ML25051A255
| ML25051A255 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 02/20/2025 |
| From: | Constellation Energy Generation |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML25051A253 | List: |
| References | |
| RS-25-030 | |
| Download: ML25051A255 (1) | |
Text
February 20, 2025 Enclosure A Page 1 of 165 Enclosure A Dresden Nuclear Power Station, Units 2 and 3, Subsequent License Renewal Application Affected Changes Introduction This enclosure contains 35 changes that are being made to the Subsequent License Renewal Application (SLRA) that were identified after its initial submission. For each item, a detailed description of the change is provided along with the affected page number(s) and specific portion(s) of the SLRA.
For clarity, entire sentences or paragraphs from the SLRA are provided with the deleted text highlighted by strikethroughs and the inserted text highlighted by bolded italics. Additionally, any revisions to the SLRA tables are shown by providing excerpts from the affected tables.
February 20, 2025 Enclosure A Page 2 of 165 Table of Contents Change # 01 - ASME Code Class 1 Small-Bore Piping............................................................. 4 Change # 02 - Reactor Vessel System AMR Update................................................................13 Change # 03 - Reactor Coolant Pressure Boundary System AMR Update...............................15 Change # 04 - Reactor Vessel Internals System AMR Update.................................................17 Change # 05 - Isolation Condenser AMR Update.....................................................................19 Change # 06 - Addition of Loss of Material as an Aging Effect for Stainless Steel Valve Bodies
.................................................................................................................................................23 Change # 07 - Reactor Vessel System AMR Update................................................................25 Change # 08 - Reactor Vessel System AMR Update................................................................27 Change # 09 - Addition of Halon Storage Tanks and Diesel Fire Water Pump Cooler...............29 Change # 10 Revision to Enhancements 1 and 5 of Bolