ML031210088
| ML031210088 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 04/28/2003 |
| From: | Baucom C Progress Energy Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| -nr, RNP-RA/03-0031 | |
| Download: ML031210088 (184) | |
Text
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 1 of 504 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING APPLICATION FOR RENEWAL OF OPERATING LICENSE Table of Contents ACRONYMS AND ABBREVIATIONS Page 9 RAI Number Paqe RAI 2.1.1-1.......
13 RAI2.1.1-2.......
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U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 2 of 504 RAI 2.3.3.9-1.........
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118 RAI 2.5.1-1.........
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129 RAI 2.5.2-2.........
135 RAI 3.0-1.........
140 RAI 3.1.2.1-1.........
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U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 3 of 504 RAI 3.1.2.1-5....................
146 RAI 3.1.2.1-6 Parts 1 and 2....................
147 RAI 3.1.2.1-7....................
150 RAI 3.1.2.1-8....................
151 RAI 3.1.2.1-9 Parts 1 and 2....................
153 RAI 3.1.2.1-10....................
156 RAI 3.1.2.2.1-1....................
157 RAI 3.1.2.2.2-1....................
158 RAI 3.1.2.2.3-1....................
159 RAI 3.1.2.2.4-1....................
161 RAI 3.1.2.2.6-1 Parts 1 and 2....................
162 RAI 3.1.2.2.7-1 Parts 1 and 2....................
164 RAI 3.1.2.2.7-2....................
166 RAI 3.1.2.2.10-1....................
167 RAI 3.1.2.2.11 -1....................
168 RAI 3.1.2.2.11-2....................
170 RAI 3.1.2.2.12-1....................
171 RAI 3.1.2.4.1 -1....................
173 RAI 3.1.2.4.1-2....................
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186 RAI 3.1.2.4.6-1....................
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U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAN03-0031 Page 4 of 504 RAI 3.3-3.......
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268 RAI 3.6.1-1.......
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U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA103-0031 Page 5 of 504 RAI 3.6.1-3.................
279 RAI 3.6.1-4.................
280 RAI 4.1-1.................
282 RAI 4.2.1 -1.................
284 RAI 4.2.2-1 Parts 1 and 2.................
288 RAI 4.2.2.3-1.................
292 RAI 4.2.3-1 Parts 1 and 2.................
294 RAI 4.3-1.................
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U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 6 of 504 RAI 4.6.4-3............
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362 RAI B.1-1............
363 RAI B.2.1 -1............
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420 RAI B.3.8-2 Part A............
421 RAI B.3.8-2 Part B............
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U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 7 of 504 RAI B.3.8-8........
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U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 8 of 504 RAI B.4.3-2......
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U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 9 of 504 ACRONYMS AND ABBREVIATIONS AAC Alternate AC AC Alternating Current ACI American Concrete Institute AEC Atomic Energy Commission AFW Auxiliary Feedwater AISC American Institute of Steel Construction AISI American Iron and Steel Institute ALARA As Low As Reasonably Achievable AMP Aging Management Program AMR Aging Management Review AMSAC ATWS Mitigation System Actuation Circuitry ANL Argonne National Laboratory ANSI American National Standards Institute API American Petroleum Institute ASA American Standards Association ASCE American Society of Civil Engineers ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials ATWS Anticipated Transient Without Scram AVT All Volatile Treatment AWS American Welding Society AWWA American Water Works Association B&PV Boiler And Pressure Vessel BIT Boron Injection Tank CASS Cast Austenitic Stainless Steel CCW Component Cooling Water CFR Code Of Federal Regulations CLB Current Licensing Basis CMAA Crane Manufacturers Association Of America, Inc.
CP&L Carolina Power & Light Company CRDM Control Rod Drive Mechanism CS Carbon Steel CSS Containment Spray System CST Condensate Storage Tank CUF Cumulative Utilization Factor CV Containment Vessel CVCS Chemical And Volume Control System DBA Design Basis Accident DBD Design Basis Document DBE Design Basis Earthquake DG Diesel Generator DS Dedicated Shutdown
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 10 of 504 DSDG Dedicated Shutdown Diesel Generator E&C Environment and Chemistry EAF Environmentally Assisted Fatigue ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EFPY Effective Full-Power Years EHC Electro-Hydraulic Control EJMA Expansion Joint Manufacturers Association EMA Equivalent Margins Analysis EOF Emergency Operations Facility EPRI Electric Power Research Institute EQ Environmental Qualification EQDP Environmental Qualification Data Package ER Environmental Report ESF Engineered Safety Features FHB Fuel Handling Building FO Fuel Oil FSAR Final Safety Analysis Report FW Feedwater GALL Generic Aging Lessons Learned (GALL) Report, NUREG - 1801 GDC General Design Criteria GL Generic Letter GSI Generic Safety Issue HAD Heat Actuated Device HEPA High-Efficiency Particulate Air Filters HELB High Energy Line Break HPSI High Pressure Safety Injection HVAC Heating, Ventilating, and Air Conditioning I&C Instrumentation and Control IA Instrument Air IASCC Irradiation Assisted Stress Corrosion Cracking IEEE Institute Of Electrical and Electronic Engineers ILRT Integrated Leak Rate Test (Containment Type A Test)
IN Information Notice INPO Institute Of Nuclear Power Operations IPA Integrated Plant Assessment IPCEA Insulated Power Cable Engineers Association ISFSI Independent Spent Fuel Storage Installation ISI In-Service Inspection IVSW Isolation Valve Seal Water LBB Leak-Before-Break LOCA Loss-of-Coolant Accident LR License Renewal LRA License Renewal Application
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 11 of 504 MCC Motor Control Center MDAFW Motor-Driven Auxiliary Feedwater Pump Pump MIC Microbiologically Induced Corrosion MOV Motor Operated Valve MSIV Main Steam Isolation Valve NEI Nuclear Energy Institute NEMA National Electrical Manufacturer's Association NFPA National Fire Protection Association NRC Nuclear Regulatory Commission NSSS Nuclear Steam Supply System OE Operating Experience PAP Personnel Access Portal pH Concentration of Hydrogen Ions PM Preventive Maintenance PORV Power-Operated Relief Valve PPS Penetration Pressurization System PRT Pressurizer Relief Tank PSAR Preliminary Safety Analysis Report P-T Pressure-Temperature PTS Pressurized Thermal Shock PVC Polyvinyl Chloride PWR Pressurized Water Reactor PWSCC Primary Water Stress Corrosion Cracking PWST Primary Water Storage Tank PZR Pressurizer QA Quality Assurance QC Quality Control RAB Reactor Auxiliary Building RAI Request for Additional Information RCDT Reactor Coolant Drain Tank RCP Reactor Coolant Pump RCPB Reactor Coolant Pressure Boundary RCS Reactor Coolant System REDS Radioactive Equipment Drain System RG Regulatory Guide RH Relative Humidity RHR Residual Heat Removal RMS Radiation Monitoring System RNP H. B. Robinson Steam Electric Plant, Unit No. 2, or Robinson Nuclear Plant RO Refueling Outage RPS Reactor Protection System RPV Reactor Pressure Vessel
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RA/03-0031 Page 12 of 504 RTNDT Reference Temperature, Nil-Ductility Transition RTPTS Reference Temperature, Pressurized Thermal Shock RTS Reactor Trip System RV Reactor Vessel RWST Refueling Water Storage Tank SAR Safety Analysis Report SBO Station Blackout SCs Structures and Components SCC Stress Corrosion Cracking SDAFW Steam-Driven Auxiliary Feedwater Pump Pump SEN Significant Event Notification SER Safety Evaluation Report SFP Spent Fuel Pit SG Steam Generator Si Safety Injection SIT Structural Integrity Test SOER Significant Operating Event Report SOV Solenoid Operated Valve SR Silicone Rubber SRP Standard Review Plan SS Stainless Steel SSCs Systems, Structures, and Components SSE Safe Shutdown Earthquake SFPCS Spent Fuel Pit Cooling System SWS Service Water System TAP Task Action Plan TEMA Tubular Exchanger Manufacturer's Association TGSCC Transgranular Stress Corrosion Cracking TID Total Integrated Dose TLAA Time-Limited Aging Analysis TSC Technical Support Center UFSAR Updated Final Safety Analysis Report USAS United States Of America Standards USE Upper Shelf Energy UT Ultrasonic Test VCT Volume Control Tank WCAP Westinghouse Commercial Atomic Power WDS Waste Disposal System WOG Westinghouse Owner's Group
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RANO3-0031 Page 13 of 504 RAI 2.1.1-1 By letters dated December 3, 2001, and March 15, 2002, the Nuclear Regulatory Commission (NRC) issued a staff position to the Nuclear Energy Institute (NEI) which described areas to be considered and options it expects licensees to use to determine what systems, structures, or components (SSCs) meet the 10 CFR 54.4(a)(2) criterion (i.e., all non safety-related SSCs whose failure could prevent satisfactory accomplishment of any safety-related functions identified in paragraphs (a)(1)(i),(ii),(iii) of this section.)
The December 3, 2001, letter provided specific examples of operating experience which identified pipe failure events (summarized in Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor')
and the approaches the NRC considers acceptable to determine which piping systems should be included in scope based on the 54.4(a)(2) criterion.
The March 15 letter, further described the staff's expectations for the evaluation of non-piping SSCs to determine which additional non safety-related SSCs are within scope. The position states that applicants should not consider hypothetical failures, but rather should base their evaluation on the plant's CLB, engineering judgement and analyses, and relevant operating experience. The paper further describes operating experience as all documented plant-specific and industry-wide experience which can be used to determine the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant-specific condition reports, industry reports such as significant operating experience reports (SOERs), and engineering evaluations.
Consistent with the staff position described in the aforementioned letters, please describe your scoping methodology implemented for the evaluation of the 10 CFR 54.4(a)(2) criterion. As part of your response please indicate the option(s) credited, list the SSCs included within scope as a result of your efforts, list those SCs for which aging management reviews were conducted, and for each SC describe the aging management programs, as applicable, to be credited for managing the identified aging effects.
RNP Response:
Please refer to Attachment V of the letter from J. Moyer (CP&L) to NRC, Serial RNP-RA/02-0159, "Supplement to Application for Renewal of Operating License," dated October 23, 2002. This letter provides a description of the modified license renewal scope as relating to 10 CFR 54.4(a)(2). Also included in Attachment V to this letter is a list of piping systems included within the modified scope, identification of the piping systems having non-safety related
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 14 of 504 components requiring AMR, and the aging management programs credited for managing the identified aging effects.
As stated in the above-referenced RNP letter, site specific and industry operating experience was reviewed in support of RNP AMRs. Operating experience (OE) sources considered include INPO OE items (SERs, SOERs, and SENs), NRC documents (INs, GLs, violations, and staff reports), 10 CFR 21 reports, and vendor bulletins, as well as corporate internal OE information from Progress Energy nuclear sites. NUREG CR-6239 "Survey of Strong Motion Earthquake Effects on Thermal Power Plants in California with Emphasis on Piping Systems," provides insight as to failures of piping systems during earthquakes.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 15 of 504 RAI 2.1.1-2 During the audit of the H.B. Robinson scoping and screening methodology, the audit team determined that the procedures reviewed in combination with the review of a sample of scoping and screening products provided adequate evidence that the scoping and screening process was conducted in accordance with the requirements of 10 CFR 54.4, "Scope,m and 10 CFR 54.21, "Contents of Application - Technical Information." Additionally, the staff discussed the applicant's position concerning the potential long-term program implementation of the LRA methodology and guidance into the operational phase of the plant during the extended period of operation. As a result, the team concluded that the applicant needs to formally document the process it intends to implement to capture the scoping and screening process upon which the applicant will rely during the period of extended operation at H.B. Robinson to satisfy the requirements of 10 CFR 54.35, "Requirements During the Term of Renewed License."
RNP Response:
With the exception of Part 54, RNP has implemented and maintained programs in accordance with the referenced regulations. Compliance with those regulations will continue through the term of the renewed license.
RNP will implement the necessary processes and programmatic controls into the configuration control process to assure that the aging management review process is appropriately applied to SSCs. (The aging management review process is defined as the identification of SSC subject to aging management review and demonstration that the effects of aging will be adequately managed so that their intended function(s) will be maintained consistent with the CLB.)
Integration of these processes and programmatic controls is intended to include the following:
Reflect the results of the aging management review process completed during integrated plant assessment in the RNP design basis.
Develop guidance for scoping, screening and aging management review.
Evaluation of TLAAs.
Identification of newly identified, aging management review results and/or TLAA in the UFSAR (10 CFR 50.71) update.
As a result of the above response, the following statement is added to the UFSAR Supplement, LRA Subsection A.3.1:
"Upon issuance of the renewed license, guidance will be incorporated into the administrative control procedures that manage the RNP configuration
U. S. Nuclear Regulatory Commission Attachment liI to Serial: RNP-RA/03-0031 Page 16 of 504 control process to ensure that the requirements of 10 CFR 54.37(b) are met."
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 17 of 504 RAI 2.1.1-3 During the audit of the H. B. Robinson scoping and screening methodology, the audit team determined that the system and component intended functions had been identified in the system design basis documents. However, during the scoping process, the intended functions had been grouped and reworded (relative to the intended functions contained in the design basis documents) when listed on the scoping worksheets. The audit team discussed the process with the applicant's staff and reviewed the process implementation guidance developed by the applicant, however, the audit team was unable to determine the methods used for the grouping and rewording of the intended functions. In addition, the audit team could not discern a clear, auditable trail from the intended functions, as listed in the design basis documents, to the grouped and reworded intended functions listed on the scoping worksheets. As a result, the team concluded that the applicant needs to formally document the process used to transfer and maintain the content of the intended functions, as listed in the design basis documents, to the grouped and reworded intended functions listed on the scoping worksheets.
RNP Response:
The development of information to support the LRA meets the requirements of a 10 CFR 50, Appendix B. The governing procedure for developing the intended functions identifies the basic documentation that was reviewed to extract the intended functions. The wording of each intended function was typically extracted verbatim and modified infrequently to capture complete meanings.
Experienced engineers prepared and reviewed the selections of intended functions to ensure the essence of the documents was fairly represented. As the IPA progressed, the level of detail resulted in new insights; scoping was again revisited. For example, as part of the screening process, the flow diagrams were reviewed and highlighted to ensure functions were captured. New subtle interfaces between in scope and out of scope systems were identified. Thus, the IPA process further scrutinized the intended functions and the scoping was updated, as required.
The scoping process and results have been the subject of a self-assessment and a Nuclear Assessment Section (NAS) assessment. There were no cases identified of incomplete, missing, or incorrect intended functions. During the scoping inspection the reconciliation of the DBD information for four systems was presented to the NRC inspectors for subsequent review. No case of missing or incorrect information was identified.
The process of identifying system intended functions from the design basis documents (DBD) provides a good example of how functions were determined.
The process follows the following steps:
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 18 of 504
- 1. Determine the information that is considered design basis information.
- 2. Catalog potential, system level, intended functions and maintain the associated source reference.
- 3. Identify the relevant DBD functional statements.
- 4. Compare the functional statements with information cataloged from other CLB sources.
- 5. Identify duplicate or overlapping functional statements and use the one that best describes the broadest aspects of the function. If necessary, expand the statements to capture the complete functional requirements.
Record the basis for modifying or using the statements provided. This can be in the form of references or comments that describe the relevant information.
- 6. A determination is made as to whether or not each functional statement is an intended function and a basis is recorded in the form of a reference or comment. An intended function is one that supports any of the criteria identified in 10 CFR 54.4(a)(1) through (a)(3).
The final set of functions is listed on a system worksheet. The basis for this result is recorded alongside each function in the form of a reference or comment.
For DBDs, the performance of process steps 1) through 3) focused on the System Functional Requirements section in the DBD. The LR project did not consider all of these paragraphs to be functions that need to be addressed under the LR Rule. The forward in the DBDs states, "Information contained herein which meets the above definition of design basis (as defined by CP&L) is underlined." (Words in italics added for clarity) The LR project team addressed this design basis information in the DBD. The remaining paragraphs, typically less than half the total, were reviewed in conjunction with other available information, e.g., UFSAR, docketed information, and statements depicting the system intended function, to capture the complete set of intended functions as defined in 10 CFR 54.4.
The information in the QA record is considered sufficient to capture the intended functions and their basis. RNP has the catalog of information, i.e., "notes," that can be used to understand how the final set of functional statements was obtained. However, RNP does not consider these "notes" part of the QA record.
The information in the QA record is adequate when used in conjunction with the plant detailed design output information, e.g., flow diagrams, plant equipment database, to identify the license renewal scope for each system and the component intended function(s) required to support these system level intended functions.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 19 of 504 RAI 2.1.2-1 The applicant describes its process of evaluating consumables in Section 2.1.2 of the application. The applicant states that the evaluation process for consumables is consistent with the NRC staff guidance on consumables provided in a letter from C. I. Grimes, NRC, to D. J. Walters, NEI, dated March 10, 2000. The applicant should state whether their evaluation process for consumables is also subject to screening guidance in accordance with NUREG-1800, Table 2.1-3 dated April 2001. If consumables are not considered subject to NUREG-1 800 scoping and screening guidance, provide a justification for their exclusion.
RNP Response:
The evaluation process used to evaluate consumables is consistent with the guidance provided in NUREG-1800, Table 2.1-3.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAtO3-0031 Page 20 of 504 RAI 2.3.1.3-1 Table 3.1-1 states, "The Pressurizer Spray Head performs no license renewal intended functions at RNP." Please explain how the spray head would not be relied upon to function, either with normal or auxiliary spray, following a postulated fire in accordance with the requirements of Appendix R to 10 CFR 50, or after a postulated steam generator tube rupture event. Note that the UFSAR lists normal and auxiliary pressurizer sprays among the functions that would be available to depressurize the primary coolant system following a steam generator tube rupture event. Explain how failure of the pressurizer spray head, a nonsafety-related component, could not prevent any of the functions of 10 CFR 54.4.(a)(i), (ii), or (iii).
RNP Response:
The pressurizer spray head is not required to function following a postulated fire in accordance with the requirements of Appendix R to 10 CFR 50, or after a postulated steam generator tube rupture event.
The spray lines are not credited for makeup in this scenario. The Appendix R and Station Blackout Safe-Shutdown Analysis Flowpath/Boundary Diagrams do not depict the spray lines as one of the Safe-Shutdown Analysis flowpaths.
Section 15.6.3.2.1 of the UFSAR discusses the methods that may be employed to depressurize the primary side during a SGTR. Specifically, it states that:
"in order of preference: (1) normal pressurizer spray; (2) pressurizer power operated relief valves (PORVs); (3) auxiliary pressurizer spray, and; (4) balancing charging/letdown or using unaffected steam generators for cooldown/depressurization." However, the UFSAR goes on to state that:
"It should be noted that the function of depressurizing from the primary side to isolate the affected steam generator for this event is not considered to be a design basis or safety related function for any of the equipment listed above."
As stated in the UFSAR, using the PORVs or balancing charging/letdown are alternate methods available for equalizing primary and secondary pressures following a steam generator tube rupture. In addition, RNP has a procedure that specifically provides actions for a SGTR with coincident loss of pressurizer normal and auxiliary sprays and PORVs.
Finally, in the SER (dated October 26, 2000) for WCAP-1 4574, "License Renewal Evaluation: Aging Management Evaluation for Pressurizers," states:
"After completing the initial review, the staff requested WOG to verify whether any of the applicable plants rely on the RCS pressure control function of the
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 21 of 504 pressurizer to prevent or mitigate the consequences of design-basis events. This additional information from WOG was requested to verify that components such as the spray head, which sprays subcooled water inside the pressurizer to control RCS pressure, were appropriately excluded from the AMR. In a conference call on June 25, 1999, WOG confirmed that none of the applicable plants rely on the RCS pressure control function of the pressurizer to prevent or mitigate the consequences of design-basis events, and therefore the passive and long-lived components (e.g., spray head) that perform the pressure control function, but do not perform the pressure boundary function, need not be within the scope of license renewal, nor be subject to an AMR according to the regulations. The staff agrees with this conclusion."
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-R/03-0031 Page 22 of 504 RAI 2.3.1.6-1 Table 3.1-1 states, 0... the feed rings/J-nozzles perform no license renewal intended functions." The staff's view is that they provide structural and/or functional support for in-scope equipment. For example, the feeding is a component that is required to deliver and distribute auxiliary feedwater, a function that must be available to meet the requirements in 10 CFR 54.4(a)(1) and (3).
Loss of one or more J-tubes could make the feeding assembly more susceptible to water hammer. Consider, too, the possibility that failure of the feeding or one or more of the J-tubes might damage the steam generator tube sheet, and prevent any of the functions of 10 CFR 54.4.(a)(i), (ii), or (iii). Please justify the exclusion of these components from the LRA aging management requirements.
RNP Response:
The RNP LRA is consistent with previously reviewed and approved applications for Westinghouse NSSS plants.
The relationship between the feedwater and AFW systems is provided below.
Per Section 2.3.4.8 of the LRA:
'The Feedwater System provides pre-heated, high pressure feedwater to the steam generators under operating conditions. The system provides for feedwater and blowdown isolation following a postulated loss of coolant accident or steam line break event, and assists in maintaining steam generator water chemistry. SG level is controlled to ensure proper water inventory for various operational and accident conditions. The control is achieved by variations in the feedwater flowrate."
Per Section 2.3.4.9 of the LRA:
'The Auxiliary Feedwater System supplies feedwater to the steam generators when normal feedwater sources are not available. The system provides for isolation of flow to a faulted steam generator following postulated accidents, such as a steam generator tube rupture or main steam line break."
The AFW system utilizes some feedwater system valves and piping to deliver feedwater to the steam generators. Minimum AFW flow is established on the basis of the most limiting plant transient condition where reliance on AFW flow is necessary for core protection. For RNP, minimum flow is based on assumptions
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 23 of 504 in the governing analysis for loss of normal feedwater and is the total flow to two (2) effective steam generators.
Prior to the installation of the current feed ring/J-tube design, the RNP feed rings were made from a standard ten-inch diameter pipe with bottom discharge holes of the type found in Westinghouse Model 44 steam generators. The susceptibility of RNP to steam generator water hammer was evaluated by the NRC as part of its generic review of secondary system fluid flow instabilities. In the Safety Evaluation performed by the Office of Nuclear Reactor Regulation (March, 1980), the staff concluded:
'That if auxiliary feedwater flow is limited to 400 gpm, steam generator water hammer is not likely to occur at this facility and, therefore, we find no undue risk to the health and safety of the public as a result of the continued operation of the H. B. Robinson Steam Electric Plant, Unit No. 2."
The new feed ring/J-tube design is less susceptible to steam generator water hammer than the original design. Age-related degradation that would leave the feed rings in a configuration more susceptible to steam generator water hammer than the original design is highly unlikely and will not impact the ability of the AFW system to add water to the steam generator.
As part of the issuance of Amendment 196 to RNP's Facility Operating License, the NRC provided a Safety Evaluation regarding a request to increase the authorized power level of RNP. In that evaluation the NRC stated:
"The increase in steam velocity will also result in an increase in steam hammer loads, which have been evaluated and determined to be negligible. The parameters at the current level of SGTP
(-0.1%/0) and a projection of parameters after the power uprate with 6-percent SGTP were analyzed and the results indicated continued acceptability of the SGs to support plant operations and analyses at the uprated power level."
Loose parts were also discussed as part of the same Safety Evaluation and the staff stated:
"The licensee's current SG program includes the identification and disposition of loose parts either by removal or monitoring. In addition, the SG program provides for the evaluation of the impact of loose parts through condition monitoring and operational assessments. Therefore, the NRC staff concludes that, based on the slight increase of the steam flow rate and slight decrease of the steam pressure, the 1. 7-percent power uprate will have a negligible impact on tube wear caused by loose parts, and that the licensee
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 24 of 504 has provided reasonable assurance that the challenges to SG tube integrity from secondary-side loose parts will be managed by the current site SG inspection program."
Based on the previous discussion, the feed rings/J-tubes do not meet the scoping requirements as defined in 10 CFR 54.4.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 25 of 504 RAI 2.3.2.3-1 On piping and instrumentation diagram 5379-1 082LR Sheet 3, at grid location G-7, vacuum breakers SI-899D and Sl-899E are highlighted as being within the scope of license renewal. These vacuum breakers appear to protect the integrity of the containment spray additive tank in support of the containment spray system's iodine removal intended function. However, LRA Table 2.3-4, which lists the components and commodity groups of the containment spray system that are subject to an AMR, does not include a specific entry for vacuum breakers. Therefore, the applicant is requested to either (1) identify the component/commodity group in LRA Table 2.3-4 that generically includes vacuum breakers (e.g., valves, piping, tubing, and fittings), (2) include an additional entry in LRA Table 2.3-4 for vacuum breakers, or (3) justify the exclusion of vacuum breakers SI-899D and SI-899E from an AMR in accordance with 10 CFR 54.21(a)(1).
RNP Response:
The Component/Commodity Group "Valves, Piping Tubing And Fittings" in LRA Table 2.3-4 contains vacuum breakers SI-899D and SI-899E.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 26 of 504 RAI 2.3.2.3-2 On piping and instrumentation diagram 5379-1082LR Sheet 5, containment spray header nozzles are highlighted as being within the scope of license renewal. It appears that these nozzles are credited with both forming a pressure boundary for the containment spray system flowpath and inducing the spray flow that is relied upon in the safety analysis (e.g., UFSAR Section 6.2.2.3.1) to ensure that adequate containment heat removal occurs. However, LRA Table 2.3-4, which lists the components and commodity groups of the containment spray system that are subject to an AMR, does not appear to include an entry that encompasses the intended functions of the spray nozzles. Therefore, the applicant is requested to either (1) include an entry in LRA Table 2.3-4 for the containment spray nozzles which identifies their pressure-boundary and spray-flow-inducing intended functions or (2) justify the exclusion of the containment spray nozzles from an AMR in accordance with 10 CFR 54.21 (a)(1).
RNP Response:
The Component/Commodity Group 'Valves, Piping, Tubing and Fittings" in LRA Table 2.3-4 includes the containment spray nozzles. The nozzles do not have a tag number at RNP and therefore were included as a commodity type and associated with the aforementioned component/commodity group. The component intended function for 'Valves, Piping, Tubing and Fittings" (including nozzles) is meant to encompass the spray function and supports the above mentioned system level function. The complete component intended function is:
"Provide pressure-retaining boundary so that sufficient flow at adequate pressure is delivered."
The nozzles will remain in place so long as the pressure-retaining boundary is maintained. Therefore, the geometric configuration of the nozzles relative to the containment space would be maintained so long as the pressure boundary is maintained. The latter part of the function "...so that sufficient flow at adequate pressure is delivered," ensures that the aging effects that could potentially influence the hydrodynamic aspects are considered.
Therefore, RNP concludes that the spray nozzles are included as 'Valves, Piping, Tubing and Fittings," and that the pressure-boundary and spray-flow-inducing intended functions are included. These commodities require an AMR.
The RNP containment spray nozzles and connected piping are stainless steel in a containment air environment. They have been determined to have no aging mechanisms that require management. This result is different from GALL since the nozzles in GALL are evaluated as carbon steel nozzles, which were determined in GALL to be susceptible to general corrosion.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 27 of 504 RAI 2.3.2.3-3 In LRA Table 2.3-4, which contains the AMR screening results for the containment spray system, table entries are provided for the spray pump heat exchanger tubing and shell and cover. However, there is no entry for the heat exchanger tubesheets. The staff reviewer noted that the LRA treats heat exchangers in certain systems (e.g., residual heat removal, safety injection, chemical and volume control, spent fuel pool cooling, and various sampling systems) in a similar manner. For other systems (e.g., steam generators, component cooling water, feedwater, and diesel generator), however, tubesheets are included in the AMR screening results table. The staff believes that heat exchanger tubesheets provide a pressure boundary which may be necessary to perform intended functions for license renewal, such as ensuring the transfer of adequate heat across heat exchanger tubes, ensuring adequate system flow, and ensuring the containment of potentially radioactive fluids. It is not clear to the staff what criteria the applicant used in determining that it was not required to include heat exchanger tubesheets in the AMR screening results for certain systems, including the containment spray system. Therefore, the applicant is requested to explain the LRA's treatment of heat exchanger tubesheets, such that the staff may verify that the scoping and screening criteria used by the applicant satisfy the criteria of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1).
RNP Response:
RNP agrees that heat exchanger tube sheets can provide a pressure boundary that is necessary to perform the component intended functions for license renewal.
In LRA Table 2.3-4, the spray pump heat exchanger tubing and shell and cover are the major subcomponents of this small heat exchanger. There is no tube sheet. The component name is based on the component description and type in the Equipment Data Base (EDB). Although the EDB refers to this as a heat exchanger, it may be thought of as a small pump cooler. It essentially consists of tubing coils inside a closed container. The tubes inlet and outlet penetrate the cover via a welded fitting. The cooling water inlet and outlet on the shell side also penetrate the same cover.
Heat Exchangers were screened in at the component Tag Number level. The sub-components, such as tubing, tube sheets, channel heads, channel covers, and shells, were developed during the AMR process and presented in the LRA tables throughout Section 2. Particular attention was given to considering material and environment combinations such that a complete set of aging mechanisms requiring management would be identified. Subcomponents such as "waterboxes" were used interchangeably with channel heads and covers. The main focus was on identifying the relevant material categories and environments.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 28 of 504 Shortly after submittal of the LRA, the RNP staff noted inconsistencies in the identification of heat exchanger subcomponents. The resulting corrective actions affected the component commodities identified in the LRA submittal. As part of the identification process, a review of the subcomponent breakdowns for heat exchangers within the scope of license renewal was made to determine those that appear to be missing major subcomponents, such as tube sheets. The corrective actions included a more complete review of these heat exchangers.
The changes are shown in the following tables.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 29 of 504 TABLE 2.3-2 COMPONENT/COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS:
RESIDUAL HEAT REMOVAL SYSTEM Component/Commodity Intended Function AMR Results RHR Heat Exchanger Provide pressure-retaining boundary so that Table 3.2-1, Item 9 Shell and Cover sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 11 Table 3.2-2, Item 5 RHR Heat Exchanger Provide pressure-retaining boundary so that Table 3.2-1, Item 1 Tubing and Tube Sheet sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 9 Provide heat transfer.
Table 3.2-1, Item 10 Table 3.2-2, Item 1 Table 3.2-2, Item 2 Table 3.2-2, Item 7 RHR Heat Exchanger Provide pressure-retaining boundary so that Table 3.2-1, Item 1 Waterbox sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 10 Table 3.2-2, Item 1 Table 3.2-2, Item 8 RHR Pump Seal Heat Provide pressure-retaining boundary so that Table 3.2-1, Item 9 Exchanger Shell sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 11 Table 3.2-2, Item 5 RHR Pump Seal Heat Provide pressure-retaining boundary so that Table 3.2-1, Item 1 Exchanger Tubing sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 9 Provide heat transfer.
Table 3.2-1, Item 10 Table 3.2-2, Item 1 Table 3.2-2, Item 2 Table 3.2-2, Item 7 TABLE 2.3-3 COMPONENT/COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS:
SAFETY INJECTION SYSTEM Component/Commodity Intended Function AMR Results SI Pump Seal Heat Provide pressure-retaining boundary so that Table 3.2-1, Item 9 Exchanger Tubing sufficient flow at adequate pressure is delivered.
Table 3.2-2, Item 1 Provide heat transfer.
Table 3.2-2, Item 2 SI Pump Seal Heat Provide pressure-retaining boundary so that Table 3.2-1, Item 9 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 11 Cover Table 3.2-2, Item 5 Table 3.2-2, Item 6
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RAI03-0031 Page 30 of 504 TABLE 2.3-4 COMPONENT/COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS:
CONTAINMENT SPRAY SYSTEM Component/Commodity Intended Function AMR Results CV Spray Pump Seal Provide pressure-retaining boundary so that Table 3.2-1, Item 9 Heat Exchanger Tubing sufficient flow at adequate pressure is delivered.
Table 3.2-2, Item 1 Provide heat transfer.
Table 3.2-2, Item 2 CV Spray Pump Seal Provide pressure-retaining boundary so that Table 3.2-1, Item 9 Heat Exchanger Shell sufficient flow at adequate pressure is delivered.
Table 3.2-1, Item 11 and Cover Table 3.2-2, Item 5 Table 3.2-2, Item 6 TABLE 2.3-9 COMPONENT/COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS:
COMPONENT COOLING WATER SYSTEM ComponentCommodity Intended Function AMR Results CCW Heat Exchanger Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Shell sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Table 3.3-1, Item 16 CCW Heat Exchanger Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Tube Sheet sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 16 Table 3.3-2, Item 15 Table 3.3-2, Item 17 CCW Heat Exchanger Provide pressure-retaining boundary so that Table 3.3-1, Item 16 Tubing sufficient flow at adequate pressure is delivered.
Table 3.3-2, Item 16 Provide heat transfer.
Table 3.3-2, Item 17 CCW Heat Exchanger Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Waterbox sufficient flow at adequate pressure is delivered Table 3.3-1, Item 16 Hot Leg Sample Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Cover Table 3.3-2, Item 15 Hot Leg Sample Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Exchanger Tubing sufficient flow at adequate pressure is delivered.
Non Regenerative Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Non-Regenerative Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Exchanger Tubing and sufficient flow at adequate pressure is delivered.
Tube Sheet PZR Liquid Sample Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Exchanger Tubing sufficient flow at adequate pressure is delivered.
PZR Liquid Sample Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Cover Table 3.3-2, Item 15 PZR Steam Sample Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Exchanger Tubing sufficient flow at adequate pressure is delivered.
PZR Steam Sample Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Cover Table 3.3-2, Item 15 I
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 31 of 504 ComponenVlCommodity Intended Function AMR Results Rod Drive Cooling Provide pressure-retaining boundary so that Table 3.3-2, Item 20 System Cooler sufficient flow at adequate pressure is delivered Equipment Frame of Housing Rod Drive Cooling Provide pressure-retaining boundary so that Table 3.3-1, Item 5 System Cooler Tubing sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 24 Provide heat transfer Table 3.3-2, Item 16 Table 3.3-2, Item 25 Sample Vessel Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Cover Table 3.3-2, Item 15 Sample Vessel Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Exchanger Tubing sufficient flow at adequate pressure is delivered.
SFP Cooling Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 SFP Cooling Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 14 Exchanger Tubing and sufficient flow at adequate pressure is delivered.
Tube Sheet SG Blowdown Sample Provide pressure-retaining boundary so that Table 3.4-1, Item 13 Heat Exchanger Shell sufficient flow at adequate pressure is delivered.
Table 3.4-1, Item 10 and Cover Table 3.4-2, Item 7 SG Blowdown Sample Provide pressure-retaining boundary so that Table 3.4-1, Item 10 Heat Exchanger Tubing sufficient flow at adequate pressure is delivered.
Waste Gas Compressor Provide pressure-retaining boundary so that Table 3.3-1, Item 24 Cooler Tubing sufficient flow at adequate pressure is delivered.
Table 3.3-2, Item 16 Waste Gas Compressor Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Cooler Channel Heads sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 and Covers Waste Gas Compressor Provide pressure-retaining boundary so that Table 3.3-1, Item 24 Cooler Tube Sheet sufficient flow at adequate pressure is delivered Table 3.3-2, Item 16 I
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAN03-0031 Page 32 of 504 TABLE 2.3-10 COMPONENT/COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS:
CHEMICAL AND VOLUME CONTROL SYSTEM Component/Commodity Intended Function AMR Results Charging Pump Heat Provide pressure-retaining boundary so that Table 3.3-2, Item 21 Exchanger Shell sufficient flow at adequate pressure is delivered.
Table 3.3-2, Item 22 Regenerative Heat Provide pressure-retaining boundary so that Table 3.3-2, Item 23 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Cover Charging Pump Heat Provide pressure-retaining boundary so that Table 3.3-2, Item 16 Exchanger Tubing sufficient flow at adequate pressure is delivered.
Table 3.3-2, Item 22 Provide heat transfer.
Charging Pump Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Waterbox sufficient flow at adequate pressure is delivered.
Table 3.3-2, Item 22 Excess Letdown Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 3 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 13 Cover Table 3.3-1, Item 14 Table 3.3-2, Item 15 Excess Letdown Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 3 Exchanger Tubing sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 8 and Tube Sheet Table 3.3-1, Item 14 Table 3.3-2, Item 1 Excess Letdown Heat Provide pressure-retaining boundary so that Table 3.3-2, Item 23 Exchanger Waterbox sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 3 Table 3.3-1, Item 8 Table 3.3-2, Item 1 Regenerative Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 3 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 8 Intershell Pipe Table 3.3-2, Item 1 Table 3.3-2, Item 23 Seal Water Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 13 Exchanger Shell and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Cover Table 3.3-2, Item 15 Seal Water Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 8 Exchanger Tubing and sufficient flow at adequate pressure is delivered.
Table 3.3-1, Item 14 Tube Sheet Table 3.3-2, Item 1 Seal Water Heat Provide pressure-retaining boundary so that Table 3.3-1, Item 8 Exchanger Waterbox sufficient flow at adequate pressure is delivered.
Table 3.3-2, Item 1 Table 3.3-2, Item 2
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 33 of 504 TABLE 3.2-1 ENGINEERED SAFETY FEATURES SYSTEMS AGING MANAGEMENT PROGRAMS EVALUATED IN THE GALL REPORT THAT ARE RELIED ON FOR LICENSE RENEWAL Componentl Aging Effect Aging Management GALL Further Commodity Group Mechanism Program Evaluation DIscussIon (1)
Recommended
- 1. Piping, fittings, Cumulative TLAA, evaluated in Yes, TLAA RHR pumps, heat exchanger tubing, tube sheet, and valves in fatigue damage accordance with channel head and cover (waterboxes) and flow orifices emergency core 10 CFR 54.21 (c) have been included in this group. Evaluation of this cooling system component/commodity group is consistent with the GALL Report. Refer to Section 4.3 for the TLAA
___evaluations associated with metal fatigue.
I
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 34 of 504 TABLE 3.2-2 ENGINEERED SAFETY FEATURES SYSTEMS AGING MANAGEMENT EVALUATIONS THAT ARE DIFFERENT FROM OR NOT ADDRESSED IN THE GALL REPORT Component Material Environment Aging Effectl Aging Management I Commodity II_)_I Mechanism I
Program I
Discussion
- 1. Boron Injection Tank; Eductors; Flow Orifices/
Elements; RWST; Pumps: Si, RHR, and CV Spray; Accumulators; Si Filters; Spray Additive Tank; Heat Exchanger Tubing: RHR, Si and CV Pump and RHR Heat Exchangers; RHR Heat Exchanger Waterbox
- Valves, Piping, Tubing and Fittinqs Stainless Steel Treated Water (including Steam)
Loss of Material from Crevice Corrosion Water Chemistry Program Except for valves, piping, and fittings in the IVSW System, these components have an internal environment of treated, borated water. The IVSW components contain treated, demineralized water. RNP has applied the Water Chemistry Program to manage crevice and pitting corrosion. As discussed in the GALL Report, Chapter V, Section D.1, discussion of Systems, Structures, and Components, stainless steel is not subject to significant general, pitting, and crevice corrosion in borated water. Also, the Water Chemistry Program controls chemical species that would promote crevice and pitting corrosion, i.e., chlorides, fluorides, sulfates, and dissolved oxygen in treated, demineralized water. In addition, RNP plant-specific operating experience supports the conclusion that crevice and pitting corrosion are not occurring in these systems.
Loss of Material from Pitting Corrosion Water Chemistry Program I
U. S. Nuclear Regulatory Commission Attachment ill to Serial: RNP-RAt03-0031 Page 35 of 504 TABLE 3.2-2 (continued) ENGINEERED SAFETY FEATURES SYSTEMS AGING MANAGEMENT EVALUATIONS THAT ARE DIFFERENT FROM OR NOT ADDRESSED IN THE GALL REPORT Component Material Environment Aging Effect!
Aging Management Commodity (1)
Mechanism Program Discussion
- 6. SI and CV Carbon Treated Loss of Material from Closed-Cycle Cooling The GALL Report applies the Closed Cycle Spray Pump Steel Water Selective Leaching Water System Cooling Water System and Selective Seal Heat (including Program Leaching of Materials Programs to manage Exchanger steam) selective leaching (for example, refer to Shell and GALL Section VII.C2.3-a). However, RNP Cover applies only the Closed-Cycle Cooling Water System Program. The RNP AMR methodology considers selective leaching of components exposed to treated water to be managed by cooling water chemistry. The chemistry of the CCW system utilizes corrosion inhibitors to protect base metal from electrochemical reactions and is maintained by the Closed-Cycle Cooling Water System Program. Therefore, aging management of selective leaching, although not consistent with the GALL Report, is effective in preventing the aging mechanism.
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U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 36 of 504 TABLE 3.2-2 (continued) ENGINEERED SAFETY FEATURES SYSTEMS AGING MANAGEMENT EVALUATIONS THAT ARE DIFFERENT FROM OR NOT ADDRESSED IN THE GALL REPORT Component Material Environment Aging Effectl Aging Management Commodity (1_)
Mechanism Program Discussion
- 7. RHR Heat Stainless Treated Cracking from SCC Closed-Cycle Cooling The RNP AMR determined that cracking due Exchanger Steel Water Water System to SCC could be applicable to stainless steel Tubing, RHR (including Program heat exchanger tubing. The Closed-Cycle Pump Seal steam)
Cooling Water System Program was applied Heat to manage the cracking due to SCC on the Exchanger shell side of the tubing. This is appropriate Tubing because that Program limits the presence of chemical impurities required for SCC to occur. Use of water chemistry controls to manage cracking due to SCC is similar to its use in the GALL Report,Section V.D1.1-a.
- 8. Boron Stainless Indoor - Not None None Required The RNP AMR determined that these Injection Tank, Steel Air components have no aging effects requiring Si Pumps, Conditioned, management for these environments. The RHR Pumps Containment applicable RNP environments do not and Heat
- Air, promote concentration of contaminants or Exchanger Air and Gas, include exposure to aggressive chemical Waterbox CV Borated species. Boric acid is not an aggressive Spray Pumps, Water chemical species for stainless steel.
ECCS Screen Leakage Filters, ECCS Sump Hood
- Filter, Eductors, Flow Orifices/
- Elements, RWST, Si Pump Recirc Strainer Filters I
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 37 of 504 TABLE 3.3-1 AUXILIARY SYSTEMS AGING MANAGEMENT PROGRAMS EVALUATED IN THE GALL REPORT THAT ARE RELIED ON FOR LICENSE RENEWAL Component/
Aging EffectI Aging Management GALL Further Commodity Group Mechanism Program Evaluation Discussion (1)
Recommended
- 14. Components in Loss of material Closed-cycle cooling No Components fabricated from copper alloys (tubing for or serviced by due to general, water system coolers cooled by the Component Cooling Water closed-cycle cooling pitting, and System) are not in GALL; also, galvanic corrosion of water system crevice dissimilar metals in contact with tubing and fouling of corrosion, and heat exchanger tubing are aging mechanisms that are MIC applicable but not in GALL. These issues are discussed in Table 3.3-2, Items 15 and 16.
The RNP AMR determined that MIC was not applicable for the closed-cycle cooling water systems, because no source of microbial contamination was identified. The Note: Table Item 15 is Closed-Cycle Cooling Water System Program manages not shown.
aging for this group. For the CCW Heat Exchanger, some activities such as inspections and detection of aging effects are incorporated in the Open-Cycle Cooling Water System Program. This is consistent with the GALL Report for the applicable aging effects/mechanisms.
- 16. Components in Loss of material Open-cycle cooling No The RNP methodology identified an additional aging or serviced by open-due to general, water system mechanism: loss of material from erosion for certain cycle cooling water pitting, crevice, coolers cooled by the SWS. This is discussed on Table systems and galvanic 3.3-2, Item 17. The RNP CCW Tube Sheet is carbon corrosion, MIC, steel, and except for erosion, the aging and biofouling; effects/mechanisms are the same and can be managed buildup of by this program.
deposit due to biofouling Aging management of this component/commodity group relies on the Open-Cycle Cooling Water System Program and is consistent with the GALL Report.
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U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 38 of 504 TABLE 3.3-2 AUXILIARY SYSTEMS AGING MANAGEMENT EVALUATIONS THAT ARE DIFFERENT FROM OR NOT ADDRESSED IN THE GALL REPORT Component Material Environment Aging Effect/
Aging Management Commodity (1_)
Mechanism Program Discussion
- 3. DELETED
- 15. Compo-Carbon Treated Loss of Material from Closed-Cycle Cooling These aging effects/mechanisms are not nents in or Steel Water Galvanic Corrosion, Water System addressed in the GALL Report. The Closed-Serviced by a (including Program Cycle Cooling Water System Program is Closed-Cycle steam) effective in managing these effects/
Cooling Water mechanisms, because it maintains the water System chemistry conditions and purity such that loss of material is minimized. This RNP AMP incorporates some activities under the RNP Open-Cycle Cooling Water System Program.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 39 of 504 TABLE 3.3-2 (continued) AUXILIARY SYSTEMS AGING MANAGEMENT MANAGEMENT PROGRAMS EVALUATED IN THE GALL REPORT THAT ARE RELIED ON FOR LICENSE RENEWAL Component Material Environment Aging Effectl Aging Management Commodity I
I (1)
I Mechanism Program IDiscussion
- 23. SW Boost Pumps; Charging Pumps; Charging Pump Lube Tank; Charging Pump Suction Stabilizers and Pulsation Dampeners; Excess Letdown Heat Exchanger Waterbox: Regen Heat Exchanger Shell and Cover; Seal Inj Filter; Seal Return Filter; Seal Water Heat Exchanger Waterbox; Volume Control Tank; Equip Frames and Housings; Heat/
Cool Coils; Flow Orifices; Valves, Piping, Tubing and Fittings (various systems)
Stainless Steel Indoor - Not Air Conditioned, Containment
- Air, Air and Gas, Borated Water
- Leakage, Outdoor None None Required The RNP AMR determined that these components have no aging effects requiring management for these environments. The applicable RNP environments do not promote concentration of contaminants or include exposure to aggressive chemical species. Boric acid is not an aggressive chemical species for stainless steel.
I1 I
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U. S. Nuclear Regulatory Commission Attachment IIl to Serial: RNP-RA/03-0031 Page 40 of 504 TABLE 3.4-1 STEAM AND POWER CONVERSION SYSTEMS AGING MANAGEMENT EVALUATIONS THAT ARE DIFFERENT FROM OR NOT ADDRESSED IN THE GALL REPORT Componentl Aging Effect/
Aging Management GALL Further Commodity Group Mechanism Program Evaluation Discussion (1)
Recommended
- 10. Heat Loss of material Closed-cycle cooling No Steam Generator Blowdown Sample Heat Exchangers exchangers and due to general water system are in scope only to maintain the pressure boundary coolers/ condensers (carbon steel function of the CCW system. Aging management of the serviced by closed-only), pitting, heat exchangers is via the Closed-Cycle Cooling Water cycle cooling water and crevice System Program and is consistent with the GALL corrosion Report. See Table 3.4-2, Item 7, for galvanic corrosion.
TABLE 3.4-2 STEAM AND POWER CONVERSION SYSTEMS AGING.MANAGEMENT EVALUATIONS THAT ARE DIFFERENT FROM OR NOT ADDRESSED IN THE GALL REPORT Component Material Environment Aging Etfect/
Aging Management Commodity (1)
Mechanism Program Discussion
- 7. Valves, Carbon Treated Loss of Material from Water Chemistry The RNP AMR determined that general,
- Piping, Steel Water General, Galvanic, Program; Closed-galvanic, pitting, and crevice corrosion of
- Tubing, (including Pitting, and Crevice Cycle Cooling Water internal surfaces of carbon steel steam Fittings, and steam)
Corrosion System system components is possible. The Water Flow Elements Chemistry Program is effective in managing in the Main loss of material due to crevice and pitting Steam corrosion for carbon steel, as discussed in System; Table 3.4-1, Item 7. Thus, it would be SDAFW effective in managing loss of material from Turbine; general and galvanic corrosion. Galvanic SGBD Sample Corrosion in the SGBD Sample Heat Heat Exchanger would be effectively managed by Exchanger the Closed-Cycle Cooling Water System as discussed in Table 3.3-2, Item 15.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 41 of 504 RAI 2.3.2.4-1 On piping and instrumentation diagram G-1 90304LR Sheet 1, containment air recirculation cooling system fans HVH-9A and HVH-9B, their suction flowpath (up to the first isolation damper), and their discharge flowpath, are not highlighted as being within the scope of license renewal. These fans and their associated components appear to provide cooling to the reactor vessel, vessel supports, and/or vessel shielding. Please confirm that the intended function of the containment air recirculation cooling system fans HVH-9A and HVH-9B and their associated components does not meet the license renewal scoping criteria of 10 CFR 54.4(a).
RNP Response:
The intended function of the reactor support cooling system fans HVH-9A and HVH-9B and their associated components does not meet the license renewal scoping criteria of 10 CFR 54.4(a).
Specifically, HVH-9A and HVH-9B and their associated components function to remove heat from the reactor vessel, vessel shield, and reactor vessel supports during normal plant operation:
This is accomplished by a flow of air cooled by the recirculation cooling system units, boosted by fans HVH-9A and HVH-9B, and directed upward through the annulus between the surface of the reactor vessel and the primary concrete shield. A portion of this flow is drawn through the reactor supports and then exhausted to the containment. HVAC units HVH-9A and HVH-9B receive non-safety related power from 480V MCC No. 20 and 480V MCC No. 17, respectively.
[Note: The function of providing heat removal from the containment, under postulated accident conditions to assure containment internal pressure does not exceed containment design pressure, is provided by HVAC units HVH-1, HVH-2, HVH-3, and HVH-4, which are part of the Containment Air Recirculation Cooling System. HVAC units HVH-1 and HVH-2 are powered from 480V Emergency Bus El, and HVAC units HVH-3 and HVH-4 are powered from 480V Emergency Bus E2. HVH-1 through -4 are in scope for license renewal as discussed in LRA Section 2.3.2.4.]
Based on the above, HVH-9A and HVH-9B do not perform any license renewal intended functions and do not meet the license renewal scoping criteria of 10 CFR 54.4(a).
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAN03-0031 Page 42 of 504 RAI 2.3.2.4-2 On piping and instrumentation diagram G-190304LR Sheet 1, the abbreviation UV.D." is used (e.g., at grid location E-5) to describe a component which is highlighted as being within the scope of license renewal. However, using the flow diagram legend on piping and instrumentation diagram HBR2-7063LR Sheets 1 & 2, the staff could not conclusively identify this component. Please identify this component type and either (1) identify the component/commodity group in LRA Table 2.3-5 that generically includes this component type, (2) include an additional entry in LRA Table 2.3-5 for this component type, or (3) justify the exclusion of this component type from an AMR in accordance with 10 CFR 54.21 (a)(1).
RNP Response:
The abbreviation NV.D.0 represents the duct subcomponent "volume damper."
The Component/Commodity Group "Ductwork and Fittings" in LRA Table 2.3-5 includes the duct subcomponent "volume damper."
Volume dampers are within the scope of license renewal and subject to an aging management review. Volume dampers are constructed of the same material as the duct in which they reside and are considered to be a subcomponent of the duct. Therefore, volume dampers are included in the aging management review result for ductwork.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 43 of 504 RAI 2.3.2.4-3 On piping and instrumentation diagram G-190304LR Sheet 1, the normal suction flowpath and ventilation dampers for the four containment air recirculation cooling system fans (HVH-1, -2, -3, and -4) are not highlighted as being within the scope of license renewal. However, on the basis of the following statement from UFSAR Section 6.2.2.2.2, it appears that the normal suction flowpath for these containment air recirculation cooling system fans, up to and including the normal suction dampers, should have been highlighted as being within the scope of license renewal:
Air operator multi-bladed dampers are installed in the air inlet to each air handling unit. These dampers and normally open butterfly valves are used to route air flow through units that are operating.
They have only two positions, fully open or fully closed: the damper operation is spring loaded to the closed position required for post-accident operation, the butterfly valves will remain open. Their design permits only nominal air leakage when closed. [emphasis added]
In consideration of 10 CFR 54.4(a) and the above statement from the UFSAR, please justify the exclusion from the scope of license renewal of the ductwork and ventilation dampers identified above. Also, if these items are determined to be within scope, considering 10 CFR 54.21 (a)(1), please identify whether they are included in LRA Table 2.3-5 as being subject to an AMR.
RNP Response:
The subject ductwork and ventilation dampers identified above perform a license renewal intended function per 10 CFR 54.4(a)(1). As such, the following actions will be taken:
1 ) Revision of the license renewal evaluation boundary on the flow diagram boundary drawing G-1 90304LR, Sheet 1, to show the ductwork and ventilation dampers identified above, to be within the evaluation boundary.
- 2) Components within the system intended function boundary that perform an intended function without moving parts or without a change in configuration or properties, i.e., the screening criteria of 10 CFR 54.21(a)(1)(i), will be identified. The passive, in-scope components that are not subject to replacement based on a qualified life or specified time period, i.e., the screening criteria of 10 CFR 54.21 (a)(1)(ii), will be then identified as requiring an aging management review.
- 3) Aging management program requirements will be applied, as required.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 44 of 504 RAI 2.3.2.4-4 On piping and instrumentation diagram G-1 90304LR Sheet 1, the 8 discharge lines from the containment air recirculation cooling system ring header which penetrate the shield wall each appear to be protected by a semi-circular or horseshoe-shaped component at their termination point inside the shield wall. It is not clear from the diagram whether the license renewal boundary includes or excludes this component. Please identify this component type and either (1) identify the component/commodity group in LRA Table 2.3-5 that generically includes this component type, (2) include an additional entry in LRA Table 2.3-5 for this component type, or (3) justify the exclusion of this component type from being considered within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in accordance with 10 CFR 54.21 (a)(1).
RNP Response:
The semi-circular or horseshoe-shaped symbol at the transition from the containment air recirculation cooling system ring header to the 8 distribution ducts, symbolize the transition from the ring header in the horizontal plane to the 8 downward pointing distribution ducts.
No component/commodity group includes this component type, since it is a symbol that depicts the physical relationship of the duct as it branches off of the containment ring header, and therefore no additional entry in LRA Table 2.3-5 is required.
This item is excluded from the scope of license renewal in accordance with 10 CFR 54.4(a), and is not subject to an AMR in accordance with 10 CFR 54.21 (a)(1), since the item is a drawing symbol and does not represent a specific component.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 45 of 504 RAI 2.3.2.5-1 The applicant has not identified hydrogen control as an intended function for the post accident hydrogen system (i.e., by grouping it in the containment isolation system, the applicant has indicated that the only intended function of the post accident hydrogen system is containment isolation). However, UFSAR Section 6.2.5.1 states:
The current licensing basis for hydrogen control is described in UFSAR Section 6.2.5.2.2, the Post Accident Hydrogen Recombiner System. The contribution of the Post Accident Containment Venting System to LOCA offsite dose give[n] in the following UFSAR Section 6.2.5.3 are also retained for historical reference information purposes. The current LOCA offsite dose calculation, based on recombiner operation which eliminates intentional containment venting, is presented in UFSAR Section 16.6.5.5.
This UFSAR citation, and the UFSAR descriptions it references, apparently indicate that the hydrogen recombiners are relied upon in the plant's current safety analysis to prevent the accumulation of a combustible concentration of hydrogen within the containment building. Therefore, according to the criterion of 10 CFR 54.4(b), please justify not considering the hydrogen control function of the post accident hydrogen system (specifically, the recombination of hydrogen with the hydrogen recombiners) as an intended function for license renewal.
RNP Response:
As described within UFSAR 6.2.5.1, hydrogen control is considered to be a mitigative function following a LOCA. However, the hydrogen control systems do not perform an intended function for license renewal as discussed in the following paragraphs.
As further noted within UFSAR 6.2.5.1, systems have been installed to prevent the hydrogen concentration from achieving flammable or explosive concentrations.
The systems that could be used to control hydrogen are the external/portable hydrogen recombiner (with associated piping valves, fittings, and electrical power and controls) and the post accident containment venting system. After the connections for the external hydrogen recombiner had been installed in accordance with the requirements of 10 CFR 50.44, the recombiner system became the preferred method for hydrogen control, because it did not involve the intentional venting of containment to the environs. The venting option was retained in the event that the recombiner system is not available. Design and
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 46 of 504 operation of the post accident containment venting system is described in UFSAR Section 6.2.5.1 only for historical purposes.
Because the design basis buildup of hydrogen in containment is such a slow process, the installation of the external hydrogen recombiner is considered to be a long-term, recovery action. During the 54-day period that hydrogen is calculated to reach 3 volume percent, there is ample time to obtain the hydrogen recombiner skid, hookup the recombiner electrically, remove blind flanges, position valves, and inspect and install the connecting piping. There is sufficient time to assure that all components of the recombiner system are operable before the system is required to be placed in operation. (Reference UFSAR Section 6.2.5.2.2.1).
Because the employment of the recombiner is essentially a recovery action, there is no need to design and construct the recombiner or its electrical and mechanical support systems to safety-related, quality class A requirements. Nor is there any requirement to consider single failures. Only the containment isolation components in the recombiner flowpath are safety related, because of the containment isolation function.
The recombiner and support system mechanical and electrical support components are not safety related. Failure of the system is not assumed because the operation of the recombiner system is a long-term recovery action.
Also, the system is not relied on to perform a function to demonstrate compliance with a license renewal regulated event. Therefore, they do not perform any intended functions for license renewal.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 47 of 504 RAI 2.3.2.5-2 The applicant has not included within the scope of license renewal the pressure-boundary components of the post accident hydrogen system flowpath that are associated with the hydrogen control intended function, except those components needed to effect containment isolation. The long-lived, passive, pressure-boundary components of this flowpath on piping and instrumentation diagram HBR2-06933LR Sheet 1 that appear to support the hydrogen control intended function include tubing, piping, valve bodies, and equipment housings for blowers, filters, and recombiners. In consideration of the scoping criteria of 10 CFR 54.4(a), please justify the exclusion of any safety-related and non safety-related pressure-boundary components associated with the hydrogen control intended function that have not been included within the scope of license renewal. Also, if any additional components are brought within scope, please identify whether they are subject to an AMR in accordance with 10 CFR 54.21 (a)(1).
RNP Response:
Refer to the RNP Response to RAI 2.3.2.5-1.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 48 of 504 RAI 2.3.2.5-3 The applicant has not included within the scope of license renewal the components supporting the post accident hydrogen system that appear to be necessary to operate the pneumatic containment isolation valves and other pneumatic valves needed for the accomplishment of the hydrogen control intended function. The components on piping and instrumentation diagram HBR2-06933LR Sheet 1 that appear to be needed to operate valves to accomplish the hydrogen control intended function include nitrogen bottles, valves, piping, tubing, and fittings. In consideration of the scoping criteria of 10 CFR 54.4(a), please justify the exclusion of any safety-related or non safety-related components supporting the hydrogen control intended function that have not been included within the scope of license renewal. Also, if any additional components are brought within scope, please identify whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
RNP Response:
The installation and subsequent operation of the external hydrogen recombiner and operation of the pneumatic containment isolation valves and other pneumatic valves needed for accomplishment of post accident containment hydrogen control is considered to be a long-term, recovery action. Therefore, components used to operate the subject valves do not perform LR intended functions.
Should hydrogen gas be generated post accident, the hydrogen recombiner system will be used as the primary means of controlling combustible gas concentration in the containment. Nitrogen gas is provided for valve operation by two nitrogen cylinders and associated regulators and piping. The nitrogen cylinders are located in close proximity to the control panels for valve operation, although only one cylinder is in operation at a time. When in service, nitrogen cylinder pressure is checked every eight hours. Utilization of the nitrogen gas to provide the motive force for valve operation is controlled by RNP operating procedures, for post accident containment hydrogen reduction.
Refer to RAI 2.3.2.5-1 for discussion of post accident containment hydrogen control as a long-term, recovery action.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 49 of 504 RAI 2.3.2.5-4 The applicant has apparently not included the hydrogen analyzers and their supporting components within the scope of license renewal. However, based upon the following descriptions from Section 6.2.5 of the UFSAR, it appears that the hydrogen analyzers provide an intended hydrogen monitoring function that is necessary to support the hydrogen control function, both through ensuring that a safe concentration of hydrogen exists at the recombiner influent, and by ensuring that recombiner operation occurs as required to prevent an excessive concentration of hydrogen in containment:
Nitrogen can be introduced to the recombiner influent so as to dilute the process flow to maintain a hydrogen concentration of no greater than 4.0 percent by volume. Hydrogen concentration in the recombiner effluent is less than 0.1 percent. The recombiner will be operated as needed to maintain a safe limit of hydrogen concentration inside containment.
A containment hydrogen monitoring system is capable of measuring hydrogen concentration in the containment atmosphere continuously over the range 0 to 10 percent hydrogen when the containment is within -4.7 psig to 42 psig. Remote indication is provided in the Control Room.
In consideration of 10 CFR 54.4(b) and the above statements from the UFSAR, please justify excluding the intended function of hydrogen monitoring from the scope of license renewal.
RNP Response:
The hydrogen analyzers and their supporting components are part of the Post-Accident Monitoring System. The Post-Accident Monitoring System is considered to be in-scope for license renewal as shown in LRA Table 2.2-3, License Renewal Scoping Results For Electrical/l&C Systems. The subject system is in scope for license renewal because it contains Regulatory Guide 1.97, Category 1 components required to follow the course of an accident. The hydrogen analyzers and their supporting components perform an intended function and are therefore considered to be within the system intended function boundary.
Note: The Post-Accident Monitoring System is entirely an electrical/l&C system.
There are no pressure-boundary components associated with the Post-Accident Monitoring System and there are no pressure-boundary components associated with the hydrogen monitoring intended function, since the hydrogen analyzers are located in the containment.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 50 of 504 The screening process determined those components that perform an intended function without moving parts or without a change in configuration or properties, i.e., the screening criteria of 10 CFR 54.21(a)(1)(i). The passive, in-scope components that are not subject to replacement based on a qualified life or specified time period, i.e., the screening criteria of 10 CFR 54.21 (a)(1 )(ii), are then identified as requiring an aging management review.
In order to determine which electrical components are passive, the screening criteria of 10 CFR 54.21 (a)(1)(i) was applied to the subject electrical components along with guidance from Appendix B of NEI 95-10, and the Standard Review Plan (NUREG 1800).
Appendix B of NEI 95-10 indicates that hydrogen analyzers do not meet the criteria of 10 CFR 54.21 (a)(1)(i). The insulated cables and connections and electrical/l&C penetration assemblies associated with the analyzers meet the screening criteria of 10 CFR 54.21 (a)(1 )(i), but do not meet the screening criteria of 10 CFR 54.21 (a)(1)(ii), because they have a qualified life.
The insulated cables and connections and electrical/l&C penetration assemblies associated with the hydrogen analyzers are electrical components in the RNP EQ program (10 CFR 50.49) and have a qualified life based on their installed configuration. Electrical components included in the RNP EQ program have a qualified life and are replaced before the end of their qualified life.
Components in the RNP EQ program do not meet the "long-lived" criteria of
§54.21 (a)(1)(ii) and are, therefore, "short-lived" by regulatory definition.
Therefore, EQ program components do not meet the screening criteria of
§54.21 (a)(1)(ii) and are not subject to AMR. The RNP EQ program is described in the UFSAR, Section 3.11. Components in the RNP EQ program are considered time-limited aging analyses (TLAAs) as defined in 10 CFR 54.3, and are addressed as such in Section 4.0 of the LRA.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAN03-0031 Page 51 of 504 RAI 2.3.2.5-5 The applicant has apparently not included within the scope of license renewal the pressure-boundary components of the post accident hydrogen system flowpath that are associated with the hydrogen monitoring intended function. Considering the scoping criteria of 10 CFR 54.4(a), please justify the exclusion from the scope of license renewal of any safety-related and non safety-related components that support the hydrogen monitoring intended function. Also, if any additional components are brought within scope, please identify whether they are subject to an AMR in accordance with 10 CFR 54.21 (a)(1).
RNP Response:
The hydrogen analyzers and their supporting components are part of the Post-Accident Monitoring System. The Post-Accident Monitoring System is considered to be in-scope for license renewal as shown in LRA Table 2.2-3, License Renewal Scoping Results For Electrical/l&C Systems.
The Post-Accident Monitoring System is entirely an electricaVl&C system. There are no pressure-boundary components associated with the Post-Accident Monitoring System and there are no pressure-boundary components associated with the hydrogen monitoring intended function, since the hydrogen analyzers are located in the containment.
Refer to the RNP Response to RAI 2.3.2.5-4 for a discussion of the electricaVl&C components associated with the hydrogen analyzers.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 52 of 504 RAI 2.3.2.5-6 On piping and instrumentation diagram G-190304LR Sheet 1, for both the containment pressure relief system and containment vacuum breaker system, a debris screen is located between the containment atmosphere and the inboard containment isolation valve. Section 9.4.3.2.7 of the UFSAR, entitled "Containment Pressure and Vacuum Relief System," describes the filtration intended function of these debris screens as follows:
The butterfly valves are protected by debris screens, located inside containment and attached to the inboard pressure and vacuum relief valves, which will ensure that airborne debris will not interfere with their tight closure.
Considering the above UFSAR description and 10 CFR 54.4(a), please justify the exclusion from the scope of license renewal of the debris screens for the butterfly valves, as well as the piping between the screens and the valves. Additionally, if the debris screens and intervening piping are determined to be within scope, considering 10 CFR 54.21 (a)(1), please identify whether they are subject to an AMR.
RNP Response:
The subject containment isolation butterfly valve debris screens and intervening piping perform a license renewal component intended function and will be subject to AMR. The component intended function of the subject screens is to provide filtration. The component intended function of the intervening piping is to provide pressure boundary.
The intervening piping material and environment was already included in the existing AMR, as it is an extension of the piping already within the evaluation boundary. As such, no additional aging effects were identified for the intervening piping. Therefore, no additional aging management program requirements were identified.
The debris screens were added to the RNP LR AMR. No aging effects were identified for the stainless steel debris screens. Therefore, no additional aging management program requirements were identified.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 53 of 504 RAI 2.3.3.1-1 Traps T-56A, B and C are shown on the Containment Vapor and Pressure Sampling System flow diagram (HBR2-6490LR) within the scope of components that require an AMR because they provide a pressure-retaining function. These safety-related components are relied on to remain functional during and following design basis events to provide samples and containment pressure. However, theses traps are not listed in Table 2.3-7 as components requiring an AMR.
Identify where the LRA addresses the AMR for these components, or provide a justification for excluding these Traps from an AMR.
RNP Response:
The components are listed on Table 2.3-7 and are included in the Component/Commodity Group "Valves, Piping, Tubing and Fittings" of the Containment Vapor and Pressure Sampling System.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 54 of 504 RAI 2.3.3.1-2 The Sampling System flow diagram 5379-353LR Sheet 1 does not show the following safety-related piping as within the scope of primary sampling system components that require an AMR because they provide a pressure-retaining function. These safety-related components are relied on to remain functional during and following design basis events to provide primary system samples.
Identify where the LRA addresses the AMR for these components, or provide a justification for excluding these components from an AMR.
The piping not shown within the scope of AMR is (a) between valve PS-951 and P-29, (b) between valve PS-953 and P-30, (c) between valves PS-955A/B and P-31, (d) between PS975 and PS-977 and PS-976, (e) between PS-974B and PS-988, and (f) between PS-969B and PS-985.
RNP Response:
The primary sampling system provides the representative samples for analysis to evaluate reactor coolant, auxiliary coolant, steam and chemical and volume control systems' chemistry during normal operation. The system operates manually, on an intermittent basis. Samples can be withdrawn continuously or obtained as grab samples under conditions ranging from power operations to cold shutdown. The system provides a central location to obtain samples for analysis from the various systems in the plant. The system is not required for safe shutdown or to mitigate the consequences of an accident, and is therefore classified as a non-safety related system. However, the sample lines that interface with safety related systems are provided with isolation valves, and those that penetrate the containment are provided with two isolation valves in series outside the containment which close upon actuation of the containment isolation signal. Valves that are actuated closed by the containment isolation signal are PS-956A through PS-956H. The valves that provide isolation to the safety related systems are PS-951, PS-953, PS-955A through PS-955E, and PS-959. Primary sample system manual valves PS-976, PS-977, PS-988, and PS-989D are the safety related boundary valves for the CVCS. Components of the primary sampling system downstream of valves PS-956B, PS-956D, PS-956F, PS-956H, PS-959, PS-976, PS-977, PS-988, and PS-989D are non-safety related.
Based on the above, the function described in the RAI to provide primary system samples during and following the design basis events is not a system intended function at RNP. The system function does not meet the safety related criteria in 10 CFR 54.4(1)(a) (1) (i)-(iii). The system interfaces with CVCS piping that performs a LR pressure boundary function and those that do not perform such a function. CVCS flow diagram 5379-685LR, Sheet 2 (F-8), shows that the first interface isolation valve, PS-975, serves such a function. Conversely, the same
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 55 of 504 flow diagram shows that valves PS-974B and PS-969B are interface valves with portions of the system that provide no CVCS intended function.
The primary sampling system is in scope based on the following mechanical system intended functions:
- Maintain RCS pressure boundary Provide containment isolation Provide a pressure-retaining boundary to prevent spatial interactions with safety related equipment The portion of the system relied upon to support the maintenance of the RCS pressure boundary is defined by the class 1 components within the system. As shown on the referenced LR flow diagram, this boundary ends at valves PS-951, PS-953, PS-955A and PS-955B. The penetration and the downstream piping, including the double isolation valves as illustrated by the highlighted portion outside the CV (5379-353LR Sheet 1), support the containment isolation function.
The portion of piping inside the CV from the class 1 boundary to the containment penetration, and the piping within the RAB, do not require an AMR since they do not have spatial interaction with safety-related equipment as presented in Attachment V of RNP-RA/02-0159, Letter from J. Moyer (CP&L) to NRC, "Supplement to Application for Renewal of Operating License," dated October 23, 2002.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 56 of 504 RAI 2.3.3.2-1 The following components are shown on the Service Water System flow diagram G-190199LR Sheets 4, 5, 6, 9 and 10 as within the scope of service water components that require an AMR because they provide a pressure-retaining function. These safety-related components are relied to remain functional during and following the design basis events to provide cooling (ultimate heat sink).
However, these are not listed in Table 2.3-8 as components requiring an AMR, nor is it identified where they are addressed. Identify where the LRA addresses the AMR for these components, indicate LR boundaries, or provide a justification for excluding these components from an AMR.
The components not listed in Table 2.3-8 are Containment Air Recirculating Units
( HVH-1, 2, 3, and 4), Safety Injection Pumps A,B,C and Air Recirculating Cooling Units (HVH-6A and 6B), Diesel Generator Air Coolers (A and B), Lube Oil Coolers (A and B) and Water Jacket Heat Exchanger (A and B), Auxiliary Feed Water Pumps and Oil Coolers (A and B), Components Cooling Heat Exchanger A and B, Air Recirculating Units (HVH-7A and 7B), Equipment Room Water Coolers (WCCU-1A and 1B), RHR Air Recirculating Cooling Units (HVH-8A and 8B),and Steam Driven AFW Pump Oil Coolers.
RNP Response:
Generally, plant coolers and heat exchangers within the scope of license renewal are subject to environments from two separate systems. These components are shown on the plant flow diagrams for their respective parent systems. Typically, these components are also depicted on the interfacing system's flow diagram using dashed lines. The dashed lines identify 'out of system" components (as described on License Renewal drawing HBR2-7063LR, Sheet 1 of 2).
Accordingly, many of the heat exchangers and coolers interfacing with the SWS are depicted on the Service Water flow diagrams as well as the corresponding system flow diagram. These components are included in the evaluations for their respective systems and therefore are not included in Table 2.3-8. The subject components are included in the appropriate LRA table as follows:
- Containment Air Recirculating Units (HVH-1, 2, 3, and 4) - LRA Table 2.3-5 (see boundary drawing G-1 90304LR, Sheet 1 of 4)
- Si Pumps A, B, C - LRA Table 2.3-3 (see boundary drawing 5379-1082LR, Sheet 2 of 5)
- Air Recirculating Cooling Units (HVH-6A and 6B) - LRA Table 2.3-18 (see boundary drawing G-190304LR, Sheet 2 of 4)
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 57 of 504
- Diesel Generator Air Coolers (A and B) - Although these are identified as "air coolers" on Service Water Boundary Drawing G-1 90199LR (Sheet 6 of 13), the components interfacing with the SWS are the iAftercoolant Heat Exchangers (A and B)" as identified on boundary drawing G-1 90204ALR Sheet 3 of 3. These heat exchangers are included in the LR boundaries for the Diesel Generator system and are therefore listed in LRA Table 2.3-22.
- Lube Oil Coolers (A and B) and Jacket Water Heat Exchanger (A and B) -
LRA Table 2.3-22 (see boundary drawing G-1 90204ALR Sheet 3 of 3)
- Auxiliary Feed Water Pumps and Oil Coolers (A and B) - LRA Table 2.3-29 (see boundary drawing G-1 90197LR Sheet 4 of 4)
- Component Cooling Water Heat Exchangers (A and B) - LRA Table 2.3-9 (see boundary drawing 5379-376LR Sheet 1 of 4)
- Air Recirculating Units (HVH-7A and 7B) - LRA Table 2.3-18 (see boundary drawing G-1 90304LR Sheet 2 of 4)
- Control Room Refrigeration Units (WCCU-1 A and 1 B) - LRA Table 2.3-19 (see boundary drawing G-190304LR, Sheet 4 of 4)
- RHR Air Recirculating Units (HVH-8A and 8B) - LRA Table 2.3-18 (see boundary drawing G-1 09304LR, Sheet 2 of 4)
- Steam Driven AFW Pump Oil Cooler - LRA Table 2.3-29 (see boundary drawing G-1 90197LR, Sheet 4 of 4)
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 58 of 504 RAI 2.3.3.2-2 The Service Water System flow diagram G-190199LR Sheet 3 does not show the following safety-related components as within the scope of service water components that require an AMR because they provide a pressure-retaining function. These safety-related components are relied on to remain functional during and following design basis events to provide cooling (ultimate heat sink).
Identify where the LRA addresses the AMR for these components, indicate LR boundaries, or provide a justification for excluding these components from an AMR.
The components not shown within the scope of AMR are penetrations Feedwater S-43, S-44 and S-45; RC Sample S-22; SG Blowdowns S-26, S-30 and S-24; Letdown Line S-27; RH Removal S-15 RC Pump Seal Water S-19, and Fl 1975A, B and C, Fl 1979, Fl 1978A, B and C, Fl 1977, Fl 1976 and Fl 1980, and the connecting piping.
RNP Response:
Penetration coolers and connected piping (including flow instrumentation) are not required to support a system intended function. Refer to UFSAR Section 9.2.1.2, Item i, which states that the SW flow to the containment piping penetration coolers is isolated.
U. S. Nuclear Regulatory Commission Attachment liI to Serial: RNP-RA/03-0031 Page 59 of 504 RAI 2.3.3.3-1 Table 2.3-9 of the component cooling water system list the heat exchangers whose tubes and shells are within the scope of components requiring an AMR because they provide a pressure-retaining function. These safety-related components are relied on to remain functional during and following design basis events to provide cooling to essential components. However it does not list the tube sheets of these heat exchangers as (except the component cooling water heat exchangers) requiring an AMR. Identify where the LRA addresses the AMR for these heat exchangers tube sheets, or provide a justification for excluding these tube sheets from an AMR.
RNP Response:
The Hot Leg Sample Heat Exchanger, PZR Steam Sample Heat Exchanger, PZR Liquid Sample Heat Exchanger, Sample Vessel Heat Exchanger, and SG Blowdown Sample Heat Exchangers do not have tube sheets. These heat exchangers are shell and cover (flanged) cooler-type heat exchangers. The cooling coils (tubing) pass directly through the flanged cover into the shell.
The CRDM Cooling System Cooler also does not have a tube sheet.
The SFP Cooling Heat Exchanger the Non Regenerative Heat Exchanger, and the Waste Gas Compressor Coolers have tube sheets that were not identified in the initial submittal. Since the initial submittal, the RNP LR evaluation has been updated to include these corrections, in addition to other corrections relating to heat exchangers.
Also, see the RNP Response to RAI 2.3.2.3-3.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 60 of 504 RAI 2.3.3.3-2 The following components are shown on the component cooling water system flow diagram 5379-376LR Sheets 1, 2, 3, and 4 as within the scope of components that require an AMR because they provide a pressure-retaining function. These safety-related components are relied on to remain functional during and following design basis events to provide cooling to essential components. However, these are not listed in Table 2.3-9 as components requiring an AMR, nor is it identified where they are addressed. Identify where the LRA addresses the AMR for these components, or provide a justification for excluding these components from an AMR.
The components shown but not listed in Table 2.3-9 are charging pumps heat exchangers, reactor coolant heat exchanger, residual heat removal heat exchangers, seal water heat exchanger, reactor coolant pumps, excess letdown heat exchanger, residual heat removal pump coolers, containment spray pump coolers, and high head safety injection pump coolers.
RNP Response:
As a general rule, components (such as heat exchangers) interfacing with two systems will be shown with solid lines on the boundary drawing for its parent system and will also be shown on the interfacing system's boundary drawing using dashed lines. In some cases, the subject component is required to support the system intended functions for both the parent system (such as heat transfer and pressure boundary) and the interfacing system (usually pressure boundary only). The convention used by RNP LR in such a case is to include the component with its parent system. If the component is not required to support its parent system's intended function, but is only in scope to support the pressure boundary intended function for the interfacing system (as is the case for the Hot Leg Sample Heat Exchanger), then the general convention is to include the component with the interfacing system whose system intended function it supports. Using this convention, the following clarifications are provided for the heat exchangers in question.
- Charging Pumps Heat Exchangers, Seal Water Heat Exchanger, and Excess Letdown Heat Exchanger - Included in the CVCS system (see LRA Table 2.3-10).
Reactor Coolant Heat Exchanger - More specifically, this is the "Hot Leg Sample Heat Exchanger." Since this heat exchanger supports only the CCW system intended function, it is listed in the CCW system (see LRA Table 2.3-9).
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 61 of 504 RHR Heat Exchangers and RHR Pump Coolers - Included in the RHR system (see LRA Table 2.3-2).
- Seal Water Heat Exchanger and Excess Letdown Heat Exchanger -
Included in the CVCS system (see LRA Table 2.3-10).
- Reactor Coolant Pumps - Included in the RCS system (see LRA Table 2.3-1).
- Containment Spray Pump Coolers - Included in the CSS (see LRA Table 2.3-4).
- High Head Si Pump Coolers - Included in the Si system (see LRA Table 2.3-3).
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 62 of 504 RAI 2.3.3.5-1 Accumulators are shown on the Instrument Air System flow diagram G-190200LR Sheet 9 as within the scope of components requiring an AMR because they provide a pressure retaining boundary. These safety-related components are relied on to remain functional during and following design basis events to provide a back-up source of air to essential components. However, these are not listed in Table 2.3-11 as components requiring an AMR, nor is it identified where they are addressed. Identify where the LRA addresses the AMR for these components, or provide a justification for excluding these components from an AMR.
RNP Response:
The subject accumulators are shown on the Instrument and Service Air flow diagram G-190200LR Sheet 9, within the scope of components requiring an AMR. The accumulators are the pressurizer nitrogen supply accumulator"A" and the pressurizer nitrogen supply accumulator "B." The components are listed on Table 2.3-12.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 63 of 504 RAI 2.3.3.6-1 Steam Dump Nitrogen Accumulators and connecting piping are shown on the Nitrogen Supply System Flow Diagram HBR2-8606LR Sheet 2 as within the scope of components requiring an AMR as they provide a pressure retaining boundary. However, no safety-related boundary is shown on the flow diagram for the connecting piping. Identify the safety-related piping boundary on the flow diagram or provide justification for excluding the remaining portion of the connecting piping that is not included.
RNP Response:
The Steam Dump Nitrogen Accumulator is credited with pneumatic supply for the Steam Generator PORVs in the event of an Appendix R fire. While the accumulator itself and the piping along the flow path from the accumulator to the PORVs is in scope for license renewal, branch piping connections are not postulated to fail during an Appendix R fire and are outside intended function evaluation boundaries.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 64 of 504 RAI 2.3.3.6-2 Pressurizer Nitrogen Accumulator Tank is listed on Table 2.3-12 as within the scope of components requiring an AMR because it provides a pressure retaining boundary. This safety-related component is relied on to remain functional during and following design basis events to provide a back-up source of nitrogen to essential components. However it is not shown on the Nitrogen Supply/Blanketing System flow diagram HBR2-08606LR sheet 2 referenced in the above system for LRA. Identify the flow diagram where it is shown within the scope of components requiring an AMR.
RNP Response:
The Pressurizer Nitrogen Supply Accumulator "A" and "B" are shown on flow diagram G-1 90200LR, Sheet 9, within the scope of components requiring an AMR.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 65 of 504 RAI 2.3.3.7-1 Section 2.3.3.7 of the LRA states that the evaluation boundaries for the portions of the Radioactive Equipment Drains that are within the scope of license renewal were determined on the basis of its function following actuation of fire suppression systems in the Reactor Auxiliary Building, as described in UFSAR Appendix 9.5.1 B, and that no flow diagrams were used to determine the evaluation boundaries. Appendix 9.5.1 B to the H. B. Robinson, Unit 2, UFSAR states that, based on evaluation of two pipe break locations that typify the areas with water-filled pipe in the auxiliary building, the floor drain system will prevent flooding of electrical safety-related equipment on the second floor.
However, 10 CFR 54.21 requires that components subject to an aging management review be listed in the application or included by reference. The LRA fails to specifically identify the components within the radioactive equipment drains system subject to an AMR other than by listing "piping and fittings" in Table 2.3-13 of the LRA. Clarify which specific piping sections and fittings are within the scope of license renewal and subject to an AMR and how these sections were found to provide protection against flooding from pipe breaks within the auxiliary building.
RNP Response:
The Radioactive Equipment Drain System is comprised of piping and fittings embedded in the RAB, as well as any connected exposed piping, and these piping sections and fittings are considered to be within the scope of license renewal and subject to an AMR.
A description of flooding effects from pipe breaks within the RAB is provided by letter from E. Utley (CP&L) to NRC, Serial NO-80-896: "Fire Protection Program,"
dated June 12, 1980, and accepted by the NRC in the Safety Evaluation Report supplement dated December 8, 1980.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 66 of 504 RAI 2.3.3.7-2 Section 2.3.3.7 of the LRA states that portions of the radioactive equipment drains piping is embedded in concrete and considered to be part of the reactor auxiliary building structure and will be screened as a civil commodity. However, LRA Table 2.4-2, which lists component commodity groups subject to an AMR does not include embedded piping with a pressure boundary intended function to maintain free flow of water through the equipment drains system. Clarify which portions of the embedded piping are included within the scope of license renewal and subject to an AMR, the intended function of this embedded piping, and which aging management programs apply to the embedded piping.
RNP Response:
The portion of the REDS piping included within the scope of license renewal and subject to an AMR includes both embedded and exposed piping and is described in the RNP Response to RAI 2.3.3.7-1.
The intended function of the REDS that is relied upon in the safety analyses or plant evaluations is to perform a function that demonstrates compliance with the Commission's regulations for Fire Protection. To accomplish this intended function, the REDS drains rooms in the RAB following a postulated fire header rupture to equalize flooding elevations and protect electrical equipment from flooding. Maintaining the drains and piping clear accomplishes this function.
Therefore, the intended function of the embedded piping is to provide a pressure-retaining boundary so that sufficient flow at adequate pressure is delivered.
The embedded piping external surface was subject to AMR via the aging management review of civilstructural components and commodities since the piping was in a stainless steel materiaVembedded concrete environment. No aging effects were identified for the subject stainless steel piping and fittings, and therefore no aging management programs were applied.
The exposed piping external surface was subject to AMR via the aging management reviews of mechanical components and commodities since the piping was in a stainless steel material/air environment. No aging effects were identified for the subject stainless steel piping and fittings, and therefore no aging management programs were applied.
The piping internal surface was subject to AMR via the aging management reviews of mechanical components and commodities since the piping was conservatively assumed to be in a stainless steel material/raw water environment. Aging effects were identified for the subject stainless steel piping and fittings, as follows:
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 67 of 504 Loss of Material due to Crevice Corrosion
- Loss of Material due to MIC
- Loss of Material due to Pitting Corrosion Crevice corrosion, pitting corrosion, and MIC only cause loss of material and will not affect the intended function of the REDS. It can therefore be concluded that while crevice corrosion, pitting corrosion and MIC are credible aging mechanisms for the REDS, they do not affect the intended function of the REDS, and therefore, do not require management for the period of extended operation.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 68 of 504 RAI 2.3.3.8-1 Section 10.4.8 of the H. B. Robinson, Unit 2, Updated Final Safety Analysis Report (HBR 2 UFSAR) states:
In the event of a failure of Lake Robinson Dam, shutdown would be accomplished in an orderly manner using the condensate storage tank. When the condensate storage tank reaches a low level limit, auxiliary feedwater pump suction would be changed to the deepwell pump discharge. This source would provide the required feedwater indefinitely or until such time that some other source of feedwater can be established. It is assumed that emergency power is not required for this accident.
Section 9.2.3 of the HBR 2 UFSAR describes that three parallel deepwell pumps are part of the primary and demineralized water system. Section 2.3.3.8 of the LRA states that the primary and demineralized water system is in scope because it contains:
- 1. SCs that are safety-related and are relied upon to remain functional during design basis events
- 2. SCs which are non safety-related whose failure could prevent satisfactory accomplishment of the safety-related functions
- 3. SCs that are relied in during postulated fires and station blackout events Table 2.3-14 of the LRA identifies valves, piping, and fittings of the primary and demineralized water system necessary to provide a pressure retaining boundary so that sufficient flow at adequate pressure is delivered as components subject to an aging management review. However, the associated LR flow diagram, G-1 90202LR, Sheet 3, indicates that only the safety-related section of piping from the auxiliary feedwater pump suction to and including valve DW-21 is within LR scope. Please clarify whether the non-safety-related piping, valve bodies, and pump casings necessary to provide a pressure retaining boundary from the deepwell pumps to valve DW-21 are included within the scope of license renewal and subject to an AMR or justify their exclusion.
RNP Response:
The components that require aging management review for the primary and demineralized water system are as shown on LR flow diagram, G-190202LR, Sheet 3. The deepwell pumps and associated flow paths are not highlighted on the drawing, because they do not perform license renewal intended functions.
