RBG-47835, Submittal of Response to License Renewal Application NRC Request for Additional Information Set 10
| ML18087A188 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 03/26/2018 |
| From: | Maguire W Entergy Operations |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML18088A782 | List: |
| References | |
| RBG-47835 | |
| Download: ML18087A188 (62) | |
Text
{{#Wiki_filter:* Entergx Proprietary Information - Withhold From Public Disclosure Under 10 CFR 2.390 The balance of this letter may be considered non-proprietary upon removal of Enclosure 2 . Entergy Operations, Inc. -c:==. River Bend Station 5485 U.S. Highway 61N 5t Francisville. LA 70775 Tel 225-381-4374 William F. Maguire Site Vice President River Bend Station RBG-47835 March 26, 2018 Attn: Document Control Desk U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville , MD 20852-2738
SUBJECT:
Response to License Renewal Application NRC Request for Additional Information (RAI) Set 10 River Bend Station, Unit 1 Docket No. 50-458 License No. NPF-47
References:
- 1) Entergy Letter: License Renewal Application (RBG-47735 dated May 25, 2017)
- 2) NRC email : River Bend Station, Unit 1, Request for Additional Information , Set 10- RBS License Renewal Application - dated February 8, 2018 (ADAMS Accession No. ML18043A008)
- 3) Entergy Letter: Request for Due Date Extension for License Renewal Application NRC Request for Additional Information - Set 10 dated February 22, 2018 (ADAMS Accession No. ML18058A085)
Dear Sir or Madam :
In Reference 1, Entergy Operations, Inc (Entergy) submitted an application for renewal of the operating license for River Bend Station (RBS) for an additional 20 years beyond the current expiration date. In an email dated February 8, 2018, (Reference 2) the NRC staff made a Request for Additional Information (RAI) needed to complete the license renewal application review. On February 22, 2018, Entergy requested a due date extension for RAI Set 10 from 30 days to 45 days (Reference 3). Enclosure 1 provides the responses to the Set 10 RAls. Enclosure 2 contains information that is considered proprietary; therefore, Enclosure 2 is requested to be withheld from disclosure to the public under 10 CFR 2.390. An affidavit from GE-Hitachi Nuclear Energy Americas LLC supporting withholding under 10 CFR 2.390 is provided in Enclosure 2. If you require additional information, please contact Mr. Tim Schenk at (225)-381 -4177 or tschenk@entergy.com .
RBG-47835 Page 2 of 2 In accordance with 10 CFR 50.91 (b)(1) , Entergy is notifying the State of Louisiana and the State of Texas by transmitting a copy of this letter to the designated State Official. I declare under penalty of perjury that the foregoing is true and correct. Executed on March 26, 2018 . Sincerely, WFM/RMC/alc : Responses to RAI Set 10 - River Bend Station : Proprietary Responses to Set 10 - River Bend Station cc: (with Enclosure)
- u. S. Nuclear Regulatory Commission Attn: Emmanuel Sayoc 11555 Rockville Pike Rockville , MD 20852 cc: (wlo Enclosure)
U. S. Nuclear Regulatory Commission Attn : Lisa Regner 11555 Rockville Pike Rockville , MD 20852 u.s. Nuclear Regulatory Commission Region IV 1600 East Lamar Blvd. Arlington, TX 76011-4511 NRC Resident Inspector PO Box 1050 St. Francisville, LA 70775 Central Records Clerk Public Utility Commission of Texas 1701 N. Congress Ave. Austin, TX 78711-3326 Department of Environmental Quality Office of Environmental Compliance Radiological Emergency Planning and Response Section Ji Young Wiley P.O. Box 4312 Baton Rouge , LA 70821-4312 RBF1-18-0040
RBG-47835 Enclosure 1 Responses to Request for Additional Information Set 10
RBG-47835 Page 2 of 60 REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION RIVER BEND STATION, UNIT 1 - SET 10 DOCKET NO.: 50-458 CAC NO.: MF9757 Office of Nuclear Reactor Regulation Division of Materials and License Renewal Question RAI 3.1.2.1.2-1 (Materials , Environments, Aging Effects Requiring Management, and Aging Management Programs)
Background
The regulation in 10 CFR 54.4(a)(3) requires applicants to include structures, systems, or components (SSCs) in the scope of their license renewal applications (LRAs) if the SSCs are within the scope of specific regulations, including those SSCs that are subject to the regulation in 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without SCRAM Events for Light-Water Cooled Nuclear Power Plants." For those SSCs that are scoped into an LRA in accordance with 10 CFR 54.4, the regulation in 10 CFR 54.21 (a)(1) requires the applicant to subject the SSCs to an aging management review (AMR) if the SSCs are: (a) are not active or do not involve changes in configuration or moving parts, and (b) are not subject to replacement based on a qualified life or specified time period. For those SSCs that are scoped into an LRA and are required to be subjected to an AMR , the regulation in 10 CFR 54.21 (a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. In AMR item #43 of Table 3.1-1 in the NUREG-1800, Revision 2 Report (SRP-LR) and in AMR Items IV.B1 .RP-28 of NUREG-1801 , Revision 2 (GALL) , the staff identifies that the combined programs in GALL AMP XI.M1, "ASME Section XI , Inservice Inspection , Subsections, IWB, IWC, and IWO," and GALL AMP XI.M2 , 'Water Chemistry," may be used as an acceptable combination of AMPs to manage loss of material in stainless steel or nickel alloy BWR reactor vessel internal (RVI) components as a result of a pitting or crevice corrosion mechanism. In LRA AMR Item 3.1.1-43 and in the Table 2 AMR items in Table 3.1.2-2 that are linked to AMR item 3.1.1-43, the applicant proposes to use the One-Time Inspection Program (OTI) Program, LRA AMP B.1.32) as an NEI Generic Note E alternative condition program for managing loss of material due to pitting or crevice corrosion in the RVI components in lieu of the applicant's Inservice Inspection Program (LRA AMP B.1.22). Issue The staff has not specified in the GALL report that a combination of OTI and Water Chemistry AMPs is an acceptable basis for managing loss of material due to pitting or crevice corrosion or other corrosion-based aging effects (e.g. , cracking induced by any of the stress corrosion cracking mechanisms) in BWR RVI components. Instead, the staff has always specified in GALL Table IV.B1 that a periodic condition monitoring program (e.g., the lSI Program or Vessel Internals Program) should be used in conjunction with the Water Chemistry Program to manage corrosion-based aging effects in BWR RVI components, where the implementation of the periodic condition monitoring program would be used to confirm the effectiveness of the Water Chemistry Program in managing the effects.
RBG-47835 Page 3 of 60 Request For reactor internals, justify why the OTI Program is considered to be an acceptable basis for verifying the effectiveness of the Water Chemistry Control - BWR Program in managing loss of material due to pitting or crevice corrosion in lieu of using either LRA AMP B.1.22, "Inservice Inspection Program ," or LRA AMP B.1.10, "BWR Vessel Internals Program ," for this aging management objective.
Response
According to NUREG-1801 , Rev. 2 (GALL) Item IV.C1.RP-158, the One-Time Inspection Program is an acceptable method of verifying the effectiveness of the Water Chemistry Control - BWR Program in managing loss of material due to pitting or crevice corrosion for stainless steel and nickel alloy components exposed to reactor coolant. This combination of programs is effective at managing this aging effect for stainless steel and nickel alloy components exposed to reactor coolant, regardless of whether they are inside or outside the reactor vessel. The reactor vessel internals components in LRA Table 3.1.2-2 that are linked to AMR Item 3.1.1-43 for loss of material are inspected within the BWR Vessel Internals Program to manage cracking . Most of these components have line items in LRA Table 3.1.2-2 showing that the BWR Vessel Internals and Water Chemistry Control - BWR programs manage cracking. The only exceptions are the in-core instrument flux monitoring dry tubes and stabilizers. The RBS response to RAI 3.1.2.1.2-2 revises LRA Table 3.1.2-2 to show that the BWR Vessel Internals and Water Chemistry Control - BWR programs manage cracking of the dry tubes and stabilizers. Question RAI 3.1.2.1.2-2 (Materials , Environments, Aging Effects Requiring Management, and Aging Management Programs)
Background
The regulation in 10 CFR 54.4(a)(3) requires applicants to include structures, systems, or components (SSCs) in the scope of their license renewal applications (LRAs) if the SSCs are within the scope of specific regulations , including those SSCs that are subject to the regulation in 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without SCRAM Events for light-Water Cooled Nuclear Power Plants." For those SSCs that are scoped into an LRA in accordance with 10 CFR 54.4, the regulation in 10 CFR 54.21 (a)(1) requires the applicant to subject the SSCs to an aging management review (AMR) if the SSCs are: (a) are not active or do not involve changes in configuration or moving parts, and (b) are not subject to replacement based on a qualified life or specified time period . For those SSCs that are scoped into an LRA and are required to be subjected to an AMR , the regulation in 10 CFR 54.21 (a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation . In LRA Table 3.1.1, AMR item 3.1.1 -103, the applicant addresses the AMPs that will be used to manage cracking in stainless steel incore instrument flux monitoring dry tubes (ICI dry tubes) that are exposed to a treated water> 140 OF environment. In the basis for the AMR and the related AMR item in LRA Table 3.1.2-2, the applicant cites use of NEI Generic Note E and identifies that it is replacing the BWR Vessel Internals Program (LRA AMP B.1.10) with the Inservice Inspection (lSI) Program (LRA AMP B.1 .22) to manage cracking of the tubes.
RBG-47835 Page 4 of 60 Issue In Section 4.6 of Aging Management Program Evaluation Report RBS-EP-15-00006, Revision 0, the applicant indicates the incore instrumentation (ICI) dry tubes at the plant are within the scope of the applicant's BWR Vessel Internals Program and are inspected in accordance the inspection and evaluations guidelines in EPRI Report No. BWRVIP-47-A. The program evaluation report also indicates that the ICI dry tubes are being replaced in accordance with the additional guidelines in GE-Hitachi Services Information Letter (SIL) 409, Revision 3, with the final replacements of the dry tubes to be completed in year 2019. Request Clarify whether the ICI dry tube replacement activities are within the scope of the condition monitoring AMP that will be used to manage cracking in the tubes and, if so, whether the replacement activities are considered to be an enhancement of the program . Additionally, justify why LRA AMR Item 3.1.1-103 proposes to use the lSI Program for management of cracking in the ICI dry tubes when the BWR Vessel Internals Program (as the existing AMP referenced for reactor internals in the LRA) already implements inspections of the dry tubes using the methodology in EPRI Report BWRVIP-47-A.
Response
The RBS BWR Vessel Internals Program implements the inspection and evaluation guidance of BWRVIP A, which states that cracking of the dry tube is judged to have no impact on safe shutdown and therefore no inspections are required from the safety perspective. BWRVIP-47-A also indicates that the guidance and recommendations of GE SIL 409, Rev. 1, can be used to address economic consequences. As noted in the request, the program is a condition monitoring program. Unacceptable findings are entered into the corrective action program . While corrective actions may include component replacement, the in-core instrument (ICI) dry tube replacement activities are not considered within the scope of the condition monitoring BWR Vessel Internals Program . LRA AMR Item 3.1 .1-103 and the LRA Table 3.1.2-2 component type "In-core instrument flux monitoring (dry tube and stabilizer)" have been revised to identify the BWR Vessel Internals Program as the program that inspects the dry tubes for cracking using the GE SIL 409 guidance referenced in EPRI Report BWRVIP-47-A. The changes to LRA 3.1.2.1.2, Tables 3.1.1 (Item 3.1.1-103) and 3.1.2-2 follow with additions underlined and deletions lined through . 3.1.2.1.2 Reactor Vessel Internals Aging Management Programs The following aging management programs manage the aging effects for the reactor vessel internals components.
- BWR Vessel Internals
- Inservice Inspection
- Water Chemistry Control - BWR
RBG-47835 Page 5 of 60 Table 3.1.1 Item Component Aging Aging Further Discussion Number Effect/Mechanism Management Evaluation Program Recommended 3.1.1-103 Stainless steel Cracking due to Chapter No Consistent with N UREG-1801 and nickel stress corrosion XI.M9, "BWR for most components. The alloy reactor cracking , Vessel BWR Vessel Internals and internal intergranular Internals," Water Chemistry Control - components stress corrosion and BWR Programs manage exposed to cracking , Chapter cracking of me&t-stainless reactor coolant irradiation-assisted XI.M2, steel and nickel alloy reactor and stress "Water internals components . neutron flux corrosion Chemistry" Grackinj of tl=te incore cracking instrl::lment Elry tl::lges is manajeEl 9y tl=te InserlJice Inspection anEl \flJater Gl=temistry Gontrol 8WR Drnnr'>rY\C'
RBG-47835 Page 6 of 60 Table 3.1.2-2 Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Note Type Function Requiring Program Item Item Management In-core Pressure Stainless Treated water Cracking IAseF¥ise IAspestisA IV.B1.R-105 3.1.1-103 A instrument boundary steel > 140°F (ext) BWR Vessel Internals flux monitoring
- Dry tube Water Chemistry Control -
- Stabilizers - - '------
BWR
RBG-47835 Page 7 of 60 Question RAI 4.2.1-1 (Reactor Vessel Fluence) INFORMATION NOTICE This is a non-proprietary version of RAI4.2.1-1, which has the proprietary information removed. Portions of the document that have been removed are indicated by an open and closed bracket as shown here [[ ]].
Background
The regulation in 10 CFR 54.21 (c)(1 )(ii) states that, for a specific time limited aging analyses (TLAA) that is dispositioned in accordance with this regulation , the applicant must demonstrate that the analysis has been projected to the end of the period of extended operation . License renewal application (LRA) Section 4.2.1, Reactor Vessel Neutron Fluence," identifies the neutron fluence analysis in the current licensing basis as a TLAA for the LRA. Specific fracture toughness requirements for normal operation and for anticipated operational occurrences for power reactors are set forth in 10 CFR Part 50, Appendix G, "Fracture Toughness Requirements." The requirements of Appendix G are imposed by 10 CFR 50.60, "Acceptance Criteria for Fracture Prevention Measures for Light Water Nuclear Power Reactors for Normal Operation." To satisfy the requirements of Appendix G, methods for determining the fast neutron fluence (E > 1.0 MeV) are necessary to estimate the fracture toughness of the pressure vessel materials. Regulatory Guide (RG) 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," describes methods and assumptions acceptable to the NRC staff fo r determining pressure vessel fluence. This RG is intended to ensure the accuracy and reliability of the fluence determination required by General Design Criteria 14, 30, and 31 of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50. LRA Section 4.2.1 states: "Neutron fluence for the welds, shells and nozzles of the [reactor pressure vessel (RPV)] beltline region was determined using the General Electric Hitachi (GEH) method for neutron flux calculation documented in report NEDC-32983P-A (Ref. 4-20) and approved by the NRC." The applicant states that the fluence methodology is adherent to the staff's guidance in RG 1.190. Issue The water density sensitivity analyses described in Section 7.1, "Calculation Uncertainties," of NEDC-32983P-A, Revision 2, "General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations," are not applicable to the above core water density distribution because the generically approved calculational model does not extend above the active fuel region based on Figure 2-2, "Schematic View of (r,z) Model" in NEDC-32983P-A, Revision 2. The uncertainty in the above core water density distribution, for example, will have an impact on the overall fluence calculation uncertainty for RPV beltline components above the active fuel region (e.g ., the BWRl6 low pressure coolant injection nozzle forging/weld considered in the development of pressure-temperature limits) . Also, the applicant's existing plant records include a condition report that identifies that the current calculational methodology in GEH Report No. NEDC-32983P-A may include one or more errors in the calculational methods for calculating RPV neutron fluxes or projecting RPV neutron fluence values.
