documented in the above referenced EPRI report, stress corrosion cracking is considered to be plausible for pressurizer support bolting and safety injection tank support bolting only. [ Reference 2, Pages 2-4,3 16; and Reference 2, Page 2 10, Notes 2,6) As shown in Table 3.13, stress corrosion cracking of high strength bolts is considered to be plausible for frames, saddles inside containment, and LOCA restraints. [ Reference 2, Page 2-9] The pressurizer support bolting is categorized under LOCA restraints, and the safety injection tank support bolting is categorized under frames and saddles inside containment. The resultant aging effects would be cracking and failure of bolt material. If this aging mechanism were left unmanaged, the efTects could progress to the point ofinsuflicient support afTorded to the components I and/or allowing excessive movement of the components. This failure of the component supports' intended function could, in tum, lead to failure of supported component function under CLB conditions, i [ Reference 2, Pages 5 4 and 611]
. Group 7 - (Frames and Saddles (inside containment) / LOCA Restraints - Stress Corrosion Cracking of High Strength Bolts)- Methods to Manage Aging Effects Mitication The c(Tects of stress corrosion cracking of high strength bolts have been mitigated as much as practical by the original selection of materials. The only reported instances of stress corrosion cracking in th;; i material were associated with improper heat treatment or improper material, if such conditions existed at CCNPP, failures would have been experienced soon after installation rather than after many years.
Therefore, it is not necessary to provide any additional specific mitigation methods. [Referenn 7, Pages 2-4 and 2-10} Application for License Renewal 3.1-42 1 Calvert Cliffs Nuclear Power Plant 1 a
. . .. - _ _ - .- _. . - - _ . ~ . _ - - - . . - _ - - -.
ATTACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS Discoverv The effects of stress corrosion cracking of high streyth bolting are observable in the form of cracking and failure of bolt material. These conditions would be readily observable during a visual inspection. [ Reference 2, Page 5-4) Group 7 - (Frames and Saddles (Inside containment) / LOCA Restraints - Stress Corrosion i Cracking of High Strength Bolts)- Aging Management Program (s) Mitigation-Here are no CCNPP programs credited for mitigation of stress corrosion cracking of high strength bolts. Discoverv ' i For discovery, the level of aging management activity needed for each category of component supports is ! determined based on the condition observed during a baseline walkdown of a representative sample of supports of each category. Therefore, discovery activities are discussed in two categories, baseline activities and follow-on aging management activities. The as found condition during the baseline walkdown dictates the level of follow-on aging management needed for the support type [ Reference 2, Page 6-1 through 6 5] Baseline Walkdowns Loss-of-coolant accident restraints (pressurizer support bolting) are subject to baseline inspection under the ISI Program. These completed Isis serve as an adequate baseline activity to document the condition of these component supports, anri the results of the Isis are maintained at CCNPP. [ Reference 2, Page 6-12] The purpose, scope, bases, etc., for the ISI are described above in the subsection. Group I - Aging Management Programs. For the frames and saddles (safety injection tank support bolting), an inspection of the safety injection tank anchor bolting is required, nis inspection will be performed using Section XI ISI procedures and techniques even though safety injection tanks are not within normal Section XI ISI scope. His additional sampling baseline walkdown will inspect the safety injection tank anchor bolts for active ARDMs and will document the condition of the anchor bolting. The inspections will be conducted m accordance with the ISI criteria stated above in the subsection, Group 1 - Aging Management Programs. [ Reference 2, Page 611] Follow-on Activities Based on the results of baselinr inspections completed per the existing ISI Program requirements, it was determined that continuing A5ME Section XI ISIS into the period of extended operations will also serve as an adequate follow-on activity for LOCA restraints (pressurizer support bolting) subject to that program. [ Reference 2, Page 5-4] For frames and saddles (safety injection tank support bolting), the results of the additional baseline walkdowns described above will determine the extent of aging management practices needed for these supports. [ Reference 2, Page 61l) Application for License Renewal 3.1-43 Calvert Cliffs Nudear Power Plant
. - . =
4 ATTACHMENT (1) APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS i Group 7 - (Frames and Saddles (inside containmen') / LOCA Restraints - Stress Corrosion l Cracidag of High Strength Bolts) . Demonstration of Aging Management Dased on the information presented above, the following conclusions can be reached with respect to stress corrosion cracking of high strength bohs for frarres, saddles, and LOCA restraints. ' Group 7 supports associated with components in the scope of license renewal are themselves considered to be with'a the scope oflicense renewal because failure of these supports could lead to failure of the supported plant component, e Stress corrosion crackfrig of high strength bolts was determined to be a plausible ARDM for the specific Group 7 supports discussed above. He effects of the ARDM are cracking and failure of bolt material that lead to loss of stnictural adequacy and subsequent loss of strength of the component support. These effects, ifleft unmanaged, could lead to loss of the intended function of the component suppons and ultimately to failure of the suoported plant component under CLB conditions, e Baseline discovery programs include elements that would enable these activities to discover the effect of this plausible aging mechanism and to determine the appropriate level of follow-on aging management activities. The Group 7 supports are either covered by these baseline inspections or additional baseline inspections will be conducted. Follow-on discovery activities include continued Isis and follow on actions dependent on the results of the a~dditional baseline walkdowns. These ectivities include elements that would ensure discovery of the effects of this plausible aging mechanism and require corrective action and actions to prevent recurrence of problem conditions, as appropriate. Group 7 suppons within the scope oflicense renewal are subject to follow on discovery activities. Re discovery aging management activities (Isis, additional baseline walkdowns) detect and correct any adverse effects of stress corrosion cracking of high strengtn bolts. Therefore, there is reasonable assurance that the effects of aging will be adequately managed such that the frames, saddles, and LOCA restraints will be capable of performing their structural support function consistent with the CLB during the period of extended operation. I 3.1.3 Conclusion The programs discussed for aging management of component supports are listed in the fcilowing table.
}
These programs are (or will be for new programs) administratively controlled by a formal review and approval process. As demonstrated above, these programs will manage the aging mechanisms and their { effects such that the intended function of the Component Suppods will be maintained consistent with the CLB during the neriod of extended operation. The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL-2, " Corrective Actions Program." QL 2 is pursuant tc 10 CFR Part 50, Appendix B, and covers all structures and components subject to AMR. Application for License Renewal 3.1-44 Calvert Cliffs Nuclear Power Plant
# _ __ _J
, ATTACHMENT (1) APPENDIX A - TECIINICAL INFORMATION l 3.1 COMPONENT SUPPORTS 1 IAMLE 3.1-4 LIST OF AGING MANAGEMENT PROGRAMS FOR COMPONENT SUPPORTS Program (s) Credited For. I Existing Snubber Visual inspection Surveillances Follow-on discovery activity for snubber supports within the scope of this commodity evaluation. Applies to Group 1. l Existing Plant Engineering Guideline on System Follow-on discovery activities for component Walkdowns(PEG 7) supports covered by completed SVP Control of Shift Activities (NO-1200) walkdowns, and for component supports Ownership of Plant Operating Spaces inspected by Additional Baseline Walkdowns (NO 1 107) (if no active ARDMs are found during additional walkdowns). Applies to Groups I through 6. Existing Section XI ISI Program Baseline and follow-on discovery activities l for component supports covered by this program. Applies to G.vups 1, 2, and 4 through 7. Modified Preventive Maintenance Checklists Follow-on discovery activity for containment air cooler fans (metal spring isolators and l fixed bases inside containment). Applies to Group 2. New ARDI Program Baseline walkdown and follow-on activities for 24 inaccessible piping supports outside containment. Plausible ARDMs for these supports are general corrosion, load:ng due to hydraulic vibration, and loading due to thermal expansion. Applies to Group 1. New Additional Baseline Walkdowns Baseline discovery activity for the component supports not covered or only partially covered by the SVP or the ISI Program, where conditions prevented extrapolation of results to cover these component supports. Applies to Groups I,2, and 7. New Plant Modification Modification of Control Room IIVAC air handler supports to replace elastomer isolators with spring type isolators. Applies t: Group 3. Application for License Renewal 3.1 45 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1) l APPENDIX A - TECHNICAL INFORMATION
- 3.1 - COMPONENT SUPPORTS 3.1.4 References 1.
CCNPP Integrated Plant Assessment Methodology, Revision 1, January 11,1996 2.
"Calvert Clifts Nuclear Power Plant, Aging Management Review of Component Supports,"
Revision 3, January 1997
- 3. CCNPP Updated Final Safety Analysis Report, Revision 19
- 4. CCNPP Engineering Standard ES 040," Piping Design Criteria," Revision 0, Decensber 1995 ,
S. CCNPP Engineering Standard ES-014. " Summary of Ambient Environmental Service i 1 Conditions," Revision 0, Nov mber 8,1995 6. Letter from Mr. C. J. Cowgill (NRC) to Mr. G. C. Creel (BGE), dated July 12,1990, "NRC Region i Resident inspection Report Nos. 50-317/90-13 and 50-318/90-13 (June 3,1990 to j June 30,1990)" 7. Letter from Mr. R. E. Denton (BGE) to NRC Document Control Dest, dated August 17,1990,
" Licensee Event Report 89-07. Revision 1"
, 8. Letter from Mr. R. W. Reid (NRC) to Mr. A. E. Lundvall, Jr. (BGE), dated March 10,1980, Transmittal of License Amendment Nos. 42 and 25
- 9. Letter from Mr. R. E. Denton (BGE) to Mr. D. II. Jaffe (NRC), dated July 20, 1984,
" Additional Information Regarding Steam Generator V'ater llammer Event"
- 10. Letter from Mr. A. W. Drcmcrick (NRC) to Mr. C.11. Cruse (BGE), " Issuance of Amendments for Calvert Cliffs Nuclear Power Plant, Unit 1 (TAC No. M92549) and Unit 2 (TAC No. M92550)," dated December 10,1996 [ Amendment Nos. 217/194]
- 11. 10 CFR 50.55a, Conditions of Construction Permits s 12. American Society of Mechanical Engineers Boiler and Pressure Vessel Code Section XI,1983 Edition through Summer,1983 Addenda 13.
NRC Regulatory Guide 1.147, " Inservice inspection Code Case Acceptability - ASME I Section XI, Division 1" 14. NRC Generic Letter 88-05," Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in Power Plants," dated March 17,1988 15. CCNPP Administrative Procedure MN 3, " Pressure Boundary Codes and Special Processes Program"
- 16. CCNPP "1995 Unit #2 ISI Outage Summary Report," Report Generated by CCNPP Procedure MN 3-110, dated July 13,1995
- 17. CCNPP "1996 Unit #1 ISI Outage Summary Report," Report Generated by CCNPP Procedure MN 3-110, dated October 16,1996
- 18. Letter from Mr. A. E. Lundvall, Jr. (BGE) to Dr. T. J. Murley (NRC), dated October 19,1984, "I&E Bulletins 79-02,79-04,79-07 and 7914" 19.
CCNPP Plant Engineering Section Guideline PEG 7, " System Walkdowns," Revision 4, November 1995 Application for License Renewal 3.1-46 Calvert Clifts Nuclear Power Plant
I NITACIIMENT (1) i APPENDIX A - TECHNICAL INFORMATION 3.1 - COMPONENT SUPPORTS
- 20. CCNPP Engineering Standard ES Ou2, " Pipe Support inspection," Revision 0, October 11,1995 i
- 21. CCNPP Administrative Procedure NO 1200, " Control of Shift Activities," Revision 8, September 10,1996
- 22. CCNPP Administrative Procedure NO-1 107, " Ownership of Plant Operating Spaces," <
Revision 2, October 28,1996 l l
- 23. 10 CFR 50.54, Conditions of Licenses
- 24. 10 CFR Part 50, Appendix R. Fire Protection 1 rogram for Nuclear Power Facilities Operating l
Prior to January 1,1979 '
- 25. 10 CFR Part SS, Operators' Licenses
- 26. INPO 84 021 (OP 204)," Conduct of Operations," Revision 1, July 1991
- 27. INPO 84 030 (OP 206)," Generic Round Sheets and Shift Operating Practices," Revision 2, June 1991
- 28. INPO 85-017 " Guidelines for the Conduct of Operations at Nuclear Power Stations,"
Fevision 2, April 1992
- 29. INPO 87 018 (OP-212)," Operations Communications Verbal," June 1985
- 30. INPO SOER 87-01, " Core Damaging Accident Following an Improperly Conducted Test,"
February 20,1987
- 31. NRC IE Circular 80-21, " Regulation of Refueling Crews," dated September 10,1980
- 32. NUREG 0737," Clarification of TMI Action Plan Requirements," November 1980
- 33. CCNPP Adn'inistrative Procedure NO-1," Nuclear Operations Program" 34 Regulatory Guide 1.114," Guidelines on Being the Operator at the Controls of a Nuclear Power Plant"
- 35. CCNPP Administrative Procedure QAP 92 15," Policy for Control Room Watch Coverage"
- 36. INPO 87-023, Good Practice MA 312, " Plant inspection Program", October 1987
- 37. CCNPP Fourth Quarter Safety Performance Evaluatici. 1995
- 38. CCNPP Technical Procedure STP M 121, " Unit 1 Acce sible Snubber Visual Inspection,"
Revision 13, January 29,1997
- 39. CCNPP Technical Procedure STP-M 12 2, " Unit 2 Ac.:essible Snubber Visual Inspection,"
Revision 14, January 3,1996
- 40. CCNPP Technical Procedure STP M 13-1, " Unit ! Inaccessible Snubber Visual Inspection,"
Revision 16, January 30,1997
- 41. CCNPP Technical Procedure STP M-13-2, " Unit 2 Snubber inspection (Inaccessible),"
Revision 13, January 3,1996 Application for License Renewal 3.1-47 Calvert Cliffs Nuclear Power Plant
4 ATTACllMENT (1)
~
APPENDIX A - TECilNICAL INFORMATION 3.1 - COMPONENT SUPPORTS 42, Generic Implementation Procedure (GIP) for Seismic Verification of Nuclear Plant Equipment, dated February 1992, copyright Seismic Qualification Utility Group (SQUG), Revision 2, corrected February 14,1992
- 43. Engineered Materials llandbook, Volume 2, " Engineering Plastics," ASM International 1988 i
1 ( J L Application for License Renewal 3.1-48 Calvert Cliffs Nucicar Power Plant
., l ATTACHMENT (2) i l-i i
i 4 1 1 i 4 APPENDIX A - TECHNICAL INFORMATION i s 3.2 - FUEL HANDLING EQUIPMENT AND OTHER I j HEAVY LOAD HANDLING CRANES ' 1 4 4 e i 1 i. l; Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant October 22,1997
ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2 FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES 3.2 Fuel Handling Equipment and Other Heavy Load Handling Cranes This is a section of the Baltimore Gas and Electric Company (BGE) License Renewal Application (LRA), addressing Fuel Handling Equipment (FHE) and other Heavy Load llandling Cranes (HLHC). The FHE and ilLHC were evaluated as a " commodity" in accordance with the Calvert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. These sections are prepared independently and will, collectively, comprise the entire BGE LRA. 3.2.1 Fuel Handling Equipment and other Heavy Load Handling Cranes Commodity Seoping The system level scoping results identified Eve systems within the scope of license renewal that are related to File and HLHC. Because the only intended functions of these five systems are structural in nature, these five systems are included in a commodity evaluation instead of being addressed individually in the standard IPA process. The five systems are listed below: [Referecce 1, page 68]
- Spent Fuel Storage;
- Refueling Fool; e New Fuel Storage and Elevator;
- Fuel Handling; and l
- Cranes This section begins with a description of the five systems that are related to FHE and HLHC. The intended functions of FHE and HLHC are listed and used to identify the components within the scope of license renewal (i.e., those required to perform the intended functions). Finally 'he components subject to Aging Management Review (AMR) are identified and dispositioned in accordance with the CCNPP IPA Methodology.
Representative historical operating experience pertinent to aging is included in appropriate areas to provide insight supporting the aging management demonstrations. This operating experience was obtained through key-word searches of BGE's electronic database ofinformation on the CCNPP dockets, and through documented discussions with currently assigned cognizant CCNPP personnel. Commodity Descrintion/Concentual Boundaries in general, the CCNPP IPA Methodology for structures addresses all structural support functions for equipment housed by a particular structure. [ Reference 1, Section 7.2.2] However, because of the effect that their failure could have on plant operations, this section of the BGE LRA presents evaluations for (a) components involved in fuel handling and transfer; and (b) cranes that routinely lift heavy loads over safety-related components. There are five systems at CCNPP with components that comprise the FHE and HLHC: Spent Fuel Storage, Refueling Pool, New Fuel Storage and Elevator, Fuel Handling, and Cranes. [ Reference 2] e Spent Fuel Storage: The Spent Fuel Storage System, also referred to as the spent fuel pool (SFP), is divided into two halves and is located in the Auxiliary Building. The pool is constructed of reinforced concrete and lined with stainless steel. Spent fuel assemblies are placed in stainless Application for License Renewal 3.2-1 Calvert Cliffs Nuclear Power Plant A - _ _ -
ATTACHMENT m 4 APPENDIX A - TECIINICAL INFORMATION 3.2-FUEL liANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES steel storage racks grouped in parallel rows, Cooling is provided by the SFP Cooling System. [ Reference 3, Scction 9.7.2.1] Additional components in the SFP include the following: Spent Fuel Shipping Cask Support Platform - The spent fuel shipping cask pit is located on the Unit I side of the dividing wall in the SFP. The Door of the pit is equipped with an energy. absorbing cask support platform that accommodates the various transfer casks used at CCNPP, and provides a second level of protection for the Door cf the SFP beyond that provided by the single-failure-proof crane. The platform is comprised of a stainless steel shell that encloses an aluminum honeycomb material which can absorb the impact energy of a spent fuel cask dropped from the single-failure-proof crane. [ Reference 3, Section 9.7.2.3] Spent Fuel Pool Platform - The SFP platform is a portable work platform with removable railings that provides an efficient work site for various maintenance activities involvir.g fuel assemblies. These have included .epair of worn fuel assembly guide tubes, eddy current tests, capsule exchanges, and fuel assembly reconstitution. The aluminum work platform is supported by stainless steel structural members and can be located along the west wall of the north (Unit 1) pool, or the east wall of the south (Unit 2) pool. [ Reference 3, Section 9.7.2.8] e Refueling Pool: The refueling pool is formed when the refueling cavity around the upper portion of the reactor vessel (RV) is filled with water from the refueling water tank via the SFP cooling pumps. The refueling pool is constructed of reinforced concrete and lined with stainless steel.
%e refueling pool ieterfaces with the SFP via the fuel transfer tube, the Safety injection System, and the Spent Fuel Pool Cooling System. [ Reference 4. Table 1] A four rell incore instrumentation ('CI) trash rack is located in the lower portion of each unit's refueling canal adjacent to the upender machine. Containers of discarded ICI waste or new/ spent fuel assemblies are temporarily placed in this stainless steel rack to facilitate handling during refueling.
[ Reference 3, Section 9.7.2.2] e New Fuel Storage and Elevator: The New Fuel Storage and Elevator System consists of the new fuel dry storage racks and the new fuel inspection machine (the new fuel inspection platform), it does not include the new fuel elevator which is in the Fuel Handling System discussed below. The new fuel inspection machine is located near the new fuel storage area. The machine is designed to automatically check the straightness and sectianal size of a fuel bundle through its full length. [ Reference 2, Section 1.1.1; Reference 5] e Fuel Handling: The Fuel Handling System includes those componems used to move fuel from the time of receipt of new fuel to the storage of spent fuel in the SFP. The system includes: New Fuel Elevator - The new fuel elevator lowers new fuel assemblies into the SFP where the spent fue: handling machine (SFHM) is able to grapple and transfer the fuel to the desired pool . location. The new fuel elevator is located in the Unit i end of the SFP. [Referenci,3, Section 9.7.2.7] , Spent Fuel Handling Machine - The SFHM, also referred to as the fuel pool service platform, is a bridge and trolley arrangement that rides on rails set in concrete on each side of the SFP. The SFHM functions to transfer fuel between the storage locations in the SFP, the new fuel elevator, the spent fuel inspection elevator, the SFP upending machine, or a spent fuel shipping cask, as necessary. [ Reference 3, Section 9.7.2.7] Application for License Renewal 3.2-2 Calvert Cliffs Nuclear Power Plant i i
ATTACHMENT d) APPENDIX A - TECIINICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTIfER llEAVY LOAD IIANDLING CRANES Fuel Upending Machines - There are two fuel upending machines for each unit, one in the Containment Structure refueling pool and the other in the SFP. Each consists of a structural steel support base from which an upending straddle frame is pivoted. The straddle frame engages the fuel carrier. When the carriage with its fuel curier is in position within the upending frame, the pivots for the fuel carrier and the upending frame are coincident. Ilydraulic cylinders attached to both the upending frame and the support base rotate the fuel carrier between a vertical and horizontal position, as required, [ Reference 3, Section 9.7.3.2] During the 1996 Unit I refueling outage, four fillet welds connecting structural members on the fuel upending machine in the refueling pool failed. It was determined that original joint design, original fabrication, and nibsequent changes to machine operations led to low-cycle fatigue failure of the welds. A nodal analysis of the fuel upending machine design determined that addition of stiffeners at the weld joints and use of dual hydraulic cylinders for machine 4 operation would make future fatigr failure of these welds unlikely. These recommendations were implemented for both fuel upending machines in Unit 2, and will be completed for the fuel upending machines in Unit 1 prior to their next scheduled use in moving fuel. Since normal service loads result in stresses that are far below the allowable stress range for the modified stainless steel structural members, fatigue is not plausible for these File subcomponents. [ Reference 2, Attachment 6] Transfer Carriage - The transfer carriage transports one or two fuel assemblies through the transfer tube between the refueling pool and the SFP. The carriage is driven by stainless steel cables connected to the carriage and through sheaves to its driving winches mounted below the , operating floor level. The fuel carrier is mounted on the carriage and is pivoted for tilting by the upending machines. [ Reference 3, Section 9.7.3.2] Reactor Refueling Machine - The reactor refueling machine (RRM) is a traveling bridge and trolley that spans the refueling pool and moves on rails. The bridge and trolley movement allow coordinate location for the fuel handling mast and hoist assembly over the fuel in the core. [ Reference 3, Section 9.7.3.1] The RRM mast and hoist assembly is used for transporting and positioning fuel assemblies in the core and over the upending machine in the refueling pool. The RRM auxiliary hoist is used in conjunction with the control element , assembly handling tool to exchange control element assemblies within the reactor core during refueling. [ Reference 3, Section 9.7.3.3] Spent Fuel Inspection Elevator - The spent fuel inspection elevator is similar to the new fuel elevator, but is equipped with a fixed underwater periscope. Fuel assemblies are raised and lowered in front of the periscope to permit fuel inspection. The spent fuel inspection elevator has additional design features to prevent the hoist from raising fuel above the point where adequate water for shielding is available. The spent fuel inspection elevator is located in the Unit 2 end of the SFP. [ Reference 3, Section 9.7.2.7; Reference 6)
. Cranes: Th: Crane System consists of all cranes, monorails, and hoisting and jib equipment at CCNPP. This includes approximately 85 cranes, which can be grouped into three types:
overhead gantry cranes, monoreil systems und underhung cranes, and overhead hoists, The mechanical components of the Crane System include overhead monorail systems, cranes, monorail tracks, carriers or trolleys, motor-driven electric hoist carriers, gears, hoists, hooks, bridges, and lift-drop sections. Electrical components include motors, connectors, contactors, electric lift and drop sections, motor starters, and control panels. [ Reference 2, Section 1.1.1] Application for License Renewal 3.2-3 Calvert Cliffs Nuclear Power Plant
ATTAClIMENT (2) ' APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES In addition to the components described above, this section of the BGE LRA addresses the structural load handling devices designed to transfer the loads of the RV head to the polar crane (PC). These items are the RV cooling shroud (part of the Primary Containment Heating and Ventilating System -- see Section 5.11 of the BGE LRA), and the RV head lifl rig (part of the Reactor VUssel internals System -- see Section 4.3 of the BGE LRA). [ Reference 2, Section 1.1.1; Reference 4, Table 1] , Sconed Structures and Comoonents and Their Intended Functions The FHE and HLHC is in scope for license renewal based on 10 CFR 54.4(a). The following intended functions of the FHE and HLHC were determined based on the requirements of s54.4(a)(1) and (2) and in accordance with the CCNPP IPA Methodology Section 7.2.2: [ Reference 2]
- Provide structural and/or functional support to safety related equipment;
- Provide structural and/or functional support to non safety-related equipment whose failure could i directly prevent satisfactory accomplishment of any of the intended safety related fune ms; and
- Suppert single-failure-proof criteria for IKting heavy loads over the SFP.
No intended functions of the FHE and HLHC were determined based on the requirements of Q54.4(a)(3). Comoonents Subject to AMR The IPA procedure was used to identify all components that provided at least one of the structural intended functions listed above. From all components in the five systems that comprise this commodity, those that are subject to AMR were determined as follov's-
- Structural components and subcomponents that perform the first function listed above are the Spent Fuel Cask Handling Crane ([SFCHC] discussed separately below), the SFP (reinforced l concrete and steel liner), the refue:ing poci (reinforced concrete and steel liner), the fuel transfer tube (steel liner), the spent fuel shipping cask support platform, and storage racks for new fuel, spent fuel, and ICI waste. [ Reference 2, Attachment 2] These items are classified as safety-related in the CCNPP Quality List, and are required to meet Seismic Category I criteria because they must remain functional before, during, or after a safe shutdown earthquake. [ Reference 7, pages 46,57,58,68,82, and 83]
- Structural subcomponents of the following items perform the second function listed above:
[ Reference 2, Attachment 2] The SFP Platform; The equipment involved in fuel handling and transfer (i.e., the spent fuel inspection elevator, ! the new fuel elevator, the fuel upending machines, the RRM, and the SFHM); The load handling equipment used for RV head removal / installation (i.e., the RV head lift rig and the RV cooling shroud); and Those cranes at CCNPP that are subject to the general guidelines of NUREG-0612, " Control of Heavy Loads at Nuclear Power Plants Resolution of Generic Technical Activity A-36" (i.e., the PC, the intake Structure Semi-Gantry Crane (ISSGC), and the Transfer Machine Jib Crane). Application for License Renewal 3.2-4 Calvert Cliffs Nuclear Power Plant
- - - _ - _ _ - -~- . .
ATTACHMENT d) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES NOTE: These three cranes handle heavy loads (i.e., loads in excess of 1600 lbs.) in the vicinity of the RV, near spent fuel in the SFP, or in areas where a load drop may damage safe shutdown 'or decay heat removal equipment. Other components in the Cranes System are excluded from the restrictions of NUREG 0612 because (1)the lift points and the safe shutdown equipment are adequately separated; or (2) the largest load lified is not a heavy load. [ Reference 3, Section 5.7] These items are functionally non-safety-related, but must be considered safety-related on a structural basis only. They are categorized as Seismic 11/1 at CCNPP because their failure or excessive movement could cause failure of a safety-related structure, system, or component. (Reference 7, pages 62,68,82,83, and 92]
- Structural subcomponents of the SFCilC rarform the first and third functions listed above.
(Reference 2, Attachment 2] This crane is designed in accordance with the single failure-proof criteria of NUREG-0554," Single Failure Proof Cranes for Nuclear Power Plants," and NUREG-0612. [ Reference 3, Section 5.7] Per the license renewal rule, ". . , Structures and components subject to an aging management review shall encompass those structures and components (i) That perform an intended function, as described in Q54.4 without moving parts or without a change in configuration or p.w ties . . . and (ii) That are not subject to periodic replacement based on a qualified life or specified time period . . . " The scoping process determined that some structural devices, such as drums, hydraulic cylinders, and wheels, aerformed their intended func: ion (s) while in motion. Such devices were considered to be active subcomponents and were eliminated from AMR. [ Reference 2, Attachment 1] It was conservatively assumed that no structural components or subcomponents in the FHE and ilLHC were replaced based on time or qualified life. [ Reference 1, page 69] Based on the results of the process described above, the portion of the FHE and HLHC that is within the scope oflicense renewal and subject to AMR includes 57 structural components and their supports. Some of the FHE and HLHC components were already addressed for their structural intended ftmetion(s) as parts of the buildings in which they are housed in Section 3.3 of the BGE LRA, and are therefore not covered in this section. These components are listed below:
- PC Girders;
- SFCHC Rail / Support Girders; e Refueling Pool Reinforced Concrete;
- Refueling Pool Stainless Steel Liner;
- Fuel Transfer Tube Stainless Steel Liner; e Spent Fuel Pool Reinforced Concrete;
- Spent Fuel Pool Stainless Steel Liner;
- Spent Fuel Pool Storage Racks; nnd
- New Fuel Storage Racks.
Application for License Renewal 3.2-5 Calvert Cliffs Nuclear Power Plant
. __ _ - . ~ .- .- . _ - _ .
ATTACilMENT (2) APPENDIX A - TECIINICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES The remaining 48 components, listed in Table 3.21, are subject to AMR and are evaluated within this section. Baltimore Gas and Electric Company may elect to replace componnts for which the AMR identifies that further analysis or examination is needed. In accordance with the License Renewal Rule, components subject to replacement based on qualified life or sp:cified time period would not be subject to AMR. 3.2.2 Aging Management The list of potential Age-Related Degradation Mechanisms (ARDMs) identified for the File and llLilC components is given in Table 3.21, with plausible ARDMs identified by a check mark (/) in the appropriate component row. [ Reference 2, Tables 4-1 and 4 3] For efficiency in presenting the results of these evaluations in this report, ARDM/ component combinations are grouped together where there are similar characteristics and the dis;ussion is applicable to all components within that group. Table 3.2-1 also identifies the group to which each ARDM/ component combination belongs. The following groups have been chosen for the components of the FliE and 11LHC: Group 1: General Corrosion /Oxidatloa for File and llLHC carbon steel components (i.e., all except the RV cooling shroud structural support members); Group 2: General Corrosion / Oxidation and Corrosion due to Boric Acid for the RV cooling shroud structural support members; Group 3: Fatigue for the PC rails; and Group 4: Fatigue. Wear. and Mechanical Degradation / Distortion for wire rope. t Application for License Renewal 3.2-6 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (2)
~
APPENDIX A - TECHNICAL INFORMATION 3.1-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES TABLE 3.2-1 ! POTENTIAL AND PLAUSIBLE ARDMs FOR THE FHE AND HLHC SYSTEM Genersi ' Fitting / SCC /- - Elevated % N88 ' Corrueise FHE/HLHC Components Cerronese Crevice . IGSCC/ MIC Teenp- Irradiaties Fatigue Wear ~ Degreds- g,, g, g%
/ Corressee ICA erstere . 85 # Beric Acid Oxidaties h Spent Fuct Shipping Cask SS Support Platform ICI Trash Racks SS Structural Members Spent Fuel Pool Platform SS Structural Members Spent Fuel Inspection Elevator subcomponents (Unit 2 only):
- SS Structural Members
- SS Iloisting Ropes /(4) /(4) /(4)
New Fuel Elevator subcomponents (Unit I only):
- SS Structural Members
- SS Iloisting Ropes /(4) /(4) /(4)
Fuel Upending Machine and Transfer Carriage subcomponents:
- SS Structural Members
- SS Iloisting Ropes & Drive Cables /(4) /(4) /(4) y RRM subcomponents:
- CS Rails. Clips, Spacers, Bolts & Stops /(1)
- CS Bridge End Trucks & Axles /(1)
- CS Bridge Girders /(1)
- CS Trolley Rails /(1)
- CS Trolley Structural Members /(I)
- CS Auxiliary lloist Frame /(1)
- SS Iloisting Ropes /(4) /(4) /(4) :
SFilM subcomponents:
- CS Rails Clips, Spacers, Bolts & Stops /(1)
- CS liridge End Trucks & Axles /(1)
- CS Bridge Girders /(1) i
- CS Trolley lu . /(I)
- CS Trolley Structural Support Members /(1)
- SS Iloisting Ropes /(4) /(4) /(4) j Application for License Renewal 3.2-7 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2- FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES TABLE 3.2-1 (continued) POTENTIAL AND PLAUSIBLE ARDMs FOR THE FHE AND HLHC SYSTEM Ceneral Pitting / ' SCC / . Elevsted . Se,,,, M8'esecal c ,,,,,,, ; FHFJHLHC Components - Corresies ~ Crevice IGSCCl MIC Teenp. Irradiation g,g Fatigee ' Wear . Degrads- g,, ,, , Corressee 1GA 808 " #
/ .erstere Berie Acid Osidaties Distortwo SFCllC subcomponents:
- CS Crane Rails, Clips, Bolts & Stops /(I)
- CS liridge End Trucks /(1)
- CS Bridge Girders /(1)
- CS Trolley Rails /(1)
- CS Trolley Structural Support Members /(1)
- IPS Iloisting Ropes (Main iloist) /(1) /(4) /(4) /(4)
- SS lioisting Ropes (Auxiliary lloist) /(4) /(4) /(4)
PC subcomponents:
- CS Crane Rails, Clips, Bolts & Stops /(1) /(3)
(Rails only)
- CS 11 ridge End Trucks /(1)
- CS Bridge Girders /(1)
- CS Trolley Rails /(I)
- CS Trolley Structural Support Members /(1)
- Alloy Steellloisting Ropes /(1) /(4) /(4) /(4) '
ISSGC subcomponents:
- CS Rails, Clips, Ilotts & Stops /(I)
- CS Gantry End Trucks /(1)
- CS Gantry Structural Members /(1)
- CS Ilridge Girders /(1)
- CS Trolley Structural Support Members /(I)
- CS Trolley Rails /(1)
- IPS Iloistmg Ropes /(1) /(4) /(4) /(4) l Application for License Renewal 3.2-8 Calvert Clifts Nuclear Power Plant
ATTACHMENT (2) -
~
APPENDIX A - TECHNICAL-INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES TABLE 3.2-1 (continued) POTENTIAL AND PIJUSIBLE ARDMS FOR THE FHE AND HLHC SYSTEM
- General Pseting / . ' SCC / . Elevated . ge,,,, N Ce m eien FHE/HLHC Components:' Corresses : Crevice ICSCC/, .MIC: Temp.) Irradinha Fasigue - ; Wear - Degrads- . 4,, ,, :
g,g
/ Corrosion ? IGA: rate e .- 838 8 # . MM
. ~u .
, m Transfer Machine Jib Crane subupi cnts: ,
- CS Structural Members /(1)
- CS Boks /(1)
~
- SS Iloisting Ropes /(4) /(4) /(4) ;
l Load llandling Equipment used for RV llead Removal /Instaiiation-
- RV licad Lift Rig /(I)
- RV Coolmg Shroud CS Structural Support /(2) /(2)
Components flooks for allllLilC /(I) , f
/ - indicates plausible ARDM determination Co..3.v.arns ARDMs ]
(#) - indicates the group (s)in which the File - Fuelllandling Equipment IGA - Intergranular Attack ARDM/ component combination is evaluated IILIIC - IIcavy Lead IIandling Cranes IGSCC - Intergranular Stress Corrosion Cracking ICI - Incoce Instrumentation MIC - Microbiological!y-Induced Corrosion ISSGC - Intake Structure Semi-Gantry Crane . SCC - Stress Corro-ion Cracking PC - Polar Crane RRM - Reactor Refueling Machine Matenals RV - Reactor Vessel CS - Carbon Steel SFCIIC- Spent Fuel Cask llandling Crane iPS - Improved Plow Steel SFIIM - Spent Fuelliandling Machine SS - Stainless Stect Application for License Renewal 3.2-9 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (2) APPENDIX A - TECIINICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES The following is a discussion of the aging management demonstration process for each group identified above. It is presented by group and includes a discussion of materials and environment, aging mechanism effects, methods of managing aging, aging management program (s), and aging management demonstration. Group 1 - (general corrosion / oxidation for FHE and HLHC carbon steel components)- Materials and Environment The components of the FHE and HLHC for this group are fabricated of various grades of steel. [ Reference 2, Attachment 3] Austenitic stainless steel and nickel-base alloys are quite resistant to general corrosion / oxidation. [ Reference 2, Attachment 5] Therefore, general corrosion / oxidation is considered a potential ARDM only for those components constructed of carbon steel, improved plow steel, or alloy steel. Except for the ISSGC, the structural components in Group I are exposed to climate-controlled environments inside the Containment and Auxiliary Buildings, inside Containment, the maximum design relative humidity and ambient air temperature for normal plant operations are 70% and 120'F, respectively. [ Reference 8, page 62] In the Auxiliary Building, components in this group are subjected to a maximum design temperature of Il0'F, with a maximum relative humidity of 70%. [ Reference 8, pages 54 through 59] Scme FHE and HLHC components are locate <l near the SFP, where condensation in the presence of oxygen could lead to oxidation. Additionally, some places can harbor pockets of liquids that may be inaccessible for visual inspection without removing interference. Carbon steel located in these areas may be subjected to more severe local environments. [ Reference 2, Attachment 6] The ISSGC is subjected to the outdoor environment above the intake Structure. There is no heavy industry nearby CCNPP to add chemicals to the atmosphere but, due to the close proximhy of the Chesapeake Bay, the ISSGC could be exposed to condensation and saltwater. [ Reference 2,
- Attachment 6; Reference 3, Sections 2.8 and 2.10]
Since corrosion was considered a potential degradation mechanism for all structural steel components, its effects were considered in the original design of the FHE and HLHC components. As a result, all exposed structural steel surfaces of these components in the Containment, Auxiliary Building, and intake Structure received a protective coating during the construction phase. [ References 9 through 17] Additionally, lubricants were specified for improved plow steel and alloy steel hoisting rupes. [ References 10 and 14] Group 1 - (general corrosion / oxidation for FHE and HLHC carbon steel components) - Aging Mechanism Effects General corrosion / oxidation is the thinning of metal by chemical attack at its surface by an aggressive environment of moisture and oxygen. Steel corrodes in the presence of moisture and oxygen as a result of electrochemical reactions. Initially, the exposed steel urface reacts with oxygen and moisture to form an oxide film as rust. Once the protective oxide film has been formed and if it is not disturbed by erosion, altemating wetting and drying, or other surface actions, the oxidation rate will diminish rapidly with time. Chlorides increase the rate of corrosion by increasing the electrochemical activity. [ Reference 2, Attachment 5; Reference 18, Attachment 1] Application for License Renewal 3.2-10 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES Corrosion products such as hydrated oxides ofiron (rust) form on exposed, unpro'ected surfaces of the steel and are readily visible, 'lhe affected surface may degrade to such an extent that visible perforation may occur, In the case of exposed surfaces of FHE and HLilC carbon steel components with protective coatings, corrosion may cause the protective coatings to lose their ability to adhere to the corroding surface. For wire rope, scrubbing (i.e., rubbing against itself, sides of sheaves, or other objects) may cause removal of the lubricant, in these cases, damage to the coatings can be visually detected well in advance of significant degradation of the steel. Additionally, some carbon steel components could be exposed locally to elevated temperatures (e.g., areas close to motors), which would not affect component function, but may cause the coatings to fail (e.g., paint flaking, lubricant drying out) and allow oxidation to occur. [ Reference 2, Attachment 6] The omloor saltwater atmosphere has afTected the protective coatings of structunt members of the ISSGC, Visual inspections of the ISSGC revealed considerable corrosion on carbon steel curfaces where protective coatings had deteriorated. [ Reference 2, Attachment 6) The results of such visual inspectims are documented and corrective actions taken to repair the surfaces, as needed, if general corrosion / oxidation is left unmanaged for an extended period of time, the resulting loss of carbon steel material could lead to the inability of the structural components identif.ed in Table 3.2-1 to perform their intended functions under current licensing basis (CLB) design loading conditions, [ Reference 2, Attachment 5] Group 1 -(general corrosion / oxidation for FHE and HLHC carbon steel components)- Methods to Manage Aging Mitigation: The effects of corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of external surfaces of steel to an aggressive environment and protecting the external surfaces with paint, lubricant, or other protective coating. Coatings serve as a protective layer, i preventing moisture and oxygen from directly contacting the steel surfaces. [ Reference 2, Attachment 6) Discoverv: The effects of general corrosion / oxidation of carbon steel are detectable by visual inspection. A visual examination by a person familiar with the components can be used to determine general mechanical and structural condition and check for rust. Observing that significant degradation of protective coatings has not occurred is an effective method to ensure that corrosion has not affected the intended function of the structural component. Since the coating does not contribute to the components' intended functions, degradation of the coating provides an alert condition that triggers corrective action before corrosion that affects the components' ability to perform its intended function can occur. The degradation on'the protective coating that does occur can be discovered and monitored by periodically inspecting the carbon steel structural components. Corrective action for failed protective coatings and any actual metal degradation can be carried out as nec:,.",ary. [ Reference 2, Attachment 6] Application for License Renewal 3.2-11 Calvert Cliffs Nucleu Power Plant
NITACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES Group ! - (general corrosion / oxidation for FHE and HLHC carbo's steel components) - Aging Management Program (s) Mitigation: The exposed metal surfaces of carbon steel structural components are covered by protective coatings that mitigate the effects of corrosion. The discovery programs discussed below verify that the protective coatings of carbon steel structural components are maintained. Discovery: Periodic inspection of carbon steel structural FHE and HLHC components for the efTects of general corrosion / oxidation is controlled through a combination of existing and modified operations and maintenance programs. e The Calvert Clifts Operating Manual, NO-1-201, establishes the requirements for implementing and using Operating Instructions as approved, preplanned methods of conducting operations. [ Reference 19] The CCNPP Performance Evaluation Program, NO-1-203, has been established to perform periodic operational checks and obtain readings to detennine equipment performance, as determined by manufacturers' recommen4ations, System Engineers' recommendations, and operating needs. [ Reference 20] These programs address controls for activities conducted as part of daily shift operations, and apply to operators and others who interact with them. [ Reference 21] The Performance Evaluation Program provides for checks of the SFHM, RRM, and associated components prior to refueling campaigns (i.e., defuel/ refuel or fuel shuf0e). The checks for the SFHM are also performed every 90 days. [ References 22 and 23] Calvert Cliffs prricedure PE 0-81-1-0-Q directs performance of checks in accordance with OI-25A, " Spent Fuel Handling Machine," which requires performing a walkdown for foreign material and cleanliness, inspecting the SFHM and associated equipment for damaged, corroded, or deteriorated parts, and checking cleanliness of rail surfaces. [ Reference 24] PE 0-81-2-0-C directs performance of checks in accordance with OI-25C," Refueling Machine," which requires the same activities for each unit's RRM. [ Reference 25] As part of the plant's administrative procedures hierarchy, the Operating Manual and the Performance Evaluation Program have been evaluated by the Nuclear Regulatory Commission (NRC) as part of its rautine licensee assessment activities. The plant's nuclear operations procedures have numerous levels of controls and reviews, including assignment of responsibility for conducting performance evaluations as required, reviewing all the evaluations for accuracy and completeness, and analyz.ing data for trends, if applicable. Specific responsibilities are assigned to BGE personnel for monitoring these programs through periodic audits. These controls provide reasonable assurance that the associated activities will continue to be an eFective method of monitoring the FHE for the effects of general corrosion / oxidation. [ References 19,20, and 21]
= For activities involving load handling at CCNPP, minimum requirements for inspection and testing of load handling equipment are established by MN-1-104," Load Handling." In addition to a visual inspection prior to each use, 'his procedure directs establishment of an annual inspection schedule for visual inspection of cranes, hoists, and wire rope, as well as non-destructive examination (NDE) of hooks for load handling equipment. [ Reference 26, Sections 5.7 A.2 and 5.8.A] All inspections are done by qualified operators who have oeen trained according to American National Standards Institute (ANSI) requirements applicable to the Apolication for License Renewal 3.2-12 Calvert Cliffs Nuclear Power Plant l
ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES type of crane being inspected. (Reference 26, Section 5.1.B] Periodic inspection results must be documented, and deficiencies that would affect the handling capacity of the equipment, including deformed, cracked, or corroded members, as well as damaged wire rope, must be corrected (through repair or replacement) prior to further use. [ Reference 26, Sections 5.8.B and 5.8.C] He procedures in effect at CCNPP comply with NUREG 0612 and the applicable ANSI standards for control of heavy loads. [ Reference 27] The Transfer Machine Jib Crane is used to raise the fuel transfer carriage out of the SFP. This is an infrequent operation which has not been performed to date. [ Reference 28] In accordance with MN 1-104, testing and inspection of this crane is required prior to initial use. Inspection results must be documented, and deficiencies that would affect the handling capacity of the equipment, including deformed, cracked, or corroded members, must be repaired prior to further use. (Reference 26, Sections 5.7.A.3 and 5.8.C] e The CCNPP Preventive Maintenance Program, MN-t 102, has been established to maintain olant equipment, structures, systems, and components in a reliable condition for normal operation and emergency use, minimize equipment failure, and extend equipment and plant life. The program covers all preventive maintenance activities for nuclear power plant structures and equipment within the plant, including those preventive maintenance activities applicable to the cranes, monorails, and hoisting andjib equipment within the scope oflicense renewal. [ Reference 29] Preventive Maintenance Tasks are automatically scheduled and implemented in accordance with Preventive Maintenance Program procedures. [ Reference 29] The following tasks implement the requirements of MN-1-104 by directing periodic visual inspections and/or NDE for the listed FHE and HLHC components: 00992009 for the SFCHC (References 30 and 31] 10992010,2099;002 for Unit 1 Unit 2 PCs (References 32 and 33] 10992007 for the ISSGC [ References 34 and 35] 10642031,20642030 for Unit 1. Unit 2 RV head lift rigs (Reference 36] 4 These preventive maintenance tasks will be modified to specify the applicable carbon steel subcomponents and explicitly present inspection requirements for discovery of degraded coatings and material loss that may be caused by general corrosion / oxidation. [ Reference 2, Attachment 8] The CCNPP Corrective Action Program is used to take the necessary corrective actions to ensure that the applicable components will remain capable of performing their intended functions under all CLB loading conditions. The Preventive Maintenance Program has been evaluated by the NRC as part of its routine licensee assessment activi'ies. The plant Maintenance Program also has had numerous levels of management review, all the way down to the specific implementation procedures. Specific responsibilities are assigned to BGE personnel for evaluating and upgrading the Preventive Maintenance Program, and for initiating program improvements based on system performance. (Reference 29] These assessments and controls p: ovide reasonable a surance that the Preventive Maintenance Program will continue to be an effective method of managing the affects of general corrosion / oxidation on carbon steel FHE and HLHC components. Application for License Renewal 3.2-13 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES Group 1 - (general corrosion / oxidation for FHC and HLHC carbon steel components) - Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to general corrosion / oxidation of carbon steel FHE and HLHC components: The carbon steel components listed in Table 3.2-1 provide structural and/or functional support to safety related equipment or to non-safety-related equipment whose failure could directly prevent satisfactory accomplishment of safety-related functions. Those components associated with the SFCHC also support single-failure-proof criteria for lifting heavy loads over the SFP. These functions must be maintained under CLB design loading conditions.
- FHE and HLHC components are exposed to moisture and oxygen in their installed locations.
- Carbon steel, improved plow steel, and alloy steel corrode in the presence of moisture and oxygen, which leads to a loss of material. This could eventually resuk in inability of the affected components to perform their intended function (s).
e Coatings, specified during original construction, mitigate the effects of corrosion by providing a protective layer that prevents moisture and oxygen from wnucting the steel.
- Periodic inspection of the FHE and HLHC components under the Performance Evaluation Program, and the load handling procedure, as applicable, detects general corrosion / oxidation of
, carbon steel components and degradation of their protective coatings, documents unsatisfactory conditions, and initiates appropriate coirective action.
- Existing preventive mcintenance tasks will be modified to provide for periodic visual inspection of applicable FHE and HLHC components, with specif.a requirements to detect the effects of general corrosion / oxidation of carbon steel subcomponents. This ensures that corrective actions will be taken such that there is a reasonab4 assurance that structural functions will be maintained.
Therefore, there is a reasonable assurance that the effects of general corrosion / oxidation will be managed for the carbon steel FHE and HLHC components listed in Table 3.2-1 such that they will be capable of a performing their intended functions, consistent with the CLB, during the period of extended operations. Group 2 - (general corrosion / oxidation and corrosion due to boric acid for the RV cooling shroud structural support members)- Materials and Environment The RV cooling shroud structural support members are bolted to the RV head and are fabricated of carbon steel. [ References 16 and 17] Inside Containment, the maximum design relative humidity for normal plant operations is 70%. [ Reference 8, page 62] The design maximum temperature around the RV cooling shroud structural support members is 150.6 F. [ Reference 8, page 19] Condensation in the presence of oxygen could lead to oxidation. Additionally, some internal portions of the RV cooling shroud can harbor pockets of liquids that may be inaccessible for visual inspection without removing interference. Carbon steel located in these areas may be subject to more severe local environments. [ Reference 2, Attachment 6) The bolted connections at the interface of the RV head and the RV cooling shroud structural support members are not normally exposed to borated water because they are all external to the vessel, but they may be exposed to boric acid as a result of leakage at the RV head penetrations. [ Reference 2, Attachment 5]. 'Iherefore, general corrosion / oxidation and corrosion due to bo-ic acid are considered potential ARDMs for the RV cooling shroud structural support members. Application for License Renewal 3.2-14 Calvert Cliffs Nuclear Power Plant
NITACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES Group 2 - (general corrosion /osidation and corrosion due to be-ic aci<l for the RV cooling shroud structural support members)- Aging Mechanism Effects Carbon steels are particularly susceptible to significant acceleration of general corrosion effects (described in Subsection Group 1, Aging Mechanism Effects, above) when exposed to boric acid in the concentrations present in primary coolant. Leakage of boric acid from RV head penetrations can result in the formation of concentrated deposits of beric acid in the form of crystals at the anchorage of the RV cooling shroud due to evaporation caused by the very high external temperature of the RV head. The consequences of this damage are loss of load-carrying cross-sectional area and weakened structural integrity. [ Reference 2, Attachment S] I Visual inspections of the RV head, which are performed during refueling outages, have found boric acid crystallization at the bolted connections between the RV cooling shroud structural support members and the RV head. [ Reference 2, Attachment 6] Boric acid crystals discovered at a weep hole in the bottom of the RV cooling shroud during an inspection of the Unit 2 RV head in April 1993 were found to be the result of leakage from a defective seal weld in a modified control element assembly pressure housing. There was no sign of RV head degradation as a result of the leak, and repairs were completed promptly. [ Reference 37, Section 7.1] If either general cor.osion/ oxidation or corrosion due to boric acid is left unmanaged for an extended period of time, the resulting loss of carbon steel material could lead to the inability of the RV cooling shroud structural support members to perform their intended function under CLB design loading conditions. Group 2 - (general corrosion / oxidation an.d corrosion due to boric acid for the RV cooling shroud structural support members)- Methods to Manage Aging Mitiention: The effects of corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of external surfaces of steel to an aggressive environment and protecting the external surfaces with paint or other prctective coating. Coatings serve as a protective layer, preventing moisture and oxygen from directly contacting the steel surfaces. [ Reference 2, Attachment 6] Boric acid corrosion can be mi;igated by minimizing leakage. The susceptible area (i.e., the RV cooling - shroud anchorage to the RV head) can be periodically observed for sigu of borated water leakage, and appropriate corrective action can be initiated as necessary to eliminate the cakage, clean spill areas, and assess any corrosion. [ Reference 2, Attachment 6] Discoverv: The effects of general corrosion / oxidation and corrosion due to boric acid on the RV cooling shroud structural support members can be discovered through a program of visual inspection of the RV head area. Inspection of the RV cooling shroud, with special attention to the bolted connections at the interface of the RV head and the RV cooling shroud, could identify general corrosion and/or residue from boric acid leakage and result in corrective actions being taken before corrosion could degrade the intended function of the RV cooling shroud structural support members. [ Reference 2, Attachment 8] Application for License Renewal 3.2-15 Calvert Cliffs Nuclear Power Plant
NITACHMENT m APPENDIX A - TECilNICAL INFORMATION , {-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES ) Group 2 - (general corrosion / oxidation and corrosion due to boric acid for the RV cooling shroud structural support members)- Aging Manage nent Program (s) Mitigation: The CCNPP Boric Acid Corrosion Inspection (BACD Program (MN 3-301, Reference 38) can mitigate the effects of boric acid corrosion through timely discovery ofleakage of borated water and removal of any boric acid residue that is found. His program requires visual inspection of the components containing boric acid for leaks, and the removal of any boric acid leekage from co,ponent surfaces. The BACI Program also verifies that the protective coatings that mitigate corrosion of the RV cooling shroud structural support members are maintained. [ Reference 2, Attachment 8] Further details on the BACI Program are discussed in the Discovery subsection below. Discoverv: Discovery of baric acid leakage is ensured by the BACI Program. [ Reference 38] This program also requires investigation of any leakage or corrosion that is found. A visual examination of [ external surfaces is performed for components containing boric acid, including the RV head penetrations. l His program will be modified to specify examinations during each refueling outage of: (a) the RV l cooling shroud anchorage to the RV head for evidence of boric acid leakage; and (b) all RV cooling shroud structural support members for general corrosion / oxidation. [Rt.ference 2, Attachment 8] He Inservice Inspection Program required the establishment of the BACI Program to systematically ensure that boric acid corrosion does not degrade the primary system bour.dary. [ Reference 39, Section 5.8.A.1] The program controls examination, test methods, and actions to minimize the loss of !. strucwai and pressure-retaining integrity of components due to boric acid corrosion. [ Reference 39, Section 3.0.C] The basis for the establishment of the program is Generic Letter 88-05, " Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants." [ Reference 38, Section 1.1) The scope of the program is threefold in that it: (a) identifies locations to be examined; (b) provides examination requirements and methods for the detection ofleaks; and (c) provides the responsibilities for initiating engineering evaluations and the racessary currective actions. [ Reference 38, Section 1.2) During each refueling outage, designated personnel perform walkdown inspections to identify and quantify any leakage found at specific locations inside the Containment and in the Auxiliary Building. The inservice inspection ensures that all components where boric acid leakage has been documented previously are also examined in accordance with the requirements of this program. A second inspection of these components is performed prior to plant startup (at normal operating pressure and temperature) if leakage was identified previously and corrective actions were taken. [ Reference 38, Sections 5.1 and 5.2] If either leakage or corrosion is discovered, issue reports are generated in accordance with CCNPP procedure QL-2-100, " Issue Reporting and Assessment," to document and resolve the deficiency. Corrective actions address the removal of boric acid residue and inspection of the affected components for general corrosion. If general corrosion is found on a component, the issue report provides for evaluation of the component for continued service and corrective actions to prevent recurrence. [ Reference 38, Section 5.3] The BACI Program is subject to periodic internal assessment activities. Internal audits are performed to ensure that e.ctivities and procedures established to implement the requirements of 10 CFR Part 50, Appendix B, comply with BGE's overali Quality Assurance Program. These audits provide a comprehensive independent serification and evaluation of quality-related activities and procedures. Audits of selected rpects of operational phase activities are performed with a frequency commensarate Application for License Renewal 3.2-16 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.3-FUEL IIANDLING EQUIPMENT AND OTHER HEAVY LOAD IIANDLING CRANES with their strength of performance and safety significance, and in su:h a manner as to assure that an audit of all safety-related functions is completed within a period of two years. [ Reference 40, Section 10.18] The BACI Program has evolved to account for operational experience. For example, both CCNPP Units have had occurrences of boric acid leakage through the ICI flange connections. [ Reference 41, Attachment page 2] Additionally, boric acid crystals discovered at the bottom of the RV cooling shroud were found to be the result ofleakage from a defective seal weld in a modified control element assembly pressure housing. [ Reference 37, Section 7.1] The BACI Program existed at the time of these events, but only required specific inspection for leaks at the beginning and end of each outage; it did not address leaks discovered outside of normal inspections. [ Reference 41, Attachment page 3] As a corrective - act!on, the BACI Program was revised to ensure that all boric acid leaks are evaluated and to specify the minimum qualification level for inspectors evaluating boric acid leaks. Apparent leaks are documented in issue reports by the individual discovering the leak. The reports are then routed to the inservice inspection group for closer inspection and evaluation by a qualified inspector. This appros.ch provides for more boric acid leakage inspection coverage, while still ensuring that appropriately qualified individuals assess and quantify any resultant damage. The corrective actions taken as a result of the programs described above will ensure that the RV cooling shroud structural support components remain capable of performing their intended function under all CLB conditions during the period of extended operation. . Group 2 - (general corrosion / oxidation and corrosion due to boric acid for the RV cooling shroud structural support members)- Demonstration of Aging Management ? Based on the information presented above, the following conclusions can be reached with respect to general corrosion / oxidation and corrosion due to boric acid for the RV cooling shroud structural support members: The RV cooling shroud structural support members provide structural and/or functional support to non-safety-related equipment whose failure could directly prevent satisfactory accomplishment of safety-related functions. This function must be maintained under CLB design loading conditions.
+ 'Ihe RV cooling shroud structural support members are fabricated from carbon steel, and the bolted connections at the interface of the RV head and the RV cooling shroud structural support members may be exposed to boric acid leakage from RV head penetrations. They are also exposed to moisture and oxygen in their installed locations.
. Carbon steel corrodes in the presence of moisture and oxygen, which leads to a loss of material.
Carbon snels are particularly susceptible to significant acceleration of general corrosion effects when exposed to boric acidin the concentrations present in primary coolant.
- Coatings, specified during original construction, mitigate the effects of corrosion by providing a protective layer that prevents moisture and oxygen from contacting the stect.
- The CCNPP BACI Program will be modified to manage the effects of general corrosion / oxidation and boric acid leakage for the RV cooling shroud structural support members. This program will ensure that leakage and corrosion are discovered and that appropriate corrective action is taken.
~
Application for License Renewal 3.2-17 Calvert Cliffs Nuclear Power Plant
ATTACilMENT (I) APPENDIX A - TECIINICAL INFORMATION 3.2-FUEL 11ANDLING EQUIPMENT AND OTilER IIEAVY LOAD IIANDLING CRANES Herefore, there is a reasonable assurance that the effects of general corrosion / oxidation and corrosion
- due to boric acid for the RV cooling shroud structural support members will be managed such that they will be capable of performing their intended function consistent with the CLB during the period of extended operations.
Group 3 - (fatigue for PC rails) . Materials and Environmini The PC rails are fabricated of carbon steel and installed inside Containment, where the maximum design relative humidity and ambient air temperature for normal plant operations are 70% and 120 F, respectively. [ Reference 2, Attachment 3; Reference 8, page 62] The rail mountings utilize a " tight fit" type of design to properly restrain the rail against its design loads. Three rail mounting options are available to connect the PC rails to the crane girder, and any combination of rail connection options can be used. [ Reference 42] The PC rails were assembled in sections with expansion joints that allow the rail sections to expand and contract without binding. r fra rail mountings are used at each expansion joint to maintain proper alignment and ensure transfer of had between sections. When a lifled load is applied, lateral loading causes uplift along the inside of the rail. Torsion and , bending are produced about both axes, in combination with a localized stress field in the vicinity of the load. As the load is transferred between rail sections, stress cycles are experienced. It has been conservatively assumed that cracks in the PC rails would prcpagate under repeated application of lified Icads. Therefore, fatigue is considered a potential ARDM for the PC rails. Group 3 -(fatigue for PC rails)- Aging Mechanism Effects Fatigue is a common degradation of structural members produced by periodic or cyclic leadings that are less than the maximum allowable static loading. Fatigue damage results in progressive, localized structural change in materials that have been subjected to fluctuating stresses and strains. Low cycle fatigue involves a low frequency of high-level, repeated loads. The number of cycles is usually less than 10' for steel structures. [ Reference 18, Attachment 1] Fatigue of steel structures is initiated by plastic deformation within a localized region of the structure. A non-uniform distribution of stresses through a cross-section may cause a stress level to exceed the yield point within a small area, and cause plastic movement after the number of stress reversal cycles reaches the material's endu ance limit. Such conditions will eventually produce a minute crack. The localized plastic movement further aggravates the non-uniform stress distribution, and further plastic movement causes the existing crack to grow. [ Reference 43, Appendix T] Short PC rail sections installed at the expansionjoints contain flame-cut holes that go through the end of each rail section on either side of the expansion joint. These holes were made during installation to permit use of standard splice bars, joint bar bolts, and spring washers with the short PC rail sections, if necessary. [ Reference 44] The flame-et,t holes result in a non-uniform distribution of stresses through the cross-section of the PC rails, and cracks have been found running radially from flame-cut holes at expansionjoints in both Units I and 2. These indications were de+ ermined to be quench cracks resulting from the hole-burning operation during installation. Since these sections of the PC rails are subject to r repeated loading whenever the PC is used for lifting loads, low-cycle fatigue is considered plausible for Application for License Renewal 3.2-18 Calvert Cliffs Nuclear Power Plant
ATTACHMFNT (2) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LJAD HANDLING CRANES_ _ . the PC rails. This aging mechanirm, if unmanaged, could result in unstable : rack growth under CLB design loading conditions Fuch that the PC rails may not be able to support the lifted loads. Group 3 -(fatigue for PC rails)- Methods to Manage Aging Mitigation: Standard PC rail sections were supplied from the steel mill with chamfered holes through the web to permit use of splice bars, if necessary. [ References 44 and 45] Cracking has not been observed at any of the holes in the standard PC rail sections at CCNPP, and cracking is consider:d to be likely only at the flame-cut holes in the short PC rail sections. Center punchir.g the ends of identified l cracks or repairing identified cracks by weld buildup can mitigate the effects of low-cycle fatigue by I relieving the stress concentration at the flame-cut holes. Alternately, some or all of the short PC rail sections can be replaced. { Discoverv: The effects of fatigue for the PC rails are detectable by visual inspection and NDE. Periodic examination can discover cracks reculting from fatigue, monitor growth of previously identified cracks, verify the effectiveness of crack repairs, and initiate appropriats corrective action prior to failure of the PC rails. Group 3 -(fatigue for PC rails)- Aging Management Program (s) l l Mitication: In 1992, indications of cracking at six flame cut holes in the short PC rail sections at the i expansion joint at azimuth 177' in Unit I were identified during visual examination and quantified using magnetic particle testing. A fracture mechanics evaluation in 1993 concluded that the peak stress intensity at these holes would exceed the critical stress intensity for unstable crack propagation under i maximum design loading conditions. The results of this evalusticn prompted repair of the cracks using weld buildup in 1994. o During the 1997 refueling outage, magnetic-particle testing revealed five flame-cut holes at four separate expansion joints in Unit 2, with at least one crack indicated. An engine <: ring evaluation is in progress, with recommendations to base any needed repair / replacement of the PC rails on the results of a fracture mechanics evaluation. [ Reference 46] Discoverv: Periodic inspection of the PC rails for the effects of fatigue and the efTectiveness of corrective actions is controlled through the existing Preventive Maintenance Program. Preventive Maintenance Tasks 10992001 and 20992000, " Perform NDE on Polar Crane Rails," are au'omatically scheduled end implemented in accordance with MN-1-102. [ Reference 29] These tasks direct visual inspection of the PC rails, and sutuequent NDE if there is evidence of cracking. [ References 47 and 48] Currently, inspection of the PC rails is performed on a four-to-dx. year intervah (Reference 48] Results are evaluated against prior inspection records to verify adequacy of weld repairs, identify trends, and determine the necessity for future inspections. The CCNPP Corrective Action Program is used to take the necessary corrective actions. The Preventive Maintenance Program is discussed further in subsection Group 1 - Aging Management Pregrams, above. Application for License Renewal 3.2-19 Calvert C!iffs Nuclear Power Plant
glTACHMFNT (2) APPENDIX A - TECHNICAL INFORMATION 3.2- FUEL HANDL1NG EQUIPMENT AND OTIIER HEAVY LOAD HANDLING CRANES Gioup 3 -(fatigue for PC rails)- Denionstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to fatigue for the PC rails: The PC rails provide structural and/or functional support to the PC whose failure could directly prevent satisfactory accomplishment of safety-related functions. This function must be maintained under CLB design loading conditions, W PC rails are fabricated of carbon steel. Quench cracks at flame-cut holes in some sections of
- the PC rails result in areas of high stress concentration.
Low cycle fatigue is a plausible ARDM for the PC rails because they are subject to repeated loading and non-uniform distribution of stresses whenever the PC is used for lifting loads. If unmanaged, this ARDM could result in unstable crack growth under CLE design loading conditions such that the PC rails may not be able to perform their structural support function.
- Periodic inspection and NDE of the PC rails under the Preventive Maintenance Program will monitor the effectiveness of weld repairs, detect crack growtti due to fatigue, document unsatisfactory conditions, and initiate appropriate corrective action.
Therefore, there is a reasonable assurance that the effects of aging will be adequately managed for the PC rails such that they will be capable of performing their intended function consistent with the CLB during the period of extended operation under all design loading conditions. Group 4 - (fatigue, wear, and mechanical degradation / distortion for wire rope) - Materials and Environment The construction materials for hoisting ropes and drive cables for the FHE and HLHC are listed in Table 3.2-1. [ Reference 2, Attachment 3] Stainlesa steel is used for wire rope that routinely comes in contact with borated water in the SFP and refueling pools. [ References 6,11,12,14,49,50, and 51] Improved plow steel, a high-quality, high-strength carbon steel, is used to fabricate the hoisting ropes for the SFCHC main hoist and ISSGC. [ References 10 and 14] Alloy steel is specified for the PC hoisting ropes. [ Reference 10] When not submerged in the SFP and refueling pools, wire rope is exposed to the external environments discussed in subsection Group 1 - Materials and Environment, above. [ Reference 2, Attachment 6) - Group 4 -(fatigue, wear, and mechanical degradation / distortion for wire rope)- Aging Mechanism Effects Fatigue is a common degradation of structural members produced by periodic or cyclic loadings. Two types of fatigue exist for structural components such as wire rope. Low-cycle fatigur involves a low frequency of high-level, repeated loads. The number of cycles is usually less than 105 for steel structures. [ Reference 18, Attachment 1] High-cycle fatigue occurs when the component cyclical stresses (including modifying factors such as stress concentrations and surface conditions) exceed the material fatigue strength for the number of cycles. Fatigue damage results in cracking and breakage of individual wires and strands that comprise the rope. Wire rope operating over sheaves and drums is subjected to cyclic bending stresses. In normal operation, wire rope is also subjected to vibration in the Application for License Renewal 3.2-20 Calvert Cliffs Nuclear Power Plant
i l ATTACHMENT m l APPENDIX A - TECHNICAL INFORMATION
'3.2- FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDL.ING CRANES form'of wave action characterized by either low-frequency or sharp, high frequency cycles. The energy generated in the rope by the wave action must be absorbed at some point (e.g., the end attachment, the tangent where the rope contacts the sheave). [ Reference 2, Attachment 5]
Wear results from relative motion between two surfaces and from the influence of hard, abrasive particles. The most common result of wear is loss of material from one or both surfaces invo!ved in the contact. When bent over a sheave, a wire rope's load-induced stretch causes it to rub against the groove. Abrasive wear also occurs as individual wires and strands move within the wire rope itself while bent around the sheave or drum. [ Reference 2, Attachment 5] Mechanical degradation / distortion of wire rope results from mechanical abuse during normal operation by abnormal or accidental forces. Examples of abuses during normal operation include sudden release of tension, rolling over sharp objects, layer to layer crushing resulting from improper drum winding, torsional imbalances caused by sudden stops, and continuous p=,mding against other objects. [ Reference 2, Attachment 5] Fatigue, wear, and mechanical degradation / distortion are all considered plausil6 for wire rope associated with FHE and HLHC. All of these mecha oms result in a loss ofload-carrying capacity. If unmanaged, the wire rope and the associated FHE and HLHC could lose their ability to perform their intended functions under the CLB design loading conditions. [ Reference 2, Attachment 6] Group 4 - (fatigue, wear, and mechanleal degradation / distortion for wire rope) - Methods to Manage Aging hiitigation: The effects of fatigue, wear, and mechanical degradation / distortion can be mitigated by proper component design and material selection, and by operational practices that reduce the number and severity of mechanical abuses on wire rope a.,sociated with the FHE and HLHC. Discoverv: The effects of fatigue, wear, and mechanical degradation / distortion on wire rope are detectable by visual inspection. The physical appearance of the outer surfaces of a wire rope is a good indicator ofits condition. A visual examination by a person familiar with hoisting ropes and drive cables can be used to identify gross damage and evidence of operational abuse. Under normal operation and in the absence of corrosion and rope distortion, the extent to which wire surfaces are worn and the number and location of broken wires can be used to estimate the remaining rope strength. Evaluation of any observed damage by a trained inspector can determine whether continued use or replacement is appropriate. [ Reference 52, page 62] Application for License Renewal 3.2-21 Calvert Cliffs Nuclear Power Plant
A*ITACHMENT m APPENDIX A - TECIINICAL INFORMATION 3.2-FUEL IIANDLING EQUIPMENT AND OTHER IIEAVY LOAD HANDLING CRANES Group 4 - (fatigue, wear, and mechanical degradation / distortion for wire rope) - Aging Management Program (s) Mitigation: There are no programs credited with mitigating the effects of these ARDMs for wire rope. Discoverv: Periodic inspection of wire rope associated with the FIIE and llLilC for the effects of fatigue, wear, and mechanical degradation / distortion is controlled through a combination of existing operations inspections and maintenance programs [ Reference 2, Attachment 8] The Calvert Cliffs Operating Manual and the Performance Evaluation Program are described in
- subsection Group 1 - Aging Management Programs, above in accordance with 01-258, " Fuel Transfer System," the hoisting ropes and drive cables for the fuel upending machines and transfer carriages are visually inspected for damage if the equipment has been secured for greater than
, 60 days, if a refueling campaign (i.e., defuel/ refuel or fuel shuffle) is imminent, or as designated following maintenance. [ Reference 53] The Performance Evaluation Program provides for wire rope inspection for the SFHM, RRM, the spent fuel inspection elevator, and the new fuel elevator prior to refueling campaigns. The checks for the SFliM and the elevators are also performed every 90 days. [ References 22,23, and 54] Calvert Cliffs procedure PE 0-81-1-0-Q direct-performance of checks in accordance with OI 25A, which requires visual inspectioa of th, hoisting rope while running the hoist through the full length of travel. [ Reference 24] PE 0-81-2-O-C directs performance of checks in accordance with 01-25C, which requires the same activities for the main hoist on each unit's RRM. [ Reference 25] Visual inspection for damage to hoisting ropes in accordance with 0125B, " Fuel Elevators," is directed by PE 0-81-3 O-Q for the spent fuel inspection elevator and the new fuel elevator. [ Reference 55]
- Calvert Cliffs procedure MN-1-104 is described in subsection Group 1 - Aging Management Programs, above. The wire rope inspections specified in this procedure and implemented through the Preventive Maintenance Program (below) require visual observation for gross damage (e.g., kinking, crushing, unstranding, and birdcaging; general corrosion; dryness o' lubricant; scrubbing; evidence of heat damage; broken or cut wires). [ Reference 26, Section 5.8.E.3]
Prior to initial use of the Transfer Machine Jib Crane to handle heavy loads (e.g., the fuel transfer carriage), a wire rope inspection is required as part of the testing and inspection discussed in subsection Group 1 - Aging Management Programs, above. [ Reference 26, Sections 5.7.A.3 and 5.8.F]
+ The CCNPP Preventive Maintenance Program is described in subsection Group 1 - Aging Management Programs, above. The following Preventive Maintenance Tasks implement the requirements of MN-1-104 by directing visual inspections of hoisting ropes and/or drive cables for the listed FHE and HLilC components:
10812007,20812009 for the Unit 1, Unit 2 Fuel Upending Machines and Transfer Carriages [ Reference 56] 10812013,20812014 for the Unit 1, Unit 2 RRM main hoists [ Reference 57] 10992016,20992010 for the Unit 1, Unit 2 RRM auxiliary hoists [ Reference 58] 00992009 for the SFCHC [ References 30 and 31] 10992010,20992002 for Unit 1, Unit 2 PCs [ References 32 and 33] 10992007 for the ISSGC [ References 34 and 35] Application for License Renewal 3.2-22 Calvert Cliffs Nuclear Power Plant
4 ATTACHMENT m APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES When damage is discovered, a more detailed inspection is made, applying quantitative criteria from industry standards for evaluation of wi.e rope condition. Continued use or replacement of damaged wire rope is determined by a person qualified as Load Handling Engineer in accordance with MN-l-104. Group 4 -(fatigue, wear, and mechanical degradation / distortion for wire rope)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to fatigue, wear, and mechanical degradation / distortion for wire rope associated with the FHE and HLHC: Wire rope, used to fabricate hoisting ropes and dri"e cables, provides structural and/or functional support for the associated FHE and HLHC. Failure of wire rope could directly prevent satisfactory accomplishment of safety-related functions that must be maintained under CLB design loading conditions, e The construction materials for wire rope i.iclude stainless steel, improved plow steel, and alloy steel, e Fatigue and wear are plausible ARDMs for wire rope when used in load handling applications. Mechanical degradation / distortion is plausible because of abnormal or accidental forces that may be applied during normal operation. If unmanaged, these ARDMs could result in a loss of load-carrying capacity such that the wire rope may not be able to perform its structural support function under CLB design loading conditions. Visual inspection of wire rope under the Calvert Cliffs Operating Manual, the Performance Evaluation Program, the load handling procedure, and the Preventive Maintenance Program, as applicable, evaluates the condition of hoisting ropes and drive cables for FHE and HLHC, documents unsatisfactory conditions, and initiates appropriate corrective action. Therefore, there is a rea:onable assurance that the effects of aging will be adequately managed for wire rope associated with the FHE and HLHC such that they will be capable of performing their intended functions, consistent with the CLB, during the period of extended operation under all design loading conditions. 3.2.3 Conclusion The aging management programs discussed for the FHE and HLHC are listed in Table 3.2-2. These programs are administratively controlled by a formal review and approval process. As demonstrated above, these programs will manage the aging mechanisms and their effects in such a way that the l intended functions of the components of the FHE and HLHC will be maintained during the period of extended operation consistent with the CLB under all design loading conditions. The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL-2, " Corrective Actions Program." QL-2 is pursuant to 10 CFR Part 50, Appendix B, and covers all structures and components subject to AMR. Application for License Renewal 3.2-23 Calvert Cliffs Nuclear Power Plant
- ATTACHMENT (2)
APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES Table 3.2-2 AGING MANAGEMENT PROGRAMS FOR THE FHE AND HLHC SYSTEM l Program Credited As-Existing Operations Section Performance Program for discovery and management of general Evaluations and associated Operating corrosion / oxidation effects in carbon steel parts of Instructions the SFHM, RRM, and associated components by
- PE 0-81-1-0-Q and Ol 25A, Spent Performing periodic visualinspections. (Group 1)
Fuel Handling Machine" (procedure) PE 0-81-2-0-C and OI-25C,
" Refueling Machine"(procedure)
Existing Load Handling Procedure, MN 1-104 Program for discovery and management of general corrosion / oxidation effects in carbon steel parts of FHE and HLHC components by performing visual inspections. (Group 1) Program for discovery and management of fatigue, wear, and mechanical degradation / distortion effects in wire rope by performing visual inspections. (Group 4) Existing Preventive Maintenance Tasks Program for discovery and management of fatigue 10992001 (20992000)," Perform effects in carbon steel PC rails by performing NDE. NDE on Polar Crane Rails" (Group 3) Existing Operating Instructions and Program for discovery and management of fatigue, Operations Section Performance wear, and mechanical degradation / distortion effects Evaluations, as applicable in wire rope for SFHM, spent fuel inspection and
. Oi-25A and PE O-81-1-O-Q," Spent "** I".el elevators, RRM main hoists, and the Fuel Fuel Handling Machine" Upendmg Machmes and Transfer Carriages,1 WPectively, by perform,m g periodic visual (procedure) ,
inspections. (Group 4) a 01-25B ard PE 0-81-3-O-Q," Fuel Elevator f(procedure)
= Ol.25C and PE 0-81-2-0-C,
" Refueling Machine"(procedure)
OI-25E," Fuel Transfer System" (procedure) Application for License Renewal 3.2-24 Calve t Cliffs Nuclear Power Plant
i ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2-FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES Table 3.2-2 AGING MANAGEMENT PROGRAMS FOR THE FHE AND HLHC SYSTEM
- Program Credited As
- Existing Preventive Maintenance Tasks
- Program for discovery and management of fatigue, 1081200'/ (20812009)," Inspect and wear, and mechanical degradation / distortion effects Lubricate Fuel Transfer Cables, in wire r Pe for the Fuel Upending Machmes and Winch:s, and Drivers" Transfer Carriages, RRM mam hoists, RRM auxiliary hoists, SFCHC, PCs, and ISSGC,
. C812013 (208120!4)," Perform respectively, by performing visual inspections.
NDE on Fuel Handling Machine (Group 4) Crane Hook" 10992016 (20992010)," Perform NDE on 45',69' Containment and Refueling Machine Crane Hooks" 00992009," Inspect Auxiliary Building Cask Handling Crane" 10992010 (20992002)," Lubricate Containment Polar Cranes" 10992007, " Inspect Intake Structure Gantry Crane" Modified Preventive Maintenance Tasks Program for discovery and management of general (modified to explicitly present corrosion / oxidation effects in carbon steel parts of inspection requirements): the SFCHC, PC, ISSGC, and RV head lift rig, 00992009," Inspect Auxiliary respectively, by performing visual inspections. Building Cask Hanuiing Crane" (Group 1) 10992010 (20992002), " Lubricate Containment Polar Cranes" 10992007, " Inspect Intake Structure Gant y Crane" 10642031 (20642030), " Perform Surface Examination on Head Lift Rig" Modified BACI Program, MN-3-301 Program for discovery and management of general corrosion / oxidation and corrosion due to boric acid for the RV cooling shroud structural support members by performing visual inspections. (Group 2) Application for License Renewal 3.2-25 Calvert Cliffs Nuclear Power Plant
6 ATTACHMFNT (2) APPENDIX A - TECIINICAL INFORMATION 3.2- FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES 3.2.4 References
- 1. CCNPP IPA Methodology, Revisiou a 2.
CCNPP Life Cycle Management Aging Management Review Report, "Fuci Handling j Equipment (File) and Other Heavy Load Handling Cranes (HLHC) Commodity Evaluation," - Revision 1
- 3. CCNPP Updated Final Safety Analysis Report, Units 1 and 2, Revision 20
- 4. CCNPP Life Cycle Management System and Structure Screening Results, Revision 4
- 5. Bechtel Specification No. 6750-C-30, " Specification for New Fuel Inspection Platform -
CCNPP Units 1 and 2," Revision 1
- 6. Bechtel Specification No. 6730-M-390, " Specification for Fuel Poo! Service Platform, New Fuel Elevator, Spent Fuel Inspection Device and Spent Fuel Storage Racks - CCNPP Units 1 and 2," Revision 8
- 7. CCNPP Engineering Standard ES-Ol l, " System, Structure, and Component (SSC) Evaluation,"
Revision 2
- 8. CCNPP Engineering Standard ES-014, " Summary of Ambient Environmental Service Conditions," Revision 0
- 9. Bechtel Specification No. 6750-C-19, " Specification for Furnishing, Detailing, Fabricating, Delivering, and Erecting Structural Steel- CCNPP Units 1 and 2," Revision 3
- 10. Bechtel Specification No. 6750-C-42, " Specification for Overhead Traveling Cranes - CCNPP Units I and 2," Revision 5 11.
Combustion Engineering Specification No. 8067 PE-801, " Project Engineering Specification for Reactor Refueling Machine," Revision 2
- 12. CCNPP Specification No. SP-551, " Specification for a Replacement Spent Fuel Pool Service Platform," Revision 4 13.
Bechtel Specification No.6750-C-31, " Specification for Furnishing, Detailing, Fabricating, Painting, and Delivering Containment and Auxiliary Building Structural Steel - CCNPP Units I and 2," Revision 3
- 14. CCNPP Specification No. SP-601, " Modification of Spent Fuel Cask Crane," Revision 4
- 15. Bechtel Specification No. 6750-M-395, " Specification for Miscellano >us Hoists and Monorails
- CCNPP Units 1 and 2," Revision 2
- 16. BGE Drawing 12017-0049, " Closure Head Lifting Rig and Cooling Duct Assembly,"
Revision 7
- 17. BGE Drawing 12017-0057 " Closure Head Lifting Rig and Cooling Duct Asser61y,"
Revision 3
- 18. CCNPP Administrative Procedure EN-1305, "Compon-nt Aging Management Review for Structures," Revision 1
- 19. CCNPP Administrative Procedure NO-1-201, "Calvert Cliffs Operating Manual," Revision 7 Application for License Renewal 3.2-26 Calvert CliiJs Nuclear Power Plant
( ATTACHMENT (2) APPENDIX A - TECHNICAL INFORMATION 3.2- FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES
- 20. CCNPP Administrative Procedure NO-1203," Operations Section Performance Evaluations,"
Revision 3
- 21. CCNPP Administrative Procedure NO-1-100," Conduct of Operations," Revision 9
- 22. CCNPP Operations Performance Evaluation Requirements Routine No.0-81-1-0-Q, " Spent Fuel Handling Machine," Revision 1
- 23. CCNPP Operations Performance Evaluation Requireinents Routine No. 0-81-2 0-C,
" Refueling Machine," Revision 1
- 24. CCNPP Operating Instructions, OI-25 A, " Spent Fuel Handling Machine," Revision 15
- 25. CCNPP Operating Instructions, OI-25C, " Refueling Machine," Revision 15
- 26. CCNPP Administrative Procedure MN-1-104," Load Handling," Revision 5
- 27. Letter from Mr. R. A. Clark (N.tC) to Mr. A. E. Lundvall, Jr. (BGE), dated May 27,1983,
" Safety Evaluation, Control of Heavy Loads -- Phase 1"
- 28. Letter from Mr. A. E. Lundvall, Jr. (BGE) to Mr. D. G. Eisenhut (NRC), dated March 1,1982,
" Control of Heavy Loads"
- 29. CCNPP Administrative Procedure MN-1-102," Preventive Maintenance Program," Revision 5
- 30. CCNPP NUCLEIS Database Repetitive Task 00992009, " Inspect Auxiliary Building Cask Handling Crane"
- 31. CCNPP Maintenance Procedure HE-19, "116/15 Ton Spent Fuel Cask Handling Crane Annual Inspection," Revision 5
- 32. CCNPP NUCLEIS Database Repetitive Tasks 10992010 (20992002), " Lubricate Containment Polar Cranes "
- 33. CCNPP Maintenance Procedure HE-05. "180/25 Ton Polar Crane Periodic Inspection,"
Revision 5
- 34. CCNPP NUCLEIS Database Repetitive Task 10992007, " Inspect Intake Structure Gantry Crane"
- 35. CCNPP Maintenance Procedure HE-20, "35/10 Ton Intake Structure Crane Annual Inspection," Revision 4
- 36. CCNPP NUCLEIS Database Repetitive Tasks 10642031 (20642030), " Perform Surface Examination on Head Lift Rig"
- 37. Letter from Mr. A. R. Blough (NRC) to Mr. R. E. Denton (BGE), dated May 6,1993, "NRC Region I Resident Inspection Report Nos. 50-317/93-10 and 50-318/93-10 (March 14,1993 -
April 24,1993)"
- 38. CCNPP Procedure MN-3-301,"CCNPP Boric Acid Corrosion Inspection Program," Revision 1 Change 0
- 39. CCNPP Procedure MN-3-110, " Inservice Inspection of ASME Section XI Components,"
Revision 2
- 40. BGE " Quality Assurance Policy for the Calvert Cliffs Nuclear Power Plant," Revision 48 Application for License Renewal 3.2-27 Calvert Cliffs Nuclear Power Plant
s ' ATTACilMFNT (D APPENDIX A . TECHNICAL INFORMATION 3 2 FUEL HANDLING EQUIPMENT AND OTHER HEAVY LOAD HANDLING CRANES l
- 41. Letter from Mr. C.11. Cruse (DGE) to NRC Document Control Desk, dated July 29,1994,
" Licensee Event Report 94 004, Revision 1, Excessive Corrosion of Incore Instrumentation Flange Components" l
- 42. BGB Drawing 61746, " Containment interior Crane Girder Plan & Details," Revision 3 l
- 43. CCNPP Life Cycle Management Aging Management Review Report," Containment Structure (System 059)." Revision 4 l
- 44. BGE Drawing 12324 0010," Crane Rail d' Accessories," Revision 1
- 45. BGE Drawing FSK C 0502,"U 2 Polar Crane Bridge Rail Field Welded Joints & Repairs,"
Revision 5
- 46. CCNPP Engineering Service Package ES199701207," Evaluate Cracks on Unit 2 Polar Crane Rail," June 13,1997 !
- 47. CCNPP Maintenance Procedure llE 18," Polar Crane Rail Inspection," Revision 2
- 48. CCNPP NUCLEIS Database Repetitive Tasks 10992001 (20992000)," Perform NDE on Polar Crane Ralls"
- 49. Combustion Engineering Specification No. 8067 PE 800," General Engineering Specification for Reactor Servicing Equipment," Revision 8
$0. Combustion Engineering Specification No. 8067 PE 802, " Pro)cci Engineering Specification for Fuel Trantfer System," Revision 1 St. BGE Drawing 12804 0028,"6 Ton Jib Crane for Transfer Assembly," Revision 3
- 52. North American Crane Bureau, Inc.," Overhead Crane inspector Training"(student workbook),
1997
- 53. CCNPP Operating Instructions, OI 25E," Fuel Transfer System," Revision 10
- 54. CCNPP Operations Performance Evaluation Requirements Routine No. 0 813 0-Q, " Fuel Elevators," Revision 0
- 55. CCNPP Operating instructions, Ol.25b, " Fuel Elevators," Revision 7
- 56. CCNPP NUCLEIS Database Repetitive Tasks 10812007 (20812009), " Inspect and Lubricate Fuel Transfer Cables, Winches, and Drivers"
- 57. CCNPP NUCLEIS Database Repetitive Tasks 10812013 (20812014)," Perform NDE on Fuel llandling Machine Crane Hook"
- 58. CCNPP NUCLEIS Database Repetitive Tasks 10992016 (20992010), " Perform NDE on 45',
69' Containment and Refueling Machine Crane Hocks" . Application for License Renewal 3.2 28 Calvert Cliffs Nuclear Power Plant
NPTACilMENT (3) APPENDIX A - TECilNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Baltimore Gas and El ctric Company Calvert Cliffs Nuclear Power Plant October 22,1997
NITACHMENT LM APPENDIX A TECilNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM 5.1 Auxiliary Feedwater System His is a section of the Baltimore Gas and Eledric Company (DGE) License Renewal Application (LRA) addressing the Auxiliary Feedwater (AFW) System. The AFW System was evaluated in accordance with , the Calvert Cliff Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methodology { described in Section 2.0 of the DGE LRA. Then sections are prepared independently and will, collec'ively, comprise the entire DOE LRA. 5.1.1 Sceping System level scoping describes conceptual boundaries for plant systems and structures, develops screening tools which capture the 10 CFR 54.4(a) scoping criteria, and then applies the tools to identify systems and structures within the scope of Ilcerse renewal. Component level scoping describes the components within the boundaries of those systems and structures that contribute to the intended functions. Scoping to determine components subject to aging management review (AMR) begins with a listing of passive intended functions and then disposition the device types as either only associated with active functions, subject to replacement, or subject to AMR either in this report or another report. Section 5.1.1.1 presents the results of the system level scoping,5.1.1.2 the results of the component level scoping, and 5.1.1.3 the results of scoping to determine components subject to an AMR. Representative historical operating experience pertinent to aging is included in appropriate areas to provide insight supporting the aging management demonstrations. This operating experience was obtained through key word searches of DGE's electronic database ofinformation on the CCNPP dockets, and through documented discussions with currently assigned ccgnizant CCNPP personnel. 5.1.1.1 System LevelScoping This section begins with a description of the system that includes the boundaries of the system as it was scoped. The intended functions of the system are listed and are used to denne what portions of the > system are within the scope oflicense renewal. System Description /Concentual Boundaries The AFW System is designed to provide emergency water from No.12 Condensate Storage Tank (CST) to the steam generators for the rermovat of sensible and decay heat, and to cool the primary system to 300'F if the main condensate pumpa or the main feed pumps are inoperative. Number 12 CST serves both Units 1 and 2. Three AFW pumps are installed per unit, consisting of one motor-driven and two non-condensing steam turbine driven pumps. The steam turbine-driven AFW train may also be used for normal system cooldown to 300'F. The motor driven portion of the system is designated for emergency use only (l.c., not for use during normal plant startup or shutdown - except testing is allowed). For a shutdown, only one pump is required to be operating, the others are in standby. Upon automatic initiation of AFW, one motor-driven arid one turbine-driven pump automatically start. [ Reference 1, Sections 10.3.1 and 10.3.2) These pumps take suction from No.12 CST, which provides 300,000 gallons of water for decay heat removal and cooldown of both units. Other major components of the AFW System include blocking valves, How control valves, check valves, tobine steam isolation and governor valves, How elements,
~
Application for License Renewal 'i.11 Calvert Cliffs Nuclear Power Plant
i ATTACllMENT (3) APPENDIX A. TECHNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM and associated piping, instrumen'.ation, and controls. [ Reference 1, Section 10.3.2; Reference 2, Section 1.1.2; References 3 and 4] De AFW System also includes the cables, conduit, and logic devices for the Auxiliary Feedwater Actuation System (AFAS). The AFAS has been installed to comply with regulatory directives resulting from the Three Mile Island Unit 2 accident in 1979, that required automatic starting capability and the addition of the motor driven AFW pump. %c AFAS starts the AFW pumps upon detection of very low level in either steam generator and it blocks AFW to a ruptured steam generator. [ Reference 2, Section 1.1.2] He motor driven AFW pump has been provided with a Dre hose connection on its suction as an alternate water source. Likewise, on loss of electric power (Appendix R scenario), a slamese fire hose connection may be installed at tl.e automatic recirculation valve on the discharge side of the pump. [ Reference 1, , Section 10.3.2] He majority of the original design of the AFW System was accomplished using the seismic design criteria typical for other CCNPP Class I systems. %e non-seismic portion of the AFW System was examined in response to the Nuclear Regulatory Commission (NRC) Generic Letter 81 14, and it was determined that the safe shutdown earthquale would not have a significant effect on system function. ; [ Reference 1, Section 10.3.1] Auxiliary feedwater piping for the steam driven train is designed per American Nuclear Standards Institute [ANSl] B 31.1, and for the motor-driven train is designed per ' American Society of Mechanical Engheers [ASME] Section III, Class 111 Boiler and Pressure Vessel Code. [ Reference 1, Table 101] The AFW System has not had sign 10 cant aging related problems over its 20 year history, in 1991, evidence of corrosion was discovered in Unit 2 AFW pumps; however, this occurred following the extended plant outage, which began in 1989. [ Reference $] Once in 1993, and two times in 1994, CCNPP experienced failures of the governor valve stem on an AFW turbine. These failures were common to Terry Turbines at several plants. They were a result of the valve stem material being susceptible to corrosion. Terry Turbine govemor valve stem failure received industry and regulatory attention in 1994 and 1995. As a result, the govemor valve stems on all four Terry Turbine units at CCNPP have been replaced with new stems made from inconel 718 Alloy, a corrosion resistant material. Calvert Cliffs has established a schedule to overhaul AFW pump turbines every 10 years. All four AFW pump turbines were overhauled the first time in 1988. Turbine No.11 was overhauled the second time in 1996, and the No. 21 in 1997. He No.12 and 22 Turbines are currently scheduled for the 1998 and 1998 outages, respectively. He inspecticns of AFW pump turbines during overhauls have revealed no defects such as cracks or corrosion. He AFW pump turbines are in good condition. The AFW turbine-driven pumps are overhauled every four years. Figure 5.1 1 is a simplified diagram of the AFW System. This figure shows the AFW System that is addressed in this section and the primary process flow systems' interfaces. [ References 3 and 4] Application for License Renewal 5.1-2 Calvert Cliffs Nuclear Power Plant
A'ITACIIMrNT G) APPENDIX A- TECilNICAL INFORhtATION 5.1 - AUXILIARY FEEDWATER SYSTEh! V E SIMPLIFIED DIAORAM N 5 cvstR> ' ( / V N i, ,,c. \- U
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% c,,%c'k CCNPP AUXILIARY FEEDWATER SYSTEM eon. atty ctosta VAtyt SIMPLIFIED DIAORAM (FOR INFORMATION ONLM (V5LR) V11HIN SCtPC Dr otCENSC RENEWAL AT TIC INitRf ACC Application for License Renewal 5.1 3 Calvert Cliffs Nuclear Power Plant
NITACHMENT (3) APPENDIX A TECHNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM System tnierfaces! The AFW System has interfaces with nine plant systems. He AFW scope relating to these interfacing systems is as follows: Deminerallred Water and Condensate Storage System ne No.12 CST and all connected SR l pipes and instrumentation are included in the AFW scope. The No.11 and 21 CSTs are non-safety related (NSR). The AFW scope includes the SR isolation valves and the downstream pipes In the suction lines from these tanks ne valves provide an AFW pressure boundary function. e Main Steam System ne turbine throttle valves through the governor valves to the turbine inlets.
- Chemical Addition System ne chemical injection pipes from the AFW headers out to and '
including the outboard SR isolation valvet The valves provide an AFW pressure boundary function.
- Engineered Safety Features Actuation System The Engineered Safety Features Actuation System provides independent actuation for the AFAS. The steam generator instruments that
- generate the necessary signals are addressed in the Feedwater System AMR. Therefore, the interface involves cables / conduits associated with transmitting the AFAS signals to the AFW
{ System, logic components, and controls associated with the pumps and valves.
- Auxiliary Steam System The Auxiliary Steam System conncets to the main steam piping upstream of the throttle /stop valves. Therefore, there are no auxillary steam components in the scope of AFW, The system interface involves only the possible use of auxiliary steam to operate the turbine-driven pumps.
Fire protection System The AFW motor driven pumps may be supplied with a backup source of water by connecting a fire hose to the suction piping of the pump. The AFW scope includes the branch piping up to the SR isolation valves (which are adjacent to the NSR hose connection fittings). The valves provide an AFW pressure boundary function, e Compressed Air System All of the remote operated valves in the system use air actuators. Rese are controlled with compressed air normally provided from the NSR portion of the Compressed Air System. Air can be provided from the two SR air accumulators for a two-hour time period following a loss of function of, or loss of power to, the NSR Compressed Air System, e Saltwater Air Compressor System The SR Saltwater Air Compressor System ties into the Compressed Air System as an emergency backup source of compressed air. Therefore, there are no saltwater air compressor components in the scope of AFW. The system interface involves only the possible introduction of compressed air from the SR Saltwater Air Compressor System into components utilizing compressed air.
- Reactor Coolant System (steam generators) piping up to the stem generator AFW nozzles.
[ Reference 2, Section 1.1.2] Application for License Renewal 5.1-4 Calvert Cliffs Nuclear Power Plant
AIIAGIMENT d) APPENDIX A. TECHNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM Sytg n Sconing Resuhn ' The AFW System is in scope for license renewal based on 10 CFR 54.4(a). The following intended functions of the ,.FW System were determined based on the requirements of 154.4(a)(1) and (2) in
] accordance with the CCNPP IPA Methodology Section 4.1.1. [ Reference 2 Section 1.1.3; Reference 6 Table 1) e Provide AFW to the steam generators for decay heat removal; e Maintain the pressure boundary of the system; j e isolate the AFW to the steam generator; Maintain electrical continuity and /or provide protection of the electrical system;
- Provide circuit protection for the steam generator pressure signal being provided from the feedwater system to Engineered Safety Features Actuation System and Reactor Protective System; 4 e Provide seismic integrity and/or protection of SR components; and
- Provide flow restriction to assure adequate recirculation now for pump cooling, and to limit
, recirculation now such that adequate AFW How is provided to the steam generators.
The following intended functions of the AFW System were determined based on the requirements of
$54.4(a)(3): [ Reference 2, Section 1.1.3; Reference 6, Table 1)
- For environmental qualification (650.49) Maintain functionality of electrical components as addressed by the environmental qualification program, and provide information used to assess the plant and environs condition during and following an accident
- For anticipated transients without scram (650.62) Provide AFAS Start Signal (diverse from Reactor Protective System) on low steam generator water level conditions indicative of an i anticipated t ansient without scram, e
For station black out ({50.63) Provide AFW to steam generators for decay heat removal and provide condensate inventory, i e For fire protection (650.48) Monitor essential AFW parameters to ensure safe shutdown in the event of a postulated fire. Parameters monitored include AFW pump discharge pressure t. No. 12 CST level. Provide alternate control of the AFW System via local hand valves, How trnsmitters, and current / pneumatic components at the auxiliary shutdown panel to ensure safe shutdown in the event of a postulated fire, i 5.1.1.2 Component Level Scoping Based on the intended functions listed abave, the portion of the AFW System that is within the scope of license renewal includes all components (electrical, mechanical, and instrument) and their supports from the CST to the steam generators. These components include No.12 CST, two turbine-driven and one motor-driven AFW pumps, steam generator blocking valves, steam generator How control valves, check i valves, piping, instrumentation, and AFAS. [ Reference 2, Section 1.1.2] 4 1 Application for License Renewal 5.1-5 Calvert Cliffs Nuclear Power Plant l
ATTACHMENT (3) APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM The following 47 device types of the AFW System were designated as within the scope of license renewal because they have at least I intended function: [ Reference 2, Table 21) AFW System Piping EB AFW System Piping EBB AFW System Piping EBC AFW System Piping EC AFW System Piping llB AFW System Piping IlBC AFW System Piping llc 2/4 Logic Component Check Valve Coll Control Valve and Control Valve Operator Voltage / Current Device Flow Element Flow Indicator FlowIndicator Controller Flow Orifice Flow Transmitter - Fuse Flow Component (Relay) Governor Valve ! Iland Controller llandswitch lland Valve Current / Voltage Device Current / Current Device Current / Pneumatic Device Ammeter Power Lamp indicator LevelIndicator LevelIndicator Alarm Level Transmitter 4KV Motor 125/250 VDC Motor Pressure Control Valve Pressure Indicator Panel Pressure Switch Pressure Transmitter Pump Relay Solenoid Valve Tank Turbine Vacuum Breaker Vahe Power Supply Position Indicating Lamp Position Switch Some components in the AFW System are common to many other plant systems and have been included in separate sections of the BGE LRA that address those components as commodities for the entire plant. These components include the following: [ Reference 2, Section 3.2] e Structural supports for piping, cables, and components are evaluated for the effects of aging in the Component Suppons Commodity Evaluation in Section 3.1 of the BGE LRA.
- Electrical control and power cabling are evaluated for the effects of ag! g in the Cables i Evaluation in Section 6.1 of the BGE LRA.
- Instrument tubing and piping and the associated supports, instrument valves, and fittings (generally everything from the outlet of the final root valve up to and including the instrument),
and the pressure boundaries of the instruments themselver, are all evaluated for the effects of aging in the Instrument Lines Commodity Evaluation in Section 6.4 of the BGE LRA. 5.1.13 Components Subject To Aging Management Review This section describes the components within the AFW System that are subject to AMR. It begins with a listing of passive intended functions, and then dispositions the device types as either only associated with active functions, subject to replacement, evaluated in ether reports, evaluated in commodity repons, or remaining to be evaluated for aging management in this section. , Application for License Renewal 5.1 6 Calvert Cliffs Nuclear Power Plant
ATTACHMENT 0) APPENDIX A. TECHNICAL INFORMATION 5.1 AUXil.!ARY FEEDWATER SYSTEM Passive Intended Functions in accordance with the CCNPP IPA Methodology Section 5.1, the following AFW System functions were determined to be passive. [ Reference 2, Table 31]
- Maintain the pressure boundary of the system; Maintain electrical continuity and/or provide protection of the ekctrical system;
- Provide seismic integrity and/or protection of SR components; and l
Provide now restriction to assure adequate recirculation How for pump cooling, and to limit recirculation now such that adequate AFW How is provided to the steam generators. Device Tynes Subject to Aging Management Review Of the 47 device types within the scope oflicense renewal: The following 21 Avice types do not have a passive intended function; two-out of four (2/4) logic component, coll, voltage / current component, How indicator, How indicator controller, fuse, now component, hand controller, hand switch, current / voltage component, current / current component, ammeter, power lamp indicator, level indicator alarm, 4KV motor, 125/250 VDC motor, relay, vacuum breaker valve, power supply, position indicating lamp, position switch. [ Reference 2, Table 3 2) The Dow transmitter device type consists of 16 How transmitters that are within the scope of license renewal. Four of the transmitters are subject to a replacement program and twelve trr.nsmitters are evaluated in the Instrument Line Commodity Evaluation in Section 6.4 of this application. [ Reference 2, Table 3 2) The following five device types are evaluated in the Instrument Line Commodity Evaluation in Section 6.4 of this application; Level Indicator, Level Transmitter, Pressure Indicator, Pressure Switch, and Pressure Transmitter. [ Reference 2, Table 3 2] One device type, Panel, is evaluated for the effects of aging in the Electrical Panels Commodity Evaluation in Section 6.2 of the BGE LRA. The remaining 19 device types that require AMR are listed in Table 5.1 l. These are the subject of the rest of this section. Unless otherwise annotated, all components of each listed device type are covered. [ Reference 2, Table 3 2) Baltimore Gas and Electric Company may elect to replace components for which the AMR identifies further analysis or examination is needed, in accordance with the License Renewal Rule, components subject to replacement based on quali0ed life or specined time period would not be subject to AMR. Application for License Renewal 5.17 Calven Cliffs Nuclear Power Plaat
A1TACllMENT (3) APPENDIX A TECilNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM i TAllLE 5.1 1 DEVICE TYPES REOUIRING AMR FOR AFW SYSTEM i ! Device type Dedeo Type Desedption . EB AFW Piping. EB EBB AFW Piping EBB EBC AFW Piping EBC EC AFW Piping. EC lill AFW Piping IIB (2) IIBC AFW Piping IIBC llc AFW Piping IIC CKV Check Valve (1) CV Control Valve and CV Operator FE Flow Elements FO Flow Orifice GOV Governor Valve liv lland Valve (t)(2) 1/P Current / Pneumatic Device (3) PCV Pressure Control Valve PUMP Pump SV Solenoid Valve TK Tank TURB Turbine Notes: (1) Instrument line manual drain, equalization, and isolation valves in the AFW System that are subject to AMR are evaluated for the effects of aging in the Instrument Line Commodity Evaluation in Section 6.4 of this application. Instrument line manual root valves are evaluated in this report, [ Reference 7. Attachment 3] (2) liarid valves and piping, which are relied upon for safe shutdown in the event of a fire and are classified as NSR, are evaluated for ;he efTects of aging in the Fire Protection Evaluation in Section 5.10 of the BGE LRA. All SR valves and piping are evaluated in this report. [ Reference 8] (3) A total of 24 current / pneumatic devices are within the scope oflicense renewal. Only eight of these devices are subject to AMR and are included in this report. The other 16 are not subject to AMR because they are either included in a replacement program or they have only active intended functions. 5.1. Aging Management The list of potential Age-Related Degradation Mechanisms (ARDMs) identified for the AFW System device types is given in Table 5.12. [ Reference 2, Table 4 2] The plausible ARDMs are identified in Application for License Renewal 5.1 8 Calvert Cliffs Nuclear Power Plant
ATTACitMENT (3) APPENDIX A- TECIINICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM the table by a check mark (/ ) in the appropriate device type column. For AMR, some device types have a number of groups associated with them because of the diversity of material used in their fabrication or differences in the environments to which they are subjected. A check mark indicates that the ARDM applies to at least one group for the device type listed, For efficiency in presenting the results of these evaluations in this report, ARDM/ device type combinations are grouped together where there are similar characteristics and the discussion is applicable to all components within that group. Exceptions are noted where appropriate. Table 5.12 also identines the group to which each ARDM/ device type combination belongs. The following groups have been selected for the AFW System.