The discussion of a potential failure of the Lake Robinson Dam, in UFSAR Section 10.4.8, is intended to provide information regarding the capability of RNP
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 69 of 504 to provide steam generator makeup water from multiple sources. In this case, the UFSAR is discussing capabilities beyond the design basis of the plant, as failure of the dam is not required to be postulated for any RNP event scenarios.
The Lake Robinson Dam is a non-safety related structure that has been evaluated to assure its capability to function during and following a design basis earthquake. Thus, failure of the dam as a result of seismic forces is not assumed. Failure of the dam is an initiating event has been investigated with respect to the RNP Individual Plant Examination for External Events (IPEEE),
however, IPEEE events are not considered to be part of the plant's design basis.
The safety-related SWS provides cooling water for safe plant shutdown, including the long-term backup supply of water to the AFW system from the UHS for the plant. The UHS for RNP is Lake Robinson. The function of supplying safety-related SWS flow is supported by the Lake Robinson Dam, which is in scope for license renewal and monitored by an aging management program as discussed in LRA Subsections 2.4.2.10 and B.3.16.
Section 2.1.3.1.2 of the SRP-LR, NUREG-1800, April 2001, discusses the scoping of non-safety related SSCs and quotes from the Statements of Consideration applicable to 10 CFR 54. One of these quotations is intended to clarify the NRC's intent for this requirement and states:
The inclusion of nonsafety-related systems, structures, and components whose failure could prevent other systems, structures, and components from accomplishing a safety function is intended to provide protection against safety function failure in cases where the safety-related structure or component is not itself impaired by age-related degradation but is vulnerable to failure from the failure of another structure or component that may be so impaired.
By including the Lake Robinson Dam in scope for license renewal, the safety functions of the SWS and the UHS are assured during the period of extended operation as intended by the LR Rule.
Based on the above, failure of the Lake Robinson Dam is not a design basis event for RNP, and the steam generator makeup function provided by the deepwell pumps and associated flow paths, as discussed in UFSAR Section 10.4.8, does not meet the scoping criterion of 10 CFR 54.4(a)(2).
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 70 of 504 RAI 2.3.3.8-2 Section 9.2.2.3.1 of the HBR 2 UFSAR states the following with regard to leakage from component cooling water system heat exchangers:
During normal operation, the leaking exchanger could be left in service with leakage up to the capacity of the makeup line to the system from the primary water treatment plant. By manual transfer, emergency power is available for makeup pump operation.
Section 9.2.2.3.1 of the HBR 2 UFSAR also states:
The severance of a cooling line serving an individual reactor coolant pump cooler would result in substantial leakage of component cooling water. However, the piping is small as compared to piping located in the missile protected area of the containment. Therefore, the water stored in the surge tank after a low level alarm, together with makeup flow, provides ample time for the closure of the valves external to the containment to isolate the leak before cooling is lost to essential components in the component cooling loop.
Section 9.2.3 of the HBR 2 UFSAR describes that the primary makeup water tank provides normal makeup to the component cooling water system. These statements indicate that the current licensing basis for H. B. Robinson, Unit 2,credits the non safety-related supply of makeup water from the primary and demineralized water system to maintain the safety-related component cooling water system operable during anticipated operational occurrences and following design basis accidents. Section 2.3.3.8 of the LRA states that the primary and demineralized water system is in scope because it contains:
- 1. SCs that are safety-related and are relied upon to remain functional during design basis events
- 2. SCs which are non-safety-related whose failure could prevent satisfactory accomplishment of the safety-related functions
- 3. SCs that are relied in during postulated fires and station blackout events Table 2.3-14 of the LRA identifies valves, piping, and fittings of the primary and demineralized water system necessary to provide a pressure retaining boundary so that sufficient flow at adequate pressure is delivered as components subject to an aging management review. However, the primary and demineralized water system LR flow diagram G-1 90202LR, Sheet 3, and component cooling water system LR flow diagram, 5379-376, Sheet 1, indicate that only the safety-related section of piping from valves CC-B32 and CC-711 to the component cooling surge tank header is within LR scope. Please clarify whether the non-safety-related piping, valve bodies, and pump casings necessary to provide a pressure
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 71 of 504 retaining boundary so that sufficient flow at adequate pressure is delivered by the primary makeup water system to the component cooling surge tank are included within the scope of license renewal and subject to an AMR or justify their exclusion.
RNP Response:
The information provided in the referenced sections of the UFSAR provide a description of system capabilities for the CCW system and the Primary and Demineralized Water System. The UFSAR provides information on functional capabilities of various systems; however, not all the functions described meet the criteria for an intended function as defined in the license renewal rule, 10 CFR 54.
Leakage from the CCW system, as discussed in UFSAR Section 9.2.2.3.1, is an anticipated condition, and procedures are in place to mitigate such as occurrence. However, leakage from the system is not a design basis event, and the procedures are intended to cope with a range of CCW degradation up to the complete loss of the system.
Severance of a CCW line, as discussed in UFSAR Section 9.2.2.3.1, also is not a design basis event. The information provided in the UFSAR is intended to show how the system would be operated to mitigate a leak and that the CCW surge tank maintains a volume of water that provides time for the plant operating staff to find and isolate a leak. The design of the surge tank is not based on this scenario. In general, ruptures of piping in moderate energy systems, such as the CCW system, are not assumed to occur as initiating events for design purposes.
Also, severance of a CCW line as a result of the effects of a pipe break in containment is not a postulated event. Evaluations of the CCW lines inside containment were performed following NRC approval of the leak-before-break analysis of RNP reactor coolant system piping in GL 84-04, "Safety Evaluation of Westinghouse Topical Report Dealing with Elimination of Postulated Pipe Breaks in PWR Primary Main Loops," dated February 1, 1984. Based on these evaluations, the CCW lines inside containment were classified as "missile protected," i. e., protected from the effects of postulated ruptures of high energy systems, and considered to be a closed system for purposes of containment isolation.
Based on the above information, the ability to provide makeup water to the CCW surge tank from the Primary and Demineralized Water System is not required for design basis events and, therefore, is not an intended function for license renewal as defined in 10 CFR 54.4(b).
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 72 of 504 RAI 2.3.3.9-1 Spent fuel pools have design features intended to prevent a significant loss of coolant inventory under accident conditions, including: a robust pool structure with a leak resistant liner, a reliable cooling system, and diverse sources of makeup water. These features are within the current licencing basis of each facility, and, because of these features, the consequences of a significant loss of coolant inventory are not typically evaluated in the safety analysis report.
Nevertheless, spent fuel pools contain sufficient energy and radioactive material that a substantial loss of coolant inventory could result in potential offsite exposures comparable to those referred to in 10 CFR 100.11. Therefore, in accordance with 10 CFR 54.4, structures and systems relied on to remain functional during and following design basis events to maintain an adequate coolant inventory within the spent fuel pool are within the scope of license renewal. These structures and systems perform the following functions:
maintain the pool pressure boundary, remove heat, and provide water to makeup for evaporative and leakage losses.
Section 9.1.3.3.1 of the HBR 2 UFSAR states the following with regard to spent fuel pool heat removal:
The SFP temperature and SFP level indicators in the SFP Building and the SFP temperature alarm and SFP level alarm in the control room warn the operator of the loss of cooling or inventory. With no heat removal, the time for SFP temperature to rise from 1 50OF to boiling for a full core discharge which fills the SFP to capacity is approximately 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The warning provided by the instrumentation alarm set points, along with this slow heatup rate, would allow sufficient time to restore adequate cooling. Redundant SFP cooling pumps, along with procedurally established alternate means to supply heat sink water to the SFP heat exchanger, ensure that cooling capability for the SFP can be restored quickly.
Section 9.1.3.3.2 of the HBR 2 UFSAR also states:
The makeup water requirement due to boiling following a complete loss of cooling after a full core offload would be less than 42 gpm.
The SFP large level makeup water source is the refueling water storage tank via the refueling water purification pump. This path has a capacity of 100 gpm which is more than adequate to replace the water lost.
The license renewal boundary diagram for the spent fuel pool cooling system, Drawing 5379-1 485LR, Sheet 1, indicates that the spent fuel pool cooling loop is within the "Q" list and ISI Class 3 boundaries, which are typically associated with safety-related sections of systems. Based on the above information, the staff concludes that the spent
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 73 of 504 fuel pool cooling loop and, at a minimum, piping, valve bodies, and pump casings necessary to deliver makeup water from the refueling water storage tank are within the scope of license renewal and subject to an AMR. However, the license renewal boundary diagram indicates the majority of the cooling loop is outside of the license renewal boundary, and Section 2.3.3.9 of the LRA states that the heat removal function is not an intended function for license renewal. The LRA does not include justification for this determination.
Please add piping, valve bodies, pump casings, and other fittings necessary to support the heat removal function of the spent fuel pool cooling system and provide makeup water addition from the refueling water storage tank to the spent fuel pool to components within the identified scope of license renewal that are subject to an AMR, or justify their exclusion.
RNP Response:
UFSAR Chapter 15 only discusses evaporation makeup requirements without identifying any potential offsite exposures. UFSAR Section 15.7.6 states: 'The evaporative losses are replenished by primary demineralized water from the 150,000 gal primary water storage tank. A redundant supply of makeup is provided by the fire hoses in the vicinity of the spent fuel pit." Although the SFPCS has the capability to be fed by the RWST as described in UFSAR Chapter 9, the RWST provides no safety related function relative to the SFP, and the connected SPFCS piping past the valve isolating the RWST from the SFPCS is non-safety related. Neither the fire protection equipment, nor the primary water sources in the vicinity of the SFP, is classified as safety-related.
A loss of an external source of decay heat removal for the spent fuel pool would not cause a significant public dose unless the SFP water level decreased below the level of the stored fuel and subsequent fuel cladding failure occurred. This would take a minimum of 3 days, over which time, a number of sources of makeup water could be used to compensate for the inventory loss. Among these sources of water are the RWST, the PWST and the fire water system. Based on the above, system functions to provide a source of an external cooling for SPFCS and to provide makeup to the SPF for water inventory control are not safety related functions per the License Renewal Rule, i.e., 10 CFR 54.4(a)(1 )(iii). Consequently, there was no need for including makeup or an external source of cooling as system intended functions.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 74 of 504 RAI 2.3.3.10-1 The applicant has not included the containment purge system within the containment isolation system, which included all plant systems having no intended function other than containment isolation. However, the applicant did not specifically identify the containment isolation intended function nor any other intended function that resulted in the containment purge system being included in the LRA. From Section 9.4.3.2.6 of the UFSAR, the staff located the following description which seems to identify two potential intended functions:
The containment purge valves must be operable and must close within the time limit specified in the IST program in order to limit post LOCA thyroid dose and to limit the increase in peak clad temperature due to reduction in containment internal pressure.
So that the NRC staff may verify that the applicant has properly applied the license renewal scoping and screening criteria in 10 CFR Part 54, please identify the intended functions, in accordance with 10 CFR 54.4(b), of the containment purge system.
RNP Response:
The intended functions, in accordance with 10 CFR 54.4(b), of the containment purge system are as follows:
- Provide containment isolation.
- Relied upon in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for Environmental Qualification (EQ).
- Mitigate fuel handling accident inside containment.
Provide Regulatory Guide, 1.97 Category 1, monitoring variable instrumentation.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 75 of 504 RAI 2.3.3.10-2 On piping and instrumentation diagram G-190304LR Sheet 1, a debris screen is located between the containment atmosphere and the inboard containment isolation valves on the containment purge inlet and containment purge exhaust lines. Section 9.4.3.2.6 of the UFSAR, entitled "Containment Purge System,"
describes the filtration intended function of these debris screens as follows:
The containment isolation butterfly valves are protected by debris screens located inside containment in the purge... ductwork, which will ensure that the airborne debris will not prevent their tight closure.
Considering the above UFSAR description and 10 CFR 54.4(a), please justify the exclusion from the scope of license renewal of the debris screens for the butterfly valves, as well as the ductwork between the screens and the valves.
Additionally, if the debris screens and intervening ductwork are determined to be within scope, considering 10 CFR 54.21 (a)(1), please identify whether they are subject to an AMR.
RNP Response:
The subject containment isolation butterfly valve debris screens and intervening ductwork perform a license renewal component intended function and will be subject to AMR. The component intended function of the subject screens is to provide filtration. The component intended function of the intervening ductwork is to provide pressure boundary.
The intervening ductwork material and environment is already included in the existing AMR, as it is an extension of the ductwork already within the evaluation boundary. As such, no additional aging effects were identified for the intervening ductwork. Therefore, no additional aging management program requirements were identified.
The debris screens were added to the RNP LR AMR. No aging effects were identified for the stainless steel debris screens. Therefore, no additional aging management program requirements were identified.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 76 of 504 RAI 2.3.3.11-1 Ventilation damper housings are not highlighted on ventilation flow diagrams or identified in the license renewal application (LRA) as within scope of license renewal.
While ventilation components such as fan housings and cooling coils are highlighted as within the scope for license renewal, ventilation damper housings are not highlighted on the ventilation flow diagrams referenced in the application. Examples of ventilation damper housings not highlighted on system flow diagrams include the following:
- 1.
Rod drive cooling system flow diagram G-1 90304LR, sheet one of 4 (E3, D3, C3, B4, B5, D5, E5).
- 2.
HVAC auxiliary building system flow diagram G-1 90304LR, sheet two (B4, D4, F4, G4) and sheet three (B6, D7, El, Fl, F8, G6, G7).
- 3.
HVAC control room area flow diagram G-1 90304L, sheet four (C6, D4, E6, E7, F3, F5, F7)
- 4.
HVAC fuel handling building flow diagram G-190304LR, sheet one of 4 (F3, F4, G5)
State whether these components are within the scope of license renewal and subject to an aging management review (AMR). If so, provide the relevant information about the components in order to provide the staff with the ability to coordinate between the component/commodity tables and the flow diagram drawings, thus allowing the staff to complete the review of the aging management tables of the LRA. If the components are not in scope or subject to an AMR, provide justification for their exclusion.
RNP Response:
Ventilation dampers are within the scope of license renewal and are included as follows:
The System Commodity 'Damper Housings" is used to identify damper housings within the scope of license renewal that provide a structural support function.
The System Commodity "DuctworkW is used to identify damper equipment housings within the scope of license renewal that provide a pressure boundary function.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAI03-0031 Page 77 of 504 Ventilation dampers are subject to AMR for the following systems, with the results as indicated in the corresponding aging management review tables of the LRA:
System Screening AMR Component/
Result Result Commodity Containment Table 2.3-5 Table Ductwork and Air 3.3 Fittings Recirculation Item 20 System Containment Table 2.3-16 Table Ductwork and Purge System 3.3 Fittings Item 20 Rod Drive Table 2.3-17 Table Ductwork and Cooling 3.3 Fittings System Item 20 HVAC Table 2.3-18 Table Ductwork and Auxiliary 3.3 Fittings Building Item 20 System HVAC Control Table 2.3-19 Table Equipment Room Area 3.3 Frames and Item 19 Housings HVAC Fuel Table 2.3-20 Table Ductwork and Handling 3.3 Fittings Building Item 20
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 78 of 504 RAI 2.3.3.11-2 The following five passive components associated with ventilation system ductwork are not identified as within the scope of license renewal or subject to an aging management program:
- 5.
Ductwork turning vanes
- 6.
Ventilation system elastomer seals
- 7.
A ventilation equipment vibration isolator flexible connections
- 8.
Ductwork test connections
- 9.
Ductwork access doors State whether these components are within the scope of license renewal and subject to an AMR. If they are, provide the information necessary to complete the aging management review result tables. If these components are not within scope and subject to an AMR, provide justification for their exclusion.
RNP Response:
The System Commodity "Ductwork" is used to identify miscellaneous ductwork components that provide a pressure retaining function. "Ductwork" includes ducts, fittings, access doors, equipment housings, flexible collars or connections, and seals.
Access doors, flexible connections and seals were subject to AMR using the System Commodity "Ductwork" grouping for untagged components in HVAC systems. Ductwork test connections are categorized as fittings. Therefore, ductwork test connections are included in the aging management review result for the System Commodity "Ductwork."
Turning vanes are within the scope of license renewal and are subject to an AMR. Turning vanes are constructed of the same material as the duct in which they reside and are considered to be a subcomponent of the duct. Therefore, turning vanes are included in the AMR result for ductwork.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 79 of 504 RAI 2.3.3.11-3 Clarify whether structural sealants used to maintain the power block building pressure boundary envelope (i.e., main control room, auxiliary building, fuel handling building, containment) at design pressure with respect to the adjacent areas are included in the scope of license renewal and subject to an aging management review. Provide information relating to structural sealants use as referenced in Table 2.1-3 on page 2.1-15 of NUREG-1 800 (Standard Review Plan-License Renewal). The Standard Review Plan states that an applicant's structural aging management program is expected to address structural sealants with respect to an AMR program. If structural sealants are not in the scope of license renewal and subject to an AMR, provide justification for their exclusion.
RNP Response:
This RAI Response is specific to structural sealants used to maintain the power block building pressure boundary envelope (i.e., main control room, RAB, FHB, containment). However, additional information is provided since structural sealants listed in Table 2.1-3 of NUREG-1800 are used in areas that are not part of the pressure boundary envelope.
There are no structural sealants used in the pressure boundary envelop of the plant buildings that are managed for aging under the RNP Structures Monitoring Program.
There are sealants used in the pressure boundary envelope of the plant buildings that are managed by other aging management programs. These include sealants used in fire barrier penetration seals in the control room portion of the RAB and sealants used in the electrical penetrations of the containment. These sealants are considered a subcomponent of the fire barrier penetration seal component and the electrical penetration component. The Fire Protection Program monitors the condition of fire barrier sealants for the control room, and the 10 CFR 50, Appendix J, Program tests for leakage rates through the electrical penetrations of the containment.
There are structural sealants in the scope of license renewal used at other plant locations that are not part of the building pressure boundary. These can be included as consumable items (b) in Table 2.1-3 of NUREG-1800. These include:
Moisture barrier seal in the Containment - managed by the ASME Code Section Xl, IWE Program Roof (membrane or built up) sealants - managed by the Structures Monitoring Program
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 80 of 504
- Seismic joint sealant - managed by the Structures Monitoring Program Concrete construction joint sealants have no license renewal intended functions and are not included in the scope of license renewal.
RNP is consistent with the guidance of item (b) Table 2.1-3 of NUREG-1 800, since structural sealants that perform a license renewal intended function are included in the scope of license renewal, an aging management review has been performed, and an aging management program has been identified as listed above.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAI03-0031 Page 81 of 504 RAI 2.3.3.13-1 Ductwork in the HVAC control room area system is identified on ventilation system flow diagrams referenced in the LRA as within the scope of license renewal. Ductwork performs the intended function of a pressure boundary.
However, it is not included in the aging management review results Table 2.3-19 of the LRA. State whether the HVAC control room area system ductwork is subject to an AMR and provide the relevant information about this component to enable the staff to complete its review of the aging management review results table in the LRA. If ductwork is not subject to an AMR, provide justification for its exclusion.
RNP Response:
Ductwork in the HVAC control room area system is subject to an aging management review, because:
- The ductwork performs an intended function within the license renewal evaluation boundary, as shown on the flow diagram boundary drawings;
- and,
- The ductwork is a passive component not subject to periodic replacement.
The ductwork is presently included in the Component/Commodity group, "Equipment Frames and Housings" in LRA Table 2.3-19. To eliminate any confusion, the Component/Commodity group "Ductwork and Fittings" has been added to the HVAC control room area system and the ductwork will be moved from the "Equipment Frames and Housings" group to the "Ductwork and Fittings" group. The AMR result remains unchanged for the HVAC control room area system ductwork.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAI03-0031 Page 82 of 504 RAI 2.3.3.13-2 The safe shutdown controls are identified in sections 9.4.2.2.1 and 9.4.2.3 of the UFSAR. The Robinson UFSAR states that in case of fire within the control room fire zone, the control room may be evacuated and the plant shutdown from the safe shutdown controls provided in other areas of the plant. The ventilation systems used to support use of the safe shutdown controls have not been included as part of the scoping and screening process. State whether the ventilation systems used to support the safe shutdown controls are within the scope license renewal and subject to an AMR in accordance with 10CFR54.4(a)(1) and (a)(2). If so, provide the relevant information about the components to enable the staff to complete its review of the aging management review result tables in the LRA. If the ventilation systems used to support the safe shutdown controls are not in the scope of license renewal and subject to an AMR, provide justification for their exclusion.
RNP Response:
Both the RAB HVAC and Control Room HVAC Systems are in scope for license renewal and have the following intended function relative to safe shutdown:
Relied upon in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for Fire Protection.
Plant shutdown from the safe shutdown controls is accomplished as described in UFSAR Section 7.4.1.1 and UFSAR Appendix 9.5.1A. The 10 CFR 50, Appendix R, Section III.G, 'Safe Shutdown Component/Cable Separation Analysis,"
documents the evaluation performed for the Appendix R ventilation support function and the acceptability of existing analyses that demonstrate that safe shutdown requirements can be satisfied.
No other ventilation systems support the use of the safe shutdown controls. Safe shutdown control panels in the Turbine Building do not need HVAC because of the open design of the Turbine Building. Therefore, ventilation systems used to support the safe shutdown controls are in the scope of license renewal and subject to an AMR.
The RAB HVAC System provides ventilation to equipment required to support use of the safe shutdown controls in the RAB. This ventilation equipment is shown within the evaluation boundary on flow diagrams G-190304LR Sheets 2 and 3. Refer to Table 2.3-18 in the LRA for further evaluation.
The Control Room Area HVAC System provides ventilation to equipment required to support use of the safe shutdown controls in the Control Room Area.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 83 of 504 This ventilation equipment is shown within the evaluation boundary on flow diagrams G-1 90304LR Sheet 4. Refer to Table 2.3-19 in the LRA for further evaluation.
U. S. Nuclear Regulatory Commission Attachment liI to Serial: RNP-RA/03-0031 Page 84 of 504 RAI 2.3.3.14-1 The fuel handling building HVAC system scoping flow diagram (G-190304) shows that fans HVE-14, HVE-15, and HVE-21 and their associated ductwork, fan housings, filters, and components are excluded from the scope of license renewal. State whether these identified fans and their associated components are subject to an AMR and provide the relevant information to enable the staff to complete the license renewal review process. If these fans and associated components are not subject to an AMR, provide justification for their exclusion.
RNP Response:
The identified fans and their associated components are not subject to an AMR because the components do not perform a license renewal intended function.
The intended function for the FHB HVAC System is to mitigate the consequences of a fuel handling accident inside the FHB to ensure that radioactive releases do not result in offsite exposures greater than the guidelines provided by 10 CFR 100. The listed components are not required to accomplish the intended function. The FHB HVAC System highlighted components, as shown on G-190304LR Sheet 1, are required to accomplish the above LR system intended function.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 85 of 504 RAI 2.3.3.15-1 A fire hose is subject to aging, yet the staff could not identify that fire hose was included in the scoping of the LRA. Fire hose is not included in Table 2.3-21 or otherwise in Section 2.3.3.15. Table 2.4-1, discusses fire hose stations, but aging of the hose is not addressed. Table 3.3-2, discusses flexible hoses, but fire hose is exposed to a water environment and the fire water system is not discussed in the component commodity column. Include fire hose with scope and perform an AMR or provide a technical basis for excluding fire hose from scope.
RNP Response:
Fire hose is considered to be a consumable, like those discussed following Table 2.3-21 on page 2.3-50 of the LRA, and is replaced in accordance with NFPA guidance.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 86 of 504 RAI 2.3.3.15-2 On drawing HBR2-8255LR, sheet 1, the license renewal boundary stops at FP-5, normally closed valve between the Unit 1 and Unit 2,fire water system. The UFSAR, 9.5.1.4.2.4 states that Unit 1 fire water is available for Unit 2. The UFSAR also references the February 28,1978 SER, which discusses the reason that the Unit 1 fire water system may be needed. Include the Unit 1 fire water system in scope of the LRA and perform an AMR or provide the technical basis for excluding this system from scope.
RNP Response:
The January 1, 1977, RNP Fire Protection Program Evaluation written to address Branch Technical Position APCSB 9.5-1 identifies the Unit 1 I Unit 2 fire loop cross connect as a separate supply for "emergency use." The February 28, 1978, RNP Fire Protection SER notes that 'in the unlikely event that blockage of the intake should occur, the licensee could open the isolation valve connecting the Unit No. 1 fire loop with the Unit No. 2 fire loop." The SER also notes the existence of adapter couplings so that an offsite fire department could pump water from the discharge canal into the fire loop. The SER recognizes the availability of the Unit 1 fire loop as a backup supply, but does not specifically credit it as the basis for acceptability.
Operability requirements for the RNP fire protection system were maintained in the RNP Technical Specifications from original licensing through 1992. With regard to fire suppression water, the Technical Specifications required that the Unit 2 fire water pumps be operable, as well as an operable flow path capable of taking suction from the Unit 2 intake structure and transferring it to the distribution piping. The Technical Specifications further required that, in the event of inoperability of this equipment, a backup fire water system be provided within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The Unit 1 fire water loop could be used as a viable backup system, but was not the only alternative in this regard. The Unit 1 fire water loop itself was not required to support Unit 2 operability, and no Technical Specifications Action Statement was associated with the inoperability of the Unit 1 fire water system.
In April 19,1991, in accordance with NRC GLs 86-10 and 88-12, RNP submitted a license amendment request to relocate fire protection program requirements from the Technical Specifications to the UFSAR. In December 7,1992, the NRC issued License Amendment No. 142, granting the requested changes to the Operating License. Subsequently, operability and surveillance requirements for site fire protection systems have been maintained in plant procedures.
These procedures contain the same basic operability requirements previously found in the Technical Specifications (2 pumps, an operable flow path), and require either a backup system be established or a unit shutdown commenced.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAN03-0031 Page 87 of 504 These procedures further state that a backup fire water system can consist of the the Unit 1 fire water loop, or alternate pump equipment such as a fire truck, but does not limit the site to these options.
In summary, the Unit 1 fire water loop was considered as a viable backup to the Unit 2 fire water pumps in the February 28, 1978 SER, but not specifically credited as a basis for acceptability of the Unit 2 fire water system. This equipment can be utilized as a backup to support unit operation in the event of inoperability of the Unit 2 fire water pumps, but is not singularly specified and other alternatives are acceptable. The Unit 1 fire water loop is not required to be operable to support Unit 2 fire water system operability. Consistent with of the Interim Staff Guidance on fire protection scoping, the Unit 1 fire water loop is not required to comply with NRC fire protection regulations, and is not required to be included in the scope of license renewal.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 88 of 504 RAI 2.3.3.15-3 UFSAR Chapter 9.5.1A, Section 3.7.1.6 discusses the deluge water spray system provided for the hydrogen seal oil unit. UFSAR Section 3.7.2.6 discusses the deluge water spray system provided for the lube oil storage tank. The UFSAR includes discussions in sections 3.7.1.3 and 3.7.2.3 that dedicated shutdown cables are routed outside the turbine building area. Also, the turbine driven auxiliary feedwater pump may be affected in a turbine building fire. The February 28, 1978, SER, Section 5.23, discusses the deluge water spray systems in these areas, "The deluge systems are adequate to control fires in this area."An unmitigated fire in this area may affect the safe shutdown cables described above. Drawing HBR2-8255LR, Sheet 2, indicates that these water suppression systems are not within the license renewal boundary. Either include these deluge water spray systems within the scope of the LRA and perform an AMR or provide the technical basis for their exclusion from scope.
RNP Response:
The cables associated with the DSDG run in conduit along the outside of the Turbine Building as described in the UFSAR. These cables are part of the RNP safe shutdown strategy; however, as noted in the UFSAR, for a fire in the Turbine Building or transformer yard the motor driven AFW pumps and normal on-site power distribution system remain available for safe shutdown of the plant.
The subject deluge systems were installed as part of the original plant design to protect the plant against oil type fires, and predate the installation of the DSDG cables. These deluge systems were not designed to protect the DSDG cables (the cables are routed along the southern face of the Turbine Building, outside the deluge areas described in the UFSAR), and are not credited with doing so.
Fire protection for the DSDG cables / conduits running along the outside of the Turbine Building is provided by hose stations in this area. These hose stations are credited with protecting the DSDG cables and are within the scope of license renewal.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAI03-0031 Page 89 of 504 RAI 2.3.3.15-4 An exemption dated November 25, 1983, discusses the acceptance of separation between RHR pumps in the RHR pit. The acceptance was based, in part, on the fact that there is a 22 foot high concrete wall between the pumps.
The UFSAR Chapter 9.5.1A, Section 3.1 1, discusses separation as a feature that helps to ensure that one RHR pump will be available in the event that the other pump is damaged by fire. The staff could not identify where in the application this barrier was identified. Verify that this barrier is included in the application and if not include this barrier within scope and perform AMR or provide technical basis for it's exclusion.
RNP Response:
This barrier is a concrete wall and was treated as a civil concrete commodity in Table 3.5-1, Item 16.
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RA/03-0031 Page 90 of 504 RAI 2.3.3.15-5 On drawings HBR2-8255LR, sheets as indicated below, the license renewal boundaries are indicated at an open isolation valve just prior to the closed valve.
Ensure that a closed valve is the license renewal boundary and is included within scope with an AMR or provide technical basis for having a license renewal boundary at an open valve.
Sheet Open Valve Closed Sheet Open Valve Closed Valve Valve 2
FP-61 FP-55 2, 5 FP-54 FP-292 2, 5 FP-56 FP-293 2,5 FP-58 FP-295 2
FP-71 FP-21 2, 5 FP-90 FP-411 6
FP-585 Unknown 6
FP-750 Unknown 6
FP-449 Unknown 6
FP-518 Unknown 6
FP-575 Unknown 6
FP-735 FP-731 6
FP-590 Unknown 6
FP-588 Unknown 6
FP-565 Unknown 6
FP-468 Unknown 6
FP-806 Unknown 6
The valves listed above were identified as license renewal boundaries consistent with their treatment in plant design and the CLB as boundary valves between the portion of the fire protection system that is required for NRC fire protection regulations and that which is installed only for commercial (insurance) risk.
These manual valves represent viable isolation points that can be utilized if a break occurs downstream. RNP is aware of no NFPA requirements or CLB commitments that specify normally closed valves, remotely operated valves, or automatic isolation capability at these points.
System design ensures that any significant leakage occurring in the portion of the fire protection system outside boundaries established for 10 CFR 50.48 compliance would be readily detected and resolved. System pressure in the RNP fire water system is normally maintained by a fire protection jockey pump.
Even a small system demand would cause a sufficient drop in pressure to initiate operation of the 2500 gpm motor driven fire water pump, which has remote indication in the control room. Isolation valves are located at strategic locations
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 91 of 504 to permit partial isolation of the fire water loop without loss of service to other sections of the system.
The RNP fire water system design includes branch piping to various non-essential portions of the site. This design facilitates early detection of system leakage and provides for isolation of faulted portions of the system using manual isolation valves. The open manual valves identified in the RAI constitute valid boundary valves credited for 10 CFR 50.48 compliance. Consistent with 10 CFR 54.4(a)(3), SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48) are in the scope of license renewal. The piping and devices outside these recognized boundary valves are typically located in buildings / areas outside the power block, are not credited with protecting safety-related or safe shutdown equipment, and do not satisfy the scoping criteria of 10 CFR 54.4(a)(3).
U. S. Nuclear Regulatory Commission Attachment liI to Serial: RNP-RA/03-0031 Page 92 of 504 RAI 2.3.3.15-6 UFSAR Sections 3.1.5.5.6, 3.1.5.6.6, reference that the Halon 1301 systems incorporate specially designed cylinder assemblies. These cylinder assemblies are not included in Table 2.3-21. Include these tanks within scope and perform AMR or provide the technical basis for its exclusion from scope.
RNP Response:
The subject cylinder assemblies are included in Table 2.3-21 in the Component' Commodity Group, 'Valves, Piping and Fittings." As such, the tanks are included in scope and are subject to AMR. Results of the AMR identified no aging effects associated with the subject component (see LRA Table 3.3-2, Item 19), and therefore, no AMP is required.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 93 of 504 RAI 2.3.3.15-7 UFSAR Sections 3.1.1.6, 3.1.2.6, 3.4.6, 3.5.6, reference the carbon dioxide (CO2) systems that include many high pressure C02 cylinders. These cylinders are not included in Table 2.3-21. Either include these cylinders in Table 2.3-21 of the LRA and identify which section of the AMR handles aging for these items, or provide the basis for excluding theses items from scope. Also, it is common for C02 systems to have nitrogen pilot tanks, verify that if nitrogen pilot tanks are used that they are included in scope and are subjected to an AMR.
RNP Response:
The subject cylinders are included in Table 2.3-21 in Component/Commodity Group, 'Valves, Piping and Fittings." As such, the cylinders are included in scope and were subject to AMR.
The Boric Acid Corrosion Program will manage loss of material due to aggressive chemical attack (caused by boric acid leakage), an aging effect/mechanism requiring management, for the subject cylinders located in the RAB. This is reflected in Item 13 of Table 3.3-1.
Nitrogen pilot tanks are not used at RNP in the C02 fire suppression systems.
Aggressive Chemical Attack Aggressive Chemical Attack is corrosion that may be localized or general and caused by a corrodent that is particularly active on a specific material. Boric acid corrosion is a good example and is typically referred to as "Boric Acid Wastage."
Boric acid is used in PWR plants as a reactivity agent. It is used in concentrations in the reactor coolant in ranges between 0 and approximately 1 weight percent. At these concentrations boric acid solutions will not cause significant corrosion even if they are in contact with carbon steel. However, reactor coolant that leaks out of the RCS system loses a substantial volume of its water by evaporation, resulting in the formation of highly concentrated boric acid solutions or deposits of boric acid crystals. These concentrated solutions of boric acid may be very corrosive for carbon steel.
General Corrosion General corrosion is normally characterized by uniform attack resulting in material dissolution and sometimes corrosion product buildup. At ordinary temperatures and in neutral or near neutral media, oxygen and moisture are the factors that affect the corrosion of iron. Both oxygen and moisture must be present because oxygen alone or water free of dissolved oxygen does not corrode iron to any practical extent. Carbon and low-alloy steels as well as cast
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 94 of 504 iron are susceptible to general corrosion, whereas stainless steels, nickel-base alloys, aluminum, copper and copper alloys and galvanized steel are resistant to general corrosion. The RNP position regarding general corrosion of carbon steel in a non-wetted environment is provided in the RNP Response to RAI 3.2.1-1.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 95 of 504 RAI 2.3.3.15-8 The UFSAR Sections 3.1.1 and 3.1.2 for the diesel generator C02 systems and in Section 3.7.1.5 and 3.7.2.5 for hazards in the turbine building reference the use of heat actuated devices (HAD's) for actuation of the C02 system. HAD's typically utilize passive tubing, this tubing could not be identified in the LRA. The tubing is often similar to the tubing of the instrument air system (see 2.3.3.5).
The LRA section 2.3.3.15 states that the fire detection and actuation systems are screened with Electrical and l&C, but these devices could not be found in that section. Include this tubing in scope and perform AMR or provide the technical basis for its exclusion from scope.
RNP Response:
The fire detection system is considered in-scope for license renewal and the HAD's are included within the LR evaluation boundary for the fire detection system, since they perform an intended function.
The subject tubing is not presently identified in the LRA. The tubing satisfies both the screening criteria of 10 CFR 54.21 (a)(1)(i) and 10 CFR 54.21 (a)(1)(ii).
The HAD tubing is considered to be within the LR evaluation boundary for the fire detection system. The HAD tubing is therefore subject to an aging management review because the screening criteria of 10 CFR 54.21 (a)(1)(i) and 10 CFR 54.21 (a)(1)(ii) is met.
The HAD tubing was included in the AMR process for the emergency diesel generator C02 system. No aging effects were identified.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 96 of 504 RAI 2.3.3.15-9 The applicant uses vertical shaft fire pumps. NFPA 20, 1973 edition, states, in section 4-3.4.1 "A cast or heavy fabricated type of nonferrous cone or basket type strainer shall be attached to the suction manifold of the pump." Drawing HBR2-8255LR, Sheet 1 of 6, does not provide enough detail to determine if strainers are installed with the fire pumps. Verify if strainers are installed and if so include the strainers within scope and perform an AMR. If strainers are not installed provide, 1) verify that code of record for Robinson for installation of the fire pumps does not require strainers, and 2) the technical basis for their exclusion from scope.
RNP Response:
RNP has one electric and one diesel powered fire pump, both of which are within the scope of license renewal. Each pump has a strainer that.prevents debris from entering the pump when it is in operation, thus protecting the pump from damage. These nonferrous strainers were initially considered part of the pump, and excluded from aging management on the basis that pumps, except casings, were not required to be considered. Upon further review, these strainers have been accorded the "provides filtration" intended function and will be managed against the effects of aging. Currently, the fire pumps are periodically removed, refurbished, and replaced under the Preventive Maintenance Aging Management Program. These strainers will be inspected concurrently under that program.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 97 of 504 RAI 2.3.3.15-10 Flame retardant coatings are discussed in the UFSAR Appendix 9.5.1 B, Section D.1.a for areas where redundant safety-related equipment is located, Sections D.2.c, D.3.c related to engineering safeguards cables, Section D.3.e relating to auxiliary building applications, Section D.3.f relating to coating of PVC jacketed cables, and cable coating are also discussed as used in the control room, cable spreading room, emergency switchgear room. Appendix 9.5.1 B is described as the fire protection program per Appendix A to BTP 9.5-1. The February 28, 1978 SER, Section 4.8, states that PVC insulated cables in critical areas will be coated with a flame retardant coating and that silicone rubber insulated cables inside containment areas will be coated with a flame retardant coating. The LRA, Section 4.4.1.43 indicates that PVC cables are still relied upon at the plant. 10 CFR 50.48, Section (b)(1 )(i) references Appendix A to BTP 9.5-1 SERs for plant's of this vintage. Flame retardant cable coatings could not be identified in the LRA. Include fire retardant cable coatings within scope of license renewal and perform an AMR or provide the technical basis for its exclusion from scope.
RNP Response:
Flame retardant coatings described in UFSAR Appendix 9.5.1 B have been added to the license renewal scope. The RNP AMR has been updated to evaluate flame retardant coatings. "Loss of material due to flaking" was identified as an aging effect/mechanism for the flame retardant coatings within the scope of license renewal. The Preventive Maintenance AMP has been revised to manage the aging effect for these components.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 98 of 504 RAI 2.3.3.15-11 UFSAR Section 3.1.2.2, Fire Barrier Description for the Diesel Generator "AN discusses 3-hour insulation that has been applied to the "B" diesel generator service water line. The February 28, 1978, SER, Section 5.1.6(1) states that the applicant proposed to install the above insulation in addition to 3-hour rated insulation on the fuel oil makeup line to the "A" diesel generator which is located in the "B" diesel generator room. No discussion of these 3-hour fire barrier materials were identified in the LRA. Include these fire barrier materials within scope of the LRA and perform an AMR or provide the technical basis for their exclusion from scope. The staff is aware that Table 2.4-2 discusses fire barrier assemblies, but the intended function as stated is to confine or retard a fire from spreading to or from adjacent areas of the plant, the barriers discussed above are not installed for this function.
RNP Response:
By letter from E. Utley (CP&L) to NRC, Serial NO-80-132, dated January 28, 1980, CP&L requested a supplement to the Fire Protection Safety Evaluation Report. The changes identified included, in section 5.1.6, uRelocate the fuel oil makeup line to the 'A' diesel generator which is located in the 'B' diesel generator room to the outside of the Auxiliary Building." Relocation of the fuel oil makeup line negated the need for 3-hour rated insulation.
The Component/Commodity Group, "Fire Barrier Penetration Seals," (Tables 2.4-2 and 2.4-3) includes 3-hour insulation on the service water line. The AMR results are provided in Table 3.3.1, Item 19.
The RNP Fire Protection Program includes inspection of the insulation on the "B" diesel generator service water line.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 99 of 504 RAI 2.3.4.4-1 In LRA drawing, G-1901 96LR Sheet 1, please clearly identify the extraction steam system evaluation boundaries to ensure that all the long-lived components with a passive function are included for an AMR.
RNP Response:
The RNP main steam and extraction steam systems are included in the G-190196 series of drawings (Sheets 1 through 4). Extraction steam piping is included on Sheets 3 and 4 of this series. Refer to LRA Section 2.3.4.4, which states that none of the extraction steam system components perform an intended function for LR. Therefore, only the main steam components subject to AMR are included in the set of evaluation boundary drawings. This includes piping and components on Sheet 1 of this series. See the RNP Response to RAI 2.3.4.4-2 for more detail relating to the evaluation of the extraction steam system.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 100 of 504 RAI 2.3.4.4-2 The extraction steam system provides turbine overspeed protection by utilizing valves to stop the flow of reheat steam to the low pressures turbine, discuss why these valves are not identified/included in a AMR table.
RNP Response:
The turbine system / extraction steam system credits two specific features for turbine overspeed protection. These are (1) non-return valves (air operated swing check valves) located in the extraction steam lines for all but the No. 1 and No. 2 feedwater heaters, and (2) emergency dump valves on these heaters that are not equipped with non-return valves.
The non-return valves prevent steam backflow from the feedwater heaters and piping into the turbine following a turbine trip, as well as prevent backflow of water in the event the heater fills up with water. In this case, the operation of the valve to close is an active function. Failure of the valve or piping pressure boundary would not result in a liability for turbine overspeed, as the diverted steam would still be prevented from returning to the turbine where it might cause overspeed. Similarly, operation of the emergency dump valves is an active function, and should the pressure boundary associated with the dump valves or piping fail, the result would be to divert steam away from the turbine. In either case, passive failure of the system components would not prevent successful accomplishment of the system intended function. Based on this screening review, the extraction steam system, while having a system intended function, has no components that are subject to aging management review.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 101 of 504 RAI 2.3.4.4-3 The applicant states that the extraction steam system was included in the scope of license renewal. However, following screening of the system, the applicant concludes that none of the system components perform an intended function without moving parts or without a change in configuration. Therefore, none of the components in the extraction steam system boundaries is subjected to an aging management review.
The staff believes that the system components, such as piping, valves etc., are long-lived components with a passive function and, therefore, are subject to an AMR. Please provide a component/commodity groups table to identify these component and their intended functions. If a component is not subject to an AMR, please provide detailed justifications for its exclusion.
RNP Response:
The extraction steam system provides a system intended function to prevent backflow from the feedwater heaters and associated piping. RNP evaluated this system and determined that a loss of component pressure boundary would not prevent successful accomplishment of the system intended function. Based on this screening review, the extraction steam system, while having a system intended function, has no components that are subject to aging management review. See the RNP Response to RAI 2.3.4.4-2 for more detail relating to this evaluation.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 102 of 504 RAI 2.3.4.4-4 In LRA Section 2.3.4.4, the applicant states that the extraction steam system was included in the scope of license renewal, however, in Item 6 of Table 3.4-1, the applicant states "...turbine and extraction steam systems are not in scope for license renewal." Please clarify this discrepancy.
RNP Response:
The turbine system and extraction steam system are included within the scope of license renewal. The intent of the statement (Table 3.4-1, Item 6) was to state that there are no components in the evaluation boundaries of the turbine system or the extraction steam system that perform a LR intended function.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 103 of 504 RAI 2.3.4.7-1 In LRA Section 2.3.4.7, the applicant states that the steam cycle sampling system was included in the scope of license renewal. Also, the applicant states that the only components with an intended function in the steam cycle sampling system are sample heat exchangers.
The staff believes that the system components, such as piping, valves etc., are long-lived components with a passive function and, therefore, are subject to an AMR. Please provide a component/commodity groups table to identify these component and their intended functions. If a component is not subject to an AMR, please provide detailed justifications for its exclusion.
In addition, in the drawing, "HRB2-09006LR Sheet 2," please identify the steam cycle sampling system evaluation boundaries to ensure that all the long-lived components with a passive function are included for an AMR.
RNP Response:
The RNP AMR process typically did not move components between systems.
Therefore, the heat exchangers for steam cycle sampling were left in the steam cycle sampling system and the system was considered to be in scope. However, the license renewal functional boundary associated with the heat exchangers is the CCW system pressure boundary. The CCW system flows through the shell and around the tubes of the steam cycle sampling heat exchangers and provides cooling of the sample flow. The tubing and shells of these heat exchangers are included on LRA Table 2.3-9 for the CCW system. This information is summarized in LRA Subsection 2.3.4.7.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 104 of 504 RAI 2.3.4.9-1 Robinson LRA, Drawing G-1 90202-LR, Sheet 3, depicts the supply from the deep-well pumps to the auxiliary feedwater pumps as not within the scope of license renewal. As noted in UFSAR Section 10.4.8, this is the source of water credited in the event of a failure of the Lake Robinson Dam. Additionally the UFSAR notes that makeup from these pumps is required after two hours at hot shutdown assuming the minimum volume of water in the condensate storage tank. Please explain, why this alternate source is not within the scope of license renewal as part of the noted design-basis events?
RNP Response:
Refer to the RNP Response to RAI 2.3.3.8-1.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 105 of 504 RAI 2.3.4.9-2 Robinson LRA, Drawing G-1 90197-LR, Sheet 4, depicts a restricting orifice 1402, which appears to be the cavitating venturi in the steam turbine auxiliary feedwater pump discharge pipe described in UFSAR section 10.4.8.2. This venturi limits flow in the event of low steam generator pressure in the event of a failed discharge flow control valve. The AMR tables do not clearly describe this venturi. Please identify where the venturi is specifically addressed and whether there are any unique AMR associated with such a passive device.
RNP Response:
This flow orifice (i.e., cavitating venturi) is constructed of both carbon steel and stainless steel (for high wear parts). This component applies to LRA Table 3.4-1, Item 2, and LRA Table 3.4-2, Items 1, 2, 11, and 13. This component was specifically evaluated in the AMR for the AFW system. Intended functions for this component include pressure boundary and flow restriction. Therefore, this component was evaluated for aging effects on the carbon steel pressure retaining sub-components and for aging effects on the wear-resistant (flow restricting) stainless steel components.
As stated in UFSAR Section 10.4.8.2, the function of this cavitating venturi is to limit flow to a low-pressure (i.e., failed) steam generator in the case of a failed discharge flow control valve.
Manual operation of the AFW system limits the flow through the discharge piping to 500 gpm. System flow testing is also limited to approximately 500 gpm. The flow at which this venturi cavitates (goes into choked flow) is approximately 625 gpm. Therefore, in order for this venturi to operate in its flow-limiting mode, there would have to be an event resulting in low steam generator pressure and a failed discharge flow control valve (FCV-6416). Any degradation resulting from this type of operation would be considered event-driven and would therefore not be subject to aging management.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 106 of 504 RAI 2.3.4.10-1 In the Robinson LRA, Drawing G-190197-LR, Sheet 1, please explain why isn't the 6-inch vent pipe on the top of the condensate storage tank highlighted as within the scope of license renewal. Is there an alternate means to provide vacuum protection for this tank?
RNP Response:
The condensate system is in-scope and the tank is part of the condensate system. The 6 inch vent pipe on top of the CST is an integral part of the CST, within the evaluation boundary, and should have been highlighted as part of the boundary of the tank. The vent pipe, as part of the CST listed in LRA Table 2.3-30, is covered in LRA Table 3.4-2, Item 13.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 107 of 504 RAI 2.3.4.10-2 In the Robinson LRA, Drawing G-1 901 97-LR, Sheet 1, the class breaks for a number of the pipes connected to the condensate storage tank appear to be directly at the tank itself and a number of pipes have such a break located immediately downstream of the first valve away from the tank. The license renewal boundary highlighting conform with these class breaks.
Please explain what is the basis for some piping being in-scope of license renewal up to the first valve and some terminating at the tank (e.g., pipe to valve C-436, pipe to valve C-438, piping from Demin water supply depicted with a dashed line, and pipe (tank overflow line?) labeled 12-C-152N-55); given the pressure boundary intended function for the tank.
RNP Response:
The pipes highlighted to the first isolation valve are below the minimum water level required to support the system intended functions. The pipes not highlighted are above this minimum water level and are not needed to support the system intended functions.
Piping within the evaluation boundary for Criterion 2 is not highlighted on any Licensing Renewal Drawing. The Criterion 2 system intended function is to "Provide a pressure-retaining boundary to prevent spatial interactions with safety related equipment."
The class breaks are ISI class breaks. The rules for demarcation of class breaks generally coincide with system intended functions.
U. S. Nuclear Regulatory Commission Attachment IIl to Serial: RNP-RA/03-0031 Page 108 of 504 RAI 2.3.4.10-3 In the Robinson LRA, Drawing G-190197-LR, Sheet 1, depicts a diaphragm within the Condensate Storage Tank. Although the diaphragm is discussed in Table 3.4-2, please explain why isn't it listed in Table 2.3-30 as a component requiring an AMR.
RNP Response:
Refer to the Table 2.3-30 entry for the CST. In that table, reference is made to aging management review Table 3.4-2, Item 5 which addresses the diaphragm within the CST.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 109 of 504 RAI 2.4.2-1 Section 3.2.1.2 of the UFSAR states that the foundation and anchor system of the S/G Drain (flash) Tank are designed to seismic Class I. Explain whether the foundation and anchor system of the S/G Drain (flash) Tank are in scope and subject to an AMR for license renewal. If they are in scope, indicate the location (under which component/commodity) and Table number where they are listed.
Provide justification if they should not be in scope.
RNP Response:
The SG Drain (flash) Tank foundation is described as the "Steam Generator Blowdown Tank foundation" in LRA Subsection 2.4.2.12, Item 2. The tank is shown on LRA Figure 2.2-1 between the Containment Building and the Turbine Building.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA103-0031 Page 110 of 504 RAI 2.4.2-2 Section 3.2.1.2 of the UFSAR states that the concrete missile shield wall and the support slab for the above-ground portions of the Service water system North Header are class 1. Explain whether the concrete missile shield wall and the support slab are in scope and subject to an AMR for license renewal. If they are in scope, indicate the location (under which component/commodity) and table number where they are listed. Provide justification if they should not be in scope.
RNP Response:
The concrete missile shield wall and the support slab for the above-ground portions of the SWS north header are listed as the "north service water header Enclosure" in Table 2.4-8 as "Reinforced Concrete (Beams, Walls, Floors, Columns, etc.)."
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 111 of 504 RAI 2.4.2-3 Section 2.4.2.3 of the LRA states that safety-related piping is routed through a Class Ill portion of the Turbine Building in a concrete trench. Table 2.4-4 lists reinforced concrete (beams, walls, floors, columns, etc.) as components requiring AMR, but does not list concrete trench as a component requiring AMR. Clarify whether the concrete trench is in scope and subject to an AMR. If it is in scope, indicate the location (under which component/commodity) and Table number where it is listed. Provide justification if it should not be in scope.
RNP Response:
The concrete trench within the Turbine Building is included as Component/Commodity Group "Reinforced Concrete (beams, walls, floors, columns, etc)" in Table 2.4-4, and the portion between the Turbine Building and the CST is included as "Reinforced Concrete (beams, walls, floors, columns, etc)" in Table 2.4-12.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 112 of 504 RAI 2.4.2-4 Section 2.4.2.12 of the LRA states that the Primary Water Storage Tank was determined to be outside of the intended function boundary for license renewal.
However, the Robinson UFSAR lists the Primary Water Storage Tank being a Class I component. Provide justifications on your determination that the Primary Water Storage Tank should not be in scope.
RNP Response:
The original RNP licensing basis considered the CVCS flow path from the boric acid storage tanks to the blender (and including the PWST and its flow path) and to the charging pumps' suction to be safety related, and required operability of this equipment in the Technical Specifications. Safety-related tanks were designed to class 1 criteria. A subsequent license change identified that only the RWST was required as a post-accident makeup source of borated water, and relocated the requirements for the CVCS and PWST to the Technical Requirements Manual. Therefore, the PWST does not support any system intended function, which resulted in the above conclusion stated in LRA Section 2.4.2.12.
Section 2.4.2.12 was submitted to the NRC prior to RNP reformulating its position with respect to 10 CFR 54.4(a)(2). Based on recent industry guidance relating to 10 CFR 54.4(a)(2) and piping systems (Criterion 2 Piping), the PWST required evaluation for its potential spatial interactions with nearby safety related equipment. There is no safety related equipment in its proximity that would be adversely affected by spray or leakage from the tank. Consequently, the PWST was determined to have no potential spatial interaction with safety related equipment and does not require aging management.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 113 of 504 RAI 2.4.2-5 Table 3.2.1-2 of the Updated Safety Analysis Report (USAR) lists Refueling water Storage Tank, Accumulator Tanks, Boron Injection tank, Fuel Oil storage tank, Chemical Drain Tank, Waste Holdup tanks, Sump Tank, Gas Decay Tanks, Spent Resin Storage Tank, Reactor Coolant Drain Tank being Class I components. However, none of the tanks is listed on Table 2.2-1, License Renewal Scoping Results for Mechanical Systems or Table 2.2-2, License Renewal Scoping Results for Structures of the LRA. The staff believes that these passive long-lived Class I tanks and their foundations are within the scope of license renewal and subject to an AMR. Clarify whether these tanks and their foundations are within scope and subject to an AMR. If they are in scope, indicate the location (under which component/commodity) and Table number where they are listed. Provide justification if they should not be in scope.
RNP Response:
A structure or component may be designed to safety grade criteria, but is not subject to AMR unless it performs an intended function for license renewal as defined in the scoping criteria section of the rule. Pertaining to safety related systems, these criteria are 10 CFR 54.4(a)(1) - (a)(3). The commitment in the UFSAR to maintain the requirements of seismic Class I is more inclusive (conservative) than these LR scoping criteria.
Equipment that is seismic Class I as defined in UFSAR Table 3.2.1-2 are "Those items vital to safe shutdown and isolation of the reactor or whose failure either singularly or in combination with the failure of another structure or piece of equipment could result in radiation doses with consequences potentially exceeding guidelines of 10 CFR 100 or whose failure might cause or increase the severity of an accident...." The tanks identified are seismic Class I because they are required to survive a seismic event. However, their failure of any tank may not result in risk to the health and safety of the public on the basis of the safety related scoping criteria.
The seismic Class I definition is not the same as the LR safety-related scoping criteria. The seismic Class I definition is more conservative than the safety-related scoping criteria 10 CFR 54.4(a)(1)(i)-(iii) which states Safety-related systems, structures and components which are those relied upon to remain functional during and following design-basis events (as defined in 1 OCRF50.49(b)(1)) to ensure the following functions -
(i) The integrity of the reactor coolant pressure boundary; (ii) The capability to shut down the reactor and maintain it in a safe shutdown condition; or
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 114 of 504 (iii) The capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34 (a) (1) or 10 CFR 100.11.
The RNP definition of Class I is more inclusive because it contains the words "or whose failure might cause or increase the severity of an accident." Increasing the severity of an accident does not necessarily mean that the criteria in the LR scoping definition would be met. The Class I definition also considers combinations of failures in determining whether the criteria are met: "whose failure either singularly or in combination with the failure of another structure or piece of equipment could result in radiation doses with consequences potentially exceeding guidelines of 10 CFR 100." The consequences of accidents relating to these tanks are described in UFSAR chapter 15 (section identified below).
This chapter concludes that the consequences are not significant to the health and safety of the public. Therefore, this definition as applied to the tanks is broader than that required to meet the LR regulations.
Of the tanks listed above in this RAI, the following tanks and foundations require an AMR and can be found in the LRA under the references cited:
UFSAR Table 3.2.1-2 LRA LRA Component/Commodity Item Reference Table 2.3-3 Refueling Water Storage Tank Refueling Water Storage Section Refueling Water Storage Tank Tank 2.4.2.12 Foundation Table 2.4-12 Concrete Tank Foundation' Boron Injection Tank Table 2.3-3 Boron Injection Tank Table 2.4-2 Reinforced Concrete Table 2.3-25 EDG Fuel Oil Storage Tank Fuel Oil Storage Tank Section Diesel Generator Fuel Oil Storage 2.4.2.12 Tank Foundation Table 2.4-12 Concrete Tank Foundation' Table 2.3-3 Si Accumulator Tanks Table 2.4-1 Equipment Supports Note:
- 1. The foundation is identified as Component/Commodity "Concrete Tank Foundation" in the the RNP LRA.
The remaining tanks (namely the Chemical Drain Tank, Waste Holdup Tanks, Sump Tank, Gas Decay Tanks, Spent Resin Storage Tank, and the Reactor Coolant Drain Tank) are mechanical components within the Liquid Waste Processing System and the Gaseous Waste Processing System that do not require an AMR. The Liquid Waste Processing System is in scope of LR rule due to it being a Criterion 2 piping system, the containment isolation function and
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 115 of 504 the electrical components associated with EQ and Regulatory Guide 1.97 functions. None of the tanks within the liquid radwaste system support these system intended functions.
The Gaseous Waste Processing System has no system function that meets the LR scoping criteria and is not in scope of the rule as explained below. In fact, an evaluation of a complete rupture of a waste gas decay tank has shown that the dose limits as described above would not be exceeded. The waste gas decay tank rupture is considered the worst-case tank rupture of any radwaste tank (liquid or gas) due to the curie content and rapid expansion of the gaseous contents (UFSAR Section 15.7.1.1 and 15.7.2.1). Paragraph 15.7.1.3 of the UFSAR concludes, "an accidental waste gas release would present no hazard to the health and safety of the public."
Based on the foregoing, none of the tanks in the Gaseous Radwaste System require an AMR because the system is not in-scope. The Liquid Radwaste System is in scope but the tanks identified do not support any intended system function and on that basis do not require an AMR. It has also been shown; the Seismic Class I designation identified in the UFSAR is not sufficient reason for a component to be identified as requiring an AMR.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 116 of 504 RAI 2.4.2-6 Table 2.4-12 of the LRA lists "Concrete Tank Foundation as a component requiring AMR. This information is too general. Please provide the name of the tanks whose their concrete foundations require AMR.
RNP Response:
LRA Subsection 2.4.12 identifies the specific tank foundations addressed on Table 2.4-12. Subsection 2.4.12 states, "The following table identifies the Yard Structures and Foundations components/commodities requiring aging management review (AMR)." The tank foundations listed in Subsection 2.4.12 are:
- Steam Generator Blowdown Tank
- CST
- Diesel Generator Fuel Oil Storage Tank
- Dedicated Shutdown Diesel Generator Fuel Oil Tank Diesel Fire Pump Fuel Oil Tank Unit 1 IC Fuel Oil Storage Tanks
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 117 of 504 RAI 2.4.2-7 Section 2.4.2.5 of the LRA states that components associated with Radwaste Building cranes and hoists and fire doors and fire penetrations were considered in the review, but does not state the review results. Provide the review results as to whether these components are subject to AMR and, if not, provide justifications.
RNP Response:
The review results are included in LRA Table 2.4-6. The crane and hoists, fire doors and fire penetrations, do not perform a license renewal intended function and were not included in Table 2.4-6.
The components/commodities intended function in the Radwaste Building is to protect and provide missile shield walls for the safety related north service water header, and to shelter and support a fire water header isolation valve inside a masonry block enclosure at the north end of the Radwaste Building. Only the components/commodities listed in Table 2.4-6 have a LR intended function.
Additionally, Table 2.4-6 should have the seismic joint filler deleted because it was inadvertently included. Also, the structural steel component/commodity intended function should be changed to "Provide structural support and/or shelter to components required for Fire Protection, ATWS and/or SBO." The reinforced concrete component/commodity should have the 'Provide structural and/or functional support to non safety-related equipment where failure of this structural component could prevent satisfactory accomplishment of any of the required safety-related functions" intended function added.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 118 of 504 RAI 2.4.2-8 Section 2.4.2.6 of the LRA states that there are three traveling screens to remove small debris from the intake water, but the screens are not listed as components requiring AMR in Table 2.4-6. Provide justifications on the exclusion of the screens for AMR.
RNP Response:
The traveling screens are designated as non-safety related in the circulating water system. The traveling screens do not provide a license renewal intended function as defined in 10 CFR 54.4 (a)(1), (2) or (3). There is a relatively low flow velocity (approximately 0.07 ft/sec) through the traveling screens during a design basis event and the condition of the RNP impoundment is relatively non-aggressive.
Additionally, the following factors were considered during review of the traveling screens for scoping:
The traveling screens are not required to perform a function during and following a design basis event, and therefore do not meet the scoping criteria of 10 CFR 54.4 (a)(1)(i), (ii), or (iii).
There is no credible failure mode of the traveling screens that could prevent satisfactory accomplishment of any of the functions identified in paragraphs 10 CFR 54.4 (a)(1)(i), (ii), or (iii). Therefore the traveling screens do not meet the scoping criteria of 10 CFR 54.4 (a)(2).
The traveling screens are not required to perform a function in support of the regulated events of 10 CFR 54.4 (a)(3).
Based on the above, the traveling screens are not considered to meet the scoping criteria of 10 CFR 54.4 (a) and do not perform a licensee renewal intended function per 10 CFR 54.4 (b).
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAN03-0031 Page 119 of 504 RAI 2.5.1-1 The screening results in Section 2.5.1 do not include any offsite power system structures or components. The license renewal rule, Section 10 CFR 54.4(a)(3),
requires that, "... all systems, structures, and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission regulation for... station blackout (10 CFR 50.63) be included within the scope of license renewal. The station blackout rule, Section 10 CFR 50.63(a)(1), required that each light-water-cooled power plant licensed to operate be able to withstand and recover from a station blackout of a specified duration (the coping duration) that is based upon factors that include: "(iii) The expected frequency of loss of offsite power, and (iv) The probable time needed to recover offsite power." Licensees, plant evaluations followed the guidance in NRC Regulatory Guide (RG) 1.155 and NUMARC 87-00 to determine their required plant specific coping duration. The criteria specified in RG 1.155 to calculate a plant specific coping duration were based upon the expected frequency of loss of offsite power and the probable time needed to restore offsite power, as well as the other two factors (onsite emergency ac power source redundancy and reliability) specified in 10 CFR 50.63(a)(1). In requiring that a plant's coping duration be based on the probable time needed to restore offsite power, 10 CFR 50.63(a)(1) is specifying that the offsite power system be an assumed method of recovering from an SBO event. Disregarding the offsite power system as a means of recovering from an SBO event would not meet the requirements of the rule and would result in a longer required coping duration.
The function of the offsite power system with the SBO rule is, therefore, to provide a means of recovering from the SBO. This meets the criteria within license renewal 10 CFR 54.4(a)(3) as a system that performs a function that demonstrates compliance with the Commission's regulations on SBO. Based on this information the staff requires that applicable offsite power system structures and components need to be included within the scope of license renewal and subject to an AMR, or additional justification for its exclusion needs to be provided. Your response should include single line diagram showing preferred offsite power recovery path. The staff guidance on scoping of equipment relied on to meet the SBO rule for license renewal is contained in a April 1, 2002, letter to the Nuclear Institute and the Union of Concerned Scientists.
RNP Response:
RNP performed a review of the SBO safety analyses and plant evaluations prior to submittal of the LRA. Based on RAI 2.5.1-1, along with the staff guidance on scoping of equipment relied on to meet the SBO rule for license renewal contained in the April 1, 2002, letter, RNP has reviewed the plant documents with emphasis on equipment related to the recovery of offsite power.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAI03-0031 Page 120 of 504 Based on the results of this recent review, RNP has concluded that the components that comprise the restoration power path for offsite power from the switchyard are within the scope of license renewal in accordance with the SBO scoping criterion, §54.4(a)(3). The first source of offsite power when recovering from an SBO event is the SUT. The SUT is fed from the Unit 1 115 KV Switchyard, which has multiple sources of supply from either the Unit 1 115 KV or Unit 2 230 KV Switchyards. The SUT East Bus 115 KV Oil Circuit Breaker (OCB) & the West Bus 115KV OCB represent the first isolation devices upstream of the SUT and demarcate the RNP 115 KV Switchyard from the CP&L Transmission & Distribution System. The second source of offsite power when recovering from an SBO event is obtained by way of the Unit Auxiliary Transformer (UAT) by backfeeding the Main Transformers. Prior to backfeeding the Main Transformers, the Main Generator connecting straps must be disconnected. The Main Transformers are fed from the Unit 2 230 KV Switchyard, which (like the Unit 1 115 KV Switchyard) have multiple sources of supply from either the Unit 1 115 KV or Unit 2 230 KV Switchyards. The 230KV South Bus OCB (52-8) & the 230KV North Bus OCB (52-9) represent the first isolation devices upstream of the UAT and demarcate the RNP 230 KV Switchyard from the CP&L Transmission & Distribution System. Refer to the Figure 1 for a simplified diagram showing these power paths. The offsite power system is discussed in UFSAR Section 8.2. TAC No. M97957 is an open NRC TAC item that addresses backfeeding at RNP. RNP is actively addressing this TAC to allow the NRC to complete the SER on backfeeding.
The electrical components comprising the restoration power path for offsite power were reviewed and the passive, long-lived components subject to an AMR are as follows:
- Generator Isolated Phase (Iso-Phase) Bus Duct
- Non-Segregated 4.16KV & 480V Bus Duct
- High-Voltage Insulators
- Switchyard Bus
- Insulated cables and connections (connectors, splices, terminal blocks)
- Transmission Conductors and connections It should be noted that in the original RNP LRA, electrical scoping had determined that the Switchyard and Transformer System and the 4KV AC Distribution Systems were not within scope. Following re-evaluation of scoping of equipment relied on to meet the SBO rule consistent with the Commission's April 1, 2002, letter, these systems were subsequently scoped in. However, due to the bounding approach taken for insulated cables and connections (i.e., no insulated cables and connections were scoped out), even though these systems were initially scoped out, the insulated cables and connections within these scoped-out systems were included in the original RNP AMR. Therefore, no additional assessment of insulated cables and connections was needed for
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 121 of 504 recovery of offsite power scoping since all insulated cables and connections were included in the original RNP AMR.
Table 1 shows the aging management review results for the electrical components credited in the restoration of offsite power. This table identifies an aging management program for bus duct. The details of this program are discussed in Attachment 1 of RAI 2.5.2-2.
Structures and component supports, that protect and support the offsite power system are also included in the scope of license renewal and are subject to aging management review. The supporting structures for restoration of offsite power include:
Building 175: Switchyard Relay Building Isolated Phase Bus Duct Yard Support Structures
- Switchyard and Transformer Structures
- 4 KV Non-Segregated Bus Duct Yard Support Table 2 identifies the Civil/Structural Component/Commodity Groups requiring aging management review for the above supporting structures for restoration of offsite power, their intended function, and the applicable table in the RNP LRA where the AMR results are discussed. The Civil/Structural Component/
Commodity Groupings for restoration of offsite power should be included in LRA Table 2.4-12, "Yard Structures and Foundations." These CiviVStructural Component/Commodity Groupings were previously identified in a letter from J.
Moyer (CP&L) to NRC, Serial: RNP-RA/02-0159: "Supplement to Application for Renewal of Operating License," dated October 23, 2002. Two new Component/
Commodity Groupings ("Battery Rack" and "Pilings") were added to LRA Table 2.4-12 via the October 23, 2002 letter.
Table 3 identifies the program credited for managing the aging of accessible concrete on supporting structures for restoration of offsite power not presently shown in the LRA. For the remainder of structures, refer to the abovementioned letter from J. Moyer (CP&L) to NRC, Serial: RNP-RA/02-0159, stating RNP's position on aging management of concrete components. RNP committed to an aging management program for monitoring accessible concrete based on Interim Staff Guidance. Refer to the RNP Responses to RAls 3.5.1-8 and 3.5.1-9.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 122 of 504 FIGURE 1. -
POWER PATH FOR RECOVERY OF OFFSITE POWER AT RNP FOLLOWING A STATION BLACKOUT (SBO) EVENT IS SIMPLIFIED DRAWING SHOWS THE SYSTEM POWER CONNECTIONS INCWDED IN THE SBO OFFSITE POWER RECOVERY POWER PATH.
THE NORTH. SOUTH EAST AND WEST SWITCHYARD SES AND OCB52-7 MRE NOT PART OF THE 550 EFVSTTE POWER RECOVERY POWER PATH BUT ARE SHOWN FOR TECHNICAL CLARIFICATION.
UNIT 1 115 KV SWITCHYARD EAST BUS WESTlJS
.SOI1 BUVS_
, I-4
- oca
-I-i-I UNIT 2 230 KV SWITCHYARD TRANSFORMER
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 123 of 504 Table 1 - Aging Management Review Results for the Offslte Power System Electrical Components Component/
Materials of Environment Aging Effect/
Aging Management Discussion Commodity Construction (1)
Mechanism Program Phase Bus Various Metals, Indoor - Not Air Oxidation, Aging Management RNP will implement an aging management Porcelain, PVC, Conditioned, Loosening of Program for Bus Duct program to check bolted connections at Silicon Caulk
- Outdoor, Bolted Connections sample sections of bus duct for proper Ohmic Heating due to Thermal torque. Visual inspections of the bus duct Cycling, Corrosion for signs of cracks, corrosion, foreign debris, due to Moisture excessive dust buildup, evidence of water intrusion or discoloration which may indicate overheating will also be performed to identify the potential existence of aging degradation. The program applies to the iso-phase bus duct as well as all non-segregated 4.16 KV and 480 V bus duct within the scope of license renewal.
High-Voltage Porcelain, Metal Outdoor Surface None Required Surface contamination is not an applicable Insulators Contamination, aging mechanism. The buildup of surface Cracking, Loss of contamination is typically a slow, gradual Material due to process. RNP is located in a rural area Wear where airborne particle concentrations are comparatively low. Consequently, the rate of contamination buildup on the insulators is not significant. Any such contamination accumulation is washed away naturally, by rainwater. The glazed surface on high-voltage insulators at RNP aids in the removal of this contamination. Therefore, there are no applicable aging effects that require management.
Cracking is not an applicable aging mechanism. Cracking or breaking of porcelain insulators is typically caused by physical damage which is event driven rather than an age-related mechanism.
Mechanical wear is an aging effect for strain
U. S. Nuclear Regulatory Commission Attachment liI to Serial: RNP-RA/03-0031 Page 124 of 504 Component/
Materials of Environment Aging Effect/
Aging Management Discussion Commodity Construction (1)
Mechanism Program and suspension insulators if they are subject to significant movement. RNP transmission conductors do not normally swing, and when they do, because of strong winds, they dampen quickly once the wind has subsided. Loss of material due to wear has not been identified during routine inspections at RNP.
Switchyard Bus Aluminum, Iron Outdoor Connection Surface None Required Connection surface oxidation is not an Oxidation, Vibration applicable aging effect. All switchyard bus connections have welded and/or compression connections. For the service conditions encountered at RNP, no aging effects have been identified that could cause a loss of intended function.
Vibration is not an applicable aging mechanism since switchyard bus has no connections to moving or vibrating equipment. Switchyard buses are connected to flexible conductors that do not normally vibrate and are supported by insulators mounted to static, structural components such as cement footings and structural steel. This configuration provides reasonable assurance that switchyard bus will perform its intended function for the period of extended operation.
Transmission Aluminum, Steel Outdoor Loss of Conductor None Required Loss of conductor strength due to corrosion Conductors Strength, Vibration of aluminum core steel reinforced transmission conductors is a very slow process. This process is even slower for rural areas with generally less suspended particles and SO2 concentrations in the air than urban areas. RNP is located in a rural area where airborne particle concentrations
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 125 of 504 Component/
Materials of Environment Aging Effect/
Aging Management Discussion Commodity Construction (1)
Mechanism Program are comparatively low. Consequently, this is not considered a significant contributor to the aging of RNP transmission conductors.
Transmission conductor vibration would be caused by wind loading. Wind loading is considered in the initial design and field installation of transmission conductors and high-voltage insulators throughout the CP&L transmission and distribution network. Loss of material (wear) and fatigue that could be caused by transmission conductor vibration or sway are not considered applicable aging effects that warrant aging management.
Notes: 1. Environments used in the aging management review are listed on LRA Tables 3.0-1 and 3.0-2. All environments are external except ohmic heating, which is considered an internal environment.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 126 of 504 Table 2 - Commodities Included In LRA Table 2.4-12 for Yard Structures and Foundations COMPONENT COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS SUPPORTING STRUCTURES FOR RESTORATION OF OFFSITE POWER Component/Commodity Intended Function AMR Results Anchorage/Embedments Provide structural support and/or shelter to LRA Table 3.5-2, Item 9 (Embedded/Encased in components required for Fire Protection, Concrete)
Anchorage/Embedments Provide structural support and/or shelter to LRA Table 3.5-1, Item 25 Exposed Surfaces components required for Fire Protection, LRA Table 3.5-2, Item 3 ATWS and/or SBO.
Battery Rack Provide structural support and/or shelter to LRA Table 3.5-1, Item 25 components required for Fire Protection, ATWS and/or SBO.
Cable Tray and Conduit Provide structural support and/or shelter to LRA Table 3.5-2, Item 1 components required for Fire Protection, ATWS and/or SBO.
Doors Provide structural support and/or shelter to LRA Table 3.5-1, Item 16 components required for Fire Protection, LRA Table 3.5-2, Item 1 ATWS and/or SBO.
Electrical Bus Duct Provide structural support and/or shelter to LRA Table 3.5-1, Item 25 (Enclosure) components required for Fire Protection, ATWS and/or SBO.
Electrical & Instrument Panels Provide structural support and/or shelter to LRA Table 3.5-1, Item 16 and Enclosures components required for Fire Protection, LRA Table 3.5-2, Item 1 ATWS and/or SBO.
Electrical Component Provide structural support and/or shelter to LRA Table 3.5-1, Item 25 Supports components required for Fire Protection, LRA Table 3.5-2, Item 3 ATWS and/or SBO.
Electrical Manhole Provide structural support and/or shelter to RAI 2.5.5-1 Table 3 components required for Fire Protection, LRA Table 3.5-1, Item 17 ATWS and/or SBO.
Expansion Anchors Provide structural support and/or shelter to LRA Table 3.5-2, Item 1 components required for Fire Protection, ATWS and/or SBO.
Miscellaneous Steel (Stairs &
Provide structural support and/or shelter to LRA Table 3.5-2, Item 3 Ladders, Platforms &
components required for Fire Protection, Connectors, Grating &
Checker Plate)
Pilings Provide structural support and/or shelter to LRA Table 3.5-2, Item 6 components required for Fire Protection, ATWS and/or SBO.
Protective Enclosure Provide structural support and/or shelter to LRA Table 3.5-2, Item 12 (Structures Sheltering or components required for Fire Protection, Enclosing Plant Equipment)
Reinforced Concrete (Beams, Provide structural support and/or shelter to RAI 2.5.1-1 Table 3 Walls, Floors, Columns, etc.)
components required for Fire Protection, LRA Table 3.5-1, Item 17 ATWS and/or SBO.
Siding Provide structural support and/or shelter to LRA Table 3.5-1, Item 16 components required for Fire Protection, LRA Table 3.5-2, Item 1 ATWS and/or SBO.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 127 of 504 COMPONENT COMMODITY GROUPS REQUIRING AGING MANAGEMENT REVIEW AND THEIR INTENDED FUNCTIONS SUPPORTING STRUCTURES FOR RESTORATION OF OFFSITE POWER ComponentlCommodity Intended Function AMR Results Structural Steel (Beams, Provide structural support and/or shelter to LRA Table 3.5-1, Item 16 Plates, Connectors, Column) components required for Fire Protection, LRA Table 3.5-2, Item 3 ATWS and/or SBO.
Threaded Fasteners Provide structural support and/or shelter to LRA Table 3.5-1, Item 25 components required for Fire Protection, LRA Table 3.5-2, Item 3 ATWS and/or SBO.
The above listed components are considered to be in the scope of license renewal and do not represent a change in commitment with regard to 10 CFR 50.63.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA103-0031 Page 128 of 504 Table 3 - Accessible Concrete Aging Management Program for Supporting Structures for Restoration of Offslte Power Component!
Material Environment Aging Effect/
Aging Management Commodity (1J)
Mechanism Program Discussion Accessible Concrete
- Outdoor, Loss of Structures Monitoring This is consistent with Interim Staff Concrete Indoor-Air Material/Freeze Program (GALL Sl.X6)
Guidance.
Conditioned, Thaw, Corrosion of Indoor-Not embedded steel, Air Aggressive chemical Conditioned attack Change in Material Properties/Corrosion of embedded steel, Aggressive chemical attack, Elevated temperature, Leaching of calcium hydroxide Cracking/Freeze Thaw, Reaction with aggregates, Corrosion of embedded steel, Aggressive chemical attack, Settlement Notes: 1. Environments used in the aging management review are listed on LRA Tables 3.0-1 and 3.0-2. All environments are external except ohmic heating, which is considered an internal environment.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 129 of 504 RAI 2.5.2-1 In the LRA Section 2.5.2, the applicant identified electrical/I&C component commodity groups to meet the screening criteria of 10 CFR 54.21 (a)(1 )(i) and evaluated against the criteria of 10 CFR 54.21 (a)(1 )(ii). LRA Table 2.5-1 ElectricaVl&C Component Groups did not include fuse holders. Please explain why fuse holders are not included in the list of commodity groups.
RNP Response:
RNP agrees that fuse holders are passive, long-lived electrical components.
RNP considers them to be another type of electrical connection similar to a terminal block. The fuse holders into which the fuses are placed are typically constructed of blocks of rigid insulating material, such as phenolic resins.
Metallic clamps are attached to the blocks to hold each end of the fuse. The clamps can be spring-loaded clips that allow the fuse ferrules or blades to slip in, or they can be bolt lugs to which the fuse ends are bolted. The clamps are typically made of either copper or aluminum.
The potential aging effects for fuse holders are listed in the Table 1 below:
TABLE 1
- POTENTIAL AGING EFFECTS FOR RNP FUSE HOLDERS Material Stressor or Mechanism Aging Effect Phenolic (base)
- Heat, oxygen Reduced insulation resistance (IR);
Radiation, oxygen electrical failure Electrical stress; thermal Increased resistance and heating cycling, electrical transients Copper or Aluminum (clip) Mechanical stress; frequent Fatigue, cracking, loss of continuity, manipulation, vibration electrical failure Connection surface Change in material properties leading oxidation or corrosion to increased resistance and heating
- The original RNP electrical AMR already includes an evaluation of phenolic materials. This evaluation shows that for the worst-case environmental service conditions encountered at RNP, the base of the fuse holder will be able to maintain its intended function throughout the period of extended operation. No additional evaluation of phenolic is warranted.
The review of fuse holders focuses on only the metallic (clip) portion of the fuse holder, since the phenolic base is bounded by the original RNP electrical AMR.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 130 of 504 The review of fuse holders applies to those that are not part of a larger (active) assembly. Fuse holders inside the enclosure of an active component, such as switchgear, power supplies, power inverters, battery chargers, and circuit boards are considered to be parts of the larger assembly. Since parts and subcomponents in such an enclosure are inspected regularly and maintained as part of the plant's normal maintenance and surveillance activities, they are not subject to an AMR.
The majority of fuse holders at RNP are located in active devices, such as control panels, switchgear, MCC's and fused disconnect switches. To discover the population of fuse holders located outside of active components, a two-fold process was utilized. The first was to interview key plant personnel and the second was to review applicable design documentation. Each process produced a list of potential candidates that were walked-down to ensure that they were not part of an active assembly. Each fuse holder or group of fuse holders was then evaluated to determine if it fulfilled a license renewal intended function. Then, an AMR against the mechanisms shown in Table 1 was performed on those in-scope fuse holders. This process resulted in the identification of two (2) fuse holders that will require aging management. RNP has elected to implement an aging management program for fuse holders to ensure they will continue to perform their intended function for the extended period of operation.
Table 2 shows the aging management review results for fuse holders located outside of active components. shows the attributes of the Aging Management Program for Fuse Holders. shows the program updates to UFSAR Supplement Appendix A.
U. S. Nuclear Regulatory Commission Attachment liI to Serial: RNP-RA/03-0031 Page 131 of 504 Table 2 - Aging Management Review Results for Fuse Holders Component/
Materials of Environment Aging Effect/
Aging Management Discussion Commodity Construction (1)
Mechanism Program Fuse Holders
- Phenolic, Indoor - Air Oxidation, Aging Management Program applies to susceptible fuse
- Copper, Conditioned, Corrosion, Program for Fuse Holders holders located outside of active Aluminum Indoor - Not Air Thermal fatigue devices. Program focuses on the Conditioned, from ohmic metallic clamp (or clip) portion of the Ohmic Heating heating and fuse holder. The parameters monitored electrical include oxidation, corrosion, chemical transients, contamination, thermal fatigue in the Mechanical form of high resistance caused by fatigue from ohmic heating, thermal cycling or frequent removal electrical transients, and mechanical and replacement, fatigue caused by frequent manipulation or vibration of the fuse itself or vibration.
Notes: 1. Environments used in the aging management review are listed on LRA Tables 3.0-1 and 3.0-2. All environments are external except ohmic heating, which is considered an internal environment.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 132 of 504 - Aging Management Program for Fuse Holders The purpose of the aging management program described herein is to provide reasonable assurance that the intended function of fuse holders located outside active devices will be maintained consistent with the current licensing basis through the period of extended operation. An active device is characterized as an assembly or enclosure made up of parts or subcomponents built to perform a specific function. Examples of active devices include switchgear, MCC's, power supplies, inverters, battery chargers, control panels, and equipment racks.
In this aging management program, thermography, contact resistance testing, or other appropriate testing will be used to identify the potential existence of aging degradation.
Scope of Program This program applies to fuse holders located outside of active devices that have been identified as being susceptible to aging effects. Fuse holders inside an active device are not within the scope of this program.
Preventive Actions No actions are taken as part of this program to prevent or mitigate aging degradation.
Parameters Monitored or Inspected This program will focus on the metallic clamp (or clip) portion of the fuse holder.
The parameters monitored include thermal fatigue in the form of high resistance caused by ohmic heating, thermal cycling or electrical transients, mechanical fatigue caused by frequent manipulation of the fuse itself or vibration, chemical contamination, corrosion, and oxidation.
Detection of Aging Effects Identified fuse holders within the scope of license renewal that are located outside of an active device will be tested at least once every 10 years. Testing may include thermography, contact resistance testing, or other appropriate testing to be determined prior to testing. Following issuance of a renewed operating license for RNP, the initial test will be completed before the end of the initial 40-year license term for Unit 2 (July 31, 2010).
Monitoring and Trending Trending of discrepancies will be performed as required in accordance with the Corrective Action Program. Corrective action, as described in Chapter 17 of the Unit 2 FSAR is part of the RNP QA Program.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 133 of 504 Acceptance Criteria The acceptance criteria will be determined based on the test selected for this inspection program.
Corrective Actions The Corrective Action Program will verify the effectiveness of corrective actions (as required). The confirmation process is considered an integral part of the Corrective Action Program. The Corrective Action Program is implemented by the QA Program in accordance with 10 CFR 50, Appendix B.
Confirmation Process The Corrective Action Program will verify the effectiveness of corrective actions (as required). The confirmation process is considered an integral part of the Corrective Action Program. The Corrective Action Program is implemented by the QA Program in accordance with 10 CFR 50, Appendix B.
Administrative Controls This program will be controlled by the Work Control Process. The administrative controls for the Work Control Process are controlled by the Document Control Program. The Document Control Program is implemented by the QA Program in accordance with 10 CFR 50, Appendix B.
Operating Experience Site specific and industry wide operating experience has shown that the loosening of fuse holders is an aging mechanism that, if left unmanaged, has led to a loss of electrical continuity function.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 134 of 504 - UFSAR Supplement Appendix A A.3.1.36 Fuse Holder Program The Fuse Holder Program focuses on the metallic clamp (or clip) portion of the fuse holder. The parameters monitored include thermal fatigue in the form of high resistance caused by ohmic heating, thermal cycling or electrical transients, mechanical fatigue caused by frequent manipulation of the fuse itself or vibration, chemical contamination, corrosion, and oxidation. The program utilizes thermography or other appropriate test (to be determined prior to implementation) to identify the potential existence of aging degradation such as high contact resistance. The program applies to fuse holders located outside of active devices. Fuse holders inside an active component, such as switchgear, power supplies, inverters, battery chargers, control panels, and circuit boards are considered to be parts of the larger assembly. Since piece parts and subcomponents in such an enclosure are inspected regularly and maintained as part of the plant's normal maintenance and surveillance activities, they are not within the scope of this program.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 135 of 504 RAI 2.5.2-2 In the LRA Section 2.5.2, the applicant identified bus ducts to meet the screening criteria of 10 CFR 54.21 (a)(1)(i) and evaluated against 10 CFR 54.21 (a)(1)(ii).
However, in Table 3.6-2, the applicant stated that "Based on the RNP AMR, no applicable aging effects were identified for the bus duct. Therefore, it is concluded that no aging management activities are required for the extended period of operation." Please explain why the connections (two end devices and intermediate points) will not require any aging management. These circuits may be exposed to appreciable ohmic or ambient heating during operation and may experience loosening related to the repeated cycling of connected loads or of the ambient temperature environment (refer to SAND 96-0344).
RNP Response:
Bus ducts exposed to appreciable ohmic or ambient heating during operation may experience loosening of bolted connections related to the repeated cycling of connected loads or the ambient temperature environment. This phenomenon can occur in heavily loaded circuits (i.e., those exposed to appreciable ohmic heating or ambient heating) that are routinely cycled.
The majority of connections to the iso-phase bus are made by welded connections. Bolted connections occur only where flexible connectors are used to connect the bus to the bushing of an end device. The intermediate sections of the bus are connected by flexible straps that are welded to the bus. The flexible connectors/couplings provide strain relief and allow for expansion of the bus bars due to heating. In addition, the iso-phase bus is cycled infrequently (typically on a refueling periodicity), and does not routinely experience the magnitude of temperature changes necessary to induce this aging effect.
Connections to the RNP non-segregated 4.16 KV bus are made by bolted connections, except for the flexible connectors used to connect the bus to the flanges of an end device. This configuration allows for thermal expansion of the copper bus bars due to heating of the transformer or switchgear, and facilitates lining up the adjacent bus bars. The non-segregated 4.16 KV phase bus is cycled infrequently (typically on a refueling periodicity or as plant conditions warrant), and does not routinely experience the magnitude of temperature changes necessary to induce this aging effect.
The loosening of bus duct connections was previously addressed at RNP as industry OE under NRC IN 2000-14, "Non-Vital Bus Fault Leads to Fire and Loss of Offsite Power." Engineering personnel determined that current preventive maintenance activities, coupled with appropriate design margins, were sufficient to preclude the catastrophic failure detailed in the IN. This has been confirmed by a review of site OE which does not show past failures or adverse trends due
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAN03-0031 Page 136 of 504 to a loosening of bolted connections from repeated cycling of connected loads or the ambient temperature environment.
Connections to the non-segregated 480 V bus ducts are made by bolted connections except for the flexible connectors used to connect the bus to the flanges of an end device. The flexible connectors prevent vibration from propagating into the rigid bus. The non-segregated 480 V bus is cycled infrequently (typically on a refueling periodicity or as plant conditions warrant),
and does not routinely experience the magnitude of temperature changes necessary to induce these effects. Some sections of the non-segregated 480 V bus duct are normally de-energized (e.g., EDG bus duct), and are only periodically energized for surveillance testing. In these instances, the loosening of bolted connections is not a credible aging effect.
Although the loosening of bolted connections is not an credible aging effect for RNP bus ducts, RNP has conservatively elected to implement an aging management program to identify and manage potential aging degradation. This will provide reasonable assurance the bus ducts will continue to perform their intended function consistent with the current licensing basis through the period of extended operation. The scope of this program includes the iso-phase bus duct, as well as the in-scope non-segregated 4.16 KV and 480 V bus ducts, (not just those sections credited for SBO).
Table 1 of the RNP Response to RAI 2.5.1-1 shows the aging management review results for the bus ducts within the scope of this review. shows the attributes of the Aging Management Program for Bus Ducts. shows the program updates to UFSAR Supplement, Appendix A.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 137 of 504 - Aging Management Program for Bus Ducts The purpose of the aging management program described herein is to provide an inspection of the iso-phase bus duct, non-segregated 4.16 KV bus ducts and non-segregated 480 V bus duct. Industry experience has shown that bus ducts exposed to appreciable ohmic or ambient heating during operation may experience loosening of bolted connections related to the repeated cycling of connected loads or the ambient temperature environment. This phenomenon can occur in heavily loaded circuits (i.e., those exposed to appreciable ohmic heating or ambient heating) that are routinely cycled.
In this aging management program, bolted connections at sample sections of bus ducts will be checked for proper torque. This activity also includes visual inspections of the bus ducts to identify the potential existence of aging degradation.
Scope of Program This program applies to the iso-phase bus duct as well as non-segregated 4.16 KV and 480 V bus ducts within the scope of license renewal.
Preventive Actions No actions are taken as part of this program to prevent or mitigate aging degradation.
Parameters Monitored or Inspected A sample of accessible bolted connections will be checked for proper torque.
This program will also inspect the bus duct for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. The bus itself will be inspected for signs of cracks, corrosion, or discoloration, which may indicate overheating. The (internal) bus supports will be inspected for structural integrity and signs of cracks.
Detection of Aging Effects This program will be completed before the end of the initial 40-year license term for Unit 2 (July 31, 2010) and every 10 years thereafter.
Monitoring and Trending Trending actions are not included as part of this program. Trending will be performed in accordance with the Corrective Action Program. Corrective action, as described in Chapter 17 of the UFSAR is part of the RNP QA Program.
Acceptance Criteria Bolted connections must meet the minimum torque specifications. Additional acceptance criterion includes no unacceptable indications of cracks, corrosion, foreign debris, excessive dust buildup, or discoloration, which may indicate overheating or evidence of water intrusion. An "unacceptable indication" is
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 138 of 504 defined as a noted condition or situation that, if left unmanaged, could lead to a loss of license renewal intended function.
Corrective Actions Corrective actions (as required) are implemented through the Corrective Action Program. The Corrective Action Program is implemented by the RNP QA Program in accordance with 10 CFR 50, Appendix B.
Confirmation Process The Corrective Action Program will verify the effectiveness of corrective actions (as required). The confirmation process is considered an integral part of the Corrective Action Program. The Corrective Action Program is implemented by the RNP QA Program in accordance with 10 CFR 50, Appendix B.
Administrative Controls The administrative controls for this program will be controlled by the Document Control Program. The Document Control Program is implemented by the RNP QA Program in accordance with 10 CFR 50, Appendix B.
Operating Experience Industry experience has shown that bus ducts exposed to appreciable ohmic or ambient heating during operation may experience loosening of bolted connections related to the repeated cycling of connected loads or the ambient temperature environment. This phenomenon can occur in heavily loaded circuits (i.e., those exposed to appreciable ohmic heating or ambient heating) that are routinely cycled.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 139 of 504 - UFSAR Supplement, Appendix A A.3.1.37 Aging Management Program for Bus Ducts RNP will implement an aging management program to check a sampling of bolted connections of bus ducts, for proper torque. Visual inspections of the bus ducts for signs of cracks, corrosion, foreign debris, excessive dust buildup, evidence of water intrusion or discoloration, which may indicate overheating, will also be performed to identify the potential existence of aging degradation. The program applies to the iso-phase bus duct, as well as all non-segregated 4.16 KV and 480 V bus duct, within the scope of license renewal. Industry experience has shown that bus ducts exposed to appreciable ohmic or ambient heating during operation may experience loosening of bolted connections related to the repeated cycling of connected loads or the ambient temperature environment.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA103-0031 Page 140 of 504 RAI 3.0-1 Several RNP AMPs were described by the applicant as being consistent with GALL, but with some deviation from GALL. These deviations are two types, exceptions and enhancement. Please provide detail definition of exception and enhancement used in the application.
RNP Response:
An exception indicates that the RNP implementing procedure (or other document) does not achieve consistency with some element of the related GALL Chapter Xl Program. Justification for the exception is provided.
An enhancement indicates that the RNP implementing procedure (or other document) requires revision to achieve consistency with some element of the related GALL Chapter Xl or SRP Appendix A.1 Program.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 141 of 504 RAI 3.1.2.1-1 In column 5, "Discussion," of aging management review (AMR) Item 18 to LRA Table 3.1-1, CP&L discusses the potential for SCC/IGSCC to occur in the RV studs and stud assembly. CP&L states that stress corrosion cracking (SCC) is not an applicable effect for alloy 4140 steels (i.e., quenched and tempered low-alloy steel conforming to Specification SA 193 for Grade B7 steels) because the minimum yield strength for the materials is less than 150 ksi. Minimum yield strength is not a material property but rather an acceptance criterion in ASME Material Specification SA-1 93 that must be met for SA-1 93, Grade B7 steels used for bolting components. For these materials, SA-1 93 specifies 105 ksi as the minimum yield strength for SA-1 93, Grade B7 materials must conform to. In the staff's generic SE on WCAP-14574 for license renewal of PWR pressurizer components, dated August 7, 2000 (ADAMS Accession Number ML003738981),
the staff concluded that SCC in these materials may be minimized if yield strengths for the bolts were held to less than 150 ksi or if hardness for the bolts was maintained to less that 32 on Rockwell C hardness scale. Therefore, in the generic SE, the staff stated that an applicant for license renewal may conclude SCC is not an applicable effect for SA-1 93, Grade B7 steels used in bolting components if the applicant would demonstrate that the yield strengths for the bolting components were controlled to less than 150 ksi or if the hardness for the bolts was controlled to less than 32 on a Rockwell C hardness scale. Confirm that intent of the discussion section for Item 18 of Table 3.1-1 of the LRA is to state that CP&L has confirmed that the yield strengths for the RV bolts are within the 105-150 ksi range. If this is the intent of the discussion section, AMR Item 18 of LRA Table 3.1-1 is consistent with GALL.
RNP Response:
The RNP LRA Table 3.1-1 (Item 18) states that studs are fabricated from A540, Grade B23 or B24. However, the minimum specified yield strength for the RV stud assemblies is 120 ksi rather than 100 ksi as originally stated in LRA Table 3.1-1, Item 18. Although the minimum yield strength for the RNP stud assemblies is still less than 150 ksi, RNP recognizes the minimum yield strength is not an actual material property, but is the minimum specified acceptance criterion. Therefore, the RNP evaluation has been updated to identify cracking due to SCC as an applicable aging effect for the reactor vessel stud assemblies.
This aging effect will be managed by the Reactor Heads Closure Studs Program consistent with GALL.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 142 of 504 RAI 3.1.2.1-2 The scope of AMR Item 21 of LRA Table 3.1-1 (Page 3.1-20 of the LRA) includes "steam generator components" that are susceptible to flow assisted corrosion (FAC). For recirculating steam generators (SGs), the steam generator commodity groups that are susceptible to FAC are covered by the scope of the AMRs for commodity group Items IV.D1.1 -d (pressure boundary and structural SG commodity groups), IV.D1.2-h (SG tube bundle commodity group), and IV.D11.3-a (upper SG assembly and separators commodity group) of GALL Volume 2, and include GALL components IV.D1.1.2, "steam nozzle and safe-end"; IV.D1.1.5, ufeedwater nozzle and safe-end"; IV.D11.2.2, "SG tube support lattice bars"; and IV.D1.3.1, "feedwater inlet ring and support." List the exact steam generator components that are covered within the scope of AMR Item 21 of Table 3.1-1 and are susceptible to FAC, and provide your basis why the AMR for the components within the scope of AMR Item 21 is considered to be consistent with the AMRs for commodity group Items IV.D1.1 -d, IV.D1.2-h, and IV.D11.3-a of GALL, Volume 2.
RNP Response:
As noted in LRA Table 3.1-1, Item 16, the subcomponents of the steam generator that are part of LRA Table 3.1-1, line 21 are as follows:
- Steam nozzle (equivalent to IV.D1.1.2)
- Feedwater nozzle thermal sleeve GALL Item IV.D1.2.2 is not applicable to RNP. As can be seen in Volume 2 of GALL, page IV.D1 -1, Item D1.2.2, Tube Support Lattice Bars are part of a Combustion Engineering design for steam generators. RNP is a Westinghouse NSSS plant. GALL Item IV.D11.3.1, Feedwater Inlet Ring and Support, has no license renewal intended function and is therefore not in scope (refer to the RNP Response to RAI 2.3.1.6-1). Therefore, for the in-scope components, Item 21 of LRA Table 3.1-1 is consistent with GALL.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAN03-0031 Page 143 of 504 RAI 3.1.2.1-3 The first AMR Item of page 10 to Table 1 of GALL, Volume 1, identifies that loss of material due to wear, loss of preload due to stress relaxation, and crack initiation and growth due to cyclic loading and/or stress corrosion cracking (SCC) are applicable aging effects for bolts used in the reactor coolant pressure boundary (RCPB), including valve closure bolting, manway and handhole bolting and bolting in high-pressure/high-temperature systems. In the discussion section of AMR Item 22 of LRA Table 3.1-1, you imply that loss of material due to wear and loss of preload due to stress relaxation are not applicable aging effects for the bolts used to secure the primary and secondary SG manways. You also imply that cracking due to cyclic loading is not an applicable effect for RCPB bolting. Provide your technical basis for concluding why loss of material due to wear and loss of preload due to stress relaxation are not applicable aging effects for the bolts used to secure the primary and secondary SG manways. Provide your technical basis for concluding why cracking due to cyclic loading is not an applicable aging effect for all RCPB bolting.
RNP Response:
As stated in LRA Table 3.1-1, Item 22, the applicable aging effects for the SG primary and secondary closure bolts are "cracking from thermal fatigue" and "loss of mechanical closure integrity from loss of material due to aggressive chemical attack."
Loss of material due to wear is not identified by GALL as an aging effect requiring management for the primary and secondary steam generator manway closure bolting (see GALL IV-D.1.1-f and -D.1.1-I). Consistent with GALL, wear is not considered applicable to RNP SG manway bolting. Note that the first AMR Item of page 10 to Table 1 of GALL, Volume 1, does identify "wear." However, a more in-depth review of GALL, Volume 2, identifies this aging mechanism only for GALL Item IV.A2.2-f, A2.2.3, Flange Bolting, which is not applicable to RNP.
Loss of preload due to stress relaxation is identified by GALL for secondary manway bolting. RNP recognizes that loss of pre-load due to stress relaxation can occur. The RNP AMR is based on industry guidance and specifications (EPRI NP-5769, with exceptions noted in NUREG-1339). According to the RNP AMR, "loss of pre-load of mechanical flanged joints, valve body-to-bonnet joints, and pressure retaining bolting associated with pumps or other process components can occur due to settling of mating surfaces, relaxation after cyclic loading, gasket creep, and loss of gasket compression due to differential thermal expansion. RNP has developed a bolting and torque program based on EPRI guidance that considers material properties, joint and gasket design, and service requirements in specifying torque and closure requirements."
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAI03-0031 Page 144 of 504 Therefore, "loss of pre-load due to stress relaxation" is not an aging effect requiring management for RCPB valve closure bolting, manway and holding bolting, or other closure bolting in high pressure and high temperature systems.
The discussion in AMR Item 22 of LRA Table 3.1-1 was not intended to indicate that cracking due to cyclic loading is not an aging effect for RCPB bolting.
Cracking due to cyclic loading (thermal fatigue) is identified as an aging effect for RCPB bolting, and "cyclic loading" for RNP was evaluated as part of the RNP TLAA (GALL Table 1, page. 5).
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 145 of 504 RAI 3.1.2.1-4 In Item 23 of LRA Table 3.1-1, the applicant identifies that crack initiation and growth by primary stress corrosion cracking (PWSCC) is applicable to the CRDM nozzles fabricated from Alloy 600 and proposes to use the Nickel-Alloy Nozzles and Penetrations Program and the Water Chemistry Program to manage this effect. While Item 23 of LRA Table 3.1-1 are consistent with the corresponding AMR for CRDM nozzles in Item IV.A2.2-a of GALL, Volume 2, you have not indicated whether the Robinson upper vessel head includes a head vent nozzle or instrumentation nozzles made from Alloy 600. State whether the RNP upper vessel head includes a head vent nozzle or instrumentation nozzles made from Alloy 600. If the Robinson upper vessel head does the component/commodity group column of Item 23 to LRA Table 3.1-1 must be amended to include these components.
RNP Response:
As identified in GALL Volume 1, Table 1, pg. 11, "CRD Nozzle" consists of Items IV.A2.2-a and IV.A2.7-b, which include components A2.2.1 (CRD Nozzle), A2.7.2 (Head Vent Pipe - Top Head), and A2.7.3 (Instrumentation Tubes - Top Head).
These components are SB-1 66/SB-1 67 (Alloy 600).
As stated in LRA Table 3.1-1, Item 23, "aging management of this component/commodity group is consistent with the GALL Report." Also, RNP did not identify any exceptions in LRA Table 3.1-1, Item 23.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 146 of 504 RAI 3.1.2.1-5 In Item 24 of LRA Table 3.1 -1, the applicant identifies that crack initiation and growth due to cyclic loading, SCC, and/or PWSCC are applicable aging effects for the RCS nozzle safe-ends, CRDM housings, and RCS components other than bolting materials or RCS components made from CASS. AMR Item IV.C2.2-f of GALL, Volume 2, provides the AMR for managing crack initiation and growth due to cyclic loading, SCC, and/or PWSCC in RCS nozzle safe-ends, including the safe-end of the hot-leg nozzle to the reactor vessel. Provide an expanded discussion of how your AMR analysis in Item 24 of LRA Table 3.1-1 has addressed potential implications and lessons learned from the Summer hot-leg nozzle cracking, and specifically how your AMR for Item 24 has resolved potential issues identified in Information Notices 2000-17, 2000-17, Supplement 1, and 2000-17, Supplement 2 (dated October 18, 2000, November 16, 2000, and February 28, 2001, respectively), as related the Summer cracking event.
RNP Response:
This issue was considered in the overall Alloy 600 Strategic Plan. As a result of the V. C. Summer cracking event, the 10-year ISI inspections performed during RO-20 were enhanced to focus on the hot-leg nozzles and to use lessons learned from V. C. Summer to enhance inspection techniques. No reportable indications were found during these inspections. Follow-up inspections will be performed as a part of the ongoing Alloy 600 management strategy. RNP is participating in industry working groups relating to Alloy 600 degradation. Refer to the RNP Response to RAI B.4.1-1.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 147 of 504 RAI 3.1.2.1-6 Parts 1 and 2 In Item 26 of LRA Table 3.1-1, you provide your AMR for the external surfaces of carbon steel components in the reactor coolant pressure boundary (RCPB). In this AMR you identify that corrosion due to potential exposure to concentrated boric acid is an applicable aging effect for the external surfaces of all carbon steel components in the reactor coolant pressure boundary, and that the boric acid wastage program will be used to manage this aging effect in the RCPB components.
- 1.
AMR 26 of LRA Table 3.1-1 does not provide a corresponding aging management review and identify aging effects for the surfaces of the carbon steel or low-alloy steel RCPB components that are exposed to the containment atmosphere, nor does Table 3.1-2 of the LRA provide an alternative AMR for the surfaces of the carbon steel RCPB components that are exposed to the containment atmosphere. In the AMR for commodity group V.E.1-b of GALL Volume 2, the staff identifies that loss of material due to general corrosion is an applicable aging effect for the external surfaces of carbon steel and low-alloy steel PWR components that are exposed to moist, humid, or damp atmospheric environments.
Provide your AMR for the external surfaces of the carbon steel or low alloy steel RCPB components that are exposed to atmospheric environments and identify all aging effects that are applicable to these components under exposure to the atmospheric environments. If aging effects are applicable, propose applicable aging management activities or programs to manage the aging effects during the period of extended operation for RNP. Provide your technical basis for your conclusions.
- 2.
Wastage of carbon steel and low alloy steel RCS components in PWRs is a concern if the components are exposed to potential leaks of the borated reactor coolant. The boric acid wastage event of the Davis Besse reactor vessel head, which is discussed in NRC Bulletin 2002-01, is a prime example of severe wastage that has occurred in the industry as a result of a prolonged exposure to the borated reactor coolant. NRC NUREG/CR-5576, "Survey of Boric Acid Corrosion of Carbon Steel Components in Nuclear Plants," provides a summary of other boric acid wastage events that have occurred in the U. S. nuclear power industry prior to the summer of 1990. You state that the AMR in Item 26 of LRA Table 3.1-1 is consistent with GALL without the need for further evaluation.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 148 of 504 The component/commodity group column of Item 26 in LRA Table 3.1-1 does not include ASME Class 1 RCS components from low-alloy steel (including RV shells and heads made from low-alloy steel grades) among those RCS components that could be potentially exposed to leaks of the borated reactor coolant and subject to loss of material as a result of boric-acid induced wastage. The discussion column of Item 26 in LRA Table 3.1-1 also does not address the implications of the Davis Besse boric-acid wastage event on the ability of the boric acid corrosion program to manage potential boric-acid-corrosion induced wastage of carbon steel and low-alloy steel components of the RCS. Amend Item 26 in LRA Table 3.1-1 to: (1) include both carbon steel and low-alloy steel ASME Class 1 components as being among the Class 1 RCS components that could potentially be affected by loss of material as a result of boric-acid induced wastage, and (2) include how the implications and lessons learned from the Davis Besse boric-acid wastage event have been addressed/resolved relative to your AMR for Item 26. In addition, indicate whether the RCS inlet, outlet and safety injection nozzles may be potentially susceptible to this aging effect and whether the scope of your AMR in Item 26 to LRA Table 3.1-1 includes these components. In addition, with respect AMR Item 26 of LRA Table 3.1-1, confirm that loss of material due to aggressive corrosive attack (i.e., due to leaks of the borated reactor coolant) is an applicable aging effect for the primary steam generator manway covers and bolts.
RNP Response:
- 1) Carbon and low alloy steel components that are indoors not exposed to weather, and not prone to condensation are not considered to be in a moist environment. In the absence of an aggressive chemical environment (i.e., boric acid leakage), significant corrosion of these materials will not occur without the presence of moisture. Hence, the RNP methodology determined that no aging effects were applicable to this category. See the RNP Response to RAI 3.2.1-1 for additional discussion on this topic.
gas - external does not discern between low alloy steel and carbon steel in determining susceptibility to boric acid wastage. For both carbon and low allow steel, the only criteria considered in this regard is whether a given SSC is potentially exposed to a boric acid environment (i.e., does it contain borated water or is it in the proximity of borated water systems).
The vessel head, flange, shell and inlet / outlet nozzles, as well as SG primary manway covers and bolting, are considered susceptible to boric acid wastage.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 149 of 504 The SI system does not connect directly to the vessel, but rather ties into the reactor coolant system piping loops. The SI system and reactor coolant system piping (including the SI nozzles at these connections) are constructed of stainless steel and are not considered susceptible to boric acid wastage.
With regard to implications and lessons learned arising from the Davis-Besse event, the RNP Response to RAI B.3.2-3 outlines the response and future activities associated with NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity," and 2002-02, "Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection Programs."
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 150 of 504 RAI 3.1.2.1-7 AMR Item 27 of LRA Table 3.1-1 (Page 3.1-24 of the LRA) provides the applicant's AMR for possible erosion in the SG secondary manways and handholds. The applicant stated that the GALL report indicates this Item is applicable to once-through steam generators; therefore, it is not applicable to RNP. For the SG secondary manways and handholds in recirculating SGs (GALL component IV.D.1.1.7), the AMR for this Item is specified in AMR commodity group Item D1.1-f (page IV D1-4) of GALL, Volume 2. RNP has recirculating steam generators. Provide your AMRs, including your identification of aging effects and aging management programs, if applicable, of the secondary manways and handholds. If erosion of the RNP SG secondary manways and handholds is not determined to be an applicable effect for the RNP SG secondary manways and handholds, provide your technical basis for deviating from the staff's AMR given in AMR commodity group Item D1.1-f (page IV D1-4) of GALL, Volume 2.
RNP Response:
For the steam generator secondary manway and handhole bolting (equivalent to GALL Volume 2, Item IV.D1.1-f (IV.D1.1.7, Secondary Manway and Handhole Bolting)) the applicable AMRs are in LRA Table 3.1-1, Item 1 (Cracking Due to thermal fatigue which is a TLAA evaluated in accordance withl 0 CFR 54.21 (c))
and LRA Table 3.1-2, Item 12 (Loss of mechanical closure integrity from loss of material due to aggressive chemical attack managed by the boric acid corrosion program). For the SG secondary manway and handhole covers (non-GALL components), the applicable AMRs are LRA Table 3.1-1, Item 1 (Cracking due to thermal fatigue which is a TLAA evaluated in accordance with10 CFR 54.21 (c)),
and Table 3.1-2, Item 5 (Loss of Material from Crevice, General, and Pitting Corrosion managed by the Water Chemistry Program).
The design of the secondary manways and handholes precludes the potential for wall thinning due to erosion. The secondary manways and handholes are located in areas of large cross section where velocity is low and erosion is not an aging concern. RNP plant-specific operating experience has confirmed that these components are not susceptible to this aging effect.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 151 of 504 RAI 3.1.2.1-8 In GALL, Volume 2, the corresponding AMRs for loss of preload/stress relaxation in PWR RV internal bolted and/or fastened connections are the AMR entries for commodity groups IV.B2.1 -d (GALL component IV.B2.1.7, upper internals assembly hold down springs), IV.B2.5-h (GALL component IV.B2.5.5, lower support plate column bolts in the lower internals assembly), and IV.B2.5-i (GALL component IV.B2.5.7, clevis inserts of the lower internals assembly).
Management programs recommended by GALL for these Items are the ISI Plan (GALL Program XI.M1) for the upper internals assembly hold down springs (GALL Item IV.B2.1-d); the ISI Plan and the loose parts monitoring activities (GALL Program XI.M14) for the lower support plate column bolts; and the ISI Plan and either the loose parts monitoring activities or the neutron noise monitoring activities (GALL Program XI.M15) for the clevis insert bolts. Your AMR in Item 30 of LRA Table 3.1-1 does not list the applicable lower and upper internal assembly subcomponents that are subject to loss of preload due to stress relaxation. Modify AMR entry 30 in LRA Table 3.1-1 to clarify which of the reactor vessel (RV) upper internal assembly components and RV lower internals assembly mechanical closure components are susceptible loss of preload due to stress relaxation and assess the consistency of your AMRs for these components against the corresponding AMRs provided in commodity group Items IV.B2.1-d, IV.B2.5-h, and IV.B2.5-i of GALL, Volume 2. In addition, you state that your AMR for the lower internal assembly clevis insert pins is not consistent with GALL because you use a slightly different combination of AMPs to manage loss of preload in the clevis insert pins but include this commodity group in both LRA Table 3.1-1 and LRA Table 3.1-2. Confirm the AMR entry for this commodity group is really not consistent with GALL and that, therefore, the applicable AMR for this commodity group is appropriately reviewed and discussed in Item 15 of LRA Table 3.1-2.
RNP Response:
RNP does not credit XI.M14, Loose Part Monitoring, or XI.M15, Neutron Noise Monitoring, for aging management (See LRA Table B-1, page B-6). As explained in the LRA for Table 3.1-1, Items 30 and 35, RNP is not consistent with GALL.
The AMR for these components is shown in Table 3.1-2, Item 15. The components evaluated in this AMR for reactor internals include:
- Upper Support Column Bolts
- Holddown Spring
- Lower Support Plate Column Bolts
- Clevis Insert Bolts The aging effect requiring management is Loss of Preload due to Stress Relaxation, which is managed by the ASME Code Section Xl, Subsections IWBI,
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 152 of 504 IWC and IWD Program, and the PWR Vessel Internals Program. As stated in the discussion in LRA Table 3.1-2, Item 15:
"As discussed previously, RNP will incorporate the applicable results of industry initiatives related to aging effects for reactor vessel internals into the PWR Vessel Intemals Program. This includes information on loss of preload due to stress relaxation.
The AMPs used at RNP will effectively manage the effects of loss of loss of preload for affected internals components."
For additional information concerning the PWR Vessel Internals Program, please refer to the RNP Response to RAI B.4.3-2.
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RA/03-0031 Page 153 of 504 RAI 3.1.2.1-9 Parts 1 and 2 AMR Item 31 of Table 3.1-1 provides your AMR for loss of fracture toughness due to neutron irradiation embrittlement and/or thermal aging and void swelling in RV internals in the fuel zone (other than Westinghouse and B&W baffle/former bolts). The corresponding AMRs in GALL, Volume 2, are those for commodity group Items IV.B2.3-c, IV.B2.4-e, IV.B2.5-c, IV.B2.5-g, and IV.B2.5-n, and include GALL components IV.B2.3.1, "core barrel"; IV.B2.3.2, "core barrel flange"; IV.B2.3.3, "core barrel outlet nozzles"; IV.B2.3.4, "thermal shield";
IV.B2.4.1, "baffle and former plates"; IV.B2.5.1, "lower core plate"; IV.B2.5.2, "fuel alignment pins"; IV.B2.5.5, "lower support plate column bolts"; IV.B2.5.7, "clevis insert bolts"; IV.B2.5.3, "lower support forging or casting"; and IV.B2.5.4, "lower support plate columns." On Tuesday, October 28, 2002, CP&L provided a tool (handout) for assisting the staff in identifying which of the GALL components were covered by the AMR Items in Table 3.1-1 of the LRA. For AMR Item 31, the "tool" indicated that the corresponding GALL components covered within the scope of AMR Item 31 were GALL components IV.B2.3.1, core barrel";
IV.B2.3.2, "core barrel flange"; IV.B2.3.3, "core barrel outlet nozzles"; IV.B2.3.4, "thermal shield"; IV.B2.4.1, "baffle and former plates"; IV.B2.5.1, "lower core plate"; IV.B2.5.2, "fuel alignment pins"; IV.B2.5.5, "lower support plate column bolts"; IV.B2.5.7, "clevis insert bolts"; IV.B2.5.3, "lower support forging or casting"; and IV.B2.5.4, "lower support plate columns."
- 1.
Provide your technical basis for omitting the following GALL components from the scope of AMR 31 in LRA Table 3.1-1: IV.B2.3.2, "core barrel flange"; IV.B2.3.3, "core barrel outlet nozzles"; IV.B2.3.4, "thermal shield";
and IV.B2.5.4, "lower support plate columns." If any of these components should be included within the scope of AMR Item 31 of LRA 3.1-1, revise AMR Item accordingly to state which AMP will be used to manage loss of fracture toughness due to neutron irradiation embrittlement and void swelling in the components.
- 2.
Commodity group Item IV.B2.5-n of GALL Volume 2 covers loss of fracture toughness due to neutron irradiation and void swelling in the lower support forging/casting and in the lower support plate columns. AMR Item 31 of Table 3.1-1 does not clearly identify whether or not the lower support and lower support plate columns are fabricated from statically cast austenitic stainless steel (CASS) materials. If either of these components is fabricated from CASS, loss of fracture toughness due to thermal aging is an applicable aging effect for the components and the uThermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program" should be proposed to manage this effect. In order for the components to be consistent with AMR Item IV.B2.5-m of GALL Volume 2, state whether the RV internal lower support and lower support plate columns are fabricated from CASS materials, and if so, provide a
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 154 of 504 supplemental AMR for these components that is consistent with AMR Item IV.B2.5-m of GALL Volume 2.
RNP Response:
Part 1 LRA Table 3.1-1, Item 31 does not provide for an evaluation of thermal aging of CASS components. A description of which parts of the reactor vessel internals are fabricated from CASS is available in Section 2.3.1.5 of the LRA. LRA Table 3.1-1, Item 31, is a review of the GALL, Volume 1, item shown on page 13 (first line of the table). This item is limited to two aging effects/mechanisms: 1) Loss of fracture toughness due to neutron irradiation embrittlement, and 2) void swelling.
The applicable GALL Items from Volume 2 for RNP are:
IV.132.3-c IV.B32.3.11:
IV.B2.3.2:
IV.B2.3.3:
IV.B2.3.4:
IV.B32.4-e IV.132.4.1 IV.132.5-c IV.132.5.11 IV.B2.5-_i IV.B2.5.2:
IV.B2.5.5:
IV.B2.5.7:
IV.132.5-n IV.132.5.3:
IV.B2.5.4:
Core barrel (CB)*
CB flange (upper)
CB outlet nozzles Thermal shield Baffle and former plates*
Lower core plate*
Fuel alignment pins*
Lower support plate column bolts Clevis insert bolts*
Lower support forging or casting*
Lower support plate columns
The material and environment combination evaluated in Volume 2 of the GALL is stainless steel in chemically treated borated water up to 3402C (6442F) with fluence > 1017 n/cm2 (E>1 MeV).
As stated in the discussion section of this AMR item:
"However, even those components that were determined to be located away from the fuel zone region have, at least, the RNP
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 155 of 504 PWR Vessel Intemals Program applied; and, of course, the Water Chemistry Program applies to the reactor vessel internals treated water environment."
The applicable components for this AMR item will act as predictors for other reactor vessel internals components that are not part of this evaluation group.
This represents a slight deviation from the GALL, however, RNP has committed to participating in industry programs and to update the PWR Vessel Internals Program as required based on industry experience and lessons learned.
Part 2 The applicable AMRs for reactor vessel internals components fabricated from CASS are as follows:
- Table 3.1-1, Item 8
- Table 3.1-1, Item 33
- Table 3.1-2, Item 14 (Table 3.1-1, Item 25, points to this AMR item)
As shown on page B-6, LRA Table B-1, RNP does not credit XI.M13, Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS), for aging management.
Reduction of fracture toughness from thermal embrittlement and neutron irradiation embrittlement will be managed with the PWR Vessel Internals Program. This is a difference from the management strategy recommended in GALL. As stated in the discussion section for Table 3.1-2, Item 14:
"RNP applies the PWR Vessel Intemals Program to manage thermal aging embrittlement of CASS components. As discussed previously, RNP will incorporate the applicable results of industry initiatives related to aging effects for reactor vessel internals into the PWR Vessel Internals Program. This includes information regarding thermal embrittlement and neutron irradiation embrittlement. The PWR Vessel Internals Program used at RNP will effectively manage the effects of loss of fracture toughness due to thermal aging and neutron irradiation embrittlement for CASS reactor internals components."
For additional information concerning the PWR Vessel Internals Program, please refer to the RNP Response to RAI B.4.3-2.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 156 of 504 RAI 3.1.2.1-10 Confirm that this Item is really not consistent with GALL and should not be included in Table 3.1-1 Item 35, and that instead the Item is appropriately addressed by the aging management review stated in Item 15 of Table 3.1-2 of the application. Also confirm that Item 35 of LRA Table 3.1-1 is redundant with Item 30 of LRA Table 3.1-1.
RNP Response:
LRA Table 3.1-1, Items 30 and 35 are reviews of GALL components appearing as the last item on pages 12 and 15 of Volume 1, respectively. As the discussion states for these two items, RNP does not consider these line items as consistent with GALL. For both these items the discussion states:
"Since this differs with the GALL Report, the discussion has been included in Item 15 of Table 3.1-2."
The AMR for these components is contained in Item 15 of LRA Table 3.1-2.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 157 of 504 RAI 3.1.2.2.1-1 In Table 2.3.1-1, you identify that all RCS pressure boundary components may be susceptible to thermal fatigue (i.e., refer to Item 1 in Table 3.1-1 of the LRA),
but only identify that some of the reactor vessel (RV) internals serving support functions are susceptible to thermal fatigue. Provide justification why a thermal fatigue analysis (TLAA) is not needed for those RV internals listed in Table 2.3.1 -
1 that are not referred to as being within the scope of Item 1 in Table 3.1-1 (i.e.,
the AMR entry in Table 3.1-1 for RCS components subject to thermal fatigue). If any of these RV internal components are within the scope of license renewal and are susceptible to thermal fatigue during period of extended operation, they must be included within the scope of Item 1 in Table 3.1-1 of the LRA and analyzed within the scope of the TLAA for thermal fatigue, as described in Section 4.3 of the LRA. Section 4.3 of the LRA must then be revised accordingly.
RNP Response:
Note: In the RAI, "Table 2.3.1-1" should be revised to read uTable 2.3-1."
The RV internals listed in Table 2.3-1 that are not referred to in Table 3.1-1, Item 1, are as follows:
- Upper Support Column Bolts
- Upper Core Plate Alignment Pins
- Lower Support Plate Columns - (CASS)
- Clevis Insert Bolts
- BMI Columns (non-CASS)
- BMI Columns Cruciform (CASS)
- Diffuser Plate Head Cooling Spray Nozzle
- Secondary Core Support Upper Instrumentation Column, Conduit, and Supports The RNP AMR evaluation deemed these components not susceptible to "Cracking Due to Thermal Fatigue." This is consistent with GALL, which also does not identify this aging effect/mechanism for the above reactor vessel internals components.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 158 of 504 RAI 3.1.2.2.2-1 In the Robinson LRA, your aging management review for the steam generator (SG) shell assembly is provided in Item 2 of Table 3.1-1 to the RNP LRA.
Amend the AMR in Item 2 to list the SG transition cone (GALL component IV.D1.1.4) as an additional component in the SG shell assembly requiring aging management, as evaluated consistent with commodity group Item IV.D1.1-c of GALL, Volume 2.
RNP Response:
Table 3.1-1, Item 2, is a review of GALL components included as the second item on page 6 of Volume 1. Since Table 3.1-1, Item 2 is consistent with GALL and did not take exception to GALL, it therefore includes the SG transition cone.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 159 of 504 RAI 3.1.2.2.3-1 Clarify in column 5 of AMR Item 3 of LRA Table 3.1-1 that the TLAA proposed in the AMR will be performed in accordance with the following requirements:
the evaluation criteria requirements and calculational method requirements of 10 CFR §50.61 for calculating the RTpTS values for the RV beltline materials (i.e., materials with amassed neutron fluences in excess of 1 x 1017 n/cm2) and for demonstrating that they will have adequate protection against PTS events through the expiration of the extended period of operation for RNP.
the requirements of 10 CFR Part 50, Appendix G, Section IV.A.2, for generating the P-T limits for the RCS through the expiration of the extended period of operation for RNP.
the requirements of 10 CFR Part 50, Appendix G, Section IV.A.1, for demonstrating that the RV beltline materials will have adequate levels of USE through the expiration of the extended period of operation for RNP, including the need to perform an appropriate equivalent margins analysis should the applicant determine that the USE value for any of the RV beltline materials is below 75 ft-lbs in the unirradiated condition or 50 ft-lbs prior to the expiration of the extended period of operation for RNP.
RNP Response:
Refer to RAI B.3.11-2 concerning the use of surveillance program data in determining the 60-year RTpTS values and 60-year USE values.
Refer to RAI 4.2.1-1 concerning the most recent determination of 60-year RTpTs values and 60-year USE values based upon the results from testing of Surveillance Capsule X in WCAP 15828, Rev. 0. The 60-year RTpTs values have been calculated for pressure vessel ferritic materials that have a 60-year fluence value greater than 1 x 10 n/cm. The calculational method requirements and evaluation criteria requirements from 10 CFR 50.61 were applied using 60-year fluence projection data. An equivalent margins analysis was developed for the RV beltline plate materials with projected USE values below 50 ft-lbs. The results demonstrate that the RV beltline materials will have adequate levels of USE through the expiration of the extended period of operation (see RAI 4.2.2-1, Part 2, for more detail).
The results demonstrated that each of the components will have adequate protection against PTS events through the expiration of the extended operational period for RNP. The requirements of 10 CFR 50, Appendix G, Section IV.A.1, will continue to be used for generating the P-T limits for the RCS through the
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 160 of 504 expiration of the extended period of operation (see RAI 4.2.3-1 for additional detail).
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 161 of 504 RAI 3.1.2.2.4-1 The discussion section of AMR Item 6 in LRA Table 3.1-1 does not appear to credit the ASME Section Xi, Subsections IWB, IWC, and IWD Program as one of the AMPs for managing crack initiation and growth in RCS small-bore piping components less than 4 NPS in size. To be consistent with the AMR in commodity group Item IV.C2-g of GALL, Volume 2, the applicant should credit the ASME Section Xi, Subsections IWB, IWC, and IWD Program as one of the three programs for managing crack initiation and growth in RCS small-bore piping components less than 4 NPS in size (i.e., in addition to the water chemistry program that meets the program attributes of GALL Program XL.M2 and a one-time inspection for the small-bore pipe that meets the program attributes describes in GALL Program XI.M32). If CP&L seeks to conclude that AMR Item 6 in LRA Table 3.1-1 is consistent with AMR Item IV.C2-g in GALL Volume 2, modify your AMR in Item 6 of LRA Table 3.1-1 to add the ASME Section Xl, Subsections IWB, IWC, and IWD Program as one of the three programs for managing crack initiation and growth in RCS small-bore piping components less than 4 NPS in size. Otherwise, provide a technical basis why the ASME Section Xi, Subsections IWB, IWC, and IWD Program does not need to be credited with managing cracking in these components and move the AMR in AMR Item 6 of Table 3.1-1 to Table 3.1-2 of the LRA.
RNP Response:
The ASME Code, Section Xl exempts 4 inch and under piping from volumetric examinations, but does require surface examinations. As such, the Section Xi Program can be used to manage externally initiated cracking in small bore piping, but would not be considered effective for internally initiated cracking. In the SER for Generic Technical Report WCAP-14575A, the NRC notes that austenitic stainless steel components in Westinghouse NSSS loops are not susceptible to external cracking unless the outside surface comes into contact with halogens. RNP controls chemicals that might contact primary loop components to prevent this from occurring, and site operating experience affirms the effectiveness of these controls. Hence, externally initiated cracking is not considered an applicable aging effect, and the Section Xl Program is not credited.
Since the Section Xl Program is listed in GALL, but not credited by RNP, the pertinent AMR discussion in Item 6 of LRA Table 3.1-1 would be more appropriate in LRA Table 3.1-2.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RAN03-0031 Page 162 of 504 RAI 3.1.2.2.6-1 Parts 1 and 2 In AMR 8 of Table 3.1-1, CP&L's basis for omitting dimensional changes due to void swelling as an applicable effect for the reactor vessel (RV) internal neutron flux thimble guide tubes is that the guide tubes are partly located outside of the RV and are not expected to experience excessive irradiation at elevated temperatures. In the staff's AMR for commodity group Item IV.B2.6-b of Table IV.B2 of GALL, Volume 2, the staff identifies that void swelling is an applicable aging effect Westinghouse-designed RV internal flux thimble guide tubes. The applicant's AMR for evaluating dimensional changes in the RNP RV internal neutron flux thimble guide tubes is, therefore, not consistent with the corresponding assessment in GALL, Volume 2. Address the following inconsistencies with GALL, Volume 2:
- 1.
CP&L's basis for omitting dimensional changes as an applicable aging effect for the RNP neutron flux thimble guide tubes is non consistent with AMR for commodity group Item IV.B2.6-b of Table IV.B2 of GALL, Volume
- 2. Since your AMR for evaluating void swelling in the thimble tubes is not consistent with GALL, Volume 2, amend Table 3.1-2 of the LRA to include a separate AMR for evaluating whether dimensional changes due to void swelling is an applicable aging effect for the RNP RV neutron flux thimble guide tubes.
- 2.
CP&L's basis for omitting void swelling as an applicable aging effect for the RNP RV neutron flux thimble guide tubes appears to rely on the basis that portions of the thimble guide tubes are located outside the RV and that these portions of the thimble guide tubes will not experience excessive irradiation at elevated temperatures. The AMR in commodity group Item IV.B2.6-b of Table IV.B2 of GALL, Volume 2, identifies that dimensional changes due to void swelling is an applicable aging effect for the portions of Westinghouse-designed RV neutron flux thimble guide tubes that are internal to the RV because the staff considers that the portions within the RV cavity may experience excessive irradiation at elevated temperatures. Therefore, in regard to performing the supplemental AMR that has been requested by the staff for evaluating whether dimensional changes due to void swelling is an applicable aging effect for the RNP RV neutron flux thimble guide tubes, provide a technical basis why void swelling is not considered to be an applicable aging effect for the portions of the flux thimble tubes that could be exposed to elevated temperature and irradiation levels. If dimensional changes due to void swelling is an applicable aging effect for the RNP RV neutron flux thimble guide tubes, include this aging effect as being applicable to the neutron flux thimble guide tubes in your supplemental AMR that was requested in Part 1 of this RAI and propose an applicable aging management program to manage this aging effect during the extended period of operation for RNP.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 163 of 504 RNP Response:
The pressure boundary portion of the flux thimble guide tubes (IV.B2.6.1) are located outside the reactor vessel and are fabricated from stainless steel. As noted within LRA Table 2.3-1, those portions of the guide tubes that provide structural support to safety-related components and that are internal to the reactor vessel are included in Item 8 of Table 3.1-1 (BMI Columns (non-CASS) and BMI Columns Cruciform (CASS) on page 2.3-14 of the LRA). The change in dimension due to the void swelling aging effect is currently a topic under investigation by the industry. RNP has selected those reactor internals components subject to the highest irradiation as potentially susceptible to this aging effect. These components will act as predictors for other reactor internals components. RNP is participating in industry programs to assess this aging effect and to update the PWR Vessel Internals Program, as required, based on industry experience and lessons learned. The PWR Vessel Internals Program, described in Section B4.3 of the LRA, includes the following statement:
"To address change in dimensions due to void swelling, RNP will continue to participate in industry programs to investigate this aging effect and determine the appropriate AMP."
Subsection A.3.1.30, PWR Vessel Internals Program, of the LRA contains the following statement:
"This is a new program that will incorporate the following commitments (1) To address change In dimensions due to void swelling, RNP will continue to participate in industry programs to investigate this aging effect and determine the appropriate AMP, (2) To address baffle and former assembly issues, RNP will continue to participate in industry programs and will implement appropriate program enhancements to manage the aging effects associated with the Baffle and Former Assembly, (3) As WOG and EPRI Materials Reliability Project (MRP) research projects are completed, RNP will evaluate the results and factor them into the PWR Vessel Internals Program. The expected results include identification of components which are the most limiting and most susceptible and identification of appropriate inspection techniques, (4) RNP will implement an augmented inspection during the license renewal term. Augmented inspections, based on required program enhancements, will become part of the ASME Section Xl program. Corrective actions for augmented inspections will be developed using repair and replacement procedures equivalent to those requirements in ASME Section Xl." [Emphasis added.]
For additional information concerning the PWR Vessel Internals Program, please refer to the RNP Response to RAI B.4.3-2.
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RA/03-0031 Page 164 of 504 RAI 3.1.2.2.7-1 Parts 1 and 2 For the pressurizer spray head, and steam generator instrumentation nozzles and drains, the staff is concerned that existing programs, such as the chemistry program and/or the ASME Section XI, Subsection IWB, IWC, and IWD Inservice Inspection Program may not be sufficient to manage SCC-induced or PWSCC-induced crack initiation and growth in these components. The corresponding AMR Items for these components are identified in commodity group Items IV.C2.5-j and IV.D1.1-j of GALL, Volume 2, respectively. Address the following specific inconsistencies with GALL for these components:
- 1. In RAI 2.1.3.1-1, the staff requested the applicant to confirm whether or not the RNP pressurizer spray head is within the scope of license renewal, along with a technical basis for the determination. In order to be consistent with GALL Item IV.C2.5-j, if the RNP pressurizer spray head is determined to be within scope of license renewal, a one-time plant-specific inspection program must be proposed to manage SCC-induced/ PWSCC-induced crack initiation and growth in the pressurizer spray head. In addition, if the pressurizer spray heads are within the scope of license renewal and are made from CASS, potential loss of fracture toughness as a result of thermal aging must be addressed as a potential aging effect for the spray head, and the one-time inspection must be sufficient to detect and size cracking in the pressurizer spray head prior to exceeding the critical crack size for the component. If, in response to RAI 2.1.3.1-1, the RNP pressurizer spray head is determined to be within the scope of license renewal, amend AMR Item 9 of LRA Table 3.1-1 to include the pressurizer spray head among the components within the scope of the commodity group for the AMR Item, and provide a revised AMR for the pressurizer spray head, including which AMPs will be credited to manage SCC-induced/
PWSCC-induced crack initiation and growth in the spray head and loss of fracture toughness if the pressurizer spray head is fabricated from CASS.
- 2. In AMR Item IV.D1.1-j of GALL, Volume 2, the staff identifies that crack initiation and growth due to SCC or PWSCC are applicable aging effects for SG instrumentation and drain line nozzles, and recommends that a plant-specific management program be evaluated for managing these aging effects. In Item 9 of LRA Table 3.1-1 (page 3.1-12 of the table), you state that RNP steam generator instrument nozzles are not fabricated from Alloy 600, so they were not included within the scope of Item 9 to LRA Table 3.1-1. However, you did not state where the AMR Item for the steam generator instrument and drain line nozzles could be found in the application, and did not provide the material of construction for the steam generator instrumentation and drain line nozzles. Either clarify where your aging management review for the
U. S. Nuclear Regulatory Commission Attachment IlIl to Serial: RNP-RAJ03-0031 Page 165 of 504 steam generator instrument and drain lines nozzles may be found or, if an aging management review has not been performed for these components, provide your AMR for the steam generator instrument and drain line nozzles, including the materials of fabrication, applicable environments, applicable aging effects, and aging management programs for the components, and include the AMR for the nozzles as a part of LRA Table 3.1-2.
RNP Response:
(1) The pressurizer spray head is not within the scope of license renewal and therefore not subject to AMR. See the RNP Response to RAI 2.3.1.3-1.
(2) GALL Item IV.D1.1-j (IV.D1.1.10), Instrument Nozzles Fabricated from Alloy 600, is not applicable to RNP. The applicable AMR items for steam generator instrument nozzles at RNP are contained in LRA Table 3.1-1, Item 1, and Table 3.1-2, Item 5. The steam generator secondary side shell penetrations are fabricated from carbon steel.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 166 of 504 RAI 3.1.2.2.7-2 According to your discussion section of aging management review (AMR) Item 10 to LRA Table 3.1-1, the RNP pressurizer surge nozzle and its safe-end are not fabricated from CASS and are, therefore, not included within the scope of the commodity group Items listed for AMR Item 10. Provide clarification which Table and AMR entry provides your AMR for the RNP pressurizer surge nozzle and its safe-end. If an AMR has not been performed for the RNP pressurizer surge nozzle and its safe-end, provide your AMR for this Item, including the materials of fabrication, applicable environments, applicable aging effects, and aging management programs for the components, and include the AMR for the surge nozzle and its safe-end as a part of Table 3.1-2.
RNP Response:
The pressurizer surge nozzle and its safe-end are evaluated in the following AMR items:
- LRA Table 3.1-1, Item 1
- LRA Table 3.1-1, Item 24
- LRA Table 3.1-2, Item 2
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 167 of 504 RAI 3.1.2.2.10-1 Regarding AMR Item 14 of LRA Table 3.1-1 (Page 3.1-15 of the LRA): In the application, CP&L states that the steam generator (SG) feedwater impingement plate and support are not applicable to RNP because they are not a part of the RNP steam generators and that the RNP steam generators use feed rings with J-nozzles. In the discussion column of AMR Item 14, CP&L clarifies that the feed rings perform no license renewal intended function. For recirculating SGs, AMR Item IV.D1.1-e of GALL Volume 2 (page IV D1-12 of the report), identifies the feedwater inlet ring and support (GALL component IV.D1.3.1) as components for aging management and that loss of material (loss of section thickness) due to erosion is an applicable aging effect for these components. Clarify whether the feed ring and support need to be included in Table 3.1-1 of the RNP LRA to be consistent with the GALL report RNP Response:
LRA Table 3.1-1, Item 14, is a review of the last line on page 8 of GALL, Volume
- 1. The "Item Number in GALL" referenced is IV.D1.1-e. This item number specifically relates to IV.D1.1.6, "Feedwater Impingement Plate and Support."
Therefore, the feedwater inlet ring and support are not part of LRA Table 3.1-1, Item 14. In addition, as stated in the LRA:
'The component/commodity group is not applicable to RNP. These components are not part of the RNP steam generators."
It should be also noted that in the RNP Response to RAI 2.3.1.6-1, the feedrings/J-nozzles are described as performing no license renewal intended function. These components are equivalent to GALL, Volume 2, Item IV.D1.3.1, uFeedwater Inlet Ring and Support." GALL, Volume 1, provides the AMR for this item on page 9 (see the fourth line of the table).
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RA/03-0031 Page 168 of 504 RAI 3.1.2.2.11-1 In Item 15 of LRA Table 3.1-1 (Page 3.1-16), you provide your AMR for various aging effects that are applicable to Alloy 600 steam generator tubes, repair sleeves, and plugs. The staff seeks additional information regarding your AMR provided in Item 15 of LRA Table 3.1-1.
A.
If sleeves and plugs have been installed in the RNP steam generators, specify the material of construction of sleeves and plugs. Specify the type of sleeves and plugs used in RNP
(
Reference:
Item D1.2.3 on page IV D1 -11 of the GALL report).
B.
Discuss the current and past degradation mechanisms in the RNP replacement steam generators and identify the regions where tube degradation has occurred.
C.
NRC has issued the following generic communications regarding steam generator tube plugs: NRC Information Notice 89-65, "Potential for Stress Corrosion Cracking in Steam Generator Tube Plugs Supplied by Babcock and Wilcox"; NRC Information Notice 89-33, "Potential Failure of Westinghouse Steam Generator Tube Mechanical Plugs"; NRC Bulletin No. 89-01, "Failure of Westinghouse Steam Generator Tube Mechanical Plugs," and Supplements 1 and 2 to NRC Bulletin 89-01; and NRC Information Notice 94-87, "Unanticipated Crack in A Particular Heat of Alloy 600 Used for Westinghouse Mechanical Plugs for Steam Generator Tubes." If any of the above NRC generic communications are applicable to the tube plugs in the RNP steam generators, discuss the corrective actions that have been taken to resolve the age related degradation issues raised in the information notices and identify which aging management programs have been applied to manage tube plug degradation.
D.
Clarify whether the applicant is committed to NEI 97-06. The applicant referenced NEI 97-06 but did not make a formal commitment to follow NEI 97-06.
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RAI03-0031 Page 169 of 504 RNP Response:
A.
No sleeves have been installed in the RNP steam generators. Refer to the RNP Response to Part A of RAI B.2.4-2 for the type of plugs currently installed in the RNP SGs.
B.
Refer to the RNP Response to part B of RAI 8.2.4-2.
C.
RNP has one steam generator tube that was plugged with Westinghouse A600 mechanical plugs supplied from heat number 4523 (Group 1 heat) that was the subject of NRC Bulletin 89-01. These plugs were subsequently repaired by installation of an A690 plug-in-plug.
D.
Refer to the RNP Response to RAI B.2.4-3.
U. S. Nuclear Regulatory Commission Attachment Ill to Serial: RNP-RA/03-0031 Page 170 of 504 RAI 3.1.2.2.11-2 In Item 15 of LRA Table 3.1-1, the applicant stated that"... Bulletin No. 88-02 has been determined to be not applicable to Robinson Nuclear Plant (RNP) based upon the steam generator design and support plate material...." In Bulletin No. 88-02, the staff reported a steam generator tube rupture event at North Anna Unit 1 which was caused by high cycle fatigue. In the bulletin, the NRC staff concluded that the following conditions could lead to a rapidly propagating fatigue failure: 1) denting at the upper support plate; 2) a fluid-elastic stability ratio approaching that for the tube that ruptured at North Anna; and 3) absence of effective anti-vibration bar support. The staff needs more information regarding the applicability of the RNP steam generators with respect to Bulletin 88-02, NRapidly Propagating Fatigue Cracks in Steam Generator Tubes." Please discuss whether any of the three factors listed above lead to fatigue-induced failure of the RNP SG tubes.
RNP Response:
RNP responded to NRC Bulletin No. 88-02 in a letter from R. B. Richey (CP&L) to Dr. J. Nelson Grace (USNRC), Serial NLS-88-049: "Response to NRC Bulletin No. 88-02, Rapidly Propagating Cracks in Steam Generator Tubes," dated March 24, 1988. The letter states:
"The purpose of this submittal is to inform you that CP&L has determined that Bulletin No. 88-02 is not applicable to H. B.
Robinson, Unit 2 (HBR2). This is based upon the HBR2 Westinghouse Model 44 steam generator support plates having been constructed of SA250(sic), Type 405 stainless steel, rather than carbon steel as indicated in the Bulletin's "For Action" statement. In addition, Westinghouse and CP&L have confirmed that the two significant contributors to high fluid-elastic stability ratio (as discussed in the Bulletin) are not in evidence at HBR2."
The material specification is a typographical error and should read SA240 Type 405.
The tube support plate design for the RNP replacement steam generators was selected to minimize the potential for tube denting. The design is discussed in the RNP Response to RAI 3.1.2.2.12-1. The RNP replacement steam generators are discussed in more detail in the RNP Response to RAI B.2.4-2.
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 171 of 504 RAI 3.1.2.2.12-1 In LRA Table 3.1-1, Item 16 (Page 3.1-17), you have stated that tube support lattice bars are not applicable to the RNP steam generators (SGs); however, it is not clear to the staff what tube support configuration (i.e., plate or lattice bar) is installed in the RNP steam generators and whether the tube support configuration would require aging management. Confirm that the tube support configuration used in the RNP steam generator designs is not a lattice bar and instead is a tube support plate that is fabricated from stainless steel. Assess whether or not loss of material due to flow-assisted corrosion and cracking are applicable aging effects for the SG tube support configuration component at RNP. Provide your technical basis for your conclusions.
RNP Response:
The design of the RNP steam generator tube support plates is available in NUREG-1 004, Safety Evaluation Report related to steam generator repairat H. B. Robinson Steam Electric Plant Unit No. 2, dated November, 1983. Section 3.3.5 discusses the design features of the quatrefoil tube support plates. The discussion is as follows:
3.3.5 Support Plates 3.3.5.1 Materials To reduce the potential for tube denting, the tube support plate material has been changed from carbon steel to ferritic stainless steel, in the replacement steam generators. Corrosion in the crevice between the tube and tube support plate has led to denting of the steam generator tubing in that area. Alternative support plate materials have been evaluated, and SA-240 Type 405 ferritic stainless steel has been selected as the optimum material for this application. This material is ASME Code-approved and is resistant to corrosion. In addition, SA-240 has a low wear coefficient when paired with Inconel and has a coefficient of thermal expansion similar to carbon steel, Corrosion of SA-240 results in an oxide which has approximately the same volume as the parent material, whereas corrosion of carbon steel results in oxides which have a larger volume than the parent material. In addition to the tube support plates, the baffle plate will be constructed of SA-240 Type 405 stainless steel.
3.3.5.2 Quatrefoil Support Plate Design
U. S. Nuclear Regulatory Commission Attachment III to Serial: RNP-RA/03-0031 Page 172 of 504 The quatrefoil tube support plate design, illustrated in Figure 3.4, consists of four flow lobes and four support lands. The lands provide support to the tube during operating conditions; the lobes allow flow around the tube. The quatrefoil design directs the flow along the tubes to minimize steam formation and chemical concentrations at the tube-to-tube support plate intersections. The quatrefoil support plate design has a lower pressure drop and results in higher average velocities along the tubes, minimizing sludge deposition. The combination of higher velocities in the support plate region and corrosion-resistant material should minimize the potential for support plate corrosion.
GALL Item IV.D1.2.2 is not applicable to RNP. As can be seen in Volume 2 of GALL, page IV D1 -1, Item D1.2.2 Tube Support Lattice Bars are part of a Combustion Engineering design for Steam Generators. RNP is a Westinghouse NSSS plant. The tube support plates at RNP are similar to GALL Item IV.D1.2.4 (IV-D1.2-k) except that the GALL Item is carbon steel and the RNP tube support plates are fabricated from stainless steel. The AMR for the tube support plates are contained in Table 3.1-1, AMR Item 1 and Table 3.1-1, AMR Item 17.
As stated in the discussion for Table 3.1-1, AMR Item 17:
"The tube support plates in the RNP steam generators are fabricated of stainless steel, not carbon steel.
The GALL Report is not specific regarding the type of corrosion involved for this component commodity group. At RNP, the AMR for this component identified cracking from SCC and loss of material from crevice corrosion, pitting corrosion, and erosion as applicable aging effects! mechanisms. For RNP, these effects!
mechanism are managed by a combination of the Steam Generator Tubing Integrity Program and the Water Chemistry Program applicable to steam generators. This is in agreement with the AMPs cited for this component in Item IV. D1.2-k of the GALL Report. The cited AMPs applied at RNP are consistent with the GALL Report."
Therefore, while tube support plates of stainless steel are not evaluated in GALL, RNP will use the same combination of programs to manage the applicable aging effects.