RBG-47835 Page 8 of 60 Request
- 1. Provide a detailed description of the above core calculational model and how this expanded model has been qualified. Describe how analytic uncertainty data, measurement benchmarking data, and calculational benchmarking data relevant to the RPV extended beltline has been incorporated into the combined uncertainty analysis applicable to the RPV extended beltline to support the qualification of an expanded model.
- 2. If the combined uncertainty analysis is greater than 20%, explain how the neutron fluence values used in downstream safety analyses have been augmented to account for any uncertainties associated with the calculation methods, nuclear data, or modeling accuracies of the analyses.
- 3. Explain how the identified error(s) included in GEH Report No. NEDC-32983P-A affect the information provided in the LRA.
Response
Response to RAI 4.2.1-1 Requests 1 and 2: RAI 4.2.1-1, Requests 1 and 2, related to the fluence calculational model and uncertainty in the RPV in the extended beltline region above the core. These requests overlap similar requests made in RAI 4.7.3-1 , Requests 1-3, for reactor vessel internals (RVI) components in the same region . [[ ]] For a complete response to RAI 4.2.1-1 , Requests 1 and 2, please see the response to RAI 4.7.3-1, Requests 1-3. Response to RAI 4.2.1-1 Request 3: The identified error in the condition report was an error in the implementation of the GEH methodology described in NEDC-32983P-A, Revision 2 and not an error in the GEH methodology. The River Bend Station specific fluence analysis has been revised to correct the identified error. The revised fluence results affect many of the values reported in the license renewal application (LRA) . The changes to LRA Section 4.2.1, Table 4.2-1, Table 4.2-2, Table 4.2-3, Table 4.2-4, Table 4.2-5, Table 4.2-6, Section 4.7.3 and Section 4.8 follow with additions underlined and deletions lined through. 4.2.1 Reactor Vessel Fluence Fluence is calculated based on a time-limited assumption defined by the operating term. Therefore, analyses that evaluate reactor vessel neutron embrittlement based on calculated fluence are TLAAs. The predicted peak high energy (> 1 million electron-volts [MeV]) neutron fluence for 54 EFPY is ~8 . 34E+ 18 neutrons per square centimeter (n/cm 2 ) at the vessel inner surface. Neutron fluence for the welds, shells and nozzles of the RPV beltline region was determined using the General Electric Hitachi (GEH) method for neutron flux calculation documented in report NEDC-32983P-A (Ref. 4-20) and approved by the NRC. The method adheres to the guidance provided in RG 1.190 (Ref. 4-8). Results of the fluence evaluation are shown in Table 4.2-1. (Ref. 4-16, 4-20) USAR Figure 5.3-1 identifies the vessel assembly configuration , and USAR Figure 5.3-6 denotes the weld seams and plate identifiers in the original beltline region. Regulations in 10 CFR 50 Appendix G define the beltline as the region of the reactor pressure vessel that directly surrounds the effective height of the active core and adjacent regions of the RPV that are predicted to experience sufficient neutron irradiation damage to be considered in the selection of the most limiting material with regard to radiation damage. In addition, 10 CFR
RBG-47835 Page 9 of 60 50 Appendix H requires material surveillance testing only for ferritic materials with neutron fluence exceeding 1.0E+ 17 n/cm 2 . The beltline is thus considered to include the reactor pressure vessel ferritic materials with projected 54 EFPY fluence that exceeds 1.0E+ 17 n/cm 2
- 2 The elevation range within which the projected fluence exceeds 1.0E+ 17 n/cm for 54 EFPY is from 191.26190.06 inches to 385.46a location between 378.26 and 443.13 inches relative to the bottom of the vessel. The beltline region for 54 EFPY includes plates and welds in shell rings 1, 2 and 3. Nozzles N6 and N12 will exceed a fluence of 1.0E+ 17 n/cm 2 at 54 EFPY. No other nozzles are projected to exceed 1.0E+ 17 n/cm 2 during the period of extended operation.
The neutron fluence calculation results are inputs into fracture toughness analyses that consider the effects of aging due to exposure to neutron irradiation and are evaluated as TLAAs. The effects of aging due to neutron irradiation are considered in the neutron embrittlement TLAAs for the reactor vessel (e.g., upper-shelf energy analysis and P-T limits analysis). The neutron fluence analysis has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21 (c)(1 )(ii).
RBG-47835 Page 10 of 60 Table 4.2-1 Peak Fluence at 54 EFPY Shell 3 and Axial Welds, Circumferential Weld AC 2 54 EFPY Peak 1.0. fluence = 3.43E+ 17 n/cm Thickness in inches = 5.41 54 EFPY Peak 14 T(a) fluence = 2.48E+ 17 n/cm 2 Shell 2 and Axial Welds 54 EFPY Peak 1.0. fluence = ~8.34E+ 18 2 n/cm Thickness in inches = 5.41 54 EFPY Peak 14 T fluence = hG46 .03E+ 18 2 n/cm Shell 1 and Axial Welds, Circumferential Weld AB Thickness in inches = 5.813 54 EFPY Peak 1.0. fluence =~7.68E+17 ( 2 n/cm 54 EFPY Peak 14 T fluence = a...a+5.42E+ 17 2 n/cm N12 Nozzles (water level instrumentation nozzles) 54 EFPY Peak 1.0. fluence =2-:-W2.99E+18 n/cm 2 Thickness in inches = 5.41 54 EFPY Peak 14T fluence = +:-942.16E+18 2 n/cm N6 Nozzles (RHR/LPCI nozzles) 54 EFPY Peak 1.0. fluence = ~2.33E+17 2 n/cm Thickness in inches = 5.41 54 EFPY Peak 14T fluence = g.,&7.1.68E+.:t.e1l 2 n/cm
- a. One-fourth of the way through the vessel wall measured from the internal surface of the vessel.
RBG-47835 Page 11 of 60 Table 4.2.2 RBS Beltline ART Values for 54 EFPY 54 54 54
% % Chemistry Initial 1f.IT EFPY EFPY EFPY Copper Nickel Factor Adjusted RT NOT Fluence l1RT NOT Margin Shift ART Component Heat (Cu) (Ni) (CF) CF of nlcm 2 of r5 1(a) r5 to(b) OF of of Plant-Specific Chemistries C2904-2 0.11 0.65 75 10 2.48E+ 17 14.7 0 7.3 14.7 29 .3 39.3 Shell Plate 3 C3001-2 0.04 0.66 26 -40 2.48E+17 5.1 0 2.5 5.1 10.2 -29.8 C2929-2 0.12 0.64 84 -50 2.48E+17 16.4 0 8.2 16.4 32 .8 -17.2
&..G4 C3054-1 0.09 0.70 58 -20 49.8 0 17.0 34.0 83.8 63.8 6.03E+18
&..G4 Shell Plate 2 C3054-2 0.09 0.70 58 10 49.8 0 17.0 34.0 83.8 93.8 6.03E+18
&.G4 C3138-2 0.08 0.63 51 0 43.8 0 17.0 34.0 77.8 77.8 6.03E+18
&.a+ ~ ~ ~ 4&4 WA C2904-1 0.11 0.65 75 10 0 5.42E+17 22.8 11.4 22.8 45.7 55.7 Shell Plate 1
&.a+ ~ +2-,9 ~ ~ &+-,e C2879-1 0.12 0.61 83 10 0 5.42E+17 25.4 12.7 25.4 50.9 60.9 Axial Welds 5P5657/Linde 0.07 0.71 95 -60 2.48E+17 18.6 0 9.3 18.6 37.3 -22.7 Shell 3 124/0931 BJ, BK, BM (S) (C)
RBG-47835 Page 12 of 60 54 54 54
% 0/0 Chemistry Initial 1.4T EFPY EFPY EFPY Copper Nickel Factor Adjusted RTNDT Fluence ~RTNDT Margin Shift ART Component Heat (Cu) (Ni) (CF) CF of n/cm 2 of f1 (a) f1 to (b) OF of of 1
5P5657/Linde 124/0931 0.04 0.89 54 -60 2.48E+17 10.6 0 5.3 10.6 21.2 -38.8 (T)(C) 5P6756/Li nde
&.G4 148.
124/0342 0.08 0.93 108 -60 92.7 0 28.0 56.0 88.7 6.03E+18 7 Axial Welds (S)i9 Shell 2 BE, BF, BG 5P6756/ Linde
&.G4 160.
124/0342 0.09 0.92 122 -50 104.7 0 28.0 56.0 110.7 6.03E+18 7 (T)i9 5P5657/ Linde
&..a7 2.Q.,.a M,.7 2.Q.,.a ~ -+:+
124/0931 0.07 0.71 95 -60 0 5.42E+ 17 29.0 14.5 29.0 58.1 -1.9 (S)i9 Axial Welds Shell 1 BA, BB 5P5657/ Linde
&..a7 +&.+ SA +&.+ ~ ~
124/0931 0.04 0.89 54 -60 0 5.42E+17 16.5 8.3 16.5 33.0 -27.0 (T)i9 5P6771 /Linde 124/0342 0.03 0.88 41 -30 2.48E+17 8.0 0 4.0 8.0 16.1 -13.9 Circumferential (S)i9 Shell 2 to Shell 3 AC 5P6771 /Linde 124/0342 0.04 0.95 54 -20 2.48E+17 10.6 0 5.3 10.6 21.2 1.2 (T)i9
- -~- --_ .- ~
RBG-47835 Page 13 of 60 54 54 54
% % Chemistry Initial lAT EFPY EFPY EFPY Copper Nickel Factor Adjusted RTNDT Fluence ~RTNDT Margin Shift ART 2
Component Heat (Cu) (Ni) (CF) CF of nlcm of lil(a) lit;,(b) of of of 4P7216/Linde
~ 2M +2-,.7 2M ~ M 124/0751 0.06 0.85 82 -50 0 (8)1£l 5.42E+17 25.1 12.5 25.1 50.1 QJ.
4P7216/Linde
~ +&.+ M +&.+ ~ -4&..a 124/0751 0.04 0.83 54 -80 0 (T)1£l 5.42E+17 16.5 8.3 16.5 33.0 -47.0 Circumferential 8hell1 to 8hell2 AS 4P7465/Linde
~ M ~ M +&.+ ~
124/0751 0.02 0.82 27 -60 0 5.42E+17 8.3 1,1 8.3 16.5 -43.5 (8)1£l 4P7465/Linde
~ M ~ M +&.+ ~
124/0751 0.02 0.80 27 -60 0 (T)1£l 5.42E+17 8.3 1,1 8.3 16.5 -43.5 N6 nozzle B.67E 116 &.+ ~ &.+ ~ ..&,.7 Q2QL4W 0.10 0.86 67 -20 0 forgings 1.68E+17 10.3 5.2 10.3 20.7 0.7 5P6771 /Linde B.67E 116 4.-+ a.G 4.-+ &:2 ~ 124/0342 0.03 0.88 41 -30 0 (8)1£l 1.68E+17 -6.3 -3.2 6.3 12.7 -17.3 N6 nozzle weld 5P6771 /Linde B.67E 116 ~ &.4 W,.7 ~ 0.04 0.95 54 -20 &.48.3 0 124/0342 (T) 1.68E+17 4.2 8.3 16.7 -3 .3 N12 forgin~ (dJ C3054-2 ~ 3M +&..d 3M ~ ~ N12 weld(d 0.09 0.70 58 10 0 Inconel182 2.16E+18 34.1 17.0 34.0 68.1 78.1
RBG -47835 Page 14 of 60 54 54 54
% 0/0 Chemistry Initial 1f<IT EFPY EFPY EFPY Copper Nickel Factor Adjusted RTNDT Fluence dRTNDT Margin Shift ART Component Heat (Cu) (Ni) (CF) CF OF n/cm 2 of lSl(a) lSt. (b) OF of of Best Estimate Chemistries from BWRVIP-135
&.G4 Shell #2 C3054-2 0.08 0.673 51 10 43.8 0 17.0 34.0 77.8 87.8 6.03E+18 5P5657/Linde 124/0931 0.034 0.824 46 -60 2.48E+17 9.1 0 4.5 9.1 18.1 -41 .9 (S)i£l Shell #3 BJ , BK, BM 5P5657/Linde 124/0931 0.034 0.824 46 -60 2.48E+17 9.1 0 4.5 9.1 18.1 -41.9 (T)i£l 5P6756/Linde &.G4 148.
0.08 0.936 108 -60 92.7 0 28 56 88.7 124/0342(S)i£l 6.03E+18 7 Shell #2 BE, BF, BG 5P6756/Linde
&.G4 148.
124/0342 0.08 0.936 108 -50 92.7 0 28 56 98.7 6.03E+18 7 (T)i£l
RBG-47835 Page 15 of 60 54 54 54 0/0 % Chemistry Initial 1,4T EFPY EFPY EFPY Copper Nickel Factor Adjusted RT NOT Fluence flRT NOT Margin Shift ART of 2 of of of of Component Heat (Cu) (Ni) (CF) CF n/cm lil(a) li (b) 6 5P6771/Linde 124/0342 0.034 0.934 46 -30 2.48E+ 17 9.1 0 4.5 9.1 18.1 -11.9 (S )!£l Shell #2 to Shell
#3: AC 5P6771 /Linde 124/0342 0.034 0.934 46 -20 2.48E+17 9.1 0 4.5 9.1 18.1 -1.9 (T)!£l 5P5657/ Linde &..a.7 ~ ~ ~ ~ -d+A 0.034 0.824 46 -60 0 124/0931 (S)!£l 5.42E+17 14.1 ZJ. 14.1 28.2 -31.8 Shell #1 BA, BB 5P5657/Linde
&..a.7 ~ ~ ~ ~ -d+A 124/0931 0.034 0.824 46 -60 0 (T)!£l 5.42E+17 14.1 ZJ. 14.1 28.2 -31.8 4P7216/Linde
&..a.7 +&9 M +&9 ~ ~
124/0751 0.038 0.820 51 -50 0 5.42E+17 15.7 7.9 15.7 31.4 -18.6 (S)!£l 4P7216/Linde
&..a.7 +&9 M +&9 ~ ~
124/0751 0.038 0.820 51 -80 0 5.42E+17 15.7 7.9 15.7 31.4 -48.6 (T)!£l Shell #1 to Shell
#2: AB 4P7465/Linde
&..a.7 4.2 84 +&.+- ~
124/0751 0.02 0.807 27 -60 848.3 0 5.42E+17 4.1 8.3 16.5 -43.5 (S)!£l 4P7465/Linde
&..a.7 4.2 84 +&.+- ~
124/0751 0.02 0.807 27 -60 848 .3 0 (T)!£l 5.42E+17 U 8.3 16.5 -43.5
RBG-47835 Page 16 of 60 54 54 54
% 0/0 Chemistry Initial 1,4T EFPY EFPY EFPY Copper Nickel Factor Adjusted RT NOT Fluence LlRT NOT Margin Shift ART Component Heat (Cu) (Ni) (CF) CF of nlcm 2 of i5 (a) i5 (b) of of of 1 A Integrated Surveillance Program for BWRVIP-135 Plate(e) &.-G4 C3054-2 0.08 0.673 51 10 43.8 0 17.0 34.0 77.8 87.8 6.03E+18 5P6756/Linde Weld(!) &.-G4 160.
124/0342 0.08 0.936 154 -60 132.1 0 14.0 28.0 110.1 (S)!fl 6.03E+18 1 5P6756/Linde Weld(!) &.-G4 160. 124/0342 0.08 0.936 154 -50 132.1 0 14.0 28.0 110.1 (T)!fl 6.03E+18 1
- a. 01: Standard deviation on initial RT NDT
- b. OLl: Standard deviation on RT NDT
- c. S = single wire; T = tandem wire
- d. The N 12 water level instrumentation nozzles are in the beltline region. Because the forging is fabricated from stainless steel, the ART is calculated using the plate heats where the nozzles are located. The weld connecting the forging to the vessel shell is Inconel 182 material and is not required to be evaluated.
- e. The ISP plate material is not the vessel target material but does lie within the beltline region (lower intermediate shell) . Therefore, this material is considered in determining the limiting ART. Only one set of surveillance data is available; therefore, upon testing of a second ISP capsule, the CF can be reviewed.
- f. The ISP weld material is considered the vessel target material and lies within the beltline region. Therefore, this material is considered in determining the limiting ART.
The adjusted CF is determine!;! to be the [RG 1.99 CF (vessel material/RG 1.99 CF surveillance material)] x CF (fitted). For this material, adjusted CF = [1 08°F/82°F] x 116.9°F = 154°F. The surveillance data is cred ible; therefore, OLI is reduced as permitted by RG 1.99.
RBG-47835 Page 17 of 60 Table 4.2-3 RSS USE Data for 54 EFPY Initial 54 EFPY Transverse 54 EFPY Transverse USE 1fiIT Fluence % Decrease USE(b) 2 Material(a) Heat Number (ft-Ib) %Cu (nlcm ) USE (ft-Ib) Plates C2904-2 60 0.11 2.48E+17 8.5 54.9 Shell Plate 3(c) C3001-2 69 0.04 2.48E+17 5.0 65.6 C2929-2 58 0.12 2.48E+17 9.0 52.8 C3054-1 100 0.09 &.G46.03E+ 18 16.5 83.5 Shell Plate 2 C3054-2 94 0.09 &.G46.03E+ 18 16.5 78.5 C3138-2 117 0.08 &.G46.03E+ 18 +&.G 15.5 gg..,a 98.9 C2904-1 54 0.11 a.a7e I ~7 10.5 48.3 5.42E+17 Shell Plate 1(d) C2879-1 54 0.12 a.a7e I ~7 11.0 48.1 5.42E+17 Axial Welds 1eJ 5P5657/Linde 124/0931 (S) 88 0.07 2.48E+17 9.0 80.1 Shell #3: BJ , BK, BM 5P5657/Linde 124/0931 (T) 89 0.04 2.48E+17 7.5 82.3 Shell #2: BE, BF, BG 5P6756 Linde 124/0342 (S) 88 0.08 &.G46.03E+ 18 ~20.5 7GA 70.0
- - -
RBG-47835 Page 18 of 60 Initial 54 EFPY Transverse 54 EFPY Transverse USE %T Fluence % Decrease USE(b) 2 Material(a) Heat Number (ft-Ib) %Cu (n/cm ) USE (ft-Ib) 5P6756 Linde 124/0342 (T) 88 0.09 &.M6.03E+18 21 .0 69.5 5P5657/Linde 124/0931 (S) 88 0.07 &..a75.42E+ 17 11 .0 78.3 Shell #1: SA, SS 5P5657/Linde 124/0931 (T) 89 0.04 &..a75.42E+ 17 9.0 81 .0 Circumferential Welds!') 5P6771 /Linde 124/0342 (S) 90 0.03 2.48E+17 7.0 83 .7 Shell #2 to Shell #3: AC 5P6771 /Linde 124/0342 (T) 85 0.04 2.48E+17 7.5 78.6 4P7216/Linde 124/0751 (S) 91 0.06 &..a75.42E+ 17 10.5 81.4 Shell #1 to Shell #2: AS 4P7216/Linde 124/075 1 (T) 99 0.04 &..a75.42E+ 17 9.0 90.1 4P7465/Linde 124/0751 (S) 111 0.02 &..a75.42E+17 7.5 102.7 Shell #1 to Shell #2: AS 4P7465/Linde 124/0751 (T) 115 0.02 &..a75.42E+ 17 7.5 106.4 Nozzles N12 forging!g) C3054-2 94 0.09 +.fM2.16E+ 18 ~13 . 0 ~81.8 fl.! ~ ~ !A'elg~ IRG9Rei H~~ 94- Q.,G9 ~.94e l ~g ~ ~ g.e7e I ~ I N6 forging(h) 020L4W 78 0.10 M7.5 +M72.2 1.68E+17 5P96771 /Linde 124/0342 g.e7e I ~e N6 weld 90 0.03 ~6 . 5 8&.+ 84.2 (S) 1.68E+17
RBG-47835 Page 19 of 60 Initial 54 EFPY Transverse 54 EFPY Transverse USE %T Fluence % Decrease USE(b) Material(a) Heat Number (ft-Ib) %Cu (n/cm2) USE (ft-Ib) 5P96771/Linde 124/0342 8.e7el~e 85 0.04 &.G 7.0 :;z.g.,.g 79. 1 (T) 1.68E+17 Best Estimate Chemistries from BWRVIP-135 Shell #2 C3054-2 94 0.08 hG46.03E+ 18 +&..Q 15.5 :;z.g.,.g 79.4 5P5657/Linde 124/0931 (S) 88 0.034 2.48E+ 17 7.5 81.4 Shell #3: BJ , BK, BM 5P5657/Linde 124/0931 (T) 89 0.034 2.48E+17 7.5 82.3 5P6756/Linde 124/0342 (S) 88 0.08 hG46.03E+ 18 ~20.5 +GA 70.0 Shell #2: BE, BF, BG 5P6756/Linde 124/0342 (T) 88 0.08 hG46.03E+ 18 ~20.5 +GA 70.0 5P6771 /Linde 124/0342 (S) 90 0.034 2.48E+17 7.5 83.3 Shel l #2 to Shell #3: AC 5P6771/Linde 124/0342 (T) 85 0.034 2.48E+17 7.5 78.6 5P5657/Linde 124/0931 (S) 88 0.034 &.-a+5.42E+ 17 8.5 80.5 Shell #1 : BA, BB 5P5657/Linde 124/0931 (T) 89 0.034 &.-a+5.42E+ 17 8.5 81.4 4P7216/Linde 124/0751 (S) 91 0.038 &.-a+5.42E+ 17 9.0 82.8 Shell #1 to Shell #2: AB 4P7216/Linde 124/0751 (T) 99 0.038 &.-a+5.42E+ 17 9.0 90.1 4P7465/Linde 124/0751 (S) 111 0.02 &.-a+5.42E+ 17 7.5 102.7 Shell #1 to Shell #2: AB 4P7465/Linde 124/0751 (T) 115 0.02 &.-a+5.42E+ 17 7.5 106.4
RBG-47835 Page 20 of 60 Initial 54 EFPY Transverse 54 EFPY Transverse USE %T Fluence % Decrease USE(b) 2 Material(a) Heat Number (ft-Ib) %Cu (nlcm ) USE (ft-Ib) Integrated Surveillance Program from BWRVIP-135(I' Plate C3054-2 95 .3 0.08 &.G46.03E+ 18 15 . G~ &+,G 80.5 5P6756/Linde 124/0342 (S) 104.4 0.08 &.G46.03E+ 18 20.0 83.5 Weld 5P6756/Linde 124/0342 (T) 104.4 0.08 &.G46.03E+ 18 20.0 83.5
- a. Regulatory Guide 1.99, Revision 2, Position 1.2 applies to all materials.
- b. USE = Initial Transverse USE x [1 - (% decrease 1 100)]
- c. Due to the lack of sufficient unirradiated data, the unirradiated USE is conservatively based on 50% shear results.
- d. Due to the lack of sufficient unirradiated data, the unirradiated USE is conservatively based on 50% shear results. Reducing this value by ~11 . 0% resu lts in a 54 EFPY USE less than 50 ft-Ibs . Therefore, a USE EMA was performed. As the +Gll%
decrease is less than the maximum perm itted reduction of 23.5% from BWRVIP-74-A and the maximum plate decrease for RBS is 19%, both bounded by the BWRVIP-74-A requirement, the Shell 1 plates remain qualified for USE. See Table ~. 2-4 .
- e. Use of shielded-metal arch weld (SMAW ) Heat 492L4871 was limited to seam patches. Certified material test reports indicate that no SMAW weld material is present at either the %T or %T location. Therefore, this heat is not required to be evaluated as part of the beltline region .
2
- f. Welds AB and AC occur within the extended beltline reg ion, defined as experiencing a fluence > 1.0E+ 17 n/cm .
- g. The N12 water level instrumentation nozzle~ occur in the beltline region . Because the forg ing and weld are non-ferritic materials , the USE is calculated using the limiting plate heat where the nozzles occur.
- h. Due to the lack of sufficient unirradiated data, the unirradiated USE is conservatively based on 60% shear results .
- i. The material is evaluated using the ISP unirradiated USE to illustrate the difference and that the material is acceptable.
RBG-47835 Page 21 of 60 Table 4.2-4 Equivalent Margin Analysis GO-Year License (54 EFPY) BWR/3-G Plate ISP Surveillance Plate USE (Heat C3054-2)
%Cu =0.08 Unirradiated USE = 95.3 ft-Ib 15t capsule measured USE = 100.6 ft-Ib 15t capsule fluence = 1.16E+ 18 n/cm 2 15t capsule measured % decrease = -5.6 (Charpy curves) 15t capsule RG 1.99 predicted % decrease = 10.2 (RG 1.99, Rev. 2, Figure 2)
Limited Beltline Plate USE
% Cu = 0.12 54 EFPY 1A T fluence = ~6 . 03E+ 18 n/cm 2 RG 1.99 predicted % decrease = 19.0 (RG 1.99, Rev. 2, Figure 2)
Adjusted % decrease = N/A (RG 1.99, Rev. 2, Position 2.2) 19.0% ::; 23.5% Therefore , vessel plates meet the criteria for equivalent margin analysis. (Ref. 4-18)
RBG-47835 Page 22 of 60 Table 4.2-5 RBS Circumferential Weld Evaluation for 54 EFPY NRC Staff Assessment RBS 54 EFPY RBS 54 EFPY Parameter Description for 64 EFPy(a) Weld AB (b) Weld AC(c) Weld copper content, % 0.10 0.06 Md40.04 Weld nickel content, % 0.99 0.85 Md40.95 Weld chemistry factor (CF) 134.9 82 4954 Neutron fluence at the end of the 1.02E+19 M790.077E+ 19 0.034E+19 requested relief period , n/cm 2 Initial reference temperature
-65 -50 -20 (RT NOT), OF Increase in reference temperature 135.6 ~30 . 0 +=kG 12.8 (toRT NOT), °F(d)
Mean adjusted reference 70.6 ~-20 -9.G -7.2 temperature (ART), of P (FIE) NRC(e) 1.78E-5 (I) (I)
- a. From Table 2.6-5 of Ref. 4-22, with corrected CF from Ref. 4-11.
- b. Weld AS occurs within the extended beltline region , defined as experiencing a fluence >
2 1.0E+ 17 n/cm . Therefore, Weld AS, which is approximately 7 inches below the active core, is presented , conservatively using the value of peak fluence at 54 EFPY.
- c. Weld AC occurs within the extended beltline region, defined as experiencing a fluence >
2 1.0E+ 17 n/cm . Therefore, Weld AC, which is approximately 20 inches above the active core, is presented , conservativelrc using the value of peak fluence at 54 EFPY.
- d. tlRT NOT = CF X , (0.28 . 0.10 ogl)
- e. P (FIE) stands for "Probability of a failure event."
- f. Although a conditional failure probability has not been calculated , the fact that the RSS values at the end of the period of extended operation are less than the 64 EFPY value provided by the NRC leads to the conclusion that the RSS RPV conditional failure probability is bounded by the NRC analysis, consistent with the requirements defined in GL 98-05.
RSG-47835 Page 23 of 60 Table 4.2-6 Effects of Irradiation of RBS Reactor Vessel Axial Weld Properties NRC Staff Assessment for RBS RBS RBS 32 EFPY 54 EFPY 54 EFPY 54 EFPY Parameter Description (Axial Welds) Shell1!£) Shell 2!!!l Shell3~ Mod 2 CB&IRPV CB&IRPV CB&IRPV Weld copper content, % 0.219 0.07 Q,.Q9 0.08 0.07 Weld nickel content, % 0.996 0.71 MaO.94 0.71 Weld chemistry factor (CF) 231 .1 95 ~154 95 Fluence at clad/weld 19 0.148 M+90.077 ~0.834 0.034 interface (10 n/cm 2) RT NDT(U), of -2 -60 -50 -60 flRT NDT without margin (oF)(a) 116 ~34.8 ~146.2 22.5 Mean RT NDT (OF) 114 -24.-7 -25.2 ~96.2 -37.5 (b) (b) (b) Vessel failure frequency 5.02E-06
- a. flRT NDT = CF x f (u . ~tl* U.lO log t)
- b. Although a vessel failure frequency has not been calculated, the fact that the RBS mean RT NDT values at 54 EFPY are less than the 32 EFPY value provided by the NRC leads to the conclusion that the RBS RPV vessel failure frequency is less than that provided in the NRC analysis, consistent with the requirements defined in GL 98-05 .
- c. Plant-specific chemistries are used for conservatism.
- d. lSI surveillance data applied.
4.7.3 Fluence Effects for Reactor Vessel Internals The design specification for the reactor vessel internals components includes requirements beyond the ASME design requirements for austenitic stainless steel base metal components exposed to greater than 1 x 10 nvt 21 (> 1 MEV) or weld metal exposed to greater than 5 x 10 nvt (> 1 MEV), where nvt equals neutron density (n) 20 multiplied by neutron velocity (v), multiplied by time (t). The effects of fluence for 60 years of operation (54 EFPY) were analyzed for the reactor vessel internals components included in the design specification. Location-specific fluence levels were determined. The internal core support structure components were then evaluated against the fluence criteria in the design specification. The evaluation determined demonstrated that the RSS internal core support structure components satisfy the neutron fluence effects requirements in meet-the design specification for operating conditions through 54 EFPY. (Ref. 4-17) Therefore, this analysis has been projected through the period of extended operation in accordance with 10 CFR 54.21 (c)(1 )(ii).
RBG-47835 Page 24 of 60
4.8 REFERENCES
4-1 NEI 95-10, Industry Guidelines for Implementing the Requirements of 10 CFR 54 - The License Renewal Rule, Revision 6, June 2005. 4-2 NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, Revision 2, December 2010. 4-3 NUREG-1801 , Generic Aging Lessons Learned (GALL) Report, Revision 2, December 2010. 4-4 EPRI Report TR-105090, Guidelines to Implement the License Renewal Technical Requirements of 10 CFR 54 for Integrated Plant Assessments and Time-Limited Aging Analyses, November 1995. 4-5 10 CFR 50 Appendix G, Fracture Toughness Requirements. 4-6 10 CFR 50 Appendix H, Reactor Vessel Material Surveillance Program Requirements . 4-7 NRC Regulatory Guide 1.99, Radiation Embrittlement of Reactor Vessel Materials, Revision 2. 4-8 NRC Regulatory Guide 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence, March 2001 . 4-9 NUREG/CR-6260 (INEL 95/0045), Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components, February 1995. 4-10 Ranganath , S. , "Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel Following a Postulated Loss of Coolant Accident," Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin , Germany, August 1979 (Accession No. 9110110105 in the NRC's Public Legacy Library). 4-11 BWRVIP-05 SER (Final) , NRC letter from G. C. Lainas to C. Terry, Niagara Mohawk Power Company, BWRVIP Chairman, "Supplement to Final Safety Evaluation of the BWR Vessel and Internals Project BWRVIP-05 Report (TAC No. MA3395)," March 7, 2000. 4-12 RBC-50417, River Bend Station Unit 1 - Relief Request RBS-ISI-004 for Alternative to Section 50.55a of Title 10 of the Code of Federal Regulations (10 CFR) for Examination Requirements of Category B1.11 Reactor Pressure Vessel Welds (TAC No. MC8201) , letter dated July 14, 2006. 4-13 CNRO-2005-00036, Request for Alternative to 10 CFR 50.55a Examination Requirements of Category B1 .11 Reactor Vessel Welds, letter dated August 24, 2005. 4-14 CNRO-2006-00010, Request for Alternative to 10 CFR 50.55a Examination Requirements of Category B1 .11 Reactor Vessel Welds , letter dated February 8, 2006. 4-15 RBS-ME-16-00008, "GEH 003N4606, Rev. 01, River Bend Station Unit 1 Main Steam Line Flow Restrictors , ~une 2016 (Proprietary)." 4-16 RBS-NE-17-00002 , "GEH 003N2078, Rev.-Ol, Entergy Operations, Inc. , River Bend Nuclear Station Plant License Renewal Fluence Projection , March October 2017 (Proprietary)." 4-17 RBS-NE-17-00004, "GEH 003N9941 , Rev. 01, Entergy Corporation , Inc. River Bend Nuclear Station , Fluence Effect Evaluation on RPV Internal Components, March October 2017 (Proprietary) ."
RBG -47835 Page 25 of 60 4-18 RBS-NE-17-00003, "GEH 003N8442, Rev. Gl, Pressure-Temperatures Limit Report for Entergy Operations, Inc. , River Bend Station , March November 2017 (Proprietary). " 4-19 CMAA Specification 70, Specifications for Electric Overhead Traveling Cranes, Copyright 1975. 4-20 NEDC-32983P-A, Revision 2, "General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations," dated January 2006 (Proprietary) . 4-21 BWRVIP-74-A: BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal , EPRI 1008872, June 2003 (Proprietary) . 4-22 "BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Shell Weld Inspection Recommendations (BWRVIP-05) ," for the BWR Owners Group, EPRI , Palo Alto , CA (TR-105697) (Proprietary) , September 28, 1995, with supplementing letters of June 24 and October 29, 1996; May 16, June 4, June 13, and December 18, 1997; and January 13 and July 28, 1998. Question RAI 4.2.6-1 (Reactor Vessel Axial Weld Failure Probability)
Background
In LRA Section 4.2.6, the applicant provides its TLAA related to the "Reactor Vessel Axial Weld Failu re Probability" analysis. As part of this TLAA evaluation , the applicant provides its updated mean RT NOT values for the components in LRA Table 4.2-6. The applicant reports that the limiting axial welds for the TLAA are those associated with the RPV lower-intermediate shell axial welds that were fabricated from Weld Heat No. 5P6756 and that the mean RTNOT value for the welds is projected to be 65.8 of at 54 EPFY. The applicant's identifies that the projected mean RT NOT value meets the 114 of acceptance criterion set for these types of weld components in the EPRI BWRVIP-74-A and BWRVIP-05 reports . Issue The calculated mean RT NOT values reported for 54 EPFY in LRA Table 4.2-6 were based on use of Position 1.1 in RG 1.99, Revision 2, which uses chemistry factor tables contained in the RG as part of the basis for performing RT NOT value projections. However, Position 2.1 of the RG includes criteria for using RPV surveillance data to perform RT NOT calculations, particularly when two or more sets of RPV surveillance data become available for incorporation into the calculations. Implementation of the applicant's BWRVIP integrated surveillance program (ISP) has generated four sets of credible surveillance data for the RPV axial welds that are made from the Weld Heat No. 5P6756 material. However, LRA Table 4.2-6 did not include any mean RTNDT calculation based on the BWRVIP ISP data that are available for these weld components. The staff's independent calculation projects that the mean RT NOT value for these welds could be as high as 110.5 of at 54 EFPY if all credible BWRVIP ISP surveillance data for the welds were applied to the calculations and the Surveillance-Ratio procedure (as defined in Position 2.1 of RG 1.99, Revision 2) is used as the basis for the chemistry factor value used in the RT NOT calculation. Request Justify the basis for not including an additional mean RT NOT calculation in LRA Table 4.2-6 for the RPV lower-intermediate axial welds that is based on the use of the BWRVIP ISP surveillance data that apply to these weld components (i.e., the current set of ISP data compiled by the EPRI BWRVIP for Weld Heat No. 5P6756) .
RBG-47835 Page 26 of 60
Response
The four sets of BWRVIP Integrated Surveillance Program (ISP) surveillance capsule data for RPV axial welds fabricated from Weld Heat No. 5P6756 material have been included in the mean reference temperature nil-ductility temperature projection calculation. LRA Table 4.2-6 has been revised as shown in the response to RAI 4.2.1-1 with additions underlined and deletions lined through. Question RAI 4.3.1-1 (Class 1 Fatigue)
Background
The regulation in 10 CFR 54.21 (c)(1) requires the applicant to provide an evaluation of each analysis conforming to the definition of a time-limited aging analysis (TLAA) in 10 CFR 54.3(a) and to demonstrate that the TLAA is acceptable in accordance with one or more of three TLAA disposition bases stated in the §54.21 (c)(1) requirement: (i) demonstration that the TLAA remains valid for the period of extended operation (ii) demonstration that the TLAA has been projected to the end of the period of extended operation (iii) demonstration that the effects of aging (associated with the TLAA) on the intended function(s) of the component(s) will be adequately managed during the period of extended operation LRA Section 4.3.1 and its subsections provide the applicant's metal fatigue TLAAs for ASME Code Class 1 components that have been analyzed in accordance with a cumulative usage factor (CUF) analysis. In this part of the LRA, the applicant dispositioned the TLAAs in accordance with 10 CFR 54.21 (c)(1 )(iii) using one of the following AMPs: (a) LRA AMP 8 .1.18, "Fatigue Monitoring Program," for all Class 1 components with CUF type fatigue analyses, other than Class 1 reactor vessel internal (RVI) components, and (b) LRA AMP 8.1.10, "8WR Vessel Internals Program ," for any RVI components that have been analyzed with CUF analyses. Issue LRA Section 4.3.1 .1 does not identify the components in the reactor pressure vessel that have been analyzed with a CUF analysis. The staff cannot determine which of the RPV components are within the scope of the TLAA addressed in LRA Section 4.3.1.1. Request Identify all RPV components that have been analyzed with a CUF analysis.
Response
The table below identifies the highest cumulative usage factor calculated for each reactor vessel subcomponent location. The cumulative usage factors in this table are based on the originally specified 120 heatups and cooldowns. These locations are evaluated as part of the environmentally assisted fatigue analysis utilizing the 60 year projected cycles with margin shown in LRA Table 4.3-1. Refined analyses are completed if required as a part of the environmentally assisted fatigue analysis. Reactor Vessel Subcomponent Location Cumulative Usage Factor Feedwater nozzle N4A 0.827 Feedwater nozzle N48, C, 0 0.946 RPV closure studs 0.9633 RPV closure region 0.615
RBG-47835 Page 27 of 60 Bottom head support skirt 0.9985 CRD nozzle 0.485 CRD fast scram control rod drive assembly 0.2 Control rod drive hydraulic system return nozzle 0.423 Core spray nozzle 0.564 Recirc inlet nozzle 0.564 Recirc outlet nozzle 0.54 Steam outlet nozzle 0.54 Vibration instrumentation nozzle 0.54 Core op & liquid control nozzle 0.261 RPV shell steam water interface 0.01 RPV shell , top head transition 0.01 RHR/LPCI nozzle 0.564 I ncore housing/nozzle 0.068 Head spray and vent assembly 0.266 Refueling bellows support 0.836 Miscellaneous brackets (feedwater sparger bracket, 0.054 guide rod bracket, steam dryer hold down bracket, core spray bracket, top head lift lug) Steam dryer support bracket 0.316 Question RAI 4.3.1-2 (Class 1 Fatigue)
Background
The regulation in 10 CFR 54.21 (c)(1) requires the applicant to provide an evaluation of each analysis conforming to the definition of a time-limited aging analysis (TLAA) in 10 CFR 54.3(a) and to demonstrate that the TLAA is acceptable in accordance with one or more of three TLAA disposition bases stated in the §54.21 (c)(1) requirement: (i) demonstration that the TLAA remains valid for the period of extended operation (ii) demonstration that the TLAA has been projected to the end of the period of extended operation (iii) demonstration that the effects of aging (associated with the TLAA) on the intended function(s) of the component(s) will be adequately managed during the period of extended operation LRA Section 4.3.1 and its subsections provide the applicant's metal fatigue TLAAs for ASME Code Class 1 components that have been analyzed in accordance with a cumulative usage factor (CUF) analysis. In this part of the LRA, the applicant dispositioned the TLAAs in accordance with 10 CFR 54.21 (c)(1 )(iii) using one of the following AMPs: (a) LRA AMP B.1.18, "Fatigue Monitoring Program ," for all Class 1 components with CUF type fatigue analyses, other than Class 1 reactor vessel internal (RVI) components, and (b) LRA AMP B.1.1 0, "BWR Vessel Internals Program ," for any RVI components that have been analyzed with CUF analyses. Issue LRA Section 4.3.1.2 does not identify which RVI components have been analyzed with a CUF analysis or adequately describe how the BWR Vessel Internals will accomplish management of fatigue-induced cracking in those RVI components that have been analyzed with a CUF analysis in the current licensing basis (CLB). Specifically, the applicant has not identified the specific BWRVIP report or reports and BWRVIP-defined methods that will be implemented (as part of the BWR Vessel Internals Program) to manage fatigue-induced cracking in the components. Without this information , the staff does not have sufficient demonstration that
RBG-47835 Page 28 of 60 implementation of the BWR Vessel Internals Program will adequately manage fatigue-induced cracking in those RVI components that have been analyzed with CUF analyses in the CLB. Request Identify each RVI component that has been analyzed with a CUF analysis in the CLB and the specific BWRVIP report that will be used to manage fatigue-induced cracking in the component during the period of extended operation. For each of these RVI components, clarify and explain the specific BWRVIP-defined aging management method (e.g., specific type of condition monitoring or inspection activity, performance monitoring activity, time-dependent evaluation, etc.) that will be used as the basis for managing fatigue-induced cracking in the component and justify why the specific method is considered to be capable of managing fatigue-induced cracking in the component during the period or extended operation. If the applicable BWRVIP report will apply a bounding inspection-based approach for the management of cracking , clarify the specific RVI component that will be inspected on behalf of the component with a CUF analysis, and identify the type of corrective actions that will be applied to the RVI component with the CUF analysis if the inspections of the bounding component identify any evidence of cracking in the component being inspected.
Response
The table below identifies the reactor vessel internals locations that are subject to aging management review that were identified with a fatigue analysis and the primary BWRVIP report associated with that location. Location Primary BWRVIP No. Core spray sparger BWRVIP-18 Core spray line thermal sleeve BWRVIP-18 Core support plate BWRVIP-25 Core plate stiffener beam BWRVIP-25 Top guide grid beams BWRVIP-183 Jet pumps BWRVIP-41 Jet pump riser clamp modification BWRVIP-41 Orificed fuel support BWRVIP-47 Shroud BWRVIP-76 Shroud support BWRVIP-38 Control rod drive housing BWRVIP-47 Control rod guide tube BWRVIP-47 Low pressure coolant injection coupling BWRVIP-42 NUREG-2191 identifies BWRVIP documents that provide guidance for managing the effects of aging on reactor vessel internals.
- Core shroud: BWRVIP-76-A provides guidelines for inspection and evaluation .
- Core plate: BWRVIP-25 provides guidelines for inspection and evaluation.
- Core spray: BWRVIP-18, Revision 1-A provides guidelines for inspection and evaluation.
- Shroud support: BWRVIP-38 provides guidelines for inspection and evaluation .
- Jet pump assembly: BWRVI P-41 and BWRVI P-138, Revision 1-A, provide guidelines for inspection and evaluation .
- Low-pressure coolant injection coupling: BWRVIP-42-A provides guidelines for inspection and evaluation.
- Top guide: BWRVIP-26-A and BWRVIP-183 provide guidelines for inspection and evaluation.
- Control rod drive housing and lower plenum components: BWRVIP-47-A provides guidelines for inspection and evaluation.
RBG-47835 Page 29 of 60 The BWR Vessel and Internals Project (BWRVIP) inspection-based reactor internals program adequately manages cracking. Therefore, it is not necessary to rely on CLB fatigue analyses or updated environmentally assisted fatigue analyses to demonstrate that cracking due to fatigue is not an aging effect requiring management. Intergranular stress corrosion cracking (IGSCC) and irradiation-assisted stress corrosion cracking (IASCC) are significantly more limiting for RPV internals than cracking caused by fatigue. The inspection techniques utilized by the BWRVIP are described within BWRVIP-03 and are acceptable for the detection and characterization of service-induced , surface-connected planar discontinuities, such as cracks due to IGSCC and IASCC, in welds and in adjacent base material. In general, fatigue cracks are expected to be at least as detectable as the tight IGSCC cracks that the BWRVIP methods were developed to detect. Also, the effects of cracks on the subcomponent function and extensive industry inspection experience we re considered to identify the appropriate locations and timing for inspections. Original fatigue analyses, such as for the shroud, did not evaluate the cracking that has now been identified at RBS. Therefore, the original fatigue analyses cannot be used to demonstrate component acceptability in the period of extended operation. The detailed BWRVIP reports for determining the acceptability of the identified cracking and postulating crack growth are utilized to evaluate the shroud and to determine the extent and schedule of the necessary future inspections. For reactor vessel internals components with fatigue TLAAs , the BWR Vessel Internals Program will manage cracking due to fatigue and due to other mechanisms for the period of extended operation in accordance with 10 CFR 54.21 (c)(1 )(iii). Question RAI 4.3.2-1 (Non-Class 1 Fatigue)
Background
The regulation in 10 CFR 54.21 (c)(1) requires the applicant to provide an evaluation of each analysis conforming to the definition of a time-limited aging analysis (TLAA) in 10 CFR 54.3(a) and to demonstrate that the TLAA is acceptable in accordance with one or more of three TLAA disposition bases stated in the §54.21 (c)(1) requirement: (i) demonstration that the TLAA remains valid for the period of extended operation (ii) demonstration that the TLAA has been projected to the end of the period of extended operation (iii) demonstration that the effects of aging (associated with the TLAA) on the intended function(s) of the component(s) will be adequately managed during the period of extended operation LRA Section 4.3.2.1 provides the applicant's metal fatigue TLAA for non-Class 1 piping or in-line components that have been analyzed with a time-dependent expansion stress/maximum allowable stress range reduction analysis (implicit fatigue analysis), as may have been required in accordance with applicable ASME Section III NC or NO design rules or ANSI B31.1 design rules . LRA Section 4.3.2.2 provides the applicant's metal fatigue TLAA for non-Class 1 components that have been analyzed in accordance with an ASME-defined cumulative usage factor analysis (CUF) analysis. The scope of these analyses includes components in the engineered safety feature (ESF) systems, auxiliary (AU X) systems, and steam and power conversion (SPC) systems. The relevant aging management review (AMR) tables for non-Class 1 systems are given in LRA Tables 3.2.2-1 - 3.2.2-7 and LRA Tables 3.2.2-8 3.2.2-8-5 for ESF system components, LRA Tables 3.3.2 3.3.2-17 and LRA Tables 3.3.2-18 3.3.2-18-26 for auxiliary (AUX) system components, and LRA Table 3.4.2-1 and LRA Tables 3.4.2-2 3.4.2-2-4 for steam and power conversion (SPC) system components. In LRA Section 4.3.2.1 , the applicant states that the non-Class 1 fatigue screening document in Appendix H of the EPRI Mechanical Tools was used to determine locations susceptible to fatigue cracking in non-Class 1 systems at
RBG-47835 Page 30 of 60 RBS and that the first step in the screening process was to identify non-Class 1 components that may have normal or upset condition operating temperature in excess of 220°F for carbon steel or 270°F for stainless steel. Issue In LRA Section 4.3.2.1, the applicant states that, for many non-Class 1 plant systems, the implicit fatigue analyses for the systems were associated with the cumulative occurrences (i.e., cycles) of the plant's heatup and cooldown operations. The applicant also identified that the implicit fatigue analyses for the pressure relief, residual heat removal (RHR) reactor core isolation cooling (RCIC), containment penetration, control rod drive (CRD), fire protection - water, combustible gas control, standby diesel generator, high pressure core spray diesel generator, reactor water cleanup, and sampling systems may have included some additional transient considerations. Thus, with the exception of the non-Class 1 systems that were specifically referred to in LRA Section 4.3.2.1, it is not evident which of the non-class 1 systems in the LRA were within the scope of the metal fatigue TLAA in LRA Section 4.3.2.1 and which of the non-Class 1 systems were specifically screened out from the TLAA using the screening methodology for fatigue in EPRI Mechanical Tools. Request Identify all non-Class 1 ESF, AUX, and SPC systems that are within the scope of the metal fatigue TLAA in LRA Section 4.3.2.1 based solely on an assessment of plant heatup and cooldown operations.
Response
No non-Class 1 engineered safety feature (ESF), auxiliary (AUX), or steam and power conversion (SPC) systems are within the scope of the metal fatigue TLAA in LRA Section 4.3.2.1 based solely on an assessment of plant heatup and cooldown operations. Component types in the non-Class 1 mechanical system tables in Chapter 3 of the RBS LRA include an entry for TLAA - metal fatigue for the following reasons.
- Temperature at that component cycles above 220°F or 270°F for carbon steel and stainless steel, respectively.
- The component type has been specifically evaluated for fatigue cycles (flex hose, expansion joint, and strainer).
For some systems, only portions of the system operate at elevated temperatures. The identification of fatigue due to exceeding the temperature threshold was performed with consideration of the component locations in the system and the component operating temperatures. Section 4.3.2.1 states, "For many plant systems, significant temperature cycles are coincident with plant heatups and cooldowns, which are limited to well below 7,000 cycles as shown in Table 4.3-1." Systems with transients that are independent of plant heatups and cooldowns are discussed in individual paragraphs in LRA Section 4.3.2.1. If the component type has been specifically identified for fatigue cycles (such as flex hose, expansion joint, and strainer), fatigue is identified for the component even for the non-Class 1 mechanical systems that operate below the temperature thresholds. Question RAI 4.3.3-1 (Effects of Reactor Water Environment on Fatigue Life)
Background
The regulation in 10 CFR 54.21 (c)(1) requires the applicant to provide an evaluation of each analysis conforming to the definition of a time-limited aging analysis (TLAA) in 10 CFR 54.3(a) and to demonstrate that the TLAA is acceptable in accordance with one or more of three TLAA disposition bases stated in the §54.21 (c)( 1) requirement: (i) demonstration that the TLAA remains valid for the period of extended operation
RBG-47835 Page 31 of 60 (ii) demonstration that the TLAA has been projected to the end of the period of extended operation (iii) demonstration that the effects of aging (associated with the TLAA) on the intended function(s) of the component(s) will be adequately managed during the period of extended operation LRA Section 4.3.3 provides the applicant's time-limited aging analysis (TLAA) evaluation for environmentally-assisted fatigue (EAF). In LRA AMP B.1.18, "Fatigue Monitoring Program," and Commitment No. 11 in LRA USAR Supplement Table AA, "Commitment Tracking List," the applicant commits to perform CUFen calculations of selected reactor coolant pressure boundary (RCPB) component locations prior to August 29, 2023. By letter dated August 1, 2017 (ML17213A064), the applicant supplemented the information in LRA Section 4.3.3 and provided additional details on the process that would be used to determine if additional EAF calculations (CUFen calculations) would need to be performed for additional RCPB components beyond those selected for CUFen analysis using the methodology in NUREG/CR-6260. The LRA supplement indicates that applicant will use a thermal zone analysis approach as its basis for determining whether additional RCPB locations will be more limiting for CUFen than those locations defined in NUREG-6260 for CUFen analysis. Issue The applicant's response to Question 2 in the LRA supplement letter of August 1, 2017, did not specifically define the details and criteria of its thermal zone analysis methodology or specifically explain how the methodology would be used to select bounding or sentinel RCPB component locations for inclusion in the CUFen calculations. However, the details related to EAF analyses in the August 1, 2017, LRA supplement are not reflected in the LRA's current USAR supplement for the TLAA (i.e. , in LRA Section A.2.2.3) . Request
- 1. Clarify whether the EAF methodology includes any methodology criteria for comparing components in different thermal zones to each other. If so, describe and justify the aspects of the methodology that will be used to make the comparison of components in different thermal zones , including any assumptions that apply to and are used in the methodology.
- 2. For the aspect of the EAF methodology that compares component locations within a given thermal zone ,
clarify whether the methodology will be based on use of a bounding thermal transient, a set of bundled thermal transients, or all plant thermal transients that apply to the components evaluated in the thermal zone. Define and justify the relevant criteria and parameters that will be used for this thermal zone component comparison basis.
- 3. Provide and justify the selection criteria that will be applied to each thermal zone in order to select the bounding or sentinel component locations for the EAF analysis.
Response
Current licensing basis CUFs are compared to identify limiting locations for which to perform environmentally assisted fatigue (EAF) evaluations. The response to Question 2 in Attachment 1 of the LRA supplement letter dated August 1, 2017 provided the basis that was utilized. The discussion below provides a specific response to each item in this request and identifies changes to the LRA USAR supplement (LRA Section A.2.2.3).
- 1. For piping, a CUF in one thermal zone can be used to bound a CUF for the same material in other thermal zones if a bounding temperature is used and the transients in the other thermal zones are the same or a subset of the transients in the first thermal zone. The methodology does not provide for comparing components in different thermal zones to each other outside of piping systems.
- 2. All plant thermal transients that apply to the components evaluated in the thermal zone are considered .
Thermal zone component comparison is used only for piping. The relevant criteria are that the highest
RBG-47835 Page 32 of 60 CUF is considered bounding when calculated based on the same set of transients and a bounding temperature.
- 3. Piping locations selected for EAF analysis within a thermal zone are:
- The location with the highest CUF.
- The location with the second highest CUF if it is at least 50 percent of the highest CUF.
- The location with the third highest CUF if it is at least 75 percent of the highest CUF.
An additional criterion is that only a CUF from an analysis with the same or a higher level of detail (i.e, NB-3200 > NB-3600 > NB-3500, unbundled> bundled> single bounding transient) is used to bound a CUF from another analysis. LRA Section A.2 .2.3 is modified as shown below to include the pertinent EAF assessment information provided in the response to Question 2 in Attachment 1 of the LRA Supplement dated August 1, 2017. Additions are underlined. Add the following to the end of LRA Section A.2 .2.3. The environmentally assisted fatigue evaluation reviews all of the Class 1 fatigue analyses in order to identify the transients that the Fatigue Monitoring Program must track to ensure that the fatigue usage factors considering environmental effects will not exceed 1.0 without appropriate corrective actions as specified in the program . This includes all of the NUREG-6260 locations. The environmentally assisted fatigue evaluation utilizes NUREG/CR-6909 (ANL-06/08)' "Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials," in the evaluation of environmentally assisted fatigue for all materials. Environmental correction factors applied to CUFs with different material types are material specific environmental correction factors . A cumulative usage factor (CUF) from one material type is not used to bound a CUF for another material type. EiQl!}g The piping evaluations are performed using ASME Code NB-3600. The fatigue analyses for Class 1 piping locations throughout the plant are based on the loads experienced at those locations. For purpose of evaluating environmentally assisted fatigue, a thermal zone is a section of piping that experiences the same transients and the transients are the same from a pressure and temperature perspective. A CUF in one thermal zone can only be used to bound a CUF for the same material in other thermal zones if a bounding temperature is used and the transients in the other thermal zones are the same or a subset of the transients in the first thermal zone . The following criteria are used to select the locations in each thermal zone for further consideration of environmentally assisted fatigue.
- The location with the highest CUF.
- The location with the second highest CUF if it is at least 50 percent of the highest CUF.
- The location with the third highest CUF if it is at least 75 percent of the highest CUF.
The NUREG/CR-6260 locations are evaluated regardless of their CUF. Reactor Vessel The reactor vessel fatigue analysis has CUFs calculated for more locations than the locations identified in NUREG/CR-6260. The CUFs for reactor vessel locations that are part of the wetted reactor coolant system pressure boundary are evaluated .
RBG-47835 Page 33 of 60 Valves and Pump Casings The RBS Class 1 valves and the reactor recirculation pump casings have fatigue analyses with CUFs that are included in the review. Class 1 valves in the following systems are included:
- Main steam (including safety relief valves)
- Feedwater
- Residual heat removal
- Reactor recirculation
- High pressure core spray
- Low pressure core spray
- Reactor water cleanup
- Reactor core isolation cooling Piping Penetrations The evaluation includes the fatigue analyses for the pressure boundary location on the flued heads of Class 1 piping penetrations.
The environmentally assisted fatigue evaluation for RBS Class 1 components is a comprehensive evaluation of plant-specific component locations in the wetted portions of the reactor coolant pressure boundary. The evaluation includes all NUREG/CR-6260 locations. The evaluation demonstrates that the Fatigue Monitoring Program is monitoring the transients necessary to ensure that fatigue analyses that are adjusted to reflect the effects of the reactor coolant environment remain valid during the period of extended operation. If monitoring indicates that a CUF may exceed 1.0 when considering environmental effects, then appropriate corrective actions will be taken as specified in the Fatigue Monitoring Program. Question RAI 4.7.3-1 (Fluence Effects fo r Reactor Vessel Internals) INFORMATION NOTICE This is a non-proprietary version of RAI 4.7.3-1, which has the proprietary information removed. Portions of the document that have been removed are indicated by an open and closed bracket as shown here [[ ]].
Background
The regulation in 10 CFR 54.21 (c)(1 )(ii) states that, for a specific time limited aging analyses (TLAA) that is dispositioned in accordance with this regulation , the applicant must demonstrate that the analysis has been projected to the end of the period of extended operation. License renewal application (LRA) Section 4.7.3, "Fluence Effects for Reactor Vessel Internals," identifies the neutron fluence analysis for the plant's reactor vessel internal (RVI) components as a TLAA for the LRA. The applicant has dispositioned this TLAA in accordance with the requirement in 10 CFR 54.21 (c)(1 )(ii) to demonstrate that the neutron fluence values for the RVI components have been projected to the end of the period of extended operation . For the case of the TLAA evaluated in LRA Section 4.7.3, fluence is an effect that factors into TLAA assessment for the RVI components evaluated in the LRA section. Issue In LRA Section 4.7.3, the applicant states: "the effects of fluence for 60 years of operation (54 EFPY) were analyzed for the RVI components included in the design specification." However, the applicant did not identify
RBG-47835 Page 34 of 60 the methodology that was used for estimating fluence for various RVI component locations or provide a discussion regarding how the chosen methodology for estimating fluence for various RVI component locations was qualified prior to use. In addition, fluence methods adherent to RG 1.190 may not be appropriate for estimating neutron fluence for some RVI components . For example, RG 1.190 permits representation of internal fuel assemblies in considerably less detail than peripheral assemblies because the neutron flux on the RPV is primarily due to fuel at the core periphery; this is not the case for components such as the top guide. Request Explain why the fluence calculational methodology used to support the disposition of the TLAA under 10 CFR 54.21 (c)(1 )(ii) is considered to be appropriate for projecting RVI component neutron fluence values to the end of the period of extended operation . Include the following information:
- 1. Demonstrate that the spatial discretization is sufficiently refined and produces a reliable neutron fluence estimate at the various RVI component locations of interest.
- 2. Demonstrate that the chosen fluence methods are qualified for estimating neutron fluence at the various RVI component locations of interest.
- 3. Explain how the neutron fluence values used in downstream safety analyses have been augmented to account for any uncertainty associated with the calculation methods, nuclear data, or modeling accuracy.
- 4. Quantify neutron fluence margins to RVI components meeting relevant acceptance criteria in downstream safety evaluations.
Response
Response to RAI 4.7.3-1 Requests 1-3: The fluence projections for the reactor pressure vessel (RPV) and reactor vessel internals (RVI) components were calculated using the NRC-approved GEH methodology described in Licensing Topical Report NEDC-32983P-A Revision 2. In the GEH methodology, [[ ..................................................................................................................... .1] The bounding coolant density in the upper plenum region is obtained from the GEH best-estimate thermal-hydraulic code, TRACG . Best-estimate analyses performed with TRACG have been approved by the NRC to support licensing applications in different areas, including thermal-hydraulic instability in NEDE-33147P-A and anticipated operational occurrence transients in NEDE-32906P-A. The use of bounding TRACG -determined coolant density in the upper plenum region is consistent with the response that Browns Ferry Nuclear Plant provided to a comparable NRC request for additional information (RAI) on the coolant density in this region . Table 1 summarizes the upper plenum water densities TRACG calculates for RBS .
RBG-47835 Page 35 of 60 Table 1 Coolant Density Distribution in the Upper Plenum from TRACG Analysis at Nominal Extended Power Uprate EPU) / Maximum Extended Load Line Limit Analysis (MELLLA) Conditions for RBS Water Density (g/cm 3 ) Level Axial Ring 1 Ring 2 Ring 3 Volume ID Level Inner Intermediate Peripheral Averaged Below the 9 [[ Separator Above the 8 Core
]]
Table 1 shows the coolant density distribution in the upper plenum, separated into rings for regions above the core. As shown in Table 1, the regions towards the center of the core have a lower coolant density and the region in the core periphery has a higher coolant density due to higher power bundles in the central location of the core causing a higher void fraction . Axially, level 8 is located below level 9. The region at level 8 is above the core. [L .......................... ]] Table 1 values are from an end of cycle statepoint at 100% current licensed thermal power (CLTP) (3091 MWt) and 83.4% of rated flow. This corresponds to the most limiting statepoint because high power with low flow results in a higher void fraction and a lower coolant density in the region above the core. Boiling water reactors (BWRs) do not typically operate at the lowest permissible flow for the entire cycle because they typically use flow to control reactivity, increasing the flow to compensate for the burnup of fuel for a certain control blade pattern sequence during the cycle . Therefore, the core flow varies between the minimum and maximum permissible flow throughout the cycle. The coolant density used in the fluence analysis is more conservative than the most bounding power/flow statepoint (i.e. snapshot in time) coolant density in the upper plenum. The effect of this conservatism is integrated over the entire operating period. The following analysis decisions conservatively account for the coolant density and fluence accrual above the core:
- The thermal hydraulic analysis results are obtained at the most limiting statepoint 100% CLTP and 83.4% rated flow and applied to the upper plenum coolant density.
* [[ .................................................. ,J].
* [L .................................................J]*
- The effect of this conservatism is integrated over the entire operating period.
[c ........................................................................... J] Response to RAI 4.7.3-1 Request 4: The reactor vessel internal (RVI) core support structures (CSS) were evaluated according to the CSS design specification 22A4052. The nominal fluences calculated for 60 years of plant operation were applied to the evaluation. For austenitic stainless steel subjected to a neutron fluence [[ J], the specification for base material provided for no special consideration beyond meeting the American Society for Mechanical Engineers (ASME) Code requirements. For austenitic stainless steel components with a neutron fluence [[ ]], the weld material needs no special consideration . The design specification states that when a fluence [L .............. J], the portion of the component and the weld
RBG-47835 Page 36 of 60 exposed to this greater fluence shall meet the strain criteria in the design specification in addition to the ASME Code requirements. The specification states that welds subjected to a neutron fluence [L ................ J] resulting from any operating and accident load or be [L ............................ J] as determined by Table NG-3352-1 of the ASME Boiler and Pressure Vessel (B&PV) Code, Section III, Sub-section NG. The fast neutron fluence at 54 effective full power years (EFPY) (equivalent to 60 years of plant operation at 90% capacity factor) were calculated for CSS and summarized in Table 2 below. Table 2: RVI Core Support Structures Neutron Fluence Item Core Support Fast Fluence at No. Structure Component 54 EFPY (n/cm 2 ) 1 Shroud 4.07E+21 [[ 2
]]
Core plate 5.88E+20 3 Core plate wedges 8.36E+20 4 Top guide/grid 4.50E+21 5 [[ ]] 6 Control rod guide tube 2.32E+21 7 Orificed fuel support 7.64E+21 8 Peripheral fuel support 8.52E+20 The following CSS components exceeded the [l ................. ll for base material, and [[. .................. ..1] for weld material:
- Shroud
- Core plate
- Top guide / grid
- Control rod guide tube (CRGT)
- Orificed fuel support (OFS)
- Peripheral fuel support (PFS)
RBG-47835 Page 37 of 60 These internal CSS components were evaluated to show that the strain criteria are met according to the design specification, and the welds subjected to the fluence [[ ......................... ]. The core plate wedges are machined parts that do not have welds. In summary, all RVI CSS components meet the acceptance criterion of the design specification for the neutron fluence values. Refer to the response to RAI 4.2.1-1 for changes to the LRA. Question RAI 4.7.3-2 (Fluence Effects for Reactor Vessel Internals)
Background
In LRA Section 4.7.3 and in the USAR Supplement for the TLAA in LRA Section A.2.5.3, the applicant states: "The effects of fluence for 60 years of operation (54 EFPY) were analyzed for the reactor vessel internals components included in the design specification. Location-specific fluence levels were determined. The internal core support structure components were then evaluated against the fluence criteria in the design specification . The evaluation determined that the RBS internal core support structure components meet the design specification for operating conditions through 54 EFPY." LRA Section 4.7.3 further references proprietary GEH report 003N9941, Rev. 0, "River Bend Nuclear Station, Fluence Effect Evaluation on RPV Internal Components." SRP-LR Section 4.7.3.1.2 states that for a TLAA disposition pursuant to 10 CFR 54.21 (c)(1 )(ii), the applicant shall provide a sufficient description of the analysis and document the results of the reanalysis to show that it is satisfactory for the 60-year period. SRP-LR Section 4.7.2.2, which contains the FSAR Supplement acceptance criteria for plant-specific TLAAs , states, "the specific criterion for meeting 10 CFR 54.21 (d) is: The summary description of the evaluation of TLAAs for the period of extended operation in the FSAR supplement is appropriate such that later changes can be controlled by 10 CFR 50.59. The description contains information associated with the TLAAs regarding the basis for determining that the applicant has made the demonstration required by 10 CFR 54.21 (c)(1 )." Issue LRA Sections 4.7.3 and A.2.5.3 do not appear to include sufficient information or analysis details to demonstrate the applicant's basis for dispositioning the TLAA in accordance with 10 CFR 54.21©(1 )(ii) other than referencing the design specification acceptance criterion for fluence levels. Such details are necessary to satisfy SRP-LR Section 4.7.3.1.2, SRP-LR Section 4.7.2.2, and 10 CFR 54.21 (d). Reguest Describe the assumptions and conservatisms that have changed from the original analysis. As part of this clarification, provide the location-specific fluence levels as projected to the end of the period of extended operation.
RBG-47835 Page 38 of 60
Response
The reactor vessel internal (RVI) core support structures (CSS) were evaluated according to the CSS design specification 22A4052. The evaluations were consistent with the design basis analysis methodology with updated loads and fluences for the license renewal application. There were no changes to the assumptions and conservatisms from the original design basis analysis. Refer to the response to Request 4 of RAI 4.7.3-1 for the fast neutron fluence of the CSS at 54 effective full power years (EFPY) (equivalent to 60 years of plant operation) . Refer to the response to RAI 4.2.1 -1 for changes to the LRA. Question RAI A.1.37-1 (Reactor Vessel Surveillance)
Background
LRA Section B.1.37 provides the Reactor Vessel Surveillance Program for the LRA. The LRA indicates the program is an existing aging management program and identifies that the version of the ISP that will be implemented for the period of extended operation will be based on EPRI 's updated ISP and methodology that is provided in the BWRVIP-86, Rev. 1-A report. The applicant provides its updated safety analysis report supplement for the AMP in LRA Section A.1 .37. The applicant's Reactor Vessel Surveillance Program (LRA AMP B.1.37) was approved to implement EPRI 's approved ISP for boiling water reactor designs in River Bend Station (RBS) Facility License Amendment 136 (ADAMS ML0320504540). The current BWRVIP surveillance capsule reports for the program are given in EPRI Non-Proprietary Report No. BWRVIP-113NP (ML102580248, which provides the RBS 1830 Capsule Report and contains the surveillance data for the specific RBS RPV shell plate [Heat No. C3054-2] and weld components [Heat No. 5P6756] represented in the ISP) and in the following additional BWRVIP supplemental surveillance program (SSP) reports that include additional data for the represented weld components : (a) BWRVIP-87NP, Revision 1 (ADAMS ML102420110, providing the data for SSP capsules D, G, and H) , (b) BWRVIP-111 NP, Revision 1 (ML102720220, providing the data for BWRVIP SSP capsules E, F, and I) , and (c) BWRVIP-169NP (ML102590092, providing the data for BWRVIP SSP capsules A, B, and C) . These reports were submitted by EPRI to the NRC's document control desk on behalf of BWR licensees participating in the BWRVIP ISP. Issue The USAR supplement summary description for the Reactor Vessel Surveillance Program states that the appropriate surveillance data are given in EPRI BWRVIP-135. However, EPRI does not submit EPRI Report BWRVIP-135 or any of its revisions to the NRC document control desk for inclusion in ADAMS. Therefore, the staff requests additional clarifications to verify that the relevant ISP surveillance data from the reports referenced in the background section are within the scope of the RBS RV Surveillance Program and that the data from these reports have been appropriately evaluated in the calculations of RPV adjusted reference temperature values , upper shelf energy values , and mean adjusted reference temperature values that were provided in LRA Section 4.2. Request Identify all BWRVIP generated RPV surveillance capsule reports that currently provide the surveillance data inputs for specific RBS RPV weld and plate materials that have been evaluated in the latest version of EPRI 's BWRVIP-135 report. Clarify whether the time-limited aging analysis (TLAA) adjusted reference temperature and upper shelf energy evaluation rows included in LRA Tables 4.2-2 and 4.2-3 under the row headings "Integrated Surveillance Program for BWRVIP-135" provide the actual BWRVIP-135 surveillance data evaluations for the these materials or only a partial summary of the BWRVIP-135 surveillance evaluations for
RBG-47835 Page 39 of 60 the materials. If the latter, the staff requests that the applicant submit the appropriate tables and evaluations from BW RVI P-135 report that apply to the specific RBS RPV plate and weld materials that have been included and evaluated in the BWRVIP ISP.
Response
The BWRVIP-generated RPV surveillance capsule reports that provide the surveillance data inputs for RBS RPV weld and plate materials evaluated in BWRVIP-135 are BWRVIP-113NP; BWRVIP-87NP, Revision 1; BWRVIP-111 NP, Revision 1; and BWRVIP-169NP. The time-limited aging analysis (TLAA) adjusted reference temperature and upper shelf energy evaluation rows included in LRA Tables 4.2-2 and 4.2-3 under the row headings "Integrated Surveillance Program for BWRVIP-135" are not a summary or a partial summary of the BWRVIP-135 surveillance evaluations. River Bend Station is a host plant for the BWR integrated surveillance program (ISP). BWRVIP-113NP (ML102580248, which provides the RBS 1830 capsule report) provided the surveillance data inputs for the reactor pressure vessel plate material C3054-2. BWRVIP-113NP and capsule reports BWRVIP-87NP, Revision 1 (ML102420110) for Capsule H; BWRVIP-111 NP, Revision 1 (ML102720220) for Capsule F; and BWRVIP-169NP (ML102590092) for Capsule C provided the surveillance data inputs for the reactor pressure vessel (RPV) weld material 5P6756. The values of copper and nickel provided in LRA Table 4.2-2 and 4.2-3 under the row headings "Integrated Surveillance Program for BWRVIP-135" for the weld materials are the most conservative values between best-estimate chemistry values, plant-specific chemistry values , and ISP values provided in BWRVIP-135. The most conservative values were used to determine the adjusted reference temperature and upper shelf energy for RBS . The values for copper and nickel in BWRVI P-135 for material 5P6756 are 0.06% and 0.93% by weight percent as described in BWRVIP-87NP, BWRVIP-111 NP, and BWRVIP-169NP. The changes to LRA Sections A.1.37 and B.1.37 follow with additions underlined and deletions lined through . A.1.37 Reactor Vessel Surveillance The integrated surveillance program for the extended period of operation (ISP(E)), based on BWRVIP document BWRVIP-86, Revision 1-A, has been approved for use by tbe NRC. BWRVIP-135 and ISP capsule reports BWRVIP-113NP, Revision 1; BWRVIP-87NP, Revision 1; BWRVIP-111 NP, Revision 1; and BWRVIP-169NP, Revision 1, provides reactor pressure vessel surveillance data and other technical material information for the plants participating in the ISP for use in predicting adjusted reference temperature and upper shelf energy at the end of the period of extended operation. B.1.37 Reactor Vessel Surveillance The integrated surveillance program for the extended period of operation (ISP(E)), based on BWRVIP document BWRVIP-86, Revision 1-A, has been approved for use by the NRC. BWRVIP-135 along with ISP Capsule Reports BWRVIP-113NP, Revision 1; BWRVIP-87NP, Revision 1; BWRVIP-111 NP, Revision 1; and BWRVIP-169NP, Revision 1, provides reactor pressure vessel surveillance data and other technical material information for the plants participating in the ISP for use in predicting adjusted reference temperature and upper shelf energy at the end of the period of extended operation. RBS follows the requirements of the BWRVIP ISP and applies the ISP data. Changes to the capsule withdrawal schedule, including spare capsules, must be approved by the NRC prior to implementation , and untested capsules placed in storage are maintained for future insertion . These measures are effective in detecting the extent of embrittlement to prevent significant degradation of the reactor pressure vessel during the period of extended operation.
RBG-47835 Page 40 of 60 Question RAI B.1.9-1 (BWR VessellD Attachment Welds)
Background
Section §54.21 (a)(3) of 10 CFR requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation . As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21 (a)(3) by referencing the GALL Report and by demonstrating that the matter evaluated in the GALL Report applies to the plant. Issue Relevant information is given in LRA Section B.1.9, "BWR VessellD Attachment Welds Program ," the applicant's program evaluation report for the AMP , and RBC Condition Report Nos. CR-RBS-2014-000253 and CR-RBS-2014-00016. The OE summaries in the referenced condition reports indicate that the applicant has been performing inspections of the feedwater sparger end brackets and their pins using the guidelines in General Electric Company (GE) SIL 658, "Feedwater Sparger End Bracket Degradation," dated July 2008. However applicant does not clarify whether further inspections in accordance with GE SIL 658 are within the scope of the AMP or whether further implementation of the augmented inspections recommended in GE SIL 658 are considered to be applicable enhancements of the "scope of program ," "detection of aging effects," and "monitoring and trending" elements of the program . Request Clarify (with an appropriate justification) whether the guidelines in GE SIL 658 are within the scope of the BWR VessellD Attachment Welds Program and, if so, whether the inspections that will be performed on feedwater and core spray brackets in accordance with the SIL are considered to be enhancements of the "scope of program ," "detection of aging effects," and "monitoring and trending" program elements that go beyond the program element criteria for inspecting these types of components in GALL AMP XI.M9 , "BWR Vessel Internals." Otherwise, justify why inspections performed in accordance with GE SIL 658 would no longer need to be continued as part of the program during the period of extended operation.
Response
The guidelines in General Electric-Hitachi Services Information Letter 658 (GE SIL 658) are not within the scope of the River Bend Station (RBS) BWR VessellD Attachment Welds Program. GE SIL 658 addresses feedwater sparger end brackets and pins. The brackets and pins are not welded to the reactor vessel ; rather they are used to attach the ends of each sparger to the sparger reactor pressure vessel (RPV) brackets which are welded to the reactor vessel. The RBS BWR VessellD Attachment Welds Program addresses the brackets welded to the reactor vessel as described in LRA Appendix B, Section B.1.9. The RBS BWR Vessel Internals Program , with enhancements, will be consistent with the program described in NUREG-1801 , Section XI.M9 , "BWR Vessel Internals". The BWR Vessel Internals program in NUREG-1801 does not include the feedwater sparger end brackets and pins discussed in GE SIL 658. As discussed in LRA Section 2.3.1.1.2, the feedwater sparger has no license renewal intended function and is not subject to aging management review. Thus, the feedwater sparger end brackets and pins are not within the scope of the BWR Vessel Internals program described in NUREG-1801 , Section XI.M9. Furthermore, GE SIL 658 states that concern for feedwater sparger condition is an economic one such that a continued degraded condition may lead to more costly repairs. Because the feedwater sparger end brackets and pins are not within the scope of the BWR Vessel Internals program described in NUREG-1801 and because GE SIL 658 addresses economic consequences rather than safety consequences, the guidelines in GE SIL 658 are not within the scope of the RBS BWR VessellD Attachment Welds Program. SIL 658 does not address core spray brackets.
RBG-47835 Page 41 of 60 Question RAI B.1.9-2 (BWR Vessel 10 Attachment Welds)
Background
Section §54.21 (a)(3) of 10 CFR requ ires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation . As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21 (a)(3) by referencing the GALL Report and by demonstrating that the matter evaluated in the GALL Report applies to the plant. Issue Relevant information is given in LRA AMP Section B.1 .9, "BWR Vessel 10 Attachment Welds Program ," and RBS specific reports RBS-EP-13-00004, "RBS FR-17 Reactor Vessel Internals Management Program Post-Outage Report," RBS-EP-15-00014, RBS RF-18 In-Vessel Visual Inspection (IVVI) Final Report," and of RBG-47362 , "Entergy Facilities Reactor Vessel Internals Inspection Histories." The OE summary in the referenced plant-specific inspection history identifies that the inspections of the feedwater brackets in 2008 included inspections of both the brackets and their alignment pins. The inspection history also indicated that wear was detected in some of the feedwater bracket pins in 2008. However, the "operating experience" program summary for LRA AMP Section B.1.9 states that the inspections of the feedwater brackets in 2008 did not result in the detection of any relevant indications in the brackets. Request Provide justification for why the inspection history is excluded , or amend the "operating experience" program element summary of LRA AMP B.1 .9, "BWR Vessel 10 Attachment Welds" Program to include an OE evaluation summary of the wear that was detected in the plant's feedwater bracket pins in 2008. As part of this summary and in light of the wear detected in 2008, 1) provide the basis why the current programmatic activities for inspecting and evaluating the brackets and th eir pins are still considered to be adequate for managing potential loss of material due to wear in the components during the period of extended operation, and 2) describe any adjustments of the AMP's program element criteria and BWRVIP report methods that currently apply to inspections and evaluations of these components .
Response
The BWR Vessel 10 Attachment Welds Program described in LRA Appendix B, Section B.1.9, is consistent with the program described in NUREG-1801 , Section XI.M4, "BWR Vessel 10 Attachment Welds." The program includes welds between the vessel wall and vessel 10 brackets that attach components to the vessel. The wear detected in 2008 occurred on feedwater sparger end brackets and pins that are not welded to the reactor vessel. The feedwater sparger end brackets are pinned to the feedwater sparger RPV brackets which are welded to the reactor pressure vessel. Thus , operating experience (OE) related to feedwater sparger end brackets and pins is not included in the OE section of the RBS BWR Vessel 10 Attachment Welds Program because the OE occurred on components not welded to the reactor vessel. As discussed in LRA Section 2.3.1.1 .2, the feedwater sparger has no license renewal intended function and is not subject to aging management review. Thus , the feedwater sparger end brackets and pins are not within the scope of the BWR Vessel Internals program described in NUREG-1801. Because the feedwater sparger end brackets and pins are not within the scope of the BWR Vessel Internals program described in NUREG-1801 , no adjustments are made to the program elements in LRA Appendix B, Section B.1.1 0, "BWR Vessel Internals."
RBG-47835 Page 42 of 60 Question RAI B.1.10-2 (BWR Vessel Internals)
Background
The regulation in 10 CFR 54.4(a)(3) requires applicants to include structures, systems, or components (SSCs) in the scope of their license renewal applications (LRAs) if the SSCs are within the scope of specific regulations, including those SSCs that are subject to the regulation in 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without SCRAM Events for Light-Water Cooled Nuclear Power Plants." For those SSCs that are scoped into an LRA in accordance with 10 CFR 54.4, the regulation in 10 CFR 54.21 (a)(1) requires the applicant to subject the SSCs to an aging management review (AMR) if the SSCs are: (a) are not active or do not involve changes in configuration or moving parts, and (b) are not subject to replacement based on a qualified life or specified time period. For those SSCs that are scoped into an LRA and are required to be subjected to an AMR, the regulation in 10 CFR 54.21 (a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. The applicant provides its responses to specific applicant action items (AAls) on specified EPRI BWRVIP reports in Appendix C of the LRA. In its response to AAI #4 on BWRVIP-27-A, the applicant states that the standby liquid control (SLC)/core LlP lines inside the reactor vessel have no safety or license renewal intended function and are not subject to aging management review. Issue The standby liquid control system (SLCS) is typically included with the scope of license renewal because the system meets the scoping criterion in 10 CFR 54.4(a)(3) for systems and components that are subject to the regulation in 10 CFR 50.62 , "Requirements for Reduction of Risk Associated with Anticipated Transients without SCRAM (ATWS) Events for Light-Water Cooled Nuclear Power Plants." In Updated Safety Analysis Report (USAR) Section 9.3.5.2, the applicant states the SLCS is designed to meet the ATWS requirements in 10 CFR 50.62. Request Provide the basis for not including the reactor internal portions of the SLCS within the scope of the LRA based on the requirements in 10 CFR 54.4(a)(3) and the system's intended function of mitigating the consequences of ATWS events.
Response
The RBS USAR states that sodium pentaborate is dispersed within the reactor core in sufficient quantity to provide a reasonable margin for leakage or imperfect mixing. As discussed in the license renewal appendix of BWRVIP-27-A, even if cracking was present in the SLC line inside the reactor vessel , the SLC system would function adequately when initiated as long as the boron is injected into the bottom head. The only SLC components necessary to accomplish the intended function are the vessel penetration, nozzle and external piping. Therefore, BWRVIP-27-A states that an aging management review of the internals piping is not needed for license renewal. The NRC safety evaluation report (December 1999) associated with BWRVIP-27 states that boron mixing and leakage considerations related to the degradation of LlP/SLC internals are qualitatively and quantitatively addressed and concluded that the recommendations in BWRVIP-27 are acceptable. Based on the above information, the RBS standby liquid control system components internal to the reactor
RBG-47835 Page 43 of 60 vessel perform no license renewal intended function and are, therefore , not subject to aging management review. Question RAI B.1 .10-4 (BWR Vessel Internals)
Background
The regulation in 10 CFR 54.4(a)(3) requires applicants to include structures, systems, or components (SSCs) in the scope of their license renewal applications (LRAs) if the SSCs are within the scope of specific regulations, including those SSCs that are subject to the regulation in 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without SCRAM Events for Light-Water Cooled Nuclear Power Plants." For those SSCs that are scoped into an LRA in accordance with 10 CFR 54.4, the regulation in 10 CFR 54.21 (a)(1) requires the applicant to subject the SSCs to an aging management review (AMR) if the SSCs are: (a) are not active or do not involve changes in configuration or moving parts, and (b) are not subject to replacement based on a qualified life or specified time period. For those SSCs that are scoped into an LRA and are required to be subjected to an AMR , the regulation in 10 CFR 54.21 (a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. In LRA Section B.1.10, BWR Vessel Internals Program , and the program document for the AMP identify that the applicant performs periodic inspections of the core shroud in accordance with the proprietary reactor vessel internal (RVI) inspection and evaluation (I&E) guidelines in EPRI Report No. BWRVIP-76-A. In year 2008, the applicant issued a plant-specific inspection report that identified cracking in the RBS core shroud that was approximately 9% of the total weld length of the limiting degraded horizontal weld (i.e ., H4 weld) in the shroud. At the time of that inspection , the core shroud was characterized as an ERPI Category B core shroud for BWRVIP-76-A inspection purposes. Since that time , further inspections of the core shroud were performed in accordance with BWRVIOP-76-A. An updated assessment in a Year 2017 condition report (i.e ., RBS record CR-RBS-2017-01066) indicates that the cumulative extent of cracking in the H4 weld is large enough to the extent that the applicant would need to re-categorize the shroud as a Category C core shroud based on the proprietary methodology in EPRI Report BWRVIP-76-A. Issue The "operating experience" discussion of LRA AMP B.1.1 0, BWR Vessel Internals Program did not discuss whether the plant's core shroud has been re-classified as a BWRVIP-76-A defined Category C shroud based on the results of the applicant's assessment in RBS Report No. CR-RBS-2017 -01066 . Request Clarify whether the BWR Vessel Internals Program has been updated to reclassify the plant's core shroud as a BWRVIP-defined Category C core shroud per the applicable criteria and methodology in the BWRVIP-76-A report. Otherwise, provide the basis why the "detection of aging effects," and "monitoring and trending" elements of the AMP would not need to be enhanced accordingly if the shroud has yet to be re-classified as a BWRVIP-76-A Category C shroud based on the results of the applicable operating experience.
Response
Station procedures for the BWR Vessel Internals Program have been revised to indicate that the vessel core shroud is classified as a BWRVIP-defined Category C core shroud per the applicable criteria and methodology in the BWRVIP-76, Revision 1-A report.
RBG-47835 Page 44 of 60 Question RAI B.1.25-1 (Internal Surfaces in Miscellaneous Piping and Ducting Components)
Background
GALL Report AMP XLM38 , "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," as modified by LR ISG 2012 02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation," states parameters monitored or inspected include visible evidence of loss of material in metallic components. LRA Section B.1.25, "Internal Surfaces in Miscellaneous Piping and Ducting Components," states "[f]or metallic components, visual inspection will be used to detect evidence of loss of material and reduction of heat transfer" and that this new program will be consistent with GALL Report AMP XI.M38, as modified by LR ISG 2012 02. The LRA (e.g., Table 3.3.29, "Combustible Gas Control") states that metallic components will be managed for cracking and reduction of heat transfer using the Internal Surfaces in Miscellaneous Piping and Ducting Components program. Issue It is not clear to the staff that the new Internal Surfaces in Miscellaneous Piping and Ducting Components program will be consistent with GALL Report AMP XLM38 because GALL Report AMP XLM38 does not include reduction of heat transfer or cracking in metallic components as aging effects. As a result of these apparent inconsistencies, it appears that the LRA has not included sufficient information with regard to various aging management program elements (e.g., "parameters monitored or inspected," "detection of aging effects," "acceptance criteria") to demonstrate that the reduction of heat transfer and cracking for metallic components will be adequately managed by the new Internal Surfaces in Miscellaneous Piping and Ducting Components program . Request Clarify whether the new Internal Surfaces in Miscellaneous Piping and Ducting Components program either: a) will be consistent with the GALL Report AMP XI.M38 and then provide an alternate aging management program to manage reduction of heat transfer and cracking of metallic components, or b) will not be consistent with the GALL Report AMP XLM38 and then provide the additional information for changes to applicable program elements that demonstrate reduction of heat transfer and cracking of metallic components will be adequately managed
Response
The River Bend Station (RBS) Internal Surfaces in Miscellaneous Piping and Ducting Components (ISMPDC) Program will be consistent with the GALL Report AMP XLM38 as stated in LRA Section B.1.25. Line items in LRA Section 3 tables specifying aging effects of reduction of heat transfer and cracking of metallic components managed by the ISMPDC program are changed to specify that aging effects will be managed by the Periodic Surveillance and Preventive Maintenance Program described in LRA Section 8.1.34. In addition, LRA Section A.1.25 and Section B.1.25 are revised to remove reduction of heat transfer and cracking as applicable aging effects for the ISMPDC program .
RBG-47835 Page 45 of 60 Changes to LRA Section 3 and Appendix A and B programs follow with additions underlined and deletions lined through. 3.3.2.1 .7 Fire Protection - Water System Aging Management Programs The following aging management programs manage the aging effects for the fire protection - water system components.
- Bolting Integrity
- Buried and Underground Piping and Tanks Inspection
- Coating Integrity
- Diesel Fuel Monitoring
- External Surfaces Monitoring
- Fire Water System
- Internal Surfaces in Miscellaneous Piping and Ducting Components
- One-Time Inspection
- Periodic Surveillance and Preventive Maintenance
- Selective Leaching
- Water Chemistry Control- Closed Treated Water Systems 3.3.2.1.9 Combustible Gas Control System Aging Management Programs The following aging management programs manage the aging effects for the combustible gas control system components.
- Bolting Integrity
- External Surfaces Monitoring
- Internal Surfaces in Miscellaneous Piping and Ducting Components
- Periodic Surveillance and Preventive Maintenance 3.3.2.1.11 HPCS Diesel Generator System Aging Management Programs The following aging management programs manage the aging effects for the HPCS diesel generator system components.
- Bolting Integrity
- External Surfaces Monitoring
RBG-47835 Page 46 of 60
- Internal Surfaces in Miscellaneous Piping and Ducting Components
- Oil Analysis
- One-Time Inspection
- Periodic Surveillance and Preventive Maintenance
- Selective Leaching
- Water Chemistry Control - Closed Treated Water Systems 3.3.2.1 .12 Control Building HVAC System Aging Management Programs The following aging management programs manage the aging effects for the control building HVAC system components .
- Bolting Integrity
- Buried and Underground Piping and Tanks Inspection
- External Surfaces Monitoring
- Internal Surfaces in Miscellaneous Piping and Ducting Components
- Periodic Surveillance and Preventive Maintenance
- Water Chemistry Control - Closed Treated Water Systems 3.3.2.1.13 Miscellaneous HVAC Systems Aging Management Programs The following aging management programs manage the aging effects for the miscellaneous HVAC systems components.
- Bolting Integrity
- External Surfaces Monitoring
- Internal Surfaces in Miscellaneous Piping and Ducting Components
- Periodic Surveillance and Preventive Maintenance
- Service Water Integrity
- Water Chemistry Control- Closed Treated Water Systems
RBG-47835 Page 47 of 60 Table 3.3.1 Summary of Aging Management Programs for the Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 Table 3.3.1: Auxiliary Systems Further Item Aging Effect! Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.3.1-42 Copper alloy, Reduction of heat Chapter XI.M20, "Open-Cycle No The heat exchangers of the RBS titanium , stain less transfer due to Cooling Water System" service water system covered by NRC steel heat exchanger foul ing GL 89-13 use closed cycle cooling tubes exposed to water rather than raw water. raw water Reduction of heat transfer for stainless steel and copper alloy heat exchanger tubes in the fire protection system and stainless steel heat exchanger I2lates in portionsof the service water system not covered by NRC GL 89 -13 is managed by the InteFAal gbiFfaGes in MisGelianeobis Piping and DbiGting GOFAponentsPeriodic Surveillance and Preventive Maintenance Program . There are no titanium heat exchanger tubes exposed to raw water in the auxiliary systems in the scope of license renewal. 3.3.1-83 Stainless steel diesel Cracking due to Chapter XI.M38, "Inspection of No Gonsistent l.¥iti=l ~J~~~G ~ gG~. eng ine exhaust stress corrosion Internal Surfaces in Cracking of stainless steel diesel piping , piping cracking Miscellaneous Piping and engine exhaust components is components , and Ducting Components" managed by the InteFAal gbiFfaGes in piping elements MisGelianeobis Piping and Dblcting exposed to diesel GOFAponentsPeriodic Surveillance and exhaust Preventive Maintenance Program .
--
RBG-47835 Page 48 of 60 Table 3.3.2-3 Service Water System Summary of Aging Management Evaluation Table 3.3.2-3: Service Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Programs Item Item Notes Heat exchanger Heat transfer Stainless steel Raw water (int) Reduction of heat IAteFAal ~l:IAaSeS VII.C1 .AP-187 3.3.1 -42 E (plates) transfer iA Mis8ellaAeel:ls PipiAg aAd Ql:IstiAg CempOAeAts Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 49 of 60 Table 3.3.2-7 Fire Protection - Water System Summary of Aging Management Evaluation Table 3.3.2-7: Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Heat transfer Copper alloy Raw water Reduction of heat IAtemal SI:lllaG8S VII.C1 .A-72 3.3.1-42 E exchanger (ext) transfer iA MisG811aA891:ls (tubes) PipiAg aAd DI:lGtiAg G9fflp9A8AtS I Periodic
.... Surveillance and I Preventive Maintenance
RBG-47835 Page 50 of 60 Table 3.3.2-9 Combustible Gas Control System Summary of Aging Management Evaluation Table 3.3.2-9: Combustible Gas Control System Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Coil Heat transfer Stainless Air - indoor Reduction of heat IRteFAal ~~FfaGes iR -- -- G steel (ext) transfer MisG8l1aR8e~s ~if')iR§ aRe Q~GtiR§ Cemf')eReRts Periodic Surveillance and Preventive Maintenance Piping Pressure Stainless Condensation Cracking IRteFAal ~~FfaG8S iR -- -- H boundary steel (int) MisG8l1aR8e~s ~if')iR§ aRe Q~GtiR§ CempeR8Rts Periodic Surveillance and Preventive Maintenance Tubing Pressure Stainless Condensation Cracking IRteFAal ~~FfaG8S iR -- -- H boundary steel (int) MisG8l1aR8e~s ~ipiR§ aRe Q~GtiR§ CempeR8Rts Periodic Surveillance and Preventive Maintenance Valve body Pressure Stainless Condensation Cracking IRt8FAai ~~FfaG8S iR -- -- H boundary steel (int) MisG8l1aR8e~s ~ipiR§ aRe QUGtiR§ Cemf')eR8Rts Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 51 of 60 Table 3.3.2-10 Standby Diesel Generator System Summary of Aging Management Evaluation Table 3.3.2-10: Standby Diesel Generator System Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Expansion joint Pressure Stainless Exhaust gas Cracking IAtemal ~l:IFfaces iA VII.H2.AP-128 3.3.1-83 A-E boundary steel (int) MiscellaAeolJs PipiAg aAd Dl:IctiAg CompoAeAts Periodic Surveillance and Preventive Maintenance Heat exchanger Heat transfer Copper Air- indoor Reduction of IAtemal ~l:IFfaces iA -- -- G (tubes) alloy (ext) heat transfer MiscellaAeol:ls PipiAg and Dl:Icting ComponeAts Periodic Surveillance and Preventive Maintenance Piping Pressure Stainless Exhaust gas Cracking IAtemal ~l:IFfaces in VII.H2.AP-128 3.3.1-83 A-E boundary steel (int) Miscellaneol:ls Piping and Dl:Icting Components Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 52 of 60 Table 3.3.2-11 HPCS Diesel Generator System Summary of Aging Management Evaluation Table 3.3.2-11: H PCS Diesel Generator System Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Expansion joint Pressure Stainless Exhaust gas Cracking IAtefRal £l:lFlaGeS iA VII.H2.AP-128 3.3.1 -83 A-s boundary steel (int) MisGellaAeel:lS J2iJ3iAQ aA9 [ll:lGtiAQ CemJ3eAeAts , Periodic Surveillance and Preventive Maintenance Heat exchanger Heat transfer Aluminum Air- indoor Reduction of IAtefRal £l:lFlaGeS iA -- -- G (fins) (ext) heat transfer MisGellaAeel:ls J2iJ3iAQ aA9 [ll:lGtiAQ CemJ3eAeAts Periodic Surveillance and Preventive Maintenance Heat exchanger Heat transfer Copper alloy Air - indoor Reduction of IAtefRal £l:lFlaGeS iA -- -- G (tubes) (ext) heat transfer MisGellaAeel:ls J2iJ3iAQ aA9 [ll:lGtiAQ CemJ3eAeAts Periodic Surveillance and Preventive Maintenance Piping Pressure Stainless Exhaust gas Cracking IAtefRal £l:lFlaGeS iA VII.H2.AP-128 3.3.1-83 A-s boundary steel (int) MisGellaAeel:ls J2iJ3iAQ aA9 [ll:lGtiAQ CemJ3eAeAts Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 53 of 60 Table 3.3.2-12 Control Building HVAC System Summary of Aging Management Evaluation Table 3.3.2-12: Control Building HVAC System Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Accumulator Pressure Stainless Air - outdoor Cracking IAtomal ~l:lFfaGos iA -- -- G boundary steel (int) MisGollaAoous PipiAg aAd DUGtiAg CompoAoAts Periodic Surveillance and Preventive Maintenance Filter housing Pressure Stainless Air - outdoor Cracking IAtemal ~uFfaGos iA -- -- G boundary steel (int) MisGollaAOOus PipiAg aAd DUGtiAg CompoAoAts Periodic Surveillance and Preventive Maintenance Flex hose Pressure Stainless Air - outdoor Cracking IAtomal ~uFfaGos iA -- -- G boundary steel (int) MisGollaAOOus PipiAg aAd DUGtiAg CompoAoAts Periodic Surveillance and Preventive Maintenance
-
RBG-47835 Page 54 of 60 Table 3.3.2-12: Control Building HVAC System Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Heat transfer Aluminum Condensation Reduction of IAt8mai ~I:lFfaS8S iA -- -- G exchanger (ext) heat transfer Miss811aA8ol:ls PipiAg (fins) aAd Dl:lstiAg CompoA8Ats Periodic Surveillance and Preventive Maintenance Heat Heat transfer Copper alloy Condensation Reduction of IAtemal ~I:lFfaS8S iA -- -- G exchanger (ext) heat transfer Miss811aA8ol:ls PipiAg (tubes) aAd Dl:lstiAg CompoA8Ats Periodic Surveillance and Preventive Maintenance Manifold Pressure Stainless Air - outdoor Cracking IAl8mai ~I:lFfases iA -- -- G boundary steel (int) Miss811aA8ol:ls PipiAg aAd Dl:lstiAg CompoA8Ats Periodic Surveillance and Preventive Maintenance Sight glass Pressure Stainless Air - outdoor Cracking IAt8mai ~I:lFfaS8S iA -- -- G boundary steel (int) Miss811aA8ol:ls PipiAg aAd Dl:lstiAg CompoA8Ats Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 55 of 60 Table 3.3.2-12: Control Building HVAC System Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tubing Pressure Stainless Air - outdoor Cracking InteFAal ~I:lFfases in -- -- G boundary steel (int) Misselianeol:ls Piping and Dl:lsting Components Periodic Surveillance and Preventive Maintenance Valve body Pressure Stainless Air - outdoor Cracking InteFAal ~I:lFfases in -- -- G boundary steel (int) Misselianeol:ls Piping and Dl:lsting Components Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 56 of 60 Table 3.3.2-13 Miscellaneous HVAC System Summary of Aging Management Evaluation Table 3.3.2-13: Miscellaneous HVAC Systems Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Heat transfer Aluminum Air - outdoor Reduction of IRtemal ~YFfaG8S iR -- -- H exchanger (ext) heat transfer MisG811aR8eyS JdipiRI aRe (fins) DYGtiRI CempeR8Rts Periodic Surveillance and Preventive Maintenance Heat Heat transfer Aluminum Condensation Reduction of IRt8mai ~YFfaG8S iR -- -- G exchanger (ext) heat transfer MisG811aR8eys JdipiRI aRe (fins) DYGtiRI CempeR8Rts Periodic Surveillance and Preventive Maintenance Heat Heat transfer Copper alloy Air - outdoor Reduction of IRt8mai ~YFfaG8S iR -- -- G exchanger (ext) heat transfer MisG811aR8eys JdipiRI aRe (tubes) DYGtiRI CempeR8Rts Periodic Surveillance and Preventive Maintenance Heat Heat transfer Copper alloy Condensation Reduction of IRt8mai ~YFfaG8S iR -- -- G exchanger (ext) heat transfer MisG811aR8eyS JdipiRI aRe (tubes) DYGtiRI CempeR8Rts Periodic Surveillance and Preventive Maintenance Heat Heat transfer Stain less Air - indoor Reduction of IRt8mai ~YFfaG8S iR -- -- G exchanger steel (int) heat transfer MisG811aR8eys JdipiRI aRe (tubes) DYGtiRI CempeR8Rts Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 57 of 60 Table 3.3.2-16 Plant Drains Summary of Aging Management Evaluation Table 3.3.2-16: Plant Drains Aging Effect i Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Piping Pressure Stainless Waste water Cracking Internal ~I:JRaSeS in -- -- H boundary steel (i nt) Missellaneol:Js Piping and Dl:Jcting Components Periodic Surveillance and Preventive Maintenance Valve body Pressure Stainless Waste water Cracking Internal ~I:JRaSeS in -- -- H boundary steel (i nt) Missellaneol:Js Piping and Dl:Jcting Components Periodic Surveillance and Preventive Maintenance
RBG-47835 Page 58 of 60 A.1.25 Internal Surfaces in Miscellaneous Piping and Ducting Components The Internal Surfaces in Miscellaneous Piping and Ducting Components Program manages cracking , loss of material, reduction of heat transfer, and change in material properties using representative sampling and opportunistic visual inspections of the internal surfaces of metallic and elastomeric components in environments of air - indoor, air - outdoor, condensation, exhaust gas, raw water, and waste water. Internal inspections will be performed during periodic system and component surveillances or during the performance of maintenance activities when the surfaces are accessible for visual inspection. Where practical, the inspections will focus on the bounding or leading components most susceptible to aging because of time in service and severity of operating conditions. At a minimum, in each 1O-year period during the period of extended operation, a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population will be inspected. Opportunistic inspections will continue in each period even if the minimum sample size has been inspected . For metallic components, visual inspection will be used to detect evidence of loss of material and reduction of heat transfer. For non-metallic components, visual inspections will be used to detect surface irregularities. Visual examinations of elastomeric components will be accompanied by physical manipulation or pressurization such that changes in material properties are readily observable. The sample size for physical manipulation will be at least 10 percent of accessible surface area. A.1.34 Periodic Surveillance and Preventive Maintenance Credit for program activities has been taken in the aging management review for the following components.
- Inspect the internal surfaces of abandoned equipment in the following nonsafety-related systems affecting safety-related systems to manage loss of material:
~ Leak detection system (system code 207)
~ Makeup water system (system code 659)
~ Fuel pool cooling system (system code 602)
~ Reactor water cleanup system (system code 601)
~ Standby service water system (system code 256)
~ Process radiation monitoring system (system code 511)
~ Floor and equipment drains system (system code 609)
- For metallic components. visually inspect components in the following systems to detect evidence of reduction of heat transfer.
~ Service water system
~ Fire protection - water system
~ Combustible gas control system
~ Standby diesel generator system
RBG-47835 Page 59 of 60
~ HPCS diesel generator system
~ Control building HVAC system
~ Miscellaneous HVAC systems
- For metallic components, visually inspect components in the following systems, and when appropriate, perform surface examinations, to detect evidence of cracking.
~ Combustible gas control system
~ Standby diesel generator system
~ HPCS diesel generator system
~ Control building HVAC system
~ Plant drains system B.1.25 Internal Surfaces in Miscellaneous Piping and Ducting Components Program Description The Internal Surfaces in Miscellaneous Piping and Ducting Components Program is a new program that will manage cracking , loss of material, reduction of heat transfor, and change in material properties using representative sampling and opportunistic visual inspections of the internal surfaces of metallic and elastomeric components in environments of air - indoor, air - outdoor, condensation, exhaust gas, raw water, and waste water. Internal inspections will be performed during periodic system and component surveillances or during the performance of maintenance activities when the surfaces are accessible for visual inspection.
Where practical, the inspections will focus on the bounding or leading components most susceptible to aging because of time in service and severity of operating conditions . At a minimum, in each 1O-year period during the period of extended operation , a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population will be inspected. Opportunistic inspections will continue in each period even if the minimum sample size has been inspected. For metallic components, visual inspection will be used to detect evidence of loss of material and reduction of heat transfer. For non-metallic components, visual inspections will be used to detect surface irregularities. Visual examinations of elastomeric components will be accompanied by physical manipulation or pressurization such that changes in material properties are readily observable. The sample size for physical manipulation will be at least 10 percent of accessible surface area.
RBG-47835 Page 60 of 60 B.1.34 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE Credit for program activities has been taken in the aging management review for the following systems and structures. Nonsafety-related Visually inspect the internal surfaces of floor and equipment systems affecting drains system (system code 609) abandoned piping safety-related components to manage loss of material. systems (continued)
- Service water For metallic com(2onents, visually ins(2ect com(2onents to system detect evidence of reduction of heat transfer.
- Fire (2rotection -
water system
- Combustible gas control system
- Standby diesel generator system
- HPCS diesel generator system
- Control building HVAC system
- Miscellaneous HVAC systems
- Combustible gas For metallic com(2onents, visually ins(2ect com(2onents, and control system when a(2(2ro(2riate, (2erform surface examinations, to detect
- Standby diesel evidence of cracking .
generator system
- HPCS diesel generator system
- Control building HVAC system
- Plant drains system Evaluation
- 4. Detection of Aging Effects Periodic surveillances and preventive maintenance activities provide for component inspections to detect aging effects. Inspection intervals provide timely detection of degradation prior to loss of intended functions .
Established inspection methods to detect aging effects of loss of material~ aM cracking, and reduction of heat transfer include visual inspections, and when a(2(2ro(2riate, surface examinations for metallic components. Inspection of elastomeric materials to detect cracking and change in material properties includes visual inspections while manually flexing the component. Manipulation of any specific elastomeric component includes at least 10 percent of available surface area, including visually identified suspect areas.}}