. Group 1 cavitation erosion of AFW piping. EB; Group 2 internal surface corrosion in a water environment; Group 3 external surface corrosion in an atmospheric environment; Group 4 - external surface corrosion of buried pipe; Group 5 - internal surface corrosion in a steam environment:
Group 6 external surface corrosion of the turbine driven pump; I Group 7 - wear and elastomer degradation of solenoid-operated valves; I Group 8 general corrosion of control valve opeintors; and Group 9 - elastomer degradation of No.12 CST perimeter seal. The following is a discussion of the aging management demonstration process for each group identified above. It is presented by group and includes a discussion of materials and environment, aging mechanism effects, methods of managing aging, aging management program (s), and aging management demonstration. Group I (cavitation erosion of AFW piping- EH)- Materials and Environment The pipe and fitting material for the AFW System Class ED piping is carbon steel, American Society for Testing and Materials (ASTM] A106 GR B. The bolting material is alloy steel. The material for the nuts is carbon steel. Cavitation erosion is only considered to be plausible for the internal piping surfaces. The bolts and nuts are not exposed to the process fluid. (Reference 2. Attachments 4 and 6) Application for License Renewal 5.1-9 Calvert Cliffs Nuclear Power Plant
a ATTACilMENT m APPENDIX A. TECHNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM {
\
l TAHLE 5.12 POTENTIAL AND PLAUSlHLE ARDMs FOR THE AFW SYSTEM l
~ l Device Types for Which ARDM is Plausible
~
POTENTIAL ARDMs TK FE l/P GOY ER EC HB HC FO Cavi'ation Erosion Corrosion Fatigue Crevice Corrosion /(3) /(5) /(2) /(2,3,4) Dynamic Loading Electrical Stressors
- Erosion Corrosion /(5)
Fatigue Fouling Galvanic Corrosion
/(4)
General Corrosion /(3) /(5) /(2) /(2,3,4) liydrogen Damage Intergranular Attack Microbiologically Induced
/(4)
Corrosion (MIC) Pitting /(3) /(5) /(2) /(2,3,4) Radiation Damage Elastomer Degradation /(9) Selective Leaching Stress Corrosion Cracking Thermal Damage Thermal Embrittlement Wear
/ - Indicates plausible ARDM determination for at least one group for the device type ilsted.
(#) - Indicates the group (s)in which this ARDM/ device type combination is evaluated Note: Not every group within the device types listed here may be susceptible to a given ARDM. This is because groups within a device type are not always fabricated from the same materials or subject to the same environments. Exceptions for each device type will be indicated in the aging management section for each ARDM discussed in this report. Note: Cavitation erosion is plausible for only portions of the EB piping. Those portions are immediately downstream of flow orifices 1/2 FO 4506,4507, and 4540 due to the large pressure drops of these locations. Application for License Renewal 5.1 10 Calvert Cliffs Nuclear Power Plant
. _ _ _ _ . _ _ _ _ _ . . _ . . ~ _ . - _ - _ _ _ _ _ _ _ . _ __. _ . . .
ATTACHMENT 0) APPENDIX A. TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM TAHLE 5.12 (continued) ' POTEtf11AL AND PLAUSlHLE ARDMs FOR THF AFW SYSTEM I Device Types for Which ARDM is Plausible POTENTIAL ARDMs PUMP PCV TURB CKY CV HV SV CV (OP) Cuvita:lon Erosion Corrosion Fitigue Crevice Cor+osion /(2,6) /(5) /(2,3) ((2,5) /(2,3) Dynamic Loading Electrical Stressors Erosion Corrosion /(5) /(5) Fatigue Fouling ] Galvanic Corrosion General Corrosion /(2) /(5) /(2,3) /(2,5) /(2,3) /(8) ilydrogen Damage Intergranular Attack
- MIC j Pitting /(2,6) /(5) /(2,3) /(2,5) /(2,3)
Radiation Damage Elastomer Degradation /(7) Select!ve Leaching Stress Corrosion Cracking Thermal Damage Thermal Embrittlement Wear /(7)
/ - Indicates plausible ARDM determination for at least one group for the device type listed.
(#) - Indicates the group (s)in which this ARDM/ device type combination is evaluated. d Note: Not every group within the device types listed here may be susceptible to a given ARDM. This is because groups within a device ope are not always fabricated from the same materials or subject to the same environments. Exceptions for each device type will be indicated in the aging management section >- for each ARDM discussed in this report. . The internal surfaces of the piping are exposed to chemistry controlled water below 200'F. For most of the AFW System, fluid How (when in use), pressure, temperature, and in line component pressure drops do not create conditions required for cavitation. The Dow is relatively steady and the pressure is much greater than vapor pressure at system operating and standby temperatures. However, large pressure J Application for License Renewal 5.1 11 Calvert Cliffs Nuclear Power Plant
ATTACitMFNT G) APPENDIX A. TECilNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM drops at Dow orifices 1/2F04506,4507 and 4540 may result in cavitation in the Class ED piping at these locations. (Reference 2, Attachments 3,4, and 6] Eroup 1 (cavitation erosion of AFW Class EH piping). Aging Mechanism Effects: As stated abua, for most of the AFW System, the Dow is relatively steady and the pressure is much greater than vapor pressure at system operating and standby temperatures, llowever, given the high ; presuite drop and low recovered downstream pressure at flow orifices 1/2FO4506,4507, and 4540, i wavitation erosion is considered plausible at these locations. The resulting material loss would be localized in nature and within several pipe diameters downstream of the orifice plates. The degradation j from cavitation erosion typica:ly erodes component walls quickly. Cavitation erosion causes loss of ' material and reduces the cross sectional area. [ Reference 2, Attachment 6] Ifleft unmanaged, cavitation erosion could eventually result in the loss of pressure-retaining capability under current licensing basis (CLD) design loading coaditions, i Group 1 (cavitation erosion of AFW Class EB piping) . Methods to Manage Aging: Mitigatlom The occurrence of cavitation crosion is expected to be limited and is unlikely to affect the intended function of the AFW System Group I components due to the limited amount of time the system is in operation.. Therefore, no specific mitigation measures are deemed necessary. Discoverv: An inspection of potentially affected piping components will provide assurance that significant cavitation erosion is not occurring, or will result in initiation of corrective action if significant cavitation crosion is occurring. [ Reference 2. Attachment 8] Representative samples of susceptible locations can be used to assess the need for additional inspections at less susceptible locations. Based on piping / component geometry and fluid flow conditions, areas most likely to experience cavitation erosion can be determined and evaluated. Group 1 (cavitation erosion of AFW Class EB piping). Aging Management Program (s): Mitigatiom There are no specific programs credited for mitigation of cavitetlan crosion of AFW Class EB piping. Discoverv: Cavitation erosion can be wadily detected through non destructive examination techniques, llowever, due to the limited use of this system, the occurrence of this ARDM is expected to be limited and not likely to affect the intended function. As such, an inspection program can provide the additional assurance needed to conclude that the effects of plausible aging are not threatening the ability of the subject piping to perform its intended function for the period of extended operation. [ Reference 2, Attachment 8] The internal surfaces of AFW piping Class EB, down stream of flow orifices 1/2 FO 4506,4507, and 4540, will be included in a new CCNPP Age-Related Degradation Inspection (ARDI) Program to accomplish the needed inspections for cavitation erosion. This program is considered an ARDI Program as defined in the CCNPP IPA Methodology presented in Section 2.0. Application for License Renewal 5.1 12 Calvert Cliffs Nuclear Power Plant
A'ITACHMENT (3) APPENDIX A - TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM i The elements of the ARDI Program will include: e Determination of the examination sample size based on plau>ible aging effects; Identification of inspection locations in the system / component based on plausible aging efTects and consequences ofloss of component intended function; Determination of examination techniques (including acceptance criteria) that would be effective, considering the aging effects for which the component is examined; e Methods for interpretation of examination results; e Methods for resolution of unacceptable examination findings, including consideration of all design loadings required by the CLB, and specification of required corrective actions; and e Evaluation of the need for follow-up examinations to monitor the progression of any age related degradation. The corrective actions will be taken in accordance with the CCNPP Corrective Action Program and will ensure that the Class EB piping will remain capable of performing the system pressure boundary integrity function under all CLB conditions. Group 1 (eevitation erosion of AFW Class EB piping)- Aging Management Demonstration: Based on the information presented above, the following conclusions can be reached with respect to cavitation crosion of the internal surfaces of the Class EB piping of the AFW System. The Class EB piping contributes to the system pressure boundary function. Given the high pressure drop across the flow orifices and low recovered downstream pressure, cavitation erosion is considered a plausible ARDM for the Class ED piping. The resulting material loss is localized in nature and would be of most concern within several pipe diameters downstream of the orifice plates. Due to the limited use of the system, it is not likely this ARDM will afTect the intended function of the piping. However, if left unmanaged, this ARDM could eventually result in the loss of pressure retaining capability under CLB design loading conditions, e To provide the additional assurance needed to conclude that the effects of this ARDM are not threatening the ability of the piping to perform its intended function, the internal surfaces of AFW piping, down stream of flow orifices 1/2 PO 4506,4507, ud 4540, will be included in the scope of an ARDI Program. Inspections will be performed and appropriate corrective action will be taken if significant degradation is discovered. Acrefore, there is a reasonable assurance that the effects of aging will be adequately managed for the AFW Class EB piping such that it will be capable of performing its intended function, consistent with the CLB, during the period of extended operation. s Application for License Renewal 5.1-13 Calvert Cliffs Nuclear Power Plant
. ATTACHMENT W APPENI)lX A- TECIINICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Group 2 (laternal surface corrosion in a water environment)- Materials and Environment Group 2 consists of components that have an internal environm.nt of treated water and whose intemal surfaces are subject to crevice corrosion, general corrosion, and/or pitting. The device types that have at least one component with Group 2 attributes include Class ED piping, Class 110 piping, motor driven AFW pumps, check valves, control valves, and hand valves. The subcomponents in these device types that are exposed to water are constructed of the following materials: [ Reference 2, Attachments 4 and 6)
- Class ED piping carbon steel pipe and fittings; e Class llB piping carbon steel pipe and fittings; e motor driven AFW pumps carbon steel casing with carbon steel, alloy steel, and stainless steel (martensitic) intemal subcomponents; e check valves carbon steel body / bonnet and bearing cops (Note: Check valve internals are not subject to AMR because the valves are not required to be in a closed position for maintaining the system pressure boundary. He only exception to this is the check valves that provide the pressure boundary between the AFW System and the Chemical Addition System. Those check valves have internals con *ucted of stainless steel.);
e control valves carbon steel is Jy/ bonnet with stainless steel stem (Note: None of the valves are required to be in the closed position for maintaining the system pressure boundary.); and
. hand valves carbon steel body / bonnet with alloy steel, stellited carbon steel, and stainless steel internal subcomponents.
The environment for internal surfaces of most of the Group 2 components Is AFW that is below 200'F. The source of water for the AFW Syvem is one of the three CSTs (Nos,11,12, or 21), which contain water that is monitored and controlled through the Secondary Chemistry Program. The Secondary Chemistry Program the CSTs in order to maintain the fluid chloride and sulfate levels below predetermined limits. The portion of the Class ED piping from the check valve to the steam generator has an internal environment of chemistry controlled water, i.e., feedwater, below 532*F. The check valve that isolates the AFW System from the Chemical Addition System is exposed to demineralized water below 200'F that contains chemicals such as hydrazine, ammonia, and arnines. [ Reference 2, Attachment 1; Reference 9] Group 2 (internal surface corrosion in a water environment)- Aging Mechanism Effects: Crevice corrosion, general corrosion, and/or pitting are plausible for Group 2 components because some of the mateilats used in their construction are susceptible to these corrosion mechanisms when exposed to a wet environment. The aggressiveness of these corrosion mechanisms is particularly dependent on water chemistry conditions and oxygen levels in the water and on the materials of construction. [ Reference 2, Attachment 6] General corrosion is thinning (wastage) of a metal by chemical attack (dissolution) at the surface of the metal by an aggressive environment. General corrosion requires an aggressive environment and materials susceptible to that environment. Wastage is not a concern for austenitic stainless steel alloys. The consequence of the damage is loss of load-carrying cross sectional area. [ Reference 2, Attachments 6 and 7] Application 1 License Renewal 5.1 14 Calvert Cliffs Nuclear Power Plant
ATTACilMENT Lh APPENDIX A. TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Crevice corrosion is intense, localized corrosion within crevices or shielded areas. It is associated with a i small volume of stagnant solution caused by holes, gasket surfaces, lap joints, crevices under bolt heads, surface deposits, designed crevices for attaching thermal sleeves to safe ends, and integral weld backing rings or bt.:k up bars. De crevice must be wide enough to permit liquid entry and narrow enough to maintain stagnant conditions, typically a few thousandths of an inch or less. Crevice corrosion is closely relt.ted to pitting corrosion and can initiate pits in many cases, as well as leading to stress corrosion cracking. [ Reference 2, Attachments 6 and 7] Pitting is another form oflocalized cttack with greater corrosion rates at some locations than at others. Pitting can be very insidious and destructive, with sudden failures in high pressure applications (especially in tubes) occurring by perforation. This form of corrosion essentially produces holes of varving depth to diameter ratios in the steel. Pits are generally elongated in the direction of gravity, in ' mr s cases, erosion corrosion, fretting corrosion, and crevice corrosion cas also lead to pitting. (Reference 2, Attachment 6s and 7s] For Group 2 components, long term exposure to the water environment may result in localized and/or general area material loss and, if unmanaged, could eventually result in loss of the pressure retaining capability under CLB design loading conditions. The areas where there are stagnant conditions, e g., drain lines and crevices, are the locations most susceptible to these corrosion mechanisms. All three of these ARDMs are plausible for carbon steel and alloy steel subcomponents. Suocomponents constructed of stellited carbon steel or martensitic stainless steel are susceptible to crevice corrosion and pitting only, his is because these materials are resistant to general corrosion. [ Reference 2, Attachment 6) Crevice corrosion, general corrosion, and pitting are not plausible for subcomponents constructed of austenitic stainless steel due to the inherent corrosion resistance of the material and the non-aggressiveness of the environment. System chemistry control maintains the fluid non-corrosive by limiting the concentration of chlorides and sulfates. Additionally, system operating temperatures (s 100'F) and standby temperatures (s 140'F) are low, thus minimizing corrosive effects. Therefore, the efTects of these ARDMs are minimal and have no effect on the intended function of the components. Ba, ' on these considerations, crevice corrosion, general corrosion, and pitting are not plausible for subcomponents constructed of austenitic stainless steel. [ Reference 2, Attachment 6] Group 2 (internal surface corrosion in a water environment)- Methods to Manage Aging: Mitigntlom The effects of corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of the Group 2 components and the piping material to an aggressive environment. Maintaining an internal environment of purified water with dissolved oxygen and other impurities maintained at low levels, results in limited corrosion reactions. In some cases, the initial formation of a passive oxide layer (magnetite) also protects the pipe interior surface by minimizing the exposure of bare metal to water. [ Reference 2, Attachments 6 and 7] Discoverv: The occurrence of corrosion (crevice corrosion, general corrosion, and pitting) is expected to be limhed and is unlikely to afTect the intended ftmetion of the AFW System Group 2 components due to
.the control of fluid chemistry. An inspection of representative plant components will provide assurance Application for License Renewal 5.1 15 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (3) APPENDIX A. TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM that significant corrosion is not occurring, or will result in initiation of corrective action if sigilficant corrosion le occurring. [ Reference 2, Attachment 8) Representative camples of susceptible locations can be used to assess the need for additional Inspections at less susceptible locations. Based on piping / component geometry and fluid flow conditions, areas most likely to experience corrosion can be determined and evaluated. ' Group 2 (internal surface corrosion la a water environment) Aging Management Programs: Mltination CCNPP Secondary Chemistry Snecifientions and Surveillt.nce Program
%e CCNPP Secondary Chemistry Specifications and Surveillance Program has been established to control bulk fluid chemistry of several plant systems, including the CSTs, to reduce corrosion product generation, transport, and deposition on system components. [ Reference 10, Section 6.1.A] He scope of the Secondary Chemistry Program includes: steam generators, CSTs, Feedwater System, Condensate System, Main Steam System, heater drnin tanks, condensate demineralizer effluent, steam generator blowdown ion exchanger effluent, and condensate preccat filters. [ Reference 9, Section 2.C] The program is based on References 11 through 16.
%c Secondary Chemistry Program monitors fluid chemistry in the CSTs, including make-up water to the CSTs, in order to minimize the concentration of corrosive impurities (chlorides, sulfates, oxygen).
Control cf fluid chemistry minimizes the corrosiveness of the environment for AFW System components, thereby minimizing the rate and effects of corrosion. The rate of corrosion is also reduced in some cases by the initial buildup of a passive oxide layer (magnetite) that minimizes bare metal , exposure to water. (Reference 2, Attachment 6s; Reference 9] Seconda<y chemistry parameters (e.g., dissolved oxygen) see measured at procedurally specified frequencies. The measured parameter values are compared against " target" values which represent a goal or predetermined warning limit. If a value is out of bounds, cormctive actions are taken as prescribed by secondary chemistry procedure CP 217, " Specifications and Surveillance: Secoudary Chemistry," thereby ensuring timely respons: to chemical excursions. [ Reference 9, Sections 6.0.C and Attachment 9] The Secondary Chemistry Program has the target and action values based on chemistry guidelines provided by Electric Power Research Institute, institute for Nuclear Power Operations (INPO), and the Nuclear Steam Supply System vendor. The corrective actions taken will help minimize the aggressiveness of the internal environment of AFW System Group 2 components so that they remain capable of performing their intended function:: under all CLB conditions. The Secondary Chemistry Program is subject to internal assessment activity both within the Chemistry Department and through the site performance assessment group. He program is recognized through these assessments as maintaining highly eTective secondary chemistry controls and aggressively pursuing continuous improvements through monitoring industry initiatives and trends in the area of secondary systems corrosion control. The program is also subject to frequent external assessments by INPO, NRC, and others. Operating experience relative to the Chemistry Program at CCNPP has been such that no site specific problems or events related to these aging mechanisms are known to have occurred that required changes Application for License Renewal 5.1 16 Calvert Cliffs Nuclear Power Plant
, 1 ATTACHMENT m APPENDIX A. TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM or adjustments to the program. It has been e.Tective in its function of mitigating corrosion and corrosion-related failures and problems. The main focus of the program is steam generator chemistry. It has been demcastrated that as long as steam generator chemistry is carefully monitored and controlled, the other secondary systems are also successfully controlled. Calve:1 Cliffs has been proactive in making programmatic changes to the Secondary Chemistry Program over its history largely in response to developments within the industry, such as successful experimentation with a new alternate amine.
4 CCNPP Dernineralized WggtChemistry Snecifications and Surveillance Progam De CCNPP Demineralized Water Chemistry Specifications and Surveillance Program has been established to: minimize impurity ingress to plant systems; reduce corrosion product generation, transport, and deposition; reduce collective radiation exposure through chemistry; improve integrity and availability of plant systems; and extend component and plant life. (Reference 10, Section 6.1.A] The d: mineralized water chemistry program is applicable to the Demineralized ','.'eter and Well Water Systems for use in primary, auxiliary, and secondary plant systems. The program is based on
- References 17 through 21. (Reference 22 Section 2]
The demineralized water chemistry program controls fluid chemistry in order to minimize the concentration of corrosive impurities and dissolved oxygen. The demineralized water chemistry parameters (e.g., specific conductivity, dissolved oxygen, chloride, fluoride, sulfate) are measured at procedurally specified frequencies. The measured parameter values are compared against " target" values, which represent a goal or predetermined warning limit. [ Reference 22, Attachment 3] If a value is out of bounds, special and/or general corrective actions (such as, resampling, increased surveillance frequency, technical evaluation) are taken as prescribed by procedure (Reference 22, Section 6.0] His , will help ensure that the aggressiveness of the internal environment for check valves that are located at the interface of AFW System and Chemical Addition System is minimized so that they remain capable of performing their intended functions under all CLB conditions. De demineralized water chemistry program is subject to internal assessment activity, both within the Chemistry Department and through the site performance assessment group. The program is recognized through these assessments as maintaining highly effective secondary chemistry controls and aggressively pursuing continuous improvements through .nonitoring industry initiatives and trends in the area of secondary systems corrosion control. The program is also subject to frequent external assessments by INPO, NRC, and others. De CP 202 program, " Specifications and Surveillance Demineralized Water, Safety Related Battery Water, Well Water Systems, and Acceptance Criteria for On line Monitors," since its inception, has essentially remained the same and has performed well. The changes in the limits of chemistry parameters aie reflective of upgrades in the capability of measuring instruments and experience gained over the years. Application for Lice ise Renewal 5.1 17 Calvert Cliffs Nucle 7ar Power Plant
ATTACHMENT LM APPENDIX A TECHNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM Discoverv-CCNPP ARDI Program for Group 2 components, crevice corrosion, general corrosion, and pitting can be reJily detected through visual inspections. Due to the control of water chemistry, the occurrence of crevice corrosian, general corrosion, and pitting is expected to be limited and not likely to affect the intended functice of the Group 2 components. An inspection program can provide the additional assurance nee.le , to conclude that the effects of pl usible aging are being effectively managed for the period of .xte1ded operation. [ Reference 2, Attachment 8] All Group 2 components will be included within a new piant program to accompilsh the needed inspections for corrosion. His program is considered an ARDI Program as defined in the CCNPP IPA Methodology presented in Section 2.0. Refer to the Group 1 discussion on aging management programs for a detalked discussion of the ARDI Program. Corrective actions will be taken in accordance with the CCNPP Corrective Action Program and will ensure that the components will remain capable of performing their pressure boundary integrity function under all CLB conditions. Group 2 (internal surface corrosion in a water environmenO - Aging Management D;monstration: Based on the information presented above, the following conclusions can be reached with respect to general corrosion, crevice corrosion, and pitting of AFW System Group 2 components:
- The AFW System Group 2 components contribute to the system pressure boundary function and their integrity must be maintained under all CLB conditions.
- Crevice corrosion, general corrosion, and pitting are plausible ARDMs for this group of components and could result in material loss which, if left unmanaged, can lead to loss of pressure-retaining capability under CLB design loading conditions.
- The CCNPP Secondary Chemistiy Specifications and Surveillance Program controls fluid chemistry in the CSTs, which minimizes the corrosiveness of the environment for the AFW System components.
- CCNPP Demineralized Water Chemistry Specifications and Surveillance Program controls the fluid chemistry for the supply of water to the Chemical Addition System, and hence to the AFW System, to minimize the corrosiveness of the environment for the AFW components that interface with that system.
- The occurrence of these ARDMs is expected to be limited and not likely to affect the intended function of the Group 2 components due to the control of fluid chemistry, low operating temperatures, and the limited operation.
- To provide the additional assurance needed to conclude that the effects of corrosion are being effectively managed, the components exposed to water will be included in the scope of an ARDI Program, inspections will oc perfomied and appropriate corrective action will be taken if significant corrosion is discovered.
Application for License Renewal 5.1-18 Calvert Cliffs Nuclear Power Plant
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ATTACilMENT m APPENDIX A- TECilNICAL INFORMATION 5.1 AUXILIARY FEEDWATER SYSTEM Herefore, there is reasonable assurance that the effects of crevice corrosion, general corrosion, and pitting on Groep 2 components will be adequately managed such that they will be capable of performing their pre:sure boundary integrity function, consistent with the CLB, during the period of extended operation. 3roep 3 (esternal surface corrosion in an atmospheric environment)- Materials and Environment Group 3 consists of components that are exposed m an atmospheric external environment and whose external surfaces are subject to crevice corrosion, general corrosion, and/or pitting. The device types that have at le .st one compor< nt with Gr up 3 attribu'es include Class 110 piping, check valves, hand valves, and tanks. The subcomi onents in ese device types that are exposed to atmospheric conditions are constructed of the followin 1 materials: (Reference 2, Attachments 4 and 6) e Class 118 piping coon steel pipe with i.lloy steel studs and carbon steel nuts; e check valves carbon steel body with alloy steel studs and carbon steel nuts; e nand vahes carbon steel body with carbon s. eel, ahoy steel, or stainless steel stems, studs and nuts; and a tarks stainless steel tank with carbon steel anchor bolts / nuts. The AFW System Group 3 components are exposed to two different external environments. in one environment there is piping, check valves, and hand valves located inside of a concrete valve pit, which I. normally closed and thereby not readily accessible. He air inside the valve pit is normal outside atmosphere and, since it is not conditioned, may contain high humidity. [ Reference 2, Attachment 6) In the other environment there is pipi.,g, hand valves, and a tank located inside of the concrete No.12 CST enclosure. The enclosure has openings to the outside, allowing for air changes generated by wind, but provides f.ill protectien from rair The concrete structure thermal mass causes the internal temperatures to temain fairly coastant. The resulting environmental conditions are non wetted, varying humidity, and low, stable te npe:atures. liowever, extremes in humidity and temperature may result in surface moisture on the protected components. A tank perimeter seal (caulk) is provided between the elevated ring foundethn and No.12 CST to prev mt moisture from being channeled under the tank. Refer to Group 9 for a discussion of aging management for the c'iulking. (Reference 2, Attachment 6)
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Group 3 (external surface corrosion in an atmospheric environment)- Aging Mechanism Effects: Crevice corrosion. peneral corrosion, e vl/or pitting are plausible for Group 3 components because some of the materiais usci in their construction are susceptible to these corrosion mechanisms wl.eu exposed tc a wet environment. The aggressiveaess of these corrosion mechanisms is particularly dependent on the overall corrosiveness of the environment and on the materials of construction Refer to the discussion in Group 2 above for a detailed descriotion of crevice corrosion, generel corrosion, and pitting. [ Reference 2 Attanment 6] For Group 3 components, long term exposure to a moist environment may result in localized and/or general area material loss and, iflefl unmanaged, could eventually result in loss of the pressure-rt. mining capability under CLB design loading conditions. He areas where there are stagnant conditions and cracks or crevict e.g., under the nut or in threaded areas of the stud, are the locations most susceptible to these corrosion .nechanisme All three of these ARDMs are p%usible for carbon steel and alloy steel Application for License Renewal 5.1-19 Calvert Cliffs Nuclear Power Plant l l I
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ATTACHMENT 0) APPENDlX A. TECHNICAL INFORMATION 5.1 - AUXEIARY FEEDWATER SYSTEM i l subcomponents. Crevice corrosion, general corrosion, and pitting are not plausible for subcomponents constructed of austenitic stainless steel due to the inherent corrosion resistance of the material and the non aggressiveness of the environment. [ Reference 2 Attachment 6) Group 3 (external surface corrosion in an atmospheric environment)- Methods to Manage Aging: Mitigation: The effects of corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of external surfaces of steel to an aggressive environment and protecting the external surfaces with paint or other protective coating. Coatings serve as a protective layer, preventing moisture and oxygen from directly contacting the steel surfaces. [ Reference 2, Attachment 8] Discoverv: The effects of crevice corrosion, general corrosion, and pitting are detectable by visual inspection. Components that do not have insulation ar.d are readily accessible can be observed periodically during routine walkdowns or inspections. Areas that are not readily accessible or that have insulation must be inspected as part of a dedicated program so that access can be provided and insulation removed as necessary. Corrective actions can be initiated if there is any evidence of corrosion identified during these inspections. [ Reference 2, Attachment 8] The external metal surfaces of some of the components and piping are covered by a protective coating, and observing that significant degradation has not occurred to this coating is an effective method to ensure that corrosion is being mitigated. Coatings degrade over time, allowing visual detection during normal operational walkdowns. The coating does not contribute to the intended function of the components; however, visually examining the coating for degradation provides an alert condition, which triggers corrective action prior to degradation that affects the component's ability to perform its intended function. The degradation of the protective coating that does occur can be discovered and managed by periodically inspecting the components and by carrying out corrective sction as necessary. [ Reference 2, Attachment 8] Group 3 (external surface corrosion in an atn.ospherie environment) - Aging Management Programs: w hiitigation: The external metal surfaces of some of the components are covered by a protective coating that mitigates the effects of crevice co,rosion, general corrosion, and pitting. The discovery programs disci!ved below ensure that the protective coatings of Group 3 components are maintained. DISMsm CONPP System Walkdown Program Calvert Cliffs Plant Engineering Guideline, PEG 7, " System Walkdowns," provides for discovery of corrosion and degraded paint by providing l'or system walkdowns by visual inspection, reporting the walkdown results, and initiating corrective action. Under this program, inspection items typically related to aging management include identifying poor housekeeping conditions (such as degraded paint), and identifying system and equipment stress or abuse such as thermal insulation damage, external leakage of fluids, etc. Non insulated equipment in accessible areas of the No.12 CST enclosure can be monitored for corrosion and degraded paint through these walkdowns. Conditions identified as adverse to quality are corrected in accordance with the CCNPP Corrective Actions Program. [ Reference 23] Application for License Renewal 5.1 20 Calvert Cliffs Nuclear Power Plant
A*PrACHMENT (3) l APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM , Under PEG.7, engineering personnel perform periodic walkdowns (typically monthly or as negotiated with the supervinr); walkdowns before, during, and after outages; and walkdowns related to a specific plant modification (s), nese walkdowns have the following characteristics: [ Reference 23 Section $ 0] e Walkdowns are conducted at periodic intervals, as set by the Plant Engineering Guideline, basci on system performance, operating conditions, etc.
- Walkdowns are generally performed by the assigned responsible engineer, who is familiar with the system and its condition. Signs of corrosion or effects of excessive loading would be detected by this individual.
- To assist in detecting such conditions, the System Walkdown guideline contains a checklist, which contains items related to aging of pip!ng and components such as checking that coatings are applied and intact. Conditions observed during the walkdown are also recorded.
- The Plant Engineering Guideline on System Walkdowns requires that any unusual condition observed during the walkdown be recorded on the walkdown sheet and assistance obtained from design engineering in evaluating the impact of the unusual condition. Conditions that warrant further action are documented on an issue report and the site corrective action program tracks the status of corrective actions. [ Reference 23]
Guideline PEG-7 promotes familiarity with the systems by the system engineers and provides extended attention to plant material condition beyond that afforded by operations and maintenance alone. As a result of experience gained, PEG-7 has been improved over time to provide guidance regarding specific standard activities that should be included in walkdowns. CCNPP ARDI Program Crevice corrosion, general corrosion, and pitting will be readily de2ectable for the Group 3 components through visual inspections. However, some of the components are in areas that are not readily accessible, such as the valve pit, or are covered by insulation. These components will be included in a new plant program to accomplish the needed inspections for corrosion. This program is considered an ARDI Program as defined in the CCNPP IPA Methodology presented in Section 2.0. Refer to the Group I discussion on aging management programs for a detailed discussion of the ARDI Program. [ Reference 2, Attachment 8] Corrective actions will 'oe taken in accordance with the CCNPP Corrective Action Program and will ensure that the components will remain capable of performing their pressure boundary integrity function under all CLB conditions. Group 3 (external Ece corrosion in an atmospherie environment) - Aging Management Demonstration: Based on the informa:lon presented above, the following conclusions can be reached with respect to general corrosion, crevice corrosion, and pitting of AFW System Group 3 components:
- The AFW System Group 3 components contribute to the system pressure boundary function and their integrity must be maintained under all CLB conditions.
Application for License Renewal 5.1 21 Calvert Cliffs Nuclear Power Plant
ATTACHMrNT (3) APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM e Crevice corrosion, general corrosion, and pitting are plausible ARDMs for this group of components and could result in material loss which, if left unmanaged, can lead to loss of pressure retaining capability under CLB design loading conditions. Guideline PEG 7 provides for discovery of corrosion and degraded paint on uninsulated components in accessible areas by providing for visual inspection through system walkdowns, reporting the walkdown results, and initiating corrective action in accordance with the CCNPP Corrective Actions Program, e he Group 3 components located in locations not readily accessible or covered by insulation will be included in the scope of an ARDI Program. Inspections will be performed and appropriate corrective act'on w;ll be taken if signi'icant corrosion is discovered. Derefore, there is reasonable assurance that the effects of crevice corrosion, general corrosion, and pitting will be adequately managed for the AFW System Group 3 components such that they will be capable of performing their pressure boundary integrity function, consistent with the CLD, during the period of extended operation. Group 4 (external surface corrosion of buried pipe)- Materials and Environment Group 4 consists of piping that is buried in soll or embedded in concrete and whose external surfaces are subject to crevice corrosion, general corrosion, MIC, and pitting. The external surfaces of the piping are protected per standard industry practice with external coating and wrapping. A cathodic protection system is also in place for the buried pipe; however, no credit is taken for mitigation of corrosion. The buried pipe and fittings are constructed of carbon steel. [ Reference 2, Attachments 4 and 6] The two main headers penetrate horizontally into the Auxiliary Building through a blockout approximately 5 feet below grade. The blockout is filled with concrete. The concrete is sufliciently impermeable to water to protect the rebar, and would therefore similarly protect the embedded portion of the pipe. Ilowever, the protective coatings at the penetration interfaces may have been damaged during construction, which could allow moisture into these areas. [ Reference 2, Attachment 6] The pipes going to and from the valve pit in the tank farm also penetrate into a concrete structure below grade. In this case, the penetrations are caulked, liowever, the caulking below grade would not be expected to provide protection from moisture for 60 years and could, therefore, allow corrosion to take place on the exterior surfaces of the pipes inside the penetrations. [ Reference 2, Attachment 6] Group 4 (external surface corrosion of buried pipe) . Aging Mechanism Effects: Crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting are plausible for Group 4 piping because the carbon steel material used in its construction is susceptible to these corrosion mechanisms when exposed to a wet environment and in electrical contact with a dissimilar metal. The aggressiveness of these corrosion mechanisms is particularly dependent on the overall corrosiveness of the environment and on the materials of construction. Refer to the discussion in Group 2 above for a detailed description of crevice corrosion, general corrosion, and pitting. [ Reference 2, Attachment 6] Application for License Renewal 5.1 22 Calven ClitTs Nuclear Power Plant
ATTACHMENT 0) APPENDIX A- TECIINICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Microbiologically-induced corrosion is accelerated corrosion of materials resulting from surface microbiological activity. Sulfate reducing bacteria, sulfur oxidizers, and iron oxidizing bacteria are most commonly associated with these corrosion effects. Microbiologically induced corrosion mest onen results in pitting, followed by excessive deposition of corrosion products. Essentially all buried piping systems and most commonly used materials are susceptible to MIC. [ Reference 2, Attachment 7] Galvanic corrosion is an accelerated corrosion caus' e d by dissimilar metals in contact in a conductive i solution. It requires two dissimilar metals in physical or electrical contact, developed potential (material dependent) and a conducting solution. [ Reference 2, Attachment 7] For this piping section, the carbon steel pipe is at a different voltage potential than the steel rebar in the enrete surrounding sections of this pipe, in a moist, conductive soil environment, this could lead to galvanic corrosion with the pipe snrificing material at locations where the protective coating has holidays (thin spots, skipped areas, or where coating degradation has occurred) and is in contact with the wet soll. For Group 4 components, long term exposure to a moist environment may result in localized and/or general area material loss and, ifleA unmanaged, could eventually result in loss of tha pressure-retaining capability under CLB design loading conditions. Soil resistivity (or conductivity), chloride and sulfate presence, oxygen content and soll aeration, pit, moisture content of the soil and wet / dry cycles, and microbe activity affect these ARDMs. [ Reference 2, Attachment 6] Damaged protective coatings / wrappings, holidays or disbonded areas in the coating / wrapping, and leakage around caulking can allow these ARDMs to develop on the exterior surfaces of the p.pe and at the interface where the piper penetrate the concrete walls. All of these ARDMs are plausible for carbon steel piping. [ Reference 2, Attachment 8]
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Group 4 (external surface corrosion of buried pipe) Meth$ls to Manan Agig Mitigation: The efhets of corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of external surfaces of steel to an aggressive environment by protecting the external surfaces with protective wTapping/ccatings and application of cathodic protection. Wrapping / coatings serve as a protective layer, preventing moisture, oxygen, and microbes from directly contacting the steel surfaces. [ Reference 2. Attachment 8] Discovery: The effects of crevice corrosion, general corrosion, MIC, and pitting are detectable by visual inspection. The wrapping and coating do not contribute to the intended function of the buried piping. Ilowever, they play a role in mitigating corrosion of buried and embedded piping. Visually examining the wrapping and coating on the buried piping for evidence of degradation provides an alert condition, which triggers corrective action before degradation that affects the underground piping's ability to perform its intended function could occur. The corrosion that does occur can be discovered and managed by inspecting the piping at areas where the wrapping has holidays or disbonded areas. Den repairs can be made to the piping or wrapping as required. (Reference 2, Attachment 8] Application for License Renewal 5.1-23 Calvert Cliffs Nuclear Power Plant
]
NITACllMENT (3) I APPENDIX A. TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Group 4 (external surface corrosion of buried pipe). Aging Management Programs: Mitigation: The external surfaces of buried piping are pro'.ected from contact with the soil or concrete by protective wrapping / coatings. This design feature mitigates the effects of crevice corrosion, general corrosion, MIC, and pitting. Although the piping is further protected with a cathodic protection system, it is not credited for mitigating these ARDMs. The discovery program discussed below ensurea that the protective coatings of Group 4 components are maintained. iReference 2, Attachment 8] Discoverv: CCNPP AFW Buded Pine Intnection Program A new prcgram for buried pipe will include AFW Group 4 piping and will provide assurance that the piping 9ill remain capable of maintaining the system precure boundary under all CLB conditions. Representative samples of buried piping will be selected for inspection to ensure that the pipe wrapp',ng/ coatings are adequately protecting the pipe from the external environment. Any evidence of the effects of crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting will initiate corrective actions in accordance with the CCNPP Corrective Actions Program. (Reference 2, Attachment 8) Group 4 (external surface corrosion of buried pipe) . Aging Management Demonstration: Ba ed on the information presented above, the following conclusions can be reached with respect to crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting of AFW System Group 4 piping: The AFW Systcm Group 4 piping contributes to the system pressure boundary function and its integrity must be maintained under all CLB conditions. Crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting are plausible ARDMs for the buried piping and could result in meterial loss which, ifleft unmanaged, can lead to loss of pressure retaining capability under CLB design loading conditions. The exte1r.::i surfaces of the piping are protected according to standard industry practice with external coating and wrapping. Through a new CCNPP AFW Buried Pipe Inspection Program, corrosion would be discovered through visual inspections of representative piping sections and corrective actions will be taken as necessary. Therefore, there is reasonable assurance that the effects of crevia corrosion, galvanic corrosion, general corrosion, MIC, and pitting will be adequately managed for the AFW System Group 4 piping such that it will be capable of performing its pressure boundary integrity function, consistent with the CLB, during the period of extended operation. Application for License Renews! 5.1 24 Calvert Cliffs Nuclear Power Plant 1 j
A'ITACllMENT m APPENDIX A- TECilNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Group 5 (laternal surface corrosion in a stear. environment) . Materials and Environments Group 5 consists of components that are exposed to an internal environment of chemistry controlled steam below 600'F, and that are subject to crevice corrosion, general corrosion, pitting, and erosion corrosion. The device types that have at least one component with Group 5 attributes include the governor valve, turbine, and control valve (turbine throttle /stop valves). The subcomponents in these device typcs exposed to steam conditions are constructed of the following materials: (Reference 2 Attachments 4 and 6) e govemor valve alloy steel vah body and bonnet with an Inconel 718 stem, chromium-molybdenum alloy steel studs, and cart on steel nuts; e turbine - carbon steel turbine case and bypass elbow with a cast iron gland case, a stainters steel lobe oil cooler, carbon steel nuts, and alloy steel shaft,je'. plug, studs, and gland cap; and
- control valve cast alloy steel body, cover, and stuffmg box with Nitralloy 135 bushings and pilot valve, carbon molybdenum nuts, low alloy steel studs, and carbon steel plugs.
l These components are normally in a standby mode, but may be put into operation during plant heatup,
, plant cooldown, steam generator filling, and monthly testing. During those times, the components are 4
subject to induction of steam. Condensation of the steam during system warmup and after system ! cooldown is minimized by draining through the trip / throttle valve leakofTs, turbine exhaust, and turbine steam ring drains. Any remaining moisture / dampness, v,hich is usually from the main steam system (auxiliary steam may be used if the main steam pressure is low), is from a chemistry. controlled source that minimizes corrosion and non-condensible gases. [Rt.ference 2, Attachment 6] Group 5 (internal surface corrosion in a steam environment)- Aging Mechanism Effects: Carbon steel, many alloy steels, and cast iron are susceptible to crevice cotrosion, general corrosion, and pitting in a humid or wet environment. Rese ARDMs are plausible for Group 5 components because of the expost re to a wet environment following operation. The aggressiveness of these corrosion mechanisms is particularly dependent on the overall corrosiveness of the environment and on the materials of constinction. All three of these ARDMs are plausible for the subcomponents constructed of carbon steel, alloy steel, cast iron, Inconel 718, or Nitralloy 135. Crevice corrosion and pitting are plausible for subcomponents constructed of stainless steel or bronze alloy materials. General corrosion is not plausible for these components because the materials are resistant to general corrosion. If left unmanaged, crevice corrosion, general corrosion, and pitting could eventually result in the loss of pressure-retaining capability under CLB design loading conditions. [ Reference 2, Attachment 6] Refer to the discussion in Group 2 above for a detailed description of crevice corrosion, general corrosion, and pitting. Erosion corrosion is a plausible ARDM for all of the internal subcomponents of the Group 5 components, with the exceptions discussed below, because they are exposed to high velocity steam during operation and condensation / dampness during standby. Erosion corrosion of the stainless steel turbine lube oil cooler is not plausible because the stainless steel is resistant to erosion corrosion ani not exposed to steam flow. The governor valve oil cooler tubes and end cap are also not susceptible because the component design, materials, and internal environment do not perpetuate this ARDM. [iteference 2, Attachment 6] j Application for License Renewal 5.1 25 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (3) APPENDIX A- TECIINICAL INFORMATION
- 5.1 - AUXILIARY FEEDWATER SYSTEM 1
Erosion corrosion is the increased rate of attack on a metal due to the relative movement between a corrosive Guid and the metal surface. Erosion is a mechanical action of a Huld and/or particulate matter on a metal surface, without the innuence of corrosion. The corrosive process is accelerated because of the erosion destruction of the protective oxide Olm, which results in chemical attack or dissolution of the underlying metal. Erosion corrosion failures can occur in a relatively short time. The periodic testing of the system usmg high velocity steam may remove general corrosion products and the protective oxide Olm, resulting in continued general corrosion and crosiori/ corrosion. The aging c0'ects can be grooves, gullies, waves, holes, or valleys in the material surface, if left unmanaged, crosion corrosion could eventually result in the loss of pressure-retaining capability under CLB design loadbg conditions. [ Reference 2, Attachments 6 and 7] Group 5 (internal surface corrosion in a steam environr.sent)- Methods to Manage Agingt Mitlption: Controlling steam chemistry wi!! minimize the concentration of corrosive impurities (e.g., chlorides, sulfates, oxypn). By maintaining water chemistry within acceptable limits, all types of corroshn can be mitigated. [ Reference 2, Attachment 8] Discoverv: The effects of corrosion (crevice corrosion, general corrosion, pitting, and erosion corrosion) on AFW System Group 5 components can be discovered and monitored through non-destructive examination techniques such as visual inspections. [ Reference 2, Attachment 8] Representative samples of susceptible locatiors can be used to assess the need for ;dditional inspections at less susceptible locations. Based on wmponent geometry and Guld Dow conditions, areas most likely to experience corrosion can be determined and evaluated. [ Reference 1, Attachment 6] Group 5 (Internal surface corrosion in a steam et.nronment)- Aging Management Programs: Mitination: CCNPP Secondary Chemistrv Snecifications and Surveillance Procram The CCNPP Secondary Chemistry Specl0 cations and Surveillance Program has been established to-minimize impurity ingress to plant systems; reduce corrosion product generation, transport, and deposition; improve integrity and availability of plant systems; and extend component and plant life. Control of fluid chemistry minimizes the corrosiveness of the environment for AFW System Group 5 components, and thereby minimizes the rate and effects of corrosion. [ Reference 10, Section 6.1.A] Refer to the Group 2 discussion on aging management programs for a detailed discussion of the Secondary Chemistry Program. The corrective actions taken as part of this program will help ensure that Grottp 5 components will remain capable of performing their intended functions under all CLB conditions. Discoverv: The occurrence of crevice corrosion, general corrosien, pitting, and erosion corrosion is expected to be limited and is unlikely to affect the intended function of the governor valves, turbines, and turbine throttle /stop valves due to the control of secondary chemistry. To ensure that these components are not experiencing signincant degradation, and to ensure that corrective actions are taken if they are, periodic visual mspections will be conducted. The turbine will be inspected as part of the periodic overhaul that is performed in accordance with the CCNPP Preventive Maintenance Program. The Application for License Renewal 5.1-26 Calvert Cliffs Nuclear Power Plant
e ATTACIIMENT m APPENDIX A. TECIINICAL INFORMATION I 5.1 - AUXILIARY FEEDWATER SYSTEM governor valve and turbine throttle /stop valves will be included in a new ARDI Prograt The corrective actions taken as part of these programs will ensure that Group 5 components will remain capable of performing their intended functions under all CLB conditions. [ Reference 2, Attachment 8] CCNPP Preventive Maintenance Procram ne CCNPP Preventive Maintenance Program has been established to maintain plant equipment. structures, systems, and components in a reliable condition for normal operation and emergency use, minimize equipment failure, and extend equipment and plant life. The program covers all preventive maintenance activities for nuclear power plant structures and equipment within the plant, including the AFW System components within the scope oflicense renewal. It is based on the INPO documents listed as References 24 through 26. [ Reference 17] The existing CCNPP Preventive Maintenance Program includes tasks that require a periodic overhaul of the AFW pump turbines, in accordance with CCNPP Technical Procedure TURB-01, " Auxiliary Feedwater Pump Turbine Overhaul," the turbine is disassembled and then inspected for damage. Measurements are taken to assure critical tolerances are within acceptance criteria. Specific subcomponents are inspected for wear, erosion, pitting, and/or surface cracking. Unsatisfactory laspection results are recorded and evaluat;d, Corrective actic,ns are initiated in accoriance with the CCNPP Corrective Actions Program, if necessary. [ References 28 and 29] Past inspections of AFW pump turbines during overhauls have revealed no defects such as cracks or corrosion The AFW pump turbines are in good condition. The Preventive Maintenance Progam has been evaluated by the NRC as part of their routine licensee assessment activities, The plant Maintenance Program also has had numerous levels of BGE management review, WI the way down to the specific implementation procedures, For example, there are specific responsibilities assigned to BGE personnel for evaluating and upgrading the Preventive Maintenance Program, Man + 27] These assessments and controls provide reasonable assurance that the Preventive Mainuuno Prqam will continue to be ac. effective method of monitoring the effects of corrosion and fatigt.e, thns ensuring that the AFW pump turbine will remain capable of performing its pressure boundary function under all CLB loading conditions. CCNPP ARQLfff3 tam Corrosion will be readily detectable for the Group 5 components through visual inspections, ne governor valves and turbine thnttle/stop valves will be included in a new ARDI Program as defined in the CCNPP IPA Methodology , resented in Section 2.0. The ARDI Program will discover and manage crevice corrosion, general corrosion, pitting, and erosion corrosion that may be occurring on these components. Corrective actions will be taken in accordance with the CCNPP Corrective Action Program and will ensure that the components will remain capable of performing the system pressure boundary integrity function under all CLB conditions. Refer to the Group 1 discussion on aging mansgement programs for a detailed discussion of the ARDI Program. [ Reference 2, Attachment 8] Application for License Renewal 5.1-27 Calvert Cliffs Nuclear Power Plant
ATTACHMENT G) APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SWrEM Group 5 (laternal surface corrosion in a steam environment)- Aging Management Demonstration: Based on the information presented above, the following conclusions can be reached with respect to corrosion of AFW System Group 5 components: e ne AFW System governor valves, turbines, and control valves (i.e., turbine throttle /stop valves) contribute to the system pressure boundary function and their integrity must be maintained under all CLB conditions. Crevice corrosion, general corrosion, pitting, and ercsion corrosion are plausible ARDMs for the Group 5 components and could result in material loss which, ifleft unmanaged, can lead to loss of pressure-retaining capability under CLB design loading conditions. The CCNPP Secondary Chemistry Specifications and Surveillance Program controls the Main Steam System fluid chemistry to minimize the corrosiveness of the environment for the AFW System components. The occurrence of these ARDMs is expected to be limited and not likely to affect the intended function of the Group 5 components due to the control of fluid chemistry and the limited operation. There is an existing turbine overhau! that is perio& ally performed, which includes inspections for corrosion and other degradation. If the inspections reveal damage, corrective actions are initiated in accordance with the CCNPP Corrective Actions Program, as necessary. To provide the additional assurance needed to conclude that the effects of corrosion are being effectively managed, the govemor valves and turbine throttle /stop valves will be included in the scope of an ARDI Program. Inspections will be performed and appropriate corrective action will , be taken if significant corrosion is discovered. Therefore, there is a reasonable assurance that the effects of corrosion will be adequately managed for the AFW System governor valves, turbines, and turbine throttle /stop valves such that they will be capable of performing their pressure boundary integrity function, consistent with the CLB, during the period of extended operation. Group 6 (external surface corrosion of the turbine-driven pump)- Materials and Er.vironment Group 6 consists of the turbine-driven pump external surfaces that are subject to crevice corrosion and pitting due to stuffing box leakoff. The affected subcomponents include the split gland and external screws / studs and nuts. All of these subcomponents are constructed of stainless steel. [ Reference 2, Attachments 4 and 6) The Group 6 turbine-driven pump subcomponents are exposed to a wet environment due to leakage of the stuffing box. Small volumes of water will collect in cracks and crevices and become stagnant, which is conducive to corrosion because harmful impurities can become concentrated. The source of the water is from the AFW System, which is supplied water from the CSTs. The water in the CSTs is monitored and controlled through the Secondary Chemistry Program. [ Reference 2, Attachment 6] Appibation for License Renewal 5.1-28 Calvert Cliffs Nuclear Pcwer Plant
ATTACHMrNT G) APPENDIX A- TECIINICAL INFOkMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Group 6 (external surface corrosion of the turbine-driven pump)- Aging Mechanism Effects: i 1 Crevice corrosion and pitting are plausible for Group 6 components because of the geometry of the subcomponents and the stagnant water conditions. Leakage from the stufling box can collect in cracks, i crevices, and between subcomponents that can cause harmful impurities in the water to concentrate, l thereby creating an environment conducive to these ARDMs. Industry experience has shown that these corrosion mechanisms are plaosible. For Group 6 subcomponents, long term exposure to the wet environment may result in small cracks and/or pits, if lefl unmanaged, the resulting material loss could eventually result in loss of the pressure-retaining capability under CLB design loading conditions. Refer to the discussion on aging mechanism effects in Group 2 for a detailed discussion of crevice corrosion and pitting. [ Reference 2, Attachment 6] Group 6 (external surface corrosion of the turbine-driven pump)- Methods to Manage Aging: Mitigation: The effects of crevice corrosion and pitting cannot be completely prevented, but they can be mitigated by minimizing the exposure of the turbine-driven pumps to an aggressive environment. Maintaining an intemal environment of purified water, with impurities maintained at low levels during normal plant operation, minimizes to some extent the buildup of harmful impurities in crevices, and thereby minimizes corrosion reactions when this water leaks onto external surfaces. The initial formation of a passive oxide layer (magnetitc) also protects the component surfaces by minimizing the exposure of bare metal to water. [ Reference 2, Attachment 6] l Discoverv: The occurrence of crevice corrosion and pitting is expected to be limited, and is unlikely to affect the intended function of the AFW System turbine-driven pump, due to the control of fiuid-chemistry, inspections of the pump subcomponents during periodic overhauls, and gland follower adjustment. However, to assure that these ARDMs are not causing significant degradation of the j external surfaces of the turbine-driven pump, they can be visually inspected on a periodic basis to detect crevice corrosion or pitting. Corrective actions can be initiated if there is any evidence of corrosion identified during these inspections. [ Reference 2, Attachment 8] Group 6 (extertal surface corrosion of the turbine-driven pump)- Aging Management Programs: Mitigation: CCNDP Secondary Chemistry Soecifications and Surveillance Program The CCNPP Secondary Chemistry Specifications and Surveillance Program has been established to: minimize impurity ingress to plant systems; reduce corrosion product generation, transport, and deposition; improve integrity and availability of plant systems; and extend component and plant life. Control of fluid chemistry minimizes the concentration of corrosive impurities (:hlorides, sulfates) for external surfaces of the turbine-driven pump due to leakage, and minimizes the rate and effects of corrosion. [ Reference 10, Section 6.1.A 3 R.-fer to the Group 2 discussion on aging management yograms for a detailed discussion of the Secondary Chemistry Program. The corrective actions taken as part of this program will help ensure that the turbine-driven pump will remain capable of performing its intended functions under all CLB conditions. Application for License Renewal 5.1 29 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (3) APPENDIX A - TECliNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Discoverv: Fot the external surfaces of the turbine-driven putnp, crevice corrosion and pitting can be readily detected through visual ir.:pections.11owever, due to the control of fluid chemistry, inspections of the pump subcomponents during overhauls, and gland follower adjustment, the occurrence of crevice corrosion and pitting is expected to be limited and not likely to affect the intended function of the turbine-driven pump. Ilowever, since the overhauls are not performed on a specific frequency, an additional inspection performed on a periodic basis can provide the additional assurance needed to conclude that the effects of these ARDMs are being efTectively managed for the period of extended operation. [ Reference 2, Attachment 8] CCNPP System Walkdown Program Guideline PEG-7 provides for discovery of corrosion and degraded paint by providing for periodic system walkdowns by visual inspection, reporting the walkdown results, and initiating corrective action. Under this program, inspection items typically related to aging management include identifying poor housekeeping conditions (such as degraded paint) and identifying system and equipment stress or abuse, such as thermal insulation damage, external leakage of fluhls, etc. 'Ihis program, along with the ' overhauls performed on the pump, will provide reasonable assurance that significant dqradation will be discovered and corrected. Refer to the discussion on aging management programt in Group 3 for further details on the System Walkdown Program. Conditions identified as adverse to quality are corrected in accordance with the CCNPP Corrective Actions Program. The corrective actions taken will ensure that the turbine-driven pump will remain capable of performing the system pressure boundary integrity function under all CLB conditions. [ Reference 23) Group 6 (external surface corrosion of the turbine-driven pump) - Aging Management Demonstration: Based on the information presented above, the following conclusions can be reached with respect to crevice corrosion and pitting of the external surfaces of the turbine-driven pump: The AFW System turbine-driven pump contributes to the system pressure boundary function and its integrity must be maintained under all CLB conditions. Crevice corrosion and pitting are plausible ARDMs for the external surfaces of this component and could result in material loss which, if left unmanaged, can lead to loss of pressure-retaining capability under CLB design loading conditions. The CCNPP Secondary Chemistry Specifications and Surveillance Program controls the Cf.t s' fluid chemistry, which minimize the corrosiveness of the water leaking onto the external surfaces of the turbine-driven pump. Tne occurrence of crevice corrosion and pitting is expected to be limited and not likely to affect the intended function of the turbine-driven pump Scause of the general resistance of stainless steels to corrosion. Guideline PEG-7 provides for discovery of corrosion and degraded paint by providing for visual inspection through periodic system walkdowns, reporting the walkdown results, and initiating correctise action in accordance with the CCNPP Corrective Actions Program. Application for License Renewal 5.1-30 Calvert Cliffs Nuclear Power Plant
i XITACHMENT m APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Therefore, there is reasonable assurance that the effects of crevice corrosion and pitting will be adequately managed for the external surfaces of the turbine-driven pump such that they will be capable of performing their pressure boundary integrity function, consistent with the CLB, during the period of extended operation. Group 7 - (wear and elastomer degradation of solenold-operated valves) - Materials and Environment: The subcomponent of the solenoid-operated valves that is subject to wear and elastomer degradation is the seat, which is constructed of ethylene propylene. He subcomponent of the solenoid-operated valves that is subject to wear only is the disk holder assembly, which is constructed of plastic. The internal surfaces of the solenoid-operated valves are exposed to compressed air, which is normally clean of debris, oil-free, and dry. [ Reference 2, Attachments 4,5, and 6) Group 7 - (wear and elastomer degradation of solenoid-operated valves) - Aging Mechanism Effects: Wear results from relative motion between two surfaces; from the influence of hard, abrasive particles or Duld stream; and from small vibratory or sliding motions under the influence of corrosive environment. The most common result of wear is damage to one or both surfaces involved in the contact. Wear rates increase as worn surfaces experience higher contact stresses than the ;urfaces of the original geometry. [ Reference 2, Attachment 7] Wear is a plausible ARDM for solenoid-operated valves because of the relative motion between their parts and the cyclic nature of operation. Wear can result in material loss and subsequent leakage of SR compressed air. The parts of concern are related to the seating of the valve, i.e., the ethylene propylene sent and the plastic disk holder assembly. The soft seat could wear to the point where leakage could prematurely deplete the two-hour supply of compressed air in the accumulators that is needed if the air compressors lose power. [ Reference 2, Attachment 6) If unmanaged, wear could eventually result in the loss of pressure-retaining capability of the Compressed Air System under CLB design loading conditions. An elastomer is a material that can be stretched to sigr.ificantly greater than original length and, upon immediate release of the stress, will return with force to approximately its original length. When an elastomer ages, there are three mechanisms primarily involved:
- 1. Scission - the process of breaking molecular bonds, typically due to ozone attack, UV light, or radiatian; ;
- 2. Crosslinking - the process of creating molecular bonds between adjacent long-chain molecules, l typically due to oxygen attack, heat or curing; and
- 3. Compound ingredient evaporation, leaching, mutation, etc.
Natural aging tests indicate that where there is a significant property change in a elastomer, it appears that it occurs within the first five to ten years after initial formulation / curing. [ Reference 2, Attachment 7] l Application for License Renewal 5.1 31 Calvert Cliffs Nuclear Power Plant
A'ITACHMENT (3) APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM For valve seating applications, elastomers generally harden as they age maamg sealing more difficult. Elastomer degradation of solenoid operated valves is plausible because the elastomer seat is exposed to moderate heat, oxygen, ozone, and oyrating stresses. [ Reference 2, Attachments 6 and 7} if unmanaged, elastomer degradation could eventually result in the loss of pressure-retaining capability of the Compressed Air System under CLB design loading conditions. Group 7 - (wear and elastomer degradation of solenoid-operated valves) - Methods to Manage Aging: Mitigatiom Since elastomer degradation is caused by exposure of susceptible subcomponents to environmental conditions that are not feasible to control (e.g., heat, oxygen, ozone), there are no reasonable methods to mitigate its effects. Since wear is caused by relative motion between susceptible subcomponents of these components, and it is not feasible to limit valve operation, there are no reasonable methods to mitigate its effects. The discovery method discussed below is deemed adequate to manage these ARDMs. [ Reference 2, Attachment 8] Discoverv: A visual inspection of the intemals of valves can be performed to detect degradation of the seating surface of the valves. 'the results of the inspections can be evaluated to determine if component or subcomponent replacement is warranted, and if so, to determine an appropriate replacement schedule. Corrective actions can be initiated accordingly. [ Reference 2, Attachment 8] Group 7 - (wear and elastomer degradation of solenoid-operated valves) - Aging Management Programs: Mitigation: There are no mitigation programs credited for wear or elastomer degradation of the solenoid-operated valves. Discoverv: The solenoid-operated valves will be included in a new ARDI Program as defined in the CCNPP IPA Methodology presented in Section 2.0. The ARDI Pro l tram will discover and manage the wear and elastomer degradation that may be occurring on these components. Corrective actions will be taken in accordance with the CCNPP Corrective Action Program and will ensure that the components will remain capable of performing the system pressure bourdary integrity function under all CLB conditions. Refer to the Group 1 discussion on aging management programs for a detailed discussion of the ARDI Program. [ Reference 2, Attachment 8] Group 7 -(wear and elastomer degradation of solenoid-operated valves)- Demonstration of Aging Management: Based on the information presented above, the following conclusions can be reached with respect to wear and elastomer degradation of the Group 7 solenoid-operated valves of the AFW System:
. The solenoid-operated valves sentribute to the pressure boundary function and their integrity must be maintained under all CLB conditions, e Wear is a plausible ARDM beuse of the relative motion between subcomponent parts and the soft seat and hard plastic materials that are in contact. Elastomer degradation is a plausible ARDM because subcomponents of this group are exposed to modarate heat, oxygen, ozone, and Application for License Renewal 5.1-32 Calvert Cliffs Nuclear Power Plani
l ATTACHMENT G) APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM operating stresses, which over a long period of time will cause their degradation. If left unmanaged, wear and elastomer degradation could eventually reselt in the loss of pressure-retaining capability of Group 7 components under CLB design loading conditions. The solenoid operated pilot valves will be included in the scope of an ARDI Program. Inspections will be performed and appropriate corrective action will be taken if significant wear i or elastomer degradation is discovered. Therefore, there is reasonable assurance that the effects of wear and elastomer degradation will be adequately managed for the seating surfaces of the solenoid-operated valves such that they will be capt.ble of performing their pressure boundary integrity function, consistent with the CLB, during the period of extended operation. Group 8 (general corrosion of control valve operators)- Materials and Environment Group 8 consists of control valve operators that are exposed to L compressed air environment and whose internal surfaces are subject to general corrosion. The subcomponents in these valve operators that provide the pressure boundary function and are exposed to compressed air are constructed of carbon steel (some are zinc plated), cast iron, brass, and bronze, [ Reference 2, Attachments 4 and 6] t The internal environment for the control valve operators is normally compressed air supplied by the instrument air compressors. The i strument air is very dry, filtered, and oil free air. Particle size, dew point and oil hydrocarbons are controlled for the instrument air supply in accordance with Instrument Society of America (ISA) standard ISA-S-7.3, " Quality Standard for Instrument Air." The dew point, which is a measurement of air moisture content, is normally maintained at -40'F at 100 psig. This dew point is well below the air quality standard of at least 18'F below the minimum local recorded ambient temperature at the plant site. [ References 1,30, and 31] Because the plant air or saltwater air compressors can be used as a backup to the instrument air
- compressors if they become unavailable, occasionally air from either the plant air or saltwater air compressors may enter the system. Additionally, the saltwater air compressors are run for a brief period of time each month for testing. The PA Subsystem air compressors use a moisture separator, which removes moisture to the air. The saltwater air compressors have an aftercooler, which cools the compressed air and condenses moisture that passes to the receiver where it is drained by an automatic valve. Based on the design and limited operation of these backup systems, perturbations in air quality outside of accepted industry air quality standards (dry, filtered, and oil-free) will be limited.
[ References 32 through 36] Group 8 (general corrosion of control valve operators)- Aging Mechanism Effects: General corrosion is plausible for Group 8 control valve operators because some of the materials used in their construction are susceptible to these corrosion mechanisms when exposed to a moist environment. The aggressiveness of these corrosion mechanisms is particularly dependent on the overall corrosiveness of the environment and on the materials of construction. General corrosion is plausible for the pressure-retaining subcomponents constructed of carbon steel or cast iron. It is not plausible for those pressure-retaining subcomponents constructed of brass or bronze because the materials are resistant to general Application for License Renewal 5.1-33 Calvert Cliffs Nuclear Power Plant
ATTACHMFNT (3) APPENDIX A- TECIINICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM corrosion. Refer to the discussion in Group 2 above for a detailed description of general corrosion. [ Reference 2, Attachment 6] Group 8 (general corrosion of control valve operators) . Methods to Manage Aging: Mitigation: The efTects of general corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of metal surfaces to a moist environment. Keeping t'ie rir quality, i.e., dewpoint, within accepted industry standards can help mitigate general corrosion by minimizing the possibility of moisture in the control valve operators. (Reference 2, Attachment 8] The AFW System control valves are supplied with compressed air from the Instrument Air Subsystem. The air quality of the Instrument Air Subsystem is normally maintained in accordance with industry standards for moisture (dewpoint) and particulate concentrations. Continued maintenance ofInstrument Air Subsystem air quality to industry standards will ensure minimal component degradation resulting from moisture or from rust particles. The use of air dryers and filters maintains the air quality within acceptable limits. In order to assure that the compressed air quality remains whhin acceptable limits, the air quality should be periodically checked and compared against the industry standards. [ Reference 2, Attachment 8] If testing shows a reduction in air quality, corrective actions can be initiated to return the air quality to normal.
- The possibility of occasional exposure to slight moisture exists from operation of the saltwater air compressors because there is no dryer for this supply. The exposure to moisture is minimal and short term, and is not expected to result in significant levels of degradation of the carbon steel components.
An inspection performed on the piping immediately downstream of the saltwater air compressors, where the worst case of general corrosion is expected, revealed only very light surface rust on the inside of each piece. After more than 20 years in operation, approximately 60% of the pipe interior contained no rust and appeared similar to the inside of new pipe. Thickness measurements showed that the wall thickness averaged only 0.001 inch less than the nominal thickness of 0.179 inch. [ Reference 2, Attachment 8] Since air in the Instrument Air and Saltwater Air Subsystems is normally very dry and there is so little corrosion evident after more than 20 years of operation, continued maintenance of the air quality is deemed an adequate aging management technique for general corrosion control in components supplied with compressed air from the Instrument Air Subsystem. Discoverv: The occurrence of general corrosion is expected to be limited and is unlikely to affect the intended function of the AFW System Group 8 components due to the control of compressed air dryness. The mitigation technique described above is deemed adequate for managing the effects of general corrosion of AFW System control valve operators. [ Reference 2, Attachment 8] Group 8 (general corrosion of control valve operators) . Aging Management Programs: Mitic_ation: CCNPP Preventive Maintenance Procram The ;NPP Preventive Maintenance Program has been established to maintain plant equipment, struc.ures, systems, and components in a reliable condition for normal operation and emergency use, minimize equipment failure, and extend equipment and plant life. The program covers all preventive Application for License Renewal 5.1-34 Calvert Cliffs Nuclear Power Plant l l
1 ATTACHMENT m APPENDIX A- TECliNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM l 1 maintenance activities for nuclear power plant structures and equipment within the plant, including the control of air dryness in the Compressed Air System. [ Reference 27] Refer to the Group 5 discussion on aging management programs for a detailed discussion of the Preventive Maintenance Program. Calvert Cliffs initiated a Preventive Maintenance Task following a review of recommendations in Significant Operatir.g Event Report SOER 88-01. This task checks the Instrument Air Subsystem air quality at three locations in the system; at the air dryer outlet, at the furthest point from the dryer, and at the approximate midpoint between these locations. Measurements of dew point and particulate count are taken periodically at these locations. This Preventive Maintenance Task is automatically scheduled and implemented in accordance with SR Preventive Maintenance Program procedures. [ References 27 and 37] According to procedure, dew point data and particulate sample results are reviewed and evaluated in accordance with SOER 88-01. SOER 88-01 recommends maintaining the air quality within the requirements of standard ISA-S-7.3. Standard ISA-S7.3 recommends limits for maximum particle size, dew point temperature, and oil content. If the air quality is determined to be abnormal, corrective actions are initiated to return the air quality to normal, and the condition of the dependent loads' internals are evaluated, as appropriate. [ References 37 and 38] Discoverv: Since the mitigation techniques are deemed adequate for managing general corrosion, no discovery techniques are credited. Group 8 (general corrosion of control valve operators)- Aging Management Demonstration: Based on the information presented above, the following conclusions can be reached with respect to general corrosion of AFW System Group 8 components:
. The AFW System Group 8 control valve operators contribute to the system pressure boundary function and their integrity must be maintained under all CLB conditions, e General corrosion is a plausible ARDM for this group of components and could result in material loss v>hich, if left unmanaged, can lead to loss of pressure-retaining capability under CLB design loading conditions, e The compressed air supplied to these components is normally very dry air, inspections of the Compressed Air System piping showed there is negligible corrosion in that picing after over 20 years of operation.
. The air quality, including air dryness, continues to be monitored and evaluated against the air quality requirements of standard ISA-S-7.3 through the Preventative Maintenance Program. If the air quality is abnormal, corrective actions are initiated to retum the air quality to normal and the condition of the dependent loads' intemals is evaluated, as appropriate.
- Based on the ongoing air quality controls and the past operating history, the occurrence of general corrosion is expected to be limited and is unlikely to affect the intended function of the Group 8 control valve operators.
Application for License Renewal 5.1-35 Calvert Cliffs Nuclear Power Plant
A'ITACHMENT 0) APPENDIX A- TECIINICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM Therefore, there is reasonable assurance that the effects of general corrosion will be adequately managed for the AFW System Group 8 control valve operators such that they will be capable of performing their pressure boundary integrity function, consistent with the CLB, during the period of extended operation. Group 9 -(elastomer degradation of No.12 CST perimeter seal)- Materials and Environment: The No.12 CST perimeter seal is a caulking material consisting of an elastomer. The caulking is exposed to atmospheric conditions, but is protected from the direct effects of the weather by the stainless steel tank's protective enclosure. [ Reference 2, Attachments 4 and 6] Group 9 (elastomer degradation of No.12 CST perimeter seal)- Aging Mechanism Effects: elastomers generally harden as they age, making sealing more dif0 cult. Elastomer degradation of the No.12 CST perimeter seal is plausible because the elastomer caulking is exposed to moderate heat, oxygen, and ozone. Over time, the caulking will become embrittled and lose its capability to prevent inoisture from entering at the ring foundation interface with the stainless steel tank. Refer to the discussion on aging mechanism effects for Group 7 for a detailed description of elastomer degradation. [ Reference 2, Attachments 6 and 7] Group 9 -(elastomer degradation of No.12 CST perimeter seal)- Methods to Manage Aging: Mitigation: Since elastomer degradation is caused by exposure of susceptible subcomponents to environmental conditions, which are not feasible to control (e.g., heat, oxygen, ozone), there are no reasonable methods to mitigate its effects. The di ivery method discussed below is deemed adequate to manage this ARDM. [ Reference 2, Attachment 8] Discoverv: Caulking and sealant does not contribute to the intended function of the No.12 CST. Ilowever, it plays a role in mitigating corrosion of the tank bottom by providing a moisture barrier. Periodic visual inspections can be made of the No.12 CST perimeter seal to detect degradation of the caulking. Based on the results of the inspections, the caulking can be repaired or replaced in order to maintain the sealing capabilities. [ Reference 2, Attachment 8] Group 9 -(elastomer degradation of No.12 CST perimeter seal)- Aging Management Programs: Mitigation: There are no mitigation programs credited for elastomer degradation of the CST perimeter seal. However, maintenance of the perimeter seal, as discussed below, is credited for mitigating external corrosion of the bottom of the No.12 CST. Discoverv: Aging management of the No.12 CST perimeter seal will be conducted consistent with the management of caulk and sealants identified in the aging management of structures in Section 33 of the BGE LRA. A new CCNPP Caulking and Sealant inspection Program will provide requirements and
. guidance for the identincation, inspection frequencies, and acceptance criteria of caulking and sealant used throughout the plant to ensure that their condition is maintained at a level that allows them to perform their intended function. [ Reference 2, Attachment 8]
Application for License Renewal 5.1-36 Calvert Cliffs Nuclear Power Plant
o ATTACHMENT m APPENDIX A- TECIINICAL INFORMATION
- 5.1 - AUXILIARY FEEDWATER SYSTEM The caulking, scalants, and expansion joints throughout the plant that are not fire barriers are typically replaced upon identification of their degraded condition. A new CCNPP Caulking and Sealant inspection Program will include the No.12 CST perimeter seal to ensure that its condition is maintained at a level that ensures it continues to provide an adequate moisture barrier through the renewal period.
The new program will establish acceptance criteria for the seal and will require a baseline inspection to determine the material condition. If unacceptable degradation exists, corrective actions will be taken. A technical basis will be developed for determining the periodicity of future inspections. Group 9 - (elastomer degradation of No.12 CST perimeter scal) - Demonstration of Aging Management: Based on the information presented above, the following conclusions can be reache6 with respect to elastomer degradation of the No.12 CST perimeter seal of the AFW System: Caulking and sealant do not contribute to the intended function of the No.12 CST However, it plays a role in mitigating corrosion of the tank bottom by providing a moisture barrier, thereby helping to maintain the pressure boundary function of the No.12 CST. The moisture barrier integrity of this perimeter seal must be maintained during the period of extended operation. elastomer degradation is a plausible ARDM because the No.12 CST perimeter seal caulking is exposed to moderate heat, oxygen, and ozone, which can cause the caulking to embrittle and crack. Ifleft unmanaged, elastomer degradation could eventually result in the loss of moisture retaining capability of the No.12 CST perimeter seal. A new CCNPP Caulking and Sealant Inspection Program will provide requirements and guidance for the identification, inspection, and maintenance of caulking and sealant used throughout the plant, including the No.12 CST perimeter seal, to ensure that their condition is maintained at a level that allows them to perform their intended function. Therefore, there is reasonable assurance that the effects of elastomer degradation on the No.12 CST perimeter seal will be managed in such a way as to maintain she components' moisture barrier integrity, consistent with the CLB, during the period of extended operation. Application for License Renewal 5.1-37 Calvert Cliffs Nuclear Power Plant
ATTACIIMENT G) APPENDIX A- TECIINICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM 5.1.3 Conclusion The aging rnanagement programs discussed for the AFW System are listed in the following table. These programs are administratively controlled by a formal review and approval process. As demonstrated above, these programs will manage the aging mechanisms and their effects in such a way that the intended functions of the components of the AFW System will be maintained during the period of extended operation, consistent with the CLB, under all design loading conditions. The analysis / assessment, corrective action, and confirmation / documentation proce , for license renewal is in accordance with QL-2, " Corrective Actions Program." QL-2 is pursuant to 10 CFR Part 50, Appendix B, and covers all structures and components subject to AMR. Application for License Renewal 5.1-38 Calvert Cliffs Nuclear Power Plant
ATTACHMENT G) APPENDIX A- TECIINICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM TABLE 5,1-3 LIST OF AGING MANAGEMENT PROGRAMS FOR THE AUXIIIARY FEEDWATER SYSTEM Program Credited As Existing CCNPP Demineralized Water Chemistry
- Mitigating the effects of crevice Specifications and Surveillance Program corrosion, general corrosion, and pitting Procedure CP-202, " Specifications and f the internal surfaces of AFW System Surveillance- Demineralized Water, Safety check valves located at the interface with Related Battery Water, Well Water the Chemical Addition System. (Group 2)
Systems, and Acceptance Criteria for On-line Monitors" Existing CCNPP Secondary Chemistry
- Mitigating the effects of crevice Specifications and Surveillance Program corrosion, general corrosion, and pitting Procedure CP-217, " Specifications and by; controlling CST water chemistry to Surveillance: SecondaryChemistry" nuninme the cormsiveness of the environment for the mternal surfaces of AFW System components. (Group 2)
Mitigating the effects of corrosion for the internal surfaces of governor valves, turbines, and control valves with steam as the internal environment. (Group 5)
- Mitigating the effects of crevice corrosion and pitting for the external surfaces of the turbine-driven pump due to stuffing box leakoff. (Group 6)
Existing CCNPP System Walkdown Program
- Discovery and management of the effects Plant Engineering Guideline, PEG-7, f crevice corrosion, general corrosion,
" System Walkdowns" and pitting for the external surfaces of uninsulated and readily accessible AFW components located in the No.12 CST enclosure. (Group 3)
Discovery and management of the effects of crevice corrosion and pitting for the external surfaces of the turbine-driven pump due to stuffing box leakoff. (Group 6) Existing CCNPP Preventive Maintenance Program
- Mitigation and management of the effects Repetitive Tasks 10191024 and 20191022, f general c rr sion of the internal
" Check Instrument Air Quality at System sudaces of control valve opecators Low Points" exposed to compressed air. (Group 8)
Application for License Renewal 5.1-39 Calvert Cliffs Nuclear Power Plant
ATTACHMENT m 1 i APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM TABLE 5.1-3 (continued) LIST OF AGING MANAGEMENT PROGRAMS FOR THE AUXII.I ARY FEEDWATER SYSTEM Program Credited As - Existing CCNPP Preventive Maintenance Program Discovery and management of the effects of Repetitive Tasks 10362000, 10362001, e rr si n f the internal surfaces of the AFW 20362018, 20362019 utilizing procedure Pump turbmes. (Group 5) TURB-01, " Auxiliary Feedwater Pump Turbine Overhaul" New ARDI Program . Discovery and management of the effects of cavitation erosion of the internal surfaces of AFW piping, down stream of flow orinces 1/2 FO 4506, 4507, and 4540. (Group 1)
. Discovery and management of the effects of crevice corrnsion, general corrosion, and pitting for the internal surfaces of AFW System components exposed to the AFW fluid. (Group 2)
. Discovery and management of the effects of crevice corrosion, general corrosion, and pitting for the external surfaces of AFW components that are not readily accessible and are located in the No.12 CST enclosure or valve pit.
(Group 3)
. Discovery and management of the effects of corrosion for the internals of the governor valves and control (i.e., turbine throttle /stop) valves. (Group 5)
. Discovery and management of the effects of elastomer degradation and wear seating surfaces on solenoid-operated valves. (Group 7)
New AFW Buried Pipe inspection Program Discovery and management of the effects of crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting for the external surfaces of buried pipe. (Group 4) New Caulking and Sealant Inspection Program Discovery and management of the effects of elastomer degradation of the perimeter seal of the No.12 CST. (Group 9) Application for License Renewal 5.1-40 Calvert Cliffs Nuclear Power Plant
e i ATTACIIMENT (3) APPENDIX A- TECHNICAL INFORMATION 5.1 - AUXILIARY FEEDWATER SYSTEM References l
- 1. "CCNPP Updated Final Safety Analysis Report," Revision 20 l
- 2. "CCNPP Aging Manegement Review Report Auxiliary Feedwater System," Revision 1
- 3. CCNPP Drawing No. 60583, " Auxiliary Feedwater System," Revision 46, December 10,1996
- 4. CCNPP Drawing No. 62533, " Auxiliary Feedwater System," Revision 45, April 20,1995
- 5. Letter from Mr. J. C. Linville (NRC) to Mr. G. C. Creel (BGE), dated April 19,1991, "NRC Region 1 Combined Inspection Report Nos. 50-317/91 06 and 50-318/91-06," (February 17,1991
- March 30,1991) l 6.
"CCNPP Component Level Scopmg Results Report for the Auxiliary Feedwater System,"
Revision 2
- 7. "CCNPP Pre-Evaluation Results for the Auxiliary Feedwater System," Revision 1, April 3,1996
- 8. "CCNPP Fire Protection Aging Management Review Report," Revision 1, January 29,1997 l 9. CCNPP Technical Procedure CP-0217, " Specifications and Surveillance: Secondary J Chemistry," Revision 5, December 18,1995
- 10. CCNPP Administrative Procedure CH 1, " Chemistry Program," Revision 1, December 13,1995 i
11, f ANSI N45.2.1," Cleaning of Fluid Systems and Associated Components During Construction Phase of Nuclear Power Plants," February 26,1973
- 12. Regulatory Guide 1.37, " Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants," March 16,1973 13, iNPO 88-021, " Guidelines for Chemistry at Nuclear Power Stations," Revision 1, September 1991
- 14. INPO 85-021, " Control of Chemicals in Nuclear Power Plants," June 1985
- 15. EPRI NP-6239, 5405 2, "PWR Secondary Water Chemistry Guidelines," Final Report, Revision 2, December 1988
- 16. EPRI TR-102134, Projects 2493,5401, "PWR Secondary Water Chemistry Guidelines," Final Report, Revision 3, May 1993
- 17. CCNPP Procedure CP-410, "Make-Up Demineralized Water System" 18.
EPRI NP-6377-SL, Volume 2, " Guidelines for the Design and Operation of Make-up Water Treatment Systems, Final Report," June 1989
- 19. EPRI NP-7077-SR, " Primary Water Chemistry Guidelines," Ret ision 2, November 1990
- 20. "NSSS Combustion Engineering Chemistry Manual CENPD-28," Revision 3, September 1982
- 21. State Water Appropriation Permit #CA69G010
- 22. CCNPP Technical Procedure CP-202, " Specification and Surveillance - Dcmineralized Water, Safety-Related Battery Water, Well Water Systems, and Acceptance Criteria for On-Line Monitors," Revision 5, June 19,1997 Application for License Renewal 5.1-41 Calvert Cli fs Nuclear Power Plant
0 ATI'ACHMENT (3) APPENDIX A- TECIINICAL INFORMATION 5.1 - AUX!LIARY FEEDWATER SYSTEM
- 23. CCNPP Plant Evaluation Guideline PEG-7, " Plant Engineering Section, System Walkdowns,"
Revision 4, November 30,1995
- 24. INPO 85-032," Preventive Maintenance," December 1988
- 25. INPO 85-037," Reliable Power Station Operation," October 1985
- 26. INPO Good Practice MA-319, " Preventive Maintenance Program Enhancement,"
December 1992
- 27. CCNPP Administrative Procedure MN 1-102," Preventive Maintenance Program," Revision 5, September 27,1996
- 28. CCNPP Repetitive Tasks 10362000,10362001,20362018, And 20362019, " Overhaul AFW Pump Turbine and Governor Valves"
- 29. CCNPP Technical Procedure TURB-01, " Auxiliary Feedwater Pump Turbine Overhaul,"
Revision 2,10 March,1997" i
- 30. Letter from Mr. G. C. Creel (BGE) to NRC Document Control Desk, dated March 10,1989,
" Response to Generic Letter 88-14, instrument Air Supply Problems Affecting Safety-Related
. Equipment"
- 31. International Society for Measurement and Control Standard ISA S7.31975 (R 1981),
" Quality Standard for Instrument Air," November 16,1981
- 32. CCNPP Operations Performance Evaluation Requirement Nos.1-12-3-0-M and 2-12-3-0-M, "Run Saltwater Air Compressors," Revision 2, February 4,1997
- 33. CCNPP Drawing No. 60712SH0001," Compressed Air System, Instrument Air and Plant Air,"
Revision 46, December 5,1996
- 34. CCNPP Drawing No. 60712SH0003," Compressed Air System, instrument Air and Plant Air,"
Revision 75, August 2,1996
- 35. CCNPP Drawing No. 62712SH0001,"Comprested Air System, Instrument Air and Plant Air,"
Revision 37, July 24,1996
- 36. CCNPP Drawing No. 62712SH')003," Compressed Air System, Instrument Air and Plant Air,"
Revision 80, February 19,1997
- 37. Repetitive Tasks 10191024 and 20191022, " Check Instrument Air Quality at System Low Points," Preventative Maintenance Program
- 38. INPO SOER 88-01," Instrument Air System Failures," May 18,1988 Application for License Renewal 5.1-42 Calvert Cliffs Nuclear Power Plant
, 4 ATTACHMENT (4)
APPENDIX A - TECHNICAL INFORMATION 5.12 -MAIN STEAM, STEAM GENERCOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS 4 i Baltimore Gas and Electric Company , Calvert Cliffs Nuclear Power Plant October 22,1997
m _ _ _ _ . __ ATTACHMENT (4) l APPENDIX A - TECHNICAL INFORMATION l 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, ! AND NITROGEN AND HYDROGEN SYSTEMS ! l 5.12 Main Steam System This is a section of the Baltimore Gas and Electric Company (DGE) License Renewal Application (LRA) addressing the Main Steam, Extraction Steam, and Nitrogen and Hydrogen Systems. The Main Steam, Extraction Steam, and Nitrogen and Hydrogen Systems have been evaluated in accordance with Cahert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. These sections are prepared independently and will, collectively, comprise the entire BGE LRA. I l 5.12.1 Scoping i System level scoping describes conceptual boundaries for plant systems and structures, develops screening tools which capture the 10 CFR 54.4(a) scoping criteria, and then applies the tools to identify systems and structures within the scope of license renewal. Component level scoping describes the components within the boundaries of those systems and structurcs that contribute to the intended functions. Scoping to determine components subject to aging management review (AMR) begins with a listing of passive intended functions, and then dispositions the device types ss either only associated with active functions, subject to replacemem, or subject to AMR either in this report or another report. OptratiDg Enerienst Representative historical operating experience pertinent to aging is included in appropriate areas to provide insight supporting the aging management demonstrations. This operating experience was obtained through key. word searches of BGE's electronic database ofinformation on the CCNPP dockets and through documented discussions with currently assigned cognizant CCNPP personnel. The Main Steam System operating experience relative to the scope of this section of the BGE LRA has resulted in several changes to improve its reliability and functionality. Several system valves have been replaced. The main steam isolation valves (MSIVs) have been replaced due to reliability concerns and to ensure their ability to consistently close within the required time limits. They were initially hydraulically actuated valves. They are now nitrogen closed, pilot actuated valves that still utilize hydraulics, but do so much more reliably. To assure their reliability, they are scheduled to be examined every four years under the Preventive Maintenance (PM) Program, at which time their actuators are sent back to the vendor for inspection / refurbishment. The check valves in the steam supply lines to the auxiliary feedwater (AFW) pumps have also been replaced due to operating problems in the past. The nature of the periodic operation (testing) of the AFW pump also resulted in problems with the pump turbine governor (not within the scope of this report) during startup. System condensation that occurrcd while the system was idle resulted in water impingement of the governor during the required periodic system automatic start testing mandated by NUREG 0737, " Clarification of TMI [Three Mile IslandJ Action Plan Requirements." To remedy this, the drains from the system have been enhanced with the installation of tanks to direct and collect the amount of condensation that accumulates during idle periods and automatic starts. This modification has eliminated the problem. The failure of some extraction steam piping, not within the scope oflicense renewal, several years in the past resuhed in the creation of the plant's Erosion Corrosion Program. This program is credited for the mitigation of several components that are within the scope oflicense renewal and included in this section Application for License Renewal 5.12-1 Calvert Cliffs Nuclear Power Plant
NITACIIMENT (4) APPENL)IX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS of the BGE LRA. He portion of the Extraction Steam System that is within the scope oflicense renewal is no longer used. It was piping used for reactor vessel head washdown. It, therefore, no longer sees an extraction steam environment. It is included in this section of the BGE LRA due to its containment penetration. There have been problems with system drains associated with portions of the system not within the scope oflicense renewal. Excessive cycling of non-scope drain motor operated valves (MOVs) has resulted in burnt out fuses and failed wiring, as well as problems with the valve bodies, couplings, and valve body connections. Due to these problems, the frequency of inspection of all system drains, including those within the scope of license renewal, has been increased, and many portions of the main steam drain piping inside and outside the scope of license renewal have been included in the plant's Erosien Corrosion Program. Drain system piping, where leaks or thinning have been discovered, is being replaced with piping that is more resistant to erosion corrosion. The portions of the Steam Generator (SG) Blowdown System that are inside containment are included in the scope of this section of the BGE LRA. This piping has been replaced with all new carbon steel piping and with bent carbon steel piping sections instead of elbow fittings. This was done to reduce the erosion corrosion of fittings. The only exception to this is the connection of the blowdown piping to the SGs themselves. The elbows at this connection were replaced with chrome-moly socket-welded elbows. , l All SG blowdown piping is covered by the Erosion Corrosion Program. Many portions of the blowdown l piping outside of containment, and not within 'he scope of license renewal, have ciready been replaced with chrome-moly piping. As piping im. a of containment is found to meet the requirements for i replacement, as defined by the Erosion Conmion Program, ii 6 planned to replace it with piping, that is more sesistant to erosion corrosion. Section 5.12.1.1 presents the resulf, of the system leve! scoping,5.12.1.2 the results of the component level scoping, and 5.12.1.3 the results of scoping to determine components subject to an A.MR. 5.12.1.1 System Level Scoping The Main Steam System AMR Report [ Reference 1] includes the Extraction Steam and Nitrogen and Hydrogen Systems in its scope. This section begins with descript! ns of these systems, which includes the boundvies of the systems as they were scoped. He intended fe..ctions of the systems are listed and { are used to define what portions of the systems are within the scope oflicense renewal. l I System Descrintion/Concentual Boundaries l The Main Steam System has the following functional requirements: [ Reference 1, Section 1.1.1] To pr. vide the flow path for SG output steam that flows to the meia high pressure turbines, the moisture separator reheaters, main feedwater pump turbines, the AFW pump turbines, and the steam seal regulator; To provide overpressure protection for the SGs; To provide for automatic removal of Nuclear Steam Supply System stored energy and sensible heat following a turbine and reactor trip;
~
Application for License Renewal 5.12-2 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS To provide for operator control of SG pressure and Reactor Coolant System temperature during plant cooldown and heatup; To provide a means of heat removal during hot standby and plant cooldown; and To remove excessive moisture from the high pressure turbine exhaust (dry the steam by heating it further) prior to entering the low pressure turbines via the reheat steam subsystem. During normal plant operations, steam is generated in the SGs. This steam Dows through a main steam header from each SG (two per unit) to the main turbine high pressure stop valves. Located in each main steam header, at the exit of each SG inside containment, is a Cow restrictor. The MSIV in each header, outside containment, represents the downstream terminus of the safety-related main steam piping (and the portion of the system within scope of license renewal). The two main steam headers are cross-connected downstream of the MSIVs. Main steam also Hows from each of the main steam headers, downstream of the containment penetration, and upstream of the MSIVs, through air-operated valves, to the AFW pump turbines when the AFW System is operated. Downstream of the MSIVs, a branch header provides a steam now path from each main steam header to the moisture separator reheaters and to the steam seal regulator (from Nos.11/21 Headers only). Another branch header connects to the SG feedwater pump turbines. One atmospheric steam dump valve and eight safety valves are connected to each main steam header between the containment penetration and the MSIV. These valves are normally shut and, when opened, exhaust main steam to the atmosphere. Four turbine bypass valves are connected to the branch header, downstream of the MSIVs, that supplies main steam to the SG feedwater pump turbines. These valves are normally shut and, when operated, exhaust main steam to the main condenser. The Extraction Steam System's functional requirements are: [ Reference 1, Section 1.1.4] To increase the temperature of the feedwater prior to its entering the SG, which results in an increase in overall plant efficiency; I To minimize thermal shock in the SG2; and r To assist in removing moisture frota the high pressure turbina third stage by supplying steam to the first stage of the moisture sepriator reheater. During normal plant operations, the e'. traction steam is used to increase the temperature of the feedwater prior to its entering the SGs. Wet steam is directed from the thn s highest stage pressure feedwa.er heaters in the condensate and feedwater systems en route to the heater drain tanks. Wet steam from the three lowest stage pressure feedwater heaters is cascadel to the previous stage feedwater heater and eventually recovered in the condenser. The functional requirements of the Nitrogen and Hydrogen System are: [ Reference 1, Section 1.1.7] To store and distribute the required amounts of nitrogen for normal plant operations; To provide nitrogen for backup to the instrument air rystem (however, this is not currently in service); and Tpplication for License Renewal 5.12-3 Calvert Cliffs Nuclear Power Plant
AT1 ACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND 2"TROGEN AND HYDROGEN SYSTEMS ( j
- I To supply hydrogen to the main generators, th? volume control tanks, and the Radiological Che@ry Explosive'Ns Storage Room.
The Nitrogen and Hydropn Systun consists of two independent systems supplying gases for normal plant operations. The nitrogen subsystem can itself be divided into two subsystems, the storage system and distribution header. The storage system includes an insulated storage tank that is ke . pressurized by a combination of ambient and electric vaporizers. The hydrogen s6syaem is a common subsystem consisting of hydrogen gas bottles, a truck fill connection, pr:,=. ontrol unit, distribution header, and the associated piping valves and controls. l System Interfaccs The interfaces discussed in this section that serve a safety-related function are within the scope oflicense renewal and addressed in this section of the BGE LRA. The non-safety-related portions of the Main Steam System that are within the scope of license renewal for fire protection considerations r.re addressed in Section 5.10, Fire Protection, of the BGE LRA. The Main Steam System has interfaces with the SG, main turbine, SG feedwater pump turbines, AFW, Steam Seal and Exhaust System, Reactor Regulating System, Main Turbine Control System, Engineered Safety Features Actuation System, Circulating Water System, the main condensers, and instrument air. [ Reference 1, Sec6cn 1.1.2; Reference 2, Section 10,1; Reference 3} The following interfaces with or portions of the Main Steam System are within the scope of license i .newal and included in this section of the BGE LRA:
=
Main steam lines from the SGs to the MSIVs. The SGs are within the scope oflicense renewal for the Reactor Coolant System, which is addr:ssed in Section 4.1 of the LRA. The Engineered Safety Features Actuation System supplies a signal to the MSIV Hydraulic Actuator and Control System to rapidly shut the MSIVs when a SG isolation Signal or Containment Spray Actuation Signal has been generated. Main steam line drains transfer moisture from the main steam piping to the auxiliary blowdown tanks during plant startup. The contents of these tanks are transferred to the Chesapeake Bay via the Circulating Water System discharge piping. These Main Steam System drains are partially within the scope of license renewal. The lines up to the drain line orifices that act as the specification break between Class EB and Class GB piping are within the scope of license renewal. The main steam line drains transfer moisture from the main steam piping to the main condensers during normal plant operation. As above, the main steam drains up to the drain line orifices that act as the specification break between Class EB and Ciass GB piping are within the scope of license renewal. Application for License Renewal 5.12-4 Calvert Cliffs Nuclear Power Plant
A'ITACilMENT (4) APIENDIX A - TECliNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS The Instrument Air System provides operating air for the main steam atmospheric dump valves and the AFW pump turbine steam isolation valves. A portion of the ai system relative to these valves !s included within the scope of license renewal and is also included in this section of the BGE LRA. The SG Blowdown System piping that is included in this section of the BGE LRA has four interfaces that are within the scope of license renewal as follows: (Reference 1, Section 1.1.2; Reference 2, Section 10.1; Reference 3]
=
The nitrogen portion of the Nitrogen and Ilydrogen System taps into the surface blowdown lines inside of containment to provide for dry layup of the SG. The SG is filled with nitrogen to ensure that no oxygen is present during layup. This piping (blowdown and nitrogen) penetrates containment. The isolation valves from the SG Lay-up Chemical Addition System interface with the SG bottom blowdown lines. The second in the series of two blowdown heat exchangers in each unit is cooled by the safety-related Service Water (SRW) System. Similarly, the SG blowdown radiation monitor coolers in each unit are cooled by the safety-related Component Cooling Water (CCW) System. The Extraction Steam System interfaces with the Feedwater Heaters, Drains and Vents System, Reheat Steam System, scavenging steam, Reactor Coolant Waste Evaporator System, Miscellaneous Waste Processing System, and the Main Steam System; however, none of these interfaces are within the seope oflicense renewal. The only portion of the system that is in scope is the system containment pent .mtion. His penetra: ion was provided to make low pressure steam available for reactor vessel head washdown. This function has since been abandoned, but the containment penetration still exists and that small section of safety-related piping at the penetrations in each " nit is within the scope of license renewal. (Reference 1, Section 1.1.5; Reference 2, Section 10.1; Refeance 41 The nitrogen distribution header runs throughout the plant, going to a variety of components ranging from the MSIVs to the auxiliary boilers. Nitrogen is used in the safety injection tanks, virtually all storage tanks, and water bearing vessels such as the volume control tanks and the SGs. Only its interface with the SG blowdown system, addressed above, and the containment penetrations for the nitrogen supply to the SGs and pressurizer quench tanks, the safety injection tanks, and the reactor coolant drain tanks are within the scope oflicense renewal. [ Reference 1, Section 1.1.8; Reference 5] The hydrogen subsystem is a common subsystem consisting of hydrogen gas bottles, a truck fill connection, pressure control unit, distribution header, and the associated piping valves and controls. The hydrogen subsystem interfaces with the Main Generator and the Chemical and Volume Control System. None of these interfacing functions are within the scope oflicense renewal. (Reference 1, Section 1.1.8; Reference 5] Because only the nitrogen portion of the Nitrogen and Hydrogen System is applicable to the scope of this report, the system will be referred to as the Nitrogen System for the balance of this report. Application for License Renewal 5.12-5 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HVDROGEN SYSTEMS System Sconing Results The Main Steam System, Extraction Steam, and Nitrogen Systems are in scooe for license renewal based on 10 CFR 54.4(a).
'lhe following intended functions of the Main Steam System (and SG Blowdown, e .3pplicable) were determined based on the requirements of Q54.4(a)(1) and (2), in accordance with the CCNPP IPA Methodology, Section 4.1.1: (Reference 3, Table 1]
Maintain the pressure boundary of the system (liquid and/or gas); Provide closure of tne SG blowdown isolation valves on receipt of a Containment Spray Actuation Signal to reduce the heat load on the SRW Syste n; Provide SG overpressure protection / decay heat removal;
- Provide SG steam line isolation; Provide motive steam to AFW pump turbines on receipt of an Auxiliary Feedwater Actuation System actuation signal; Maintain electrical continuity and/or provide protection of the electrical system; Maintain mechanical operability snd/or provide protection of the mechanical system; and Restrict flow to a specified value in support of a design basis event response.
The following Main Steam System intended functions were determined based on the requirements of 654.4(a)(3): (Reference 3, Table 1]
- For fire protection (Q50.48) - Provide Reactor Coolant System heat removal in the event of a postulated severe fire (addressed ir. Section 5.10, Fire Protection, of the BGE LRA);
For environmental qualification (Q50.49) - Maintain the functionality of electrical components as addressed by the Environmental Qualification Program; For station blackout (Q50.63)- Provide SG overprmure protection / decay heat removal; For station blackout (Q50.63)- Provide SG steam line isolation; a For station blackout ( 50.63) - Provide motive steam to AFW pump turbines on receipt of an Auxiliary Feedwater Actuation System actuation signal; and a For station blackout (850.63)- Provide valve position indication and manual closure of MSIV bypass isolation valves following a loss of AC power. All components of the Main Steam System evaluated in this section of the BGE LRA are Seismic Category I and are subject to the applicable loading conditions identified in the Updated Final Safety Analysis Report Section 5A.3.2 for Seismic Category I systems and equipment design. The main steam piping from the SG to the containment penetration is designed in accordance with American Nuclear Standards Institute (ANSI) B31.1, Power Piping Code. From the penetration to the MSIVs, the piping meets the design requirements of ANSI B31.7, Class II, Nuclear Power Piping Code. The steam supply piping to the AFW pumps is designed in accordance with ANSI B31.1, Power Piping Code. The piping J Application for License Renewal 5.12-6 Calvert Cliffs Nuclear Power Plant
ATTACHMrNT (4) 5.12 APPENDIX A - TECIINICAL INFORMATION l MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM , AND NITROGEN ANDIIYDROGEN SYSTEMS Section XI Inservice Inspection Program. The above s EB 12, and EB-8, respectively, which have a rating of 1000s psig/580 own F. Steam g piping is designated as Classes EB 6 and EB-14, which have The a rating of 1000 Class EB-6 piping is non-penetration piping that is designed in The .. accordance with AN Class Il piping for the purposes of the See [ References 2,6,7, and 8] . Section Figure 512.1. XI Inservice the scope of this section of the BGE LRA. Additionally, the e n instrument air p 125 psig/100'F, and is designed in accordance with ANSI B31.1. It is o ASME Section XI Inservice Inspection Program. [ References 2,9,10, e and 11] The following intended functions of the Extraction Steam System e were determ requirements [ Reference 4, Table 1] of f54.4(a)(1) and (2), in acco4 dance with, the CCNPP IPA Metho To provide containment isolation, and To maintain electrical continuity and/or provide protection of the electrical system The extraction steam piping within scope for license renewal or is the containm reactor vessel head washdown. This piping is designated as Class GB 24, is rated a r designed in accordance with ANSI B31.7, Class 11, and is notrvice included in the ASM Inspection Program. See Figure 512.2. (References 12 and 13] Application for License Renewal 5.12-7 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION - 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS N E&t2 Net WSLR Addressed m a pg,, E&t2 Not g.g soE wSLR MAIN STEAM REUEFS1 SAFETIES M R R R R R R R R ORANS , E&t2 ANC
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X X FLOW RESTRICTING wSLR m secean s to at em M ORANS , E&t2 (TmcAu ' r l BGE LRA n g } ES12 1RCLR Witthn Scope
... ............ .... ....f.. g 1F DRAMS , E&S STEAM (TmCA4 ' C ~- GENERATOR TO AUXIUARY RED PUMP a TUR994!.WSLR e
- E&M
- feat
- . r&M - .
s_o -ace 4x x , 4-i-+ +++ N CONTAMMedT
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FIGUIL, 5 12.1 ' S "so.svsrPE eruvur . P MAIN STEAM AND LNTERFACING SYSTEMS (TYPICAL FOR EACilSTEAM GENERATOR) (SIMPLIFIED DIACRAM - FOR INFORMATION ONLY) Application for License Renewal 5.12-8 Calvert Clifts Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECilNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS TEST Not HB-45 CONTAINMENT HBJ5: Not WSLR1 WSLR WSLR ! WSLR z TO NITROGEN m i m SAFETY f' SYSTEM '
" INJECTION TEST TANKS Not HB45 i HB45 Not
, SLRW - WSLR W WSLR,
, SLR (
, , , r NITROGEN TO SYSTEM N N ; REACTOR COOLANT l
DRAIN TANK l Not HB45 HB45; Not WSLR . WSLR --> TO WSLR WSLRm
, w STEAM GENERATORS NITR EN TO
- N N ; PRESSURIZER QUE.NCH TANK Not GB-24 TEST GB24 Not WSLR WSLR WSLR WSLR EXTRACTION REACTOR VESSEL STEAM SYSTEM X W- [ HEAD WASHDOWN CONNECTION CONTAINMENT FIGURE 5.12-2 l NITROGEN AND EXTRACTION STEAM PENETRATIONS (TYPICAL FOR FACH l' NIT)
(slMPLIFIED DL4 GRAM FoR INFoRMATioN ONLY) The following intended functions of the Nitrogen System were determined based on the requirements of
$54.4(a)(1) and (2), in accordance with the CCNPP IPA Methodology, Section 4.1.1: [ Reference 5, Table 1]
To provide containment isolation; and To maintain the pressure boundary of the system. The Nitrogen System piping in scope for license renewal is the nitrogen penetration piping and the nitrogen piping to the .%s via the surface blowdown piping. The penetration piping is designated as Class HB-45, is rated r.t 300 psig/150 F, is designed in accordance with ANSI B31.7, Class II, and is not included in the ASME Section XI Inservice Inspection Program. The nitrogen piping to the SG is designated as Class EB-6, is rated at 1000 psig/525'F, is designed in accordance with ANSI B31.1, and is Class 11 for the purposes of the ASME Section XI Inservice inspection Program. See Figure 5-12.2. [ References 8,11, and 14] Application for License Renewal 5.12-9 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AO HYDROGEN SYSTEMS 5.12.1.2 Compnent Level Scoping Based on the intended system functions listed above, the ponions of the Main Steam System that are within the scope of license renewal, and addressed in this section of the BGE LRA, include all piping, components, component supports, instrumentation, and cables for the sections of the system from the SG l outlet to MSIVs, AFW branch header to AFW stop control valves, surface and bottom blowdown to containment isolation control valves, the safety-related main steara system drains up to the flow restrictor3 or the MOVs, and the air supply piping to the AFW stop control valves. [ Reference 3, Tables I and 2; References 6,7,9,10,12, and 15 through 19] The following 34 device types in the Main Steam System were designated as within the scope of license renewal because they have at least one intended function: [ Reference 1, Table 2-1] Class EB Piping (EB) Hand Indicator Controller Pressure Switch (PS) Class HB Piping (HB) (HIC) Pressure Transmitter (PT) f Accumulator (ACC) Hand Switch (HS) Relief Valve (RV) Check Valve (CKV) Hand Vale (HV) Relay (RY) Control Valve (CV) Heat Exchanger (HX) Solenoid Valve (SV) Encapsulation (ENC) Current / Current Device (1/I) Temperature Element (TE) Flow Control Valve (FCV) Current / Pneumatic Device (I/P) Tank (TK) Flow Element (FE) Power Lamp Indicators (JL) Miscellaneous Indicating Lamp (XL) Flow Orifice (FO) Level Switch (LS) Position Indicating Lamp (ZL) Flow Transmitter (PT) Motor-Operated Valve (MOV) Position Switch (ZS) Fuse (FU) Pressure Control Valve (PCV) Pressure Indicator Control (PIC) Hand Controller (HC) Pressure Indicator (PI) Five device types in the Main Steam System are common to many other plant systems and have been included in the Instrument Line Commodity Evaluation in Section 6.4 of the BGE LPA. These device types are: [ Reference 1, Table 3-2]
- Flow Transmitters;
. Level Switches; Pressure Indicators; Pressure Switches; and a
Pressure iransmitters. One additional device type, hand valves, has also been evaluated in the BGE LRA Section 6.4 for those hand valves that have a specific function associated with an instrument. The portions of the Extraction Steam System within the scope of license renewal consist of piping, component supports, and hand valves associated with the extraction steam containment penetrations and Application for License Renewal 5.12-10 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS two IE fuses and their associated cables, panels, and supports. [ Reference 1 Table 21; Reference 4, Tables 1 and 2; Reference 12] The following three device types in the Extraction Steam System were determined to be within the scope oflicense renewal because they have at least one intended function: [ Reference 1, Table 2-1] Class CS Piping Fuse Hand Valve There are no Extraction Steam System device ty% that are included in separate commodity AMR reports. The portions of the Nitrogen System within the scope of license renewal consist of piping, component supports, and check and nand valves associated with SG blowdown and containment penetrations 20A, 20B, and 20C [ Reference 1, Table 2-1; Reference 5, Tables 1 and 2; Reference 14] The following four device types in the Nitrogen System were designated as within the scope of license renewal !vcause they have at least one intended function: [ Reference 1, Table 2-1] Class HB Piping Class EB Piping Check Valve Hand Valu There are no Nitrogen System device types that are included in separate commodity AMR reports. For all systems addressed in this section of the BGE LRA, applicable component suppons, ubles, and electrical components are discussed in the Commodity Evaluations for those commodities, i.e., Sections 3.1,6.1, and 6.2 of the BGE LRA for Component Supports, Cables, and Electrical Panels, respectively. 5.12.1.3 Components Subject to AMR This section describes the components within the Main Steam, Extraction Steam, and Nitrogen Systems that are subject to an AMR. It begins with a listing of passive intended functions and then dispositions the component types as either only associated with active functions, subject to replacement, evaluated in other reports, evaluated in commodity reports, or retraining to be evaluated for aging management in this report. Passive Intended Functions In accordance with CCNPP IPA Methodology, Section 5.1, the following Main Steam System functions were determined to be passive. [ Reference 1, Table 3-1] Maintain the pressure boundary of the system (liquid and/or gas); Application for License Renewal 5.12-11 Calvert Cliffs Nuclear Power Plant
ATTACHMENT fy ! APPENulX A TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR HLOWIK)WN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS Maintain electrical continuity and/or provide protretion of the electrical system; and
+
Restrict flow to a specified value in supprt of a design basis event response. For the second of these functions, only the system electrical cables perfort a passive function. All other electrical system components perform an active function only. System cables are evaluated !n Section 6.1 of the DGE LRA. i The following Extraction Steam Systtm functions were determined to be passive: (Reference 1 Table 31)
+
Provide cortainment isolation; and Maintain electrical continuity and/or provide protection of the electrical system. As for main steam above, only electrical cables perfonn a passive electrical function and they are also addressed in Section 6.1 of the BGE LRA. The following Nitrogen System functions were determined to be passive: [ Reference 1. Table 3 1) { P. , idt containment isolation; and M mtal.) the pressure boukdary of the system (liquid and/or gas). Component TypuSuldect to AMR i Of the 34 device types in the Main Steam System that are within the scope oflicense renewal: 11 device types haw only .nctive functions - fuses, hand controllers, hand indicator controllers, haad ta vitches, current /currint devices, power lamp indicators, pressure indicator controls, relays, miscellaneous indicating lamps, position switch indicating lamps, and position switches; { Reference 1,Tabin 3 2) 5 device types are subject to (or partially subject to) the MSIV.13 Refurbishment Program; therefore, these specific devices are not evaluated for plausible age-related degradation nechanisms (ARDMs). These devices are: )ne of the two AMR report accumulator groups, one of the six AMR report check valve groups, one of the eight AMR report control valve groups; all llow control valves; and one of the fourteen AMR report hand valve groups. [ Reference 1 Attachment 1; Reference 20]
+
$ device types are evaluated in the Instiument Line Commodity Evaluation section of the BGE LRA Flow transmitters, level switches, pressure indicators, pressure switches, and pressure transmitters are the device types included in these other evalt.ations. Iland valves within the scope oflicense renewal associated with instruments, not evaluated in this report, are evaluated in the same BGE LRA section; and (Reference I, Table 3 2)
I device type, solenold valves is partially evaluated in the Environmentally Qualified Equipment Commodity Evaluation (Section 6.3 of the BGE LRA). This applies to one of the two AMR report solenoid valve groups. There were other system solenoid valves that were dispositioned in the system pre-evaluation as being short lived environmentally qualified devices. As such, they Application for License Renewal 5.12 12 Calvert Cliffs Nuclear Power plant
.- - .- .. = - .- -- . - - _ _ - . . - - - - - - - - _ - - - -
ATTACliMENT (Q APPENDIX A TECl!NICAL INFORMATION 5.12 MAIN STEAM, STEAM GENERATOR IILOWDOWN, EXTRACTION STEAM, AND NITROGEN ANDllYDROGEN SYSTEMS are included in a replacement program for short lived environmemally qualified devices and not subject to AMR. [ Reference 1. Attachment 3s] The 18 device types listed in Table 5.121 are subject to AMR and included in this report. [ Reference 1 Table 3 2) TABLE 5.121 MAIN STEAM SYSTEM DEVICElyPES REOUIRING AMR Class EB Piping (EB) Flow Control Valves (FCV) Motor Operated Valves (MOV) Class llB Piping (11B) Flow Elements (FE) Rellef Valves (RV) Accumulators (ACC) Flow Orifices (FO) Pressure Control Valves (PCV) Check Valves (CKV) lland Valves (IIV) Solenoid Valves (SV) Control Valves (CV) lleat Exchangers(llX) Temperature Elements (TE) Encapsulation (ENC) Current / Pneumatic Devices (1/P) Tanks (1K) The MSIV 13 Refurbishment Program [Referme 20] is a PM Program through which the M31V actuators and their associated subcomponents are scheduled to be removed from the valve every fuir years for shipment to the manufacturer (Edwards) to be irispected and rebuilt as necessary. The current 4 practice is to perform this task every two years. Because of the frequency and scope of this activity, these actuator subcomponents are not evaluated for plausible ARDMs in accordance with Section 6.1.2 of the IPA Methodology. This program, therefore, provides for the aging management of the actuators and their associated subcomponents. Of the three device types in the Extraction Steam Srstem that are within the scope oflicense renewal, the fuses do not support a passive function, so the two device types listed in Table 5.12-2 are included in this AMR [ Reference 1, Table 3 3) TABLE 5.12 2 UXTRACTION STEAM S? STEM DEVICE Tyres REQUIRING AMR Class GB Piping (GB) lland Valves (11V) All four of the device types in the Nitrogen System that are within the scope of license renewal are included in this AMR. They are listed in Table 5.12 3. [ Reference 1. Table 3-4] 4 J Application for License Renewal 5.12 13 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 . MAIN STEAM, STEAM GENERATOR HLOWDOWN, EXTRACTION STEAM. AND NITROGEN AND HYDROGEN SYSTEMS TABLE 5.12 3 NITROGLN SYSTEM DEYlCE TYPES REQUIRtNG AMR Class EB piping (EB) Check Valves (CKV) Class llB Piping (llB) lland Valves (llV) in addition to these device types, there are device types from three other systems that have been included in the Main Sicam System AMR report, as discussed earlier in this report. These are the encapsulations for the Feedwater and Chemical and Volume Control Systems, per the Auxiliary Building AMR report (Reference 21), and hand valves from the Chemical Addition System [ Reference 1). The latter were not able to be covered elsewhere and interface with the SO blowdown piping, so they have been included in this section of the BOE LRA. 5.12.2 Aging Management A list of potential ARDMs for the Main Steam Extraction Steam, and Nitrogen System device types presented in Tables 5.121 through 5.12-3 is given in Table 5.12 4. Once the potential ARDMs are identified, they are evaluated for each of the device types to which they apply. Based on the evaluation of the device types' operating environment and design, a number of these potential ARDMs are determined to be non plausible and will not require further evaluation, nese mechanisms are identified by an (x) in the "Not Plausible for System" column of Table 5.12-4. The plausible ARDMs are identified in the table by a check mark (/) in the appropriate device type column. For efficiency in presenting the results of these evaluations in this report, device type /ARDM combinations were grouped together where there are similar characteristics and the dis.ussion is applicable to all equipment types within that group. Exceptions are uoted where appropriate. Five groups have been selected for the Main Steam. Extraction Steam, and Nitrogen Systems. Table 5.12-4 identifies the group in which each device type /ARDM combination belongs and defines the group scope. [ Reference 1, Table 41, Table 4 if Flow elements are not included in the table because they are covered by the evaluations for msin steam piping. [ Reference 1. Tables 41 and 4 2,083 FE 01 Attachment 3) ) Application for License Renewal 5.12 14 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOW?ii, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS TABLE 5.12-4 POTENTIAL AND PLAUSisLE / .1DMS FOR MAIN STEAM, EXTRACTION STEAM, AND NITROGEN MAIN STFAM ExTascw Straw. xe . POTmitAs. Nrinoca Dmcz Tmts Not ARDMs -EB -GB -HB CKY CV HV ACC ENC' FG HX 1/P MOV FCV' PCV RV SV TE TK PIAtw Cavitatxm /(2) Erosion Corrosion x j Fatigue ! Crevice #(1) /(1) /(1) #(I) #(I) #(1) #(1) #(I) #(1) Common Dynamic x leading Electrical x Stressors tronon #(2) /(2) /(2) /(2) /(2) #(2) #(2) Corrosion Fatigue x Foulmg x Galvame x Corror'on General /(I) #(1) /(1) #(1) #(I) /(1) #(1) #(I) #(1) #(1) #(I) #(I) #(1) Corrosion flydrogen x Damage Intergranular x Attack MIC x Partxle Wear x Erosion Pittmg #(I) #(1) #(1) #(I) #(I) /(I) /(I) #ft) #41) Radiation x Damage Rubber x Degradarxm 9 Applicatior, for License Renewal 5.12-15 Calvert Clifts Nuclear Power Plant
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS TAst.E 5.12-4 POTENTIAL AND PLAUSIBLE ARDMS FOR MAIN STEAM, EXTRACTION STEAM, AND NITROGEN Mm stuw, Exmcrure SmM, xe NITaocEN DEUCE Tim M SmM Dmcz TWEs Nor POTENTIAL ARDMs -EB -GB -HB CKY CV HV ACC ENC' FO HX L? MOV FCY' FCV RV SV TE TK PLatm Saltwater x Anack l Selective /(3) Leaching stress x conesen Cracking stress x Relaxation Thennal x Damage Thermal x Embrittlement Wear /(4)
/ -indicates plausible ARDM determination
- -indicates non-plausible ARDM determination
(#) - indicates the group in which this SC/ARDM combination is evaluated Note 1 - Encapsulations evaluated are from the Main Steam, Main Feedwater, and Chemical and Volume Control Systems (see page 5.12-14). Note 2 - Flow control valves are not evaluated for plausible ARDMs, all flow control valves are in the MSIV-13 Refurbishment Program. MIC = Microbiologically-Induced Corrosion Group I covers crevice corrosion, general corrosion, and pitting for all device types. Group 2 includes erosion corrosion and cavitation crosion of piping and erosion corrosion of check valves, control valves, flow orifices, hand valves, heat exchangers, and MOVs. Group 3 covers the selective teaching of the SG blowdown radiation monitor cooler. Group 4 covers the wear within control valves.
+ yptication for License Renewal 5.12-16 Calvert Cliffs Nuclear Power Plant t
ATTACllMENT (4) APPENDlX A TECilNICAL INFORMATION 5.12 . MAIN .4 TEAM, STEAM GENERATOR llLOWDOWN3 EXTRACTION STEAM, AND NITROGEN AND flVDROGEN SYSTEMS The following is a discussion of the aging management demonstration process for each group identined in Table 5.12 4. It is presented by group and includes discussion sections on materials and environment, aging mechanism effects, methods to manage aging, aging management program (s), and aging management demonstration. Group 1 (crevlee corrosion, general corrosion, and pitting for all device types) . Materials and Environment All of the applicable piping in the M4 Ni n Extraction Steam, and Nitrogen Systems is seamless carbon steel. Pipingjoints are butt weU4 % ty bore piping (main steam lines from the sos to the MSIVs and the AFW pump turbine supy,y ,dpivi: and socket welded for small bore piping (all steam drain piping, SO blowdown piping, nitrogen piping, extraction steam piping, and instrument air piping wiiin the scope oflicense renewal). [ Reference 1 Attachment 3s for Pipe; References 8,11, and 13] 3 All other device types or device type subcomponents that are subject to all three ARDMs are also carbon or alloy steel. De following other device types or device type subcomponents are subject to crevice corrosion and pitting only: ne Type 316 stainless steel Main Steam System now orinces; De stellite et stainless steel A351 CF 8M in some Main Steam System check valve seats / discs (main steam to AFW pumps); The Type 316 stainless steel in the bodies / bonnets and/or stems / seats / plugs in some Main Steam System control valves (steam atmospheric dump valves and SO blowdown valves); The stellite or stainless steel A351 CF 8M internals of some Main Steam System, Extraction Steam System, and Nitrogen System hand valves (SO layup interface valves via bottom blowdown lines; extraction steam containment isolation, reactor head washdown, and test connection valves; SO nitrogen inlet valves; and main steam drain valves); The stainless steel Al82 F316, A351 CF 8M, Type 316 or Type 630 body / bonnet / stem in some Main Steam System hr.nd valves (SO blowdown valves); and a The stellite, llastelloy X, or A567 disc / seat in some Main Steam System MOVs (main steam drain valves). [ Reference 1, Attachment 3s for Element, Check Valve, Control Valve, Motor- l Operated Valve, and Pipe) The internal environment for the Main Steam System and its components during power generation is saturated steam at a design pressure / temperature of 1000 psig/580*F and normal operating parameters of approximately 850 psig/520*F. [ Reference 2, Chapter 10.1; Reference 8) During normal operation, between test actuations of the AFW System, the main steam lines to the AFW pumps will experience significant condensation of residual steam from those test actuations such that reactuation of the system will result in two-phase Dow through the main steam drains from the system which have been redesigned post Three Mile Island to accommodate this. The portion of the Extraction Steam System that is within the scope oflicense renewal is the piping that penetrates containment to provide a reactor head washdown function. This function is not used; Application for License Renewal 5.12-17 Calvert Cliffs Nuclear Power Plant
ATTACllMENT (4) APPENDIX A TECilNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR llLOWDOWN, EXTRACTION STEAM, AND NITROGEN ANDllVDROGEN SYSTEMS therefore, this piping is usually empty except when subjected to the presence of testing air. [ Reference 1, 4 Attachment 3s for 046-GB 01 and 046 llV Ol; Reference 4, Table 2] ' He Nitrogen System has design conditions of 300 psig/IS0'F, although it can also contain testing air. { Reference 1, Attachment 3s for 07411B-01 and 074 liv Ul; Reference 5, Table 2] He internal environment for the SG blowdown piping is one of a saturated mixture of steam and feedwater that is subcooled to water via the blowdown heat exchangers. The blowdown beat exchangers within scope contain SG blowdown on the shell side and SRW or CCW on the tube side for the non regenerative SG blowdown heat exchanger and the SO blowdown radiation monitor cooler, respectively. The internal environment for the instrument air piping is air that has been dried to a dewpoint of-40*F with design operating conditions of 125 psig/100'F. [ Reference 1. Attachment 6s; References 2,9,10, and 11). Group 1 (crevice corrosion, general corrosion, and pitting for all device types) Aging Mechanism Effects l Carbon steel is susceptible to general and localized (crevice and pitting) corrosion mechanisms, whereas rtainless steel is generally considered to be susceptible only to localized corrosion. Carbon steel piping containing steam or steam / water environments is particularly susceptible to general corrosion over a , period of time, particularly when the system is subjected to intermittent periods of operation and shutdown. He rate of general corrosion of :arbon steel is reduced after the initial buildup of the magnetite protective corrosion film. Exposure to higher oxygen concentrations during shutdown results in the removal or partial removal and then recreation of this film, ne effect of this process is component wall thinning over a relatively large area, which could result in pressure boundary failure if extensive. [ Reference 1, Attachment 6s,7s, and 8] In the saturated steam environment of the Main Steam System, the internal environment (high velocity steam during operating / testing and condensation / dampness during standby) perpetuate general corrosion of the piping and carbon steel components. He periodic exposure to condensation may result in uniform thinning of the pressure boundary material. The areas of primary concem for general corrosion are piping low spots. [ Reference 1, Attachment 6s,7s, and 8] The extraction steam piping within the scope oflicense renewal is piping that penetrates containment to provide a containment washdown function. This function is no longer used so that the piping is normally empty and occasionally subject to the presence of testing air. Since the air can contain moisture, the piping and components are subject to general corrosion. [ Reference 1, Attachment 3s for 046-08 01 and 046 llV Ol; Reference 4, Table 2] The SG blowdown piping and components are subject to general corrosion due to the exposure of the piping to a corrosive medium (i.e., a high velocity, two-phase mixture of steam and water) during normal operation and, to a lesser extent, during shutdown periods. The fact that the system is operated in an intermittent manner exposes it to higher general corrosion rates than the other piping within the scope of Application for License Renewal 5.12 18 Calvert Cliffs Nuclear Power Plant
ATTACliMENT (f) APPENDIX A - TECilNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM. AND NITROGEN AND HYDROGEN SYSTEMS this section of the BGE LRA. For this reason, the system piping is being repisced with piping made from a more corrosion resistant material as it is warranted. [ Reference 1, Attachment 6s,7s, and 8) For the Nitrogen System piping and components, the periodic exposure of this piping to testing air may result in general corrosion. [ Reference 1, Attachment 6s,7s, and 8] For the Instrument Air System piping and instrument air containing components (e.g., the accumulators) included in this scope, general corrosion is considered to be plausible; however, it is also considered to be imlikely since the dewpoint of the air is controlled to minus 40'F. At this value, there is insufficient moisture to cause signincant occurrences of this mechanism. [ Reference 1, Attachment 6s,7s, and 8] For the alloy steel temperature element thermowells, the corrosive environment during shutdown and, to a lesser extent, the normal operation ensironment, can cause general corrosion, albeit at low rates, due to the chromium content of the steel. During shutdown, in particular, the higher oxygen concentrations in the system present the opportunity for general corrosion. [ Reference 1. Attachment 7 for Element, Attachment 6 for 083 TE-Ol] The Main Steam, Main Feedwater, and Chemical and Volume Contml Sys: ems' encapsulations are also susceptible to general corrosion during shutdown conditions, when the carbon ueel, of which they are made, could be exposed to potentially moist air if their protective contings are damaged. [ Reference 1 Attachment 7 and Attachment 6s for Encapsulation] Crevice corrosion and pitting can occur in areas of piping that are not exposed to the general flow stream, such as areas with a lack of complete penetration of butt welds, clearances at socket weld fit ups, holes, gasket surfaces, lap joints, crevices under bolt heads, integral welding backing rings, etc. The crevice must be wide enough to permit liquid entry and narrow enough to maintain static conditions, typically a few thousandths of an inch or less. These areas may comprise small, localized volumes of stagnant solution for which fluid chemistry may deviate from bulk system chemistry, liigher concentrations of impurities may exist in these crevices due to out of specification system chemistry during shutdown conditions and due to stagnant flow conditions in the crevice, in an oxidizing environment, a crevice can set up a differential aeration cell to concentrate an acid solution within the crevice. Even in a reducing environment, alternate wetting and drying can concentrate aggressive ionic species to cause pitting and crevice corrosion. The resulting degradation is highly localized pits or cracks. Controls over piping fit up and welding quality during construction limit the locations of potential crevices in the large bore piping. Most susceptible locations for crevices are the small bore piping (including drains and instrument taps from the large bore piping) where socket welding creates por atial crevices due to the design of thejoint. The effects of crevice corrosion and pitting are expected to be more severe in areas of the main steam system (e.g., SG blowdown) where there exists a two-phase fluid. [ Reference 1, Attachment 6s,7s, and 8] For the alloy steel temperature element thermowell assemblies, areas not exposed to the general flowstream that could be subject to crevice corrosion and pitting are the half couplings that attach them to the main piping. In the heat exchangers, areas such as locations where internal parts interface with the shell are susceptible to these ARDMs. In the Main Steam System flow orifices, the accumulation of condensation can occur at the orifice junctions with the piping and flanges making them susceptible to Application for License Renewal 5.12 19 Calvert Clifts Nuclear Power Plant
l ' ATTACllMENT (4) l APPENDIX A - TECilNICAL INFORMATION l 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS crevice corrosion and pitting at those locations. In any of the system valves, crevice corrosion in the gaps between valve subcomponents is possible (including those valves with non-carbon steel subcomponents); however, a lack of dissolved oxygen and chloride ions in solution and, in some cases, a protective oxide passive layer will delay the corrosive process. Valves can also have stagnant condensation conditions that are conducive to pitting; however, the rate of pitting is proportional to the concentration of chlorides present. [ Reference 1. Attachment 6s and 7s for Element] For the nitrogen piping that is within scope, the crevice corrosion and pitting ARDMs are not considered to be plausible due to the normal no flow condition of the piping at the containment penetrations and the normal presence of nitrogen. Local stagnant flow conditions and/or the presence of moisture are required for these mechanisms. The same is true for the extraction steam piping that is within scope, his portion of the system is no longer used and does not see flow conditions. [ Reference 1, Attachment 6s and 7s] For the instrument air system piping and components within scope, these ARDMs are net plausible because of the controlled system dewpoint of minus 40'F. There is insufficient moisture present for either mechanism to occur. [ Reference 1. Attachment 6s,7s, and 8] ne Main Steam System accumulators (carbon steel), pressure control valves (aluminum), current / pneumatic devices (aluminum and brass), some relief valves (staintess steel), and the solenoid valves (brass) are also subjected to the dry, instrument air environment such that these ARDMs are not plausible for them either, particularly the aluminum, brass, and stainless steel devices. [ Reference 1, Attachment 6s and 7s] The encapsulations are not subject to these ARDMs since the normal operating temperatures of these devices (550*F for the Chemical and Volume Control System,435'F for feedwater, and 520'F for main steam) are such that condensation due to local environmental conditions is not possible and the er.capsulations are insulated. Even if condensation could develop during shutdown, the water would quickly evaporate during stanup. Since the encapsulations are insulated, the possibility for condensation on the cooler encapsulation metal due to the relative humidity and ambient temperature of the surrounding air is eliminated. [ Reference 1, Attachment 6s and 7 for Encapsulation] For the Main Steam System relief valves, the process fluid is very high quality steam due to chemistry control and maintenance his is not a corrosive environment, particularly for the stainless steel material l from which they are fabricated; therefore, pitting and crevice corrosion are not plausible. [ Reference 1, Attachment 6 for 083 RV Ol] Corrosion (general, crevice, or pitting) is also not plausible for any device bolting, since it is not exposed to any process fluids. [ Reference 1 Attachment 4s,5s, and 6s] Long-term repeated exposure to the described environments may result in localized pitting and/or general area material loss which, if unmanaged, could eventually result in toss of the pressure retalning capability under current licensing basis (CLB) design loading conditions. Therefore, general corrosion, crevice corrosion, and pitting corrosion have been determined to be plausible ARDMs for which aging Application for License Renewal 5.12-20 Calvert Cliffs Nuclear Power Plant
ATTACllMENT (4) APPENDIX A - TECllNICAL INFORA1ATION 5.12 - h1AIN STEAh!, STEAh! GENERATOR HLOWDOWN, EXTRACTION STEAh!, AND NITROGEN ANDliVDROGEN SYSTEh1S effects must be managed for the systems included within the scope of this section of the BGE LRA. [ Reference 1, Attachment 6s and 7s] Group 1 (crevice corrosion, general corrosion, and pitting for all device types) - 51cthods to hinnage Aging Mitigation: The eflects of corrosion cannot be completely prevented, but they can be mitigated by minimizing the exposure of the carbon steel components and piping to an aggressive environment. [ Reference 1, Attachment 6s and 7s] Maintaining a main stearr environment of high quality steam via the secondary chemistry control program results in limited corrosion reactions, ne initial formation of the passive magnetite oxide layer also protects the pipe interior surface by minimizing the exposure of bare metal to water. [ Reference 1, Attachment 6s and 7s] Maintaining the instrument Air System air quality at a dewpoint of minus 40'F or less, by maintaining proper dryer alignment and operation, results in limited corrosion reactions due to the lack of the moisture required to cause the reactions. The use of stainless steel and non ferrous materials in some of the system components also prevents system corrosion. [ Reference 1 Attachment 6s and 7s] The portions of the Extraction Steam System that are within the scope oflicense renewal are abandoned in place because the reactor vessel head washdown function is no longer used. The containment penetration piping between the containment isolation valves is not subjected to the steam environment. The system is ambient beyond the outside isolation valve. [ Reference 1. Attachment 6s and 7s] The normal operation of the Nitrogen System is such that system corrosion is not a problem since the system normally contains dry nitrogen. The potential for corrosion is introduced only for a short duration in each refueling cycle during testing of the system when testing air is used. [ Reference 1, Attachment 6s and 7s] Discoverv: The effects of corrosion on system components can be discovered and monitored through non-destructive examination techniques such as visual inspections, inspections at susceptible locations can be used to assess the need for additional inspections at less susceptible locations. Based on piping / component geometry and fluid flow conditions, areas most likely to experience corrosion can be detennined and evaluated. The inspections must be performed on a frequency that is sufficient to ensure that minimum wall thickness requirements will be met until at least the next examination is performed (e.g., as part of periodic crosion corrosion inspections or normal PM). [ Reference 1, Attachment 8] Group 1 (crevice corrosion, general corrosion, and pitting for all d'evice types) - Aging h1anagement Program (s) Mitigation: The CCNPP Chemistry Program has been established to: minimize impurity ingress to plant systems; reduce corrosion product generation, transport, and deposition; reduce collective radiation exposure through chemistry; improve integrity and availability of plant systems; and extend component and plant life. [ Reference 22, Section 6.1.A] The scope of the Secondary Chemistry Program procedure, Application for License Renewal 5.12 21 Calvert Cliffs Nuclear Power Plant
ATTACllMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS CP 217, " Specifications and Surveillance for Secondary Chemistry," (Reference 23], which controls Feedwater System chemistry, includes the SGs, condensate storage tanks, feedwater, condensate, the Main Steam System, heater drain tanks, condensate demineralizer emuent, SG blowdown ion exchanger emuent, and condensate precoat filters. [ Reference 23, Section 2.C] The program is based on References 24 through 30. The Secondary Chemistry Program controls fluid chemistry Iri order to minimize the concentration of corrosive impurities (chlorides, sulfates, oxygen) and optimizes 11ild pil. Control of secondary fluid chemistry minimizes the corrosive environment for Main Steam Systtm components, and limits the rate and effects of corrosion. [ Reference 1. Attachment 8] The rate of corMon is also reduced by the initial buildup of the passive magneti'c oxide layer that minirnizes bare metal exposure to water. [ Reference 1 Attachment 6s] Secondary chemistry parameters are measured at procedurally specified frequencies, ne measured parameter values are compared against " target" values which represent a goal or predetermined warning limit. If a measured value is outside of its required range, corrective actions are taken (e.g., power reduction, plant shutdown) in accordance with CP 217. Remedial actions are specified to minimize corrosion degradation of components and to ensure that secondary system integrity is maintained. [ Reference 23, Sec. 6.0 and 2.C] In conformance with the plant Technical Specifications, the plant is expected to be operated in a manner such that the secondary coolant chemistry parameters will be maintained within those limits that result in negligible corrosion of the SG tubes. To assure this goal is met, the Secondary Chemistry Program has the target and action values based on chemistry guidelines provided by Electric Power Research Institute (EPRI), institute for Nuclear Power Operations (INPO), and the CCNPP Nuclear Steam Supply System vendor. These values ensure a timely response to chemical and radiochemical excursions with appropriate corrective actions. [ Reference 23] The Chemistry Program is subject to internal assessment activity both within the CCNPP Chemistry Section and through the site performance assessment group. This maintains highly effectise secondary chemistry controls and aggressively pursues continuous improvements by monitoring industry initiatives and trends in the area of secondary systems corrosion control. He program is also subject to frequent external assessments by INPO, NRC, and others. The operating experience review for the CCNPP Chemistry Program identified no site specific problems or events related to these aging mechanisms that required significant changes or adjustments to the program. It has been effective in its function of minimizing corrosion and preventing corrosion related , failures and problems. The main focus of the program is SG chemistry, it has been demonstrated that as long as SG chemistry is carefully monitored-and controlled, the other secondary systems are also ' successfully controlled. CCNPP has been proactive in making programmatic changes to the secondary chemistry prograrn over its history, largely in response to developments within the industry, such as successful experimentation with a new alternate amine. For the non regenerative SG blowdown heat exchangers and the SG blowdown radiation monitor coolers, credit is also taken for CCNPP Technical Procedure CP 206, " Specifications and Surveillance Application for License Renewal 5.12 22 Calvert Cliffs Nuclear Power Plant g
NLTACIIMrNT (4) q APPENDIX A - TECllNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN , STEAM, EXTRAC AND NITROGEN ANDllVDROGEN SYSTEMS for Component Cooling / Service Water Systems."
~ ' [ Reference 31]
and CCW System (SG blowdown radiation monitor c ea exchangers) e concentrations of the amount of oxygen in the water which aids in the preven razine to minimize degradation. [ Reference 32, Attachment 8] mechanisms. Continu p p ng or component Calvert Cliffs procedure CP 206 describes the surveillance and specification f System fluid. CP 206 lists the parameters to smonitor, or monitoring the the SRWfrequency of mon the target and action levels for the SRW System fluid . parameters g ese parameters, and [Ref erence 31. Attachment 1] These chemistry parameters are currently monitored on a frequency rangin ree times per week to once a month. All of the parameters listed in CP 206 currently have target values t range or limit for the associated parameter. Two of, ave theaction parameters, levels pil and hy l associated with them. For pil, the current action level is less than 9 0 or greate the current action level is less than 5 or greater than 25forparts p i an 9.8, hydrazine Attachment 1] er million (ppm). [ Reference 31, { Operational experience relited to CP 206 has shown no problems related to th with respect to the CCW System. In 1996, CP 206 e use ofwas e revised to include dis this procedure parameter to act as a method for the discovery of any unusual corrosion of ron as a chemistry ents. System chemistry as excellent. Action levels for all fo and 2 CCW/SRW major system changes during the 1996 ered were refueling due to outage have been made to determine outage evolutions that orrectcan affect the CCW/SRW this condition to prevent chemuoy targets being exceeded. [ Reference 33] and take action c emistry The SRW System usually operates within normal parameters except when the outage lay up. During an outage lay up, the SRW System experiences some misys I internal component surfaces are exposed to air. After the when nor corrosion SRW the System is once again established, some of this minor corrosion is remowd from the pipe inne into the system where it is detected. it was discovered surfacethat and releasedsuspended header is taken out of service for heat exchanger cleaning and total system f the in service heat exchanger. suspended solids levels drop to the normal . e erence 33] value ofless than 1 that steps can be taken to return chemistry crevice corrosion / pitting. em chemistry parameters parameters so to n s, and thus minimize the efTects of
' Application for License Renewal 5.12 23 Calvert Cliffs Nuclear Power Plant
O ATTACHh1ENT (4) l l APPENDIX A TECHNICAL INFORMATION i 5.12 MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS l For the hand valves in the Chemical Addition System (03511%02), credit has been taken for CP 202, i Specifications and Surveillance - Demineralized Water, Safety Related Battery Water, Well Water Systems, and Acceptance Criteria for On Line Monitors. CP 202, has been established to: Minimize impurity ingress to plant systems; Reduce corrosion product generation, transport, and deposition; Improve integrity and availability of plant systems; and Extend component and plant life (Reference 22, Section 6.1.A] ne Demineralized Water Chemistry Program is applicable to the Demineralized Water and Well Water Systems for use in primary, auxillary, and secondary plant systems. It also specifies the requirements for dedicating demineralized water for the use in safety related batteries and acceptar.cc criteria for on line monitors. { Reference 34, Section 2] He program is based on the following: CCNPP Procedure CP-4 M, Make-Up Demineralir.ed Water System; EPRI !?P 6377 SL, Volume 2, Guidelines for the Design and Operation of Make-up Water Treatment Systems, Final Report, June 1989; INPO 88-021, Guidelines for Chemistry of Nuclear Power Stations, Revision 1, September 1989; EPRI TR 105714, Primary Water Chemistry Guidelines, Revision 3, November 1995; Combustion Engineering Manual CENPD 28, " Combustion Engineering Chemistry Manual," Revision 3, September 1982; and State Water Appropriation Permit No. CA690010. The Demineralized Water Chemistry Program controls fluid chemistry in order to minimize the concentration of corrosive impurities and optimizes specific conductivity. Control of fluid chemistry prevents a corrosive environment for the Chemical Addition System hand valves and limits the rate and effects of crevice corrosion, general corrosio. and pitting corrosion. (Reference 1. Attachment 8] The demineralized water chemistry parameters are measured at procedurally-specified frequencies. The measured parameter values are compared against target values that represent a goal or predetermined warning limit. If a measured value is outside the specified range, special, and/or general corrective actions (such as resampling, increased surveillance frequency, and/or technical evaluation) are taken as prescribed by CP-202. [ Reference 34, Section 6.0] The corrective actions taken will ensure that Chemical Addition System hand valves subject to crevice corrosion, general corrosion, and pitting remain capable of performing their intended functions under all Cl.D conditions. The Demineralized Water Chemistry Program is subject to internal assessment activity both within the CCNPP Chemistry Section and through the site performance assessment group. The program is recognized through these assessments as maintaining highly effective secondary chemistry controls, and aggressively pursuing continuous improvements through monitoring industry initiatives and trends in the area of secondary systems corrosion control. The program is also subject to frequent external assessments by INPO, NRC, and others. Application for License Renewal 5.12-24 Calvert Cliffs Nuclear Power Plant
g[TACHMENT t4) APPENDIX A TECHNICAL INFORh1ATION 5.12 MAIN STEAM, STEAM GENERATOR HLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS The CP 202 program, since its inception, has essentially remained unchanged ar.d has performed well. The changes in the limits of chemistry parameters are reflective of upgrades in the capability of measuring instruments and experience gained over the years. Operating experience, relative to the CP-202 Program at CCNPP, has been such that no site specluc problems or events are known to have occurred that required significant changes or adjustments to the program, it has been effective in its function of preventing corrosion and corrosion related failures and problems. (ReTerence 35] The quality of the air to Instrument Air System components that are within scope is periodically verified, in accordance with Checklists IPM10000 and IPM10001, per system repetitive tasks under the Plant PM Program discussed in the following Discovery section. These checklists assure that the system is being maintained in accordance with industry standards for moisture (dewpoint) and particulate contamination. [ Reference 1, Attachment 8] Discovem For non stagnant areas where local fluid chemistry will not differ significantly from the system bulk fluid chemistry, general corrosion will result in wall thinning over a relatively large area. The wall thickness of all main steam piping, where this applies, is monitored as part of the Erosion Corrosion Program, and is thereby managed for the efTects of general corrosion. Erosion corrosion is discussed in detail later in the section on Group 3, The effects of general corrosion in the main steam and blowdown valves can be evaluated through the erosion corrosion inspections of a representative sample of components to determine the extent of corrosion. [ Reference 1) For Main Steam or Extraction Steam components in stagnant or crevice areas, localized corrosion, i.e., crevice corrosion and pitting, can be readily detected through non-destructive examination techniques.
'This type of corrosion occurs over a long period of time prior to any threat of minimum wall thickness reaching an unacceptable value. As such, an inspection program to identify occurrence of localized corrosion is an effective means of determining if corrective actions are required for managing this aging mechanism. [ Reference 1]
All components susceptible to general, crevice, and pitting corrosion within the scope of this section of the BGE LRA, with the exception of the MSlVs, will be included in a new plant program to accomplish the needed inspections for general corrosion. This program is considered an Age-Related Degradation inspection (ARDI) Program as defint., in the CCNPP IPA Methodology presented in Section 2.0. The elements of the ARDI Program will include:
- Determination of the examination sample size based on plausible aging effects;
- Identification of inspection locations in the system / component based on plausible aging effects and consequences ofloss of component intended function;
- Determination of examination techniques (including acceptance criteria) that would be effective, conddering the aging effects for which the component is examined;
- Methods for interpretation of examination results; Application for License Renewal 5.12 25 Calvert Cliffs Nuclear Power Plant
A1TACHMENT (4) APPENDIX A - TECilNICAL INFORMATION 5.12 . MAIN STEAM, STEAM GENERATOR HLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND llYDROGEN SYSTEMS Methods for resolution of unacceptable examination Ondings, including consideration of all design loadings required by the CLB, and speelucation of required corrective actions; and Evaluation of the need for follow up examinations to monitor the progression of any age related degradation. The corrective actions will be taken in accordance with the CCNPP Corrective Action Program, end will ensure that the components will remain capable of performing the system pressure boundary imegrity function under all CLB conditions. Main steam isolation valves are periodically inspected as part of the plant's PM Program. There are specinc PM activities (Repetitive Tasks 10832098 and 99 and 20832089 and 90, for the Units 1 and 2
- ' MSIVs, respectively) for each of the MSIVs that require the periodic disassembly and inspection of these 1 valves, per the requirements of procedure MSIV 04. These regularly scheduled inspections would result in the detection of the iffects of degradation such that corrective action would be taken. [ Reference 1 Attachment 8; References 36 and 37]
l The PM Program has been established to maintain plant equipment, structures, systems, and components ! in a reliable condition for normal operation and emergency use, minimize equipment failure, and extend i equipment and plant life. The program covers all PM activities for nuclear power plant structures and equipment within the plant. [ Reference 38] It is based on INPO documents. [ References 39 through 41] The PM Program undergoes periodic evaluation by the NRC during Plant Performance Reviews which serve as inputs to the NRC Systematic Assessment of Licensee Performance and senior management meeting reviews. The plant Maintenance Program itself has numerous levels of management review, all the way down to the specine implementation procedures. Preventive Maintenance Program evaluation and any resultant upgrades are primarily based on equipment trends. [ Reference 42] These controls provide reasonable assurance that the PM Program will continue to be an effective method of managing the effects of general corrosion, erosion corrosion, and wear, as applicable, for the MSIVs and Instrument Air System components included in the scope of this section of the BGE LRA. 4 Group 1 (crevice corrosion, general corrosion, and pitting for all device types) - Demonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to crevice corrosion, general corrosion, and pitting of Feedwater System components:
- The Main Steam Extractior steam, and Nitrogen System components, as well as the other Feedwater, Chemical and Volume Control System, and Chemical Addition System components included in the scope of this section of the BGE LRA, provide a system pressure-retaining boundary function and their integrity must be maintained under CLB design conditions.
- Crevice corrosion, general corrosion, and pitting are plausible for the components and result in material loss which, ifleft unmanaged, can lead to loe af piessure-retalning boundary integrity.
- The rate of attack is affected by the local Huld chemistry, but the CCNPP Secondary Chemistry Program (and SRW System Program for the non regenerative SG blowdown heat exchangers and
- Application for License Renewal 5.12 26 Calvert Clifts Nuclear Power Plant
ATTACllMI'NT (4) j APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS radiation monitor cooiers, as well as the Demineralized Water System Program for the Chemical Addition System hand valves) p;ovides controls for system bulk Huld chemistry in order to mitigate the overall effects of corrosion; however, localized corrosion (crevice corrosion and l pitting) may be more prevalent than general corrosion in areas of low How velocity and in l crevices. Wall thickness inspections for crosion corrosion, discussed in the erosion corrosion section of this report, will monitor general and localized corrosion mechanisms in areas subject to high Dow for the applicable piping and components. Predictions of wall thickness based on erosion corrosion may not be conservative for localized corrosion in stagnant and low flow areas and should not be relied upon solely for detection. Elements of the PM Program provide for the periodic inspection and maintenance of the MSIVs and for the maintenance of the applica* ole portions of the Instrument Air System in accordance with industry standards. To provide additional assurance that localized corrosion is not signl0 cant in stagnant and low Dow areas, the in scope components will be included in an ARDI Program, inspections will be performed and appropriate corrective action will be taken if significant corrosion is discovered. There is, therefore, reasonable assurance that the effects of crevice corrosion, general corrosion, and pitting of Main Steam, Extraction Steam, and Nitrogen System components, as well as the other Feedwater, Chemical and Volume Control System, and Chemical Addition System components, within the scope of this section of the BGE LRA, will be managed in such a way as to maintain the components' pressure boundary integrity, consistent with the CLD, during the period of extended operation. 4 Group 2 (erosion corrosion and entitation erosion of piping and erosion corrosion of check valves, 4 control valves, flow orifices, hand vahes, heat exchangers, and MOVs) - Materials and Env!ronment: The components and materials affected by erosion corrosion an vin steam piping; the main steam drains piping; the SO blowdown piping; the non regenerative Su tm.vdown heat exchanger tubesheets and tubesheet nozzle necks, heads, and Danges; the inlet and safe ends of the SG flow venturis; main steam drain check valves; main steam to AFW pump check valves; main steam to AFW pump isolation control valves; hand valves for the main steam atmospheric dump valves and the steam supply to the AFW pumps; and the main steam drain MOVs All of these components are fabricated of carbon steel. [ Reference 1, Attachment 4s,6s, and 7s] In addition to these components, the following additional components are affected: the Main Steam System atmospheric dump valves, which are carbon stect with stainless steel stems, seats, and plugs; and the MSIVs, which are carbon steel with stellited seating surfaces. These valves and the indicated non-carbon steel subcomponents are potentially affected by erosion corrosion. (Reference 1, Attachment 4s,'6s, and 7s] Application for License Renewal 5.12 27 Calvert Cliffs Nuclear Power Plant
ATTACHMrNT (4) l APPENDlX A TECHNICAL INFORMATION 5.!2 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM. AND NITROGEN AND HYDROGEN SYSTEMS i ' ne SO blowdown piping, in addition to being affected by erosion corrosion is also affected by cavitation erosion. He SO blowdown valves have been evaluated for this mechr . ism with the erosion corrosion mechanism. [ Reference 1. Attachment 6s,7s, and 8] The environment discussion for Group 1 also applies to the systems / components included for this group. Group 2 (erosion corrosion and envitation erosion of piping and erosion corrosion of check valves, control valves, flow orifices, hand valves, heat exchangers, and MOVs) . Aging Mechanism Effects Erosion corrosion is an increase in the rate of attack of a metal because of the relative movement between a corrosive fluid and a metal surface. Mechanical wear or abrasion can result. nc Ould movement or turbulence accelerates corrosion by continually eroding the protective surface film as it forms, resulting in chemical attack or dissolution of the underlying metal. The occurrence of crosion corrosion is highly dependent on construction material and fluid now conditions. Carbon and low alloy , steels are particularly susceptible when subjected to a high velocity, turbulent flow (single or two phase) of water with low oxygen content and a pil less than 9.3. Erosion corrosion can result in material loss in areas that are subject to disturbances in the flowstream, such as those caused by bends, tees, valves, thermowells, pumps, and localized internal surface irregularities his process can result in significant wall thickness reduction in a period of time much shorter than the period of extended operation, especially for carbon steel. Erosion corrosion can reduce the component wall thickness and result in grooves, gullies, waves, holes, and valleys on the metal surface. [ Reference 1. Attachment 6s and 7s] If left unmanaged, it could result in the loss of the pressure boundary function under CLB design loading conditions. Cavitation erosion is similar to crosion corrosion; however, the attack on the protective passive layer is caused by the formation and collap 3 of vapor bubbles located in close proximity to the material surface. This mechanism requires Guid now and pressure variations that temporarily drop the liquid pressure below its vapor pressure. [ Reference 1, Attachment 6s and 7s] Group 2 (erosion corrosion and cavitation erosion of piping and erosion corrosion of check valves, control valves, flow orifices, hand valves, heat exchangers, and MOVs) . Methods to Manage Aging Mitlantion: The effects of erosion corrosion can be mitigated by selecting crosion corrosion resistant materials and maintaining optimal fluid chemistry conditions. Carbon or low alloy stects are particularly susceptible when they are in contact with high velocity turbulent flow (single or two phase) of water with low oxygen content and a pH less than 9.3. The oxygen levels are so low that there is insufficient oxygen present to refctm the passive magnetite layer once it is stripped away. The original piping design took materials of corstruction and crosion and corrosion allowances into consideration. As the plant is operated, fluid chemistry parameters, such as dissolved oxygen concentration and Guid pil level, can be controlled to minimize the effects of erosion corrosion. [ Reference 1, Attachment 7a and 8] The effects of cavitation crosion can be managed through material selection and inspections of the piping / components. [ Reference 1, Attachment 7s and 8) Application for License Renewal 5.12 28 Calvert Cliffs Nuclear Power Plant
_ _ --. . .- -. - - - _ . = __- -- - _ _ - - . - .. A1TACilMENT (q APPENDIX A TECHNICAL INFORhfATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS Discoverv: The effects of erosion corrosion or cavitation crosion on system components can be discovered through measurement and monitoring of wall thickness and/or through visual inspections. De results of measurements and inspections at susceptible locations can be used to assess the need for measurements and inspections at less susceptible locations. Based on piping geometry and Guld flow conditions, areas of the system most likely to experience crosion corrosion can be determined and evaluated. The measurements and inspections must be perfonned on a fregeency that is sumcient to ensure that minimum wall thickness requirements will be met until at least the next examination is performed. (Reference 1. Attachment 8; Reference 35] Group 2 (crosion corrosion and cavitation erosion of piping and erosion corrosion of check valves, control valves, flow oriflees, hand valves, heat exchangers, and MOVs) . Aging Management Programs Mitigation: The CCNPP Secondary Chemistry Program, discussed in Group i for general and local corrosion, specifically considers crosion corrosian. The limits for impurity concentration and fluid pit are set to minimize crosion corrosion while also minimizing other forms of corrosion in the secondary system. This program is credited for the mitigation of all components subject to erosion corrosion included under this group discussion. The SRW System Chemistry Program, discussed under Group 1, also provides mitigation for the SRW side of the non-regenerative SG blowdown heat exchangers. Discoverv: He CCNPP Erosion Corrosion Program was implemented formally in 1984 afler the failure of extraction steam piping at CCNPP. The program is intended to ensure nuclear and personnel safety by early identification and prevention of secondary pipe wall thinning caused by accelerated corrosion, cavitation, or crosion that could lead to ruptures in high energy piping. All of the main steam related piping addressed in the system AMR (main steam headers, main steam to the AFW pumps, main steam drains, and SG blowdown) is included in this program. The program is based on EPRI and NRC documents, References 43 through 45 [ Reference 35] All piping within the scope of the program is evaluated and categorized to determine inspection points where thickness measurements will be taken, inspection points are determined primarily based on the results of the previous inspections and the erosion trends that are discovered as the data collected grows. The CHECKWORK software developed by EPRI is used as a backup for identifying inspection points and supplements CCNPP site specific information where appropriate. An ultrasonic non-destructive examination is used to determine the wall thickness at a number of grid locations for each inspection point, nese data are used with a predictive model to determine additional inspection points, to adjust an inspection point's priority, or to estimate the time remaining before an inspection point's wall thickness reaches the minimum allowable. The results are then analyzed to determine the need to repair or replace components. [ Reference 35] Class 11 piping has predetermined minimum wall thickness values that are based on the allowable stresses as addressed m the original design code ANSI B31.7. ANSI B31.7 refers to ANSI B31.1 for Class 11 piping design criteria, which includes an additional thickness allowance to compensate for Application for License Renewal 5.12 29 Calvert Clifts Nuclear Power Plant
NITACIIMENT (O l i APPENDIX A . TECHNICAL INFORMATION 5.12 - AIAIN STEAM. STEAM GENERATOR BLOWDOWN. EXTRACTION STEAM, i AND Nil'ROGEN ANDllYDROGEN SYSTEMS l crosion and other mechanical considers 'ns. His additional thickness value is specified by Design Engineering at CCNPP. [ Reference 15] Inspection data is tracked and extrapolated to estimate the time until the minimum wall thickness will be reached. When an inspection point is estimated to be within 48 to 72 months of the minimum wall thickness, it is placed on a " Yellow Alert." When an inspection point is estimated to be within 24 to 48 months of minimum wall thickness, it is placed on a " Red Alent." When an inspection point is or is 4 estimated to be within 24 months of the required minimum thickness, it is classified as " Unsatisfactory." If any of the alert values are reached, corrective actions are initiated in accordance with the inspection procedure and the Corrective Action Program. [ Reference 35)
)
Daltimore Gas and Electric Company has been proactive in the management of crosion corrosion at CCNPP. The Erosion Corrosion Program was started formally in 1984 after the failure of non safety related extraction steam piping, prior to the 1986 feedwater break incident at Surry Power Station. Prior to initiation of the formal program, periodic ultrasonic testing inspections were being performed on a less formal basis, ne program has undergone modifications based on industry experience. For example, CCNPP is a member of the CIIECKWORK Users group, which is an industry organization that shares industry information and provides training on methods and technology. CilECKWORK software provides a systematic method for identifying locations that theoretically are particularly susceptible to i erosion corrosion, and for documenting and tracking the inspection results. His software has been ! updated to reflect current knowledge and experience. The NRC periodically performs an inspection and review of the Erosion Corrosion Program. In the past, site visits included the use of the NRC's own examination equipment to verify data that was collected by CCNPP Erosion Corrosion Program personnel. He inspections are followed by a formal report of the results, in the past, the NRC has made recommendations that CCNPP has incorporated to improve the program. [ Reference 46] Other assessments include those performed by INPO and by the CCNPP Nuclear Performance Assessment Department. Institute for Nuclear Power Operations performs periodic independent assessments and provides recommended enhancements based on good practices utilized in the industy. [Referenen7] Internal reviews have been performed by the CCNPP Nuclear Performance Assessment Department several times in the past in accordance with 10 CFR, Part $0, Appendix D criteria. All of these controls provide reasonable assurance that the Erosion Corrosion Program will continue to be an effective method of monitoring the effects of crosion corrosion on the piping, and ensuring that corrective actions are taken prior to a piping section reaching its minimum allowable wall thickness. Regarding operating experience, CCNPP had experienced piping failures in the past that were documented in Licensee Event Reports to the NRC, Since the extraction steam system failures and the inception of the formal erosion corrosion program, there have been no further major failures. He data collected during the inspections has served to build an extensive data base for piping system evaluations. The ARDI Program, discussed under Group 1, is also credited for all of the components affected by erosion corrosion (and the SG blowdown piping / valves affected by cavitation erosion), with the Application for License Renewal 5.1240 Calvert Cliffs Nuclear Power Plant
ArrACHMENT (4) APPENDIX A TECllNICAL INFORMATION 5.12 MAIN STEAM, STEAM GENERATOR HLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND HYDROGEN SYSTEMS exception of the piping included under the Esosion Corrosion Program and the main steam MSIVs. [ Reference 1, Attachment 8] ne MSIV specific repetitive tasks of the PM Program, also discussed under Group 1, are credited for the discovery of the effects of erosion corrosion for these valves. [ References 36 and 37]
~
Group 2 (erosion corrosion and envitation erosion of piping and erosion corrosions of check valves, control valves, flow orifices, hand valves, heat exchangers, and MOVs) Demonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to erosion corrosion of the applicable Main Steam System piping and components: The Main Steam System components and related p9ing provide the system pressure retaining boundary and their integrity mutt be maintained under all CLB design conditions. Erosion corrosion is plausible for the subject components and piping (as well as cavitation crosion for the 50 blowdown piping) and may result in wall thinning, which, if left um.anaged, can lead to loss of pressure retaining boundary integrity. J The CCNPP Chemistry Program provides controls for system fluid chemistry in order to minimize the efTects of erosion corrosion (via both the Secondary Chemistry Program for all components and the SRW System Chemistry Program for the SRW side of the non regenerative
- 50 blowdown heat exchangers), While degradation is not entirely prevented, the rate and, therefore, the predictions of when minimum wall thickness will be reached are related to the system chemistry.
I The CCNPP Erosion Corrosion Program monitors the effects of crosion corrosion on specific Main Steam System piping through mecsurement of pipe wall thickness on a frequency dependent upon the rate of degradation. The program requires the performance of corrective 1 actions before a pipe wall thins to below the minimum required wall thickness established by the original construction code. Periodic inspections of the MSIW are performed in accordance with Repetitive Tasks 10832098, 10832099,20832039, and 20832090 of the PM Program, and procedure MSIV 04 [ Reference 37] to monitor valve degradation. To ensure that all components not covered by the Erosion Corrosion Program or the PM Program are being managed for crosion corrosion, they will be included in the scope of an ARDI Program. Inspections will be performed, and appropriate corrective action will be taken if significant degradation is encountered. There is, therefore, reasonable assurance that the effects of erosion corrosion and cavitation erosion will be managed to maintain the Main Steam System components' pressure boundary integrity under all design loadings, required by the CLB, during the period of extended operation. Application for License Renewal 5.12 31 Calvert Clifts Nuclear Power Plant
l A1TACDMENT.Jd) APPE& 4 A - TECilNICAL INFORh1ATION 5.12 h1AIN STEAh!, STEAal GENERATOR HLOWDOWN, EXTRACT;ON STEAh!, l AND NITROGEN ANDIIYDROGEN SYSTEhtS l Group 3 (selective leaching of the SG blowdown radiation monitor cooler) - hinterials and l Environment The only component affected by this ARDh1 is the SO Blowdown radiation monitor cooler, which has: I { A yellow brass, ASThi B135, shell; l A red brass, ASThi D36, tube sheet and bafiles;
- A forged brass, ASThi B283, hub; and
+
A gray cast iron, ASThi A278, bonnet, ne shell, hub, and bonnet of the cooler are susceptible to selective leaching. Red brass is only 15% zinc and is sign 10cantly less susceptible than the other materials. The shell side environment is SG blowdown, which could be a two phase mixture of steam and water upon entry into the cooler. The tube side environment is CCW System water. [ Reference 48] Group 3 (selective leaching of the SG blowdown radiation monitor cooler) . Aging hiechanism Effects: Selective teaching is the removal of one element from a solid alloy by corrosion processes. The environmental conditione that are normally required for this ARDh1 are high temperature, stagnant aqueous solution, an.i porous inorganic scale. Acidic solutions and oxygen aggravate the mechanism. With this mechn. ism, the overall dimensions of the component do not change. The voldr left by the teaching of the vulnerable element, which are often obstructed from view by debris or surface deposits, can lead to sudden unexpected failure due to the poor strength of the remaining material. The most common example of selective teaching is "dezincincation," or the removal of zinc, from brass alloys. %ere are the " layer type" and " plug type" submechanisms of dezinciGcation. The layer type mechanism is a uniform attack, whereas the plug-type is extremely localized and leads to pitting. Cast iron is also susceptible to a selective teaching process called " graphitic corrosion" by which the iron or steel matrix is stripped from the graphite network leaving a matrix of graphite, volds and rust. [ Reference 1, Attachment 7 for llent Exchangers; Reference 48] Group 3 (selective leaching of the SG blowdown radiatioh monitor cooler)- hiethods to hianage Aging: Mitiption: Since oxygen content, pH, and the production of scale are significant contributors to the selective leaching process, it can be mitigated for the materials in this cooler through chemistry control of the Guids flowing through it. All three of these P.u!d properties can be managed through chemical addition to the fluid systems. Discoverv: De presence of damage from selective leaching can be detected via visual inspection of ti.e potentially affected subcomponents. The removal of any surface scale on the material will reveal the effects of the selective teaching process ifit is occurring. [ Reference 48] Application for License Renewal 5.12 32 Calvert Cliffs Nuclear Power Plant
ATTACHMENT.(d) APPENDIX A - TECHNICAL INFORMATION 5.12 i MAIN STEAM STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, l AND NITROGEN AND HYDROGl;N SYSTEMS Group 3 (selective leaching of the SG blowdown radiation monitor cooler)- Aging Management Programs: Mitiption: The r. elective leaching process will be effectively mitigated by the Component Cooling /SRW System Chemistry Program (CP 206) and the Secondary Chemistry Program (CP 217) that have been previously described under the Group i Aging Management Program discussions. Discoverv: These coolers will be added to the ARDI Program for the performance of visual inspections. This program is also described under the Group 1 Aging Management Program discussions. Group 3 (selective leaching of the SG blowdown radiation monitor cooler) - Demonstration of Aging Management: Based on the factors presented above, the following conclusions can be reached with respect to the selective leaching of SO blowdown radiation monitor cooler subcomponents:
'The cooler subcomponents provide a system pressure retaining boundary for the safety related CCW System and their integrity must be maintained under all CLB design conditions.
Selective leaching of the cooler subcomponent surfaces is plausible for the wolers such that surface deterioration may result wHeh, if left unmanaged, could lead to loss of th: coolers' l pressure-retalning integrity. Maintenance of CCW chemistry (CP 206) and secondary system chemistry (CP 217) provides a I means of mitigation of the selecting leaching ARDM for the SO blowdown radiation monitor coolers. To ensure that all subcomponent surfaces of the coolers are being managed for selective leaching, they will be included in the scope of an ARDI Program. Inspections will be performed, and appropriate corrective action will be taken if significar. subcomponent surface degradation is encountered. There is, therefore, reasonable assurance that the effects of selective leaching will be -;mged to maintain the safety-related CCW System pressure boundary integrity within the SO blown wa r, diation monitor coolers under, all design loadings required by the CLB, during the period of extenda JJ eration. Group 4 (wear of control valves)- Materials and Environment: The only compomnts affected by this ARDM are the stainless steel seats and plugs of the steam atmospheric dump valves and the stellited carbon steel bodies and disc assemblics of the MSIVs. The environment for these vahc is the Main Steam System, as described under Group 1 above. [ Reference 1, Attachment 6s,7s, ano 8] Group 4 (wear of control valves)- Aging Mechanism Effects: Wear of the seating surfaces of the main steam atmospheric dump valves is plausible due to their contact under heavy load and their relative motion resulting from valve cycling. The valve stem is resistant to Application for License Renewal 5.12 33 Calvert Cliffs Nuclear Power Plant
ATTACitMENT (41 APPENDIX A - TECliNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR HLOWDOWN, EXTRACTION STEAM, AND NITROGEN ANDIIYDROGEN SYSTEMS l l
\
I wear and is not subject to relative motion that would cause wear. In the MSIVs, wear may occur ! between the piston assembly and the body in the bore area; but, since this is not the major pressure- { retalning section of the valve (i.e., not the disc and seat), this wear is insufficient to affect the pressure I boundary function. Wear of the seating surfaces between the body (the seat) and disc assembly is plausible due to contact under heavy load and relative motion. The aging effect for these valves as a result of wear is the loss of the pressure-retaining capability of the mating surfaces within the valves. [ Reference 1, Attachment 6s,7s, and 8] Group 4 (wear of control valves)- Methods to Manage Aging: Mitigation: There is no available mitigation methodology for this mechanism. The use of stellited surfaces in the MSIVs minimizes the effects of seating surface wear. [ Reference 1 Attachment 6s,7s, and 8] ! Discoverv: This mechanism can be detected via the periodle inspection of the valves for degraded seating surface conditions. [ Reference 1, Attachment 5s,7s, and 8] Group 4 (went of control valves) . Aging Management Programs: Mitigation: There is no mitigation program credited for this ARDM. [ Reference 1. Attachment 6s,7s, 4 and8] Discoverv: The atmospheric dump valves and their internals are to be included in the ARDI Program described under Group 1 above. The MSIVs and their internals are , criodically inspected as a function of specific repetitive tasks within the PM Program. These are also described under Group 1 above. [ Reference 1, Attachment 6s,7s, and 8] Group 4 (wear of control valves)- Demonstration of Aging Managementt ' Based on the factors presented above, the following conclusions can be reached with respect to the wear of the seating surfaces within tiie applicable control valves: The valve seating surfaces provide a system pressure-retaining boundary and their integrity must be maintained under all CLB design conditions. Wear of the seating surfaces is plausible for the subject valves that may result in surface deterioration vthich, if left unmanaged, could lead to loss of the valves' pressure-retaining integrity. To ensure that all the seating surfaces of the atmospheric dump valves are being managed for wear, they will be included in the scope of an ARDI Program. Inspections will be performed, and appropriate corrective action will be taken if significant seating surface degradation is encountered. The seating surfaces of the MSIVs are managed for wear as a result of the repetitive tasks under the plant's PM Program that require the periodic disassembly of these valves for inspection of the valve internals (MSIV 04). Application for License Renewal 5.12 34 Calvert Cliffs Nuclear Power Plant
1 ATTACllMEN1 (4) APPENDIX A TECIINICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM. AND NITROGEN ANDIIYDROGEN SYSTEMS There is, therefore, rersonable assurance that the effects of control valve wear will be managed to maintain the Main Steam System components pressure boundary integrity under all design loadings required by the CLD during the period of extended operation. 5.12. Conclusion The programs discussed for the Main Steam, Extraction Steam, and Nitrogen Systems are listed in Table 5.12 5. These programs are (and will be for new programs) administratively controlled by a formal review and approval process. As has been demonstrated in the above section, these programs will manage the aging mechanisms and their effects such that the intended functions of the components of the applicable systems will be maintained, consistent with the CLD, during the period of extended operation. The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL 2, " Corrective Actions Program." QL-2 is pursuant to 10 CFR Pan 50, Appendix H, and covers all structures and components subject to AMR. Application for License Renewal 5.12-35 Calvert Cliffs Nuclear Power Plant
ATTACllMENT (4) APPENDIX A - TECIINICAL INFORMATION { 5.17 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, l AND NITROGEN ANDIIYDROGEN SYSTEMS TABl.E 5.12 5 LIST OF AGING MANAGEMENT PROGRAMS FOR Tile MAIN STEAM, EXTRACTION STEAM, AND NITROGEN SYSTEMS STATUS 7 PROGRAM CREDITED AS Existing CCNPP Chemistry Program Mitigating the effects of crevice corrosion, general ' Procedure CP 202, corrosion, and pitting of the Chemical Addition System i
" Specifications and Surveillance components that interface with the SGs (Group l),
for Demineralized Water, Safety Related Battery Water, Well Water Systems, and Acceptance Criteria for On-Line Monitors" Existing CCNPP Erosion Corrosion Detecting and managing the effects of crosion corrosion of Program Procedure MN 3 202, Main Steam and SG Blowdown System components as well
" Erosion / Corrosion Monitoring of as the general corrosion, crevice corrosion, and pitting of Secondary Piping" the same piping inspected as part of this program (Groups 1 and 2).
Existing CCNPP Chemistry Program j Mitigating the effects of crevice corrosion, general Procedure CP 206, corrosion, and pitting on the SRW side of the
" Specifications and Surveillance non-regenerative SG blowdown heat exchanger and the SG for Component Cooling / Service blowdown radiation monitor cooler (Groups I and 2), as Water Systems" well r.s the selective leaching of the subcomponents in the SG blowdown radiation monitor cooler (Group 3).
Existing CCNPP Chemistry Program Mitigating the effects of crevice corrosion, general Procedure CP 217, corrosion, pitting (Group 1), erosion corrosion (Group 2),
" Specifications and Surveillance and wear (Group 4) of Main Steam and SG Blowdown 4 for Secondary Systems" System components, and the general corrosion of Nitrogen System piping and components that interface with the SGs via the blowdown lines (Group 1).
Existing MSIV-4; PM Repetitive Tasks Detecting and managing the effects of corrosion and wear 10832098,10P32099,20832089, within the MSIVs, and managing the effects of corrosion and 20832090;IPM10000 and within the applicable portions of the Instrument Air System IPM10001 that interface with the Main Steam System (Groups 1, 2, and 4). Existin;; MSIV 13,"MSIV Actuator Managing the efTects of aging of the MSIV actuators and Removal and installation" their related subcomponents (N/A to any group). New ARDI Program Detecting and managing the effects of all types of corrosion of applicable Main Steam, Extraction Steam, Nitrogen, SG Blowdown, Instrument Alt, Chemical and Volume Control, Main Feedwater, and Chemical Addition Systems' components, as well as wear of the atmospheric steam dump valves (Groups 1,2,3, and 4). Application for License Renewal 5.12-36 Calvert Cliffs Nuclear Power Plant
~ , l ATTACHMENT (4) ;
i { APPENDIX A TECilNICAL INFORMATION 5.12 i MAIN STEAM, STEAM GENERATOR HLOWDOWN, EXTRACTION STEAM, AND NITROGEN AND flYDROGEN SYSTEMS ! 5.12.4 References 1. CCNPP " Aging Management Review Report for the Main Steam System (083)," Revision 1 February 1997
- 2. "CCNPP Updated Final Safety Analysis Report," Revision 20 3.
" Component Level ITLR Screening Results for the Main Steam System, System No. 033,"
Revision 1, June 19,1996 4. CCNPP " Component Level ITLR Screening Results for the Extraction Steam System (#046)," Revision 0, April 6,1993 5. CCNPP "ITLR Screening Results for the Nitrogen System (#074)," Revision 0, November 12,1993 6. 60700S110001, " Main Steam and Reheat System Operations Drawing," Revision 37, December 3,1996 r 7. CCNPP Drawing 62-700-E Sil.1. " Main Steam and Reheat System Operations Drawing," Revision 40, January 26,1996
- 8. CCNPP Drawing 927678Ml31, "M 600 Piping Class Sheets," Revision 49, 1
November 12,1996 {
- 9. CCNPP Drawing 60712S110005, " Compressed Air System Instrument Air and Plant Air Operating Drawing," Revision 6, November 11,1996
- 10. CCNPP Draving 62712S110003, " Compressed Air System Instrument Air and Plant Air Operating Drawing," Revision 84, April 16,1997 11.
CCNPP Drawing 92767Sil llB 1,"M 600 Piping Class Sbeets," Revision 57, July 31,1996 12. CCNPP Drawing 60734S110003, " Reactor Coolant Waste Processing System Operating Drawing," Revision 31, January 16,1997
- 13. CCNPP Drawing 92767Sil-GB-1, "M 600 Piping Class Sheets," Revision 52, November 12,1996 14.
CCNPP Drawing 60726, " Nitrogen Generating and Blanket System Operating Drawing," Revision 48, October 8,1996 15. CCNPP Drawing 60740S110001, " Miscellaneous Steam Line Drainage Systems Operation Drawing," Revision 32, November 4,1996 16. CCNPP Drawing 62740S110001, " Miscellaneous Steam Line Drainage Systems Operation Drawing," Revision 35, October 8,1996 17. CCNPP Drawing 60583, " Auxiliary Feedwater System Operating Drawing," Revision 46, December 10,1996 18. CCNPP Drawing 62583, " Auxiliary Feedwater System Operating Drawing," Revision 45, April 20,1995 Application for Licenpe Renewal 5.12 37 Calvert Cliffs Nuclear Power Plant
AU)LCHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM. AND NITROGEN AND HYDROGEN SYSTEMS 19. CCNPP Drawing 60761," Steam Generator Blowdown Recovery System Operating Drawing" Revision 40, November 4,1996 20. CCNPP Procedure MSlV-13. "MSIV Actuator Removal and Installation," Revision 2, February 17,1997
- 21. CCNPP " Aging Management Review Report for Auxiliary Building," Revision 3 February 21,1997
- 22. CCNPP Administrative Procedure CH 1, " Chemistry Program," Revision 1 December 13,1995 23.
CCNPP Techn! cal Procedure CP-217. " Specifications and Surveillance - Secondary Chemistry," Revision 5, December 18,1995
- 24. INPO 88-021, " Guidelines for Chemistry at Nuclear Power Stations," Revision 1 September 1991
- 25. INPO 85 021," Control of Chemicals in Nuclear Power Plants," June 1985
- 26. EPRI NP 6239, 5405 2, "PWR Secondary Water Chemistry Guidelines," Final Report, Revision 2, December 1988
- 27. EPRI TR 102134, Projects 2493, 5401, "PWR Secondary Water Chemistry Guidelines," Final Report, Revision 3, May 1993
- 28. CENPD 28," Combustion Engineering Chemistry Manual," Revision 3, September 1982 l
- 29. ANSI N45.2.1, " Cleaning of Fluid Systems and Associated Components During the l Construction Phase of Nuclear Power Plants," February 26,1973
- 30. U. S. Nuclear Regulatory Guide 1.37," Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water Cooled Nuclear Power Plants," March 16,1973
- 31. CCNPP Technical Procedure CP-206, " Specifications and Surveillance Component Cooling / Service Water Systems," Revision 3, November 4,1996
- 32. CCNPP 1996 Component Cooting and Service Water Assessr.ent, Februay 26,1997
- 33. " Component Cooling System Aging Management Review," Revision 1, November 7,1996
- 34. CCNPP Technical Procedure CP-202," Specifications and Surveillance Demineralized Water, Safety Related Battery Water, Well Water Systems, and Acceptance Criteria for On Line Monitors," Revision 3, November 14,1995 35.
CCNPP Administrative Procedure MN 3 202, " Erosion / Corrosion Monitoring of Secondary Piping," Revision 1, July 1,1996 36. Repetitive Tasks 10832098,10832099, 20832089, and 20832090, "MSIV Inspections," Preventive Maintenance Program
- 37. CCNPP Procedure MSIV-4, " Disassembly and Assembly of MSIV," Revision 9, August 27,1991
- Application for License Renewal 5.12-38 Calvert Cliffs Nuclear Power Plant
.,o
ATTACHMENT (4) APPENDIX A - TECHNICAL INFORMATION 5.12 - MAIN STEAM, STEAM GENERATOR BLOWDOWN, EXTRACTION STEAM, AND NITROGEW AND HYDROGEN SYSTEMS
- 38. CCNPP Administrative Procedure MN.l.102," Preventive Maintenance Program," Revision 5 September 27,1996
- 39. INPO 85 032," Preventive Maintenance," December 1988
- 40. IhPO 85 037," Reliable Power Station Operation," October 1985
- 41. INPO Good Practice MA 319," Preventive Maintenance Program Enhancement," August 1980
- 42. CCNPP Engineering Standard ES-020 " Specialty input Screens for the Engineering Service Process," Revision 1, May 1,1996
- 43. " Metal Fatigue in Engineering." 11. O. Fuchs and R.1. Stephens, John W!!ey and Sons, Copyright 1980
- 44. EPRI NP.3944, " Erosion / Corrosion in Nuclear Plant Steam Piping: Causes and Inspection l Program Guidelines," April 1985
- 45. NRC Generic Letter 89 08," Erosion / Corrosion induced Pipe Wall Thinning," May 2,1989
- 46. Letter from Mr. G. C. Creel (BGE) to NRC Document Control Desk, dated February 26,1990,
" Implementation of the Erosion / Corrosion Program Controlling Procedure Generic Letter 89-08"
- 47. Letter from Mr. M. V. Ilodges (NRC) to Mr. G. C. Creel (BGE), dated April 9,1990,
" Inspection Reports 50-317/90 01 and 50-318/90 01," Inspection of Activities Related to Modification, Erosion Corrosion, and Inservice Activities
- 48. " Corrosion Engineering," Mars G. Fontana and Norbert D, Greene, M.Graw llill, Inc.,
Copyright 1967 Application for License Renewal 5.12 39 Calvert Cliffs Nuclear Power Plant __ . _ _ _ _ _ ._ -_ _ _ _ _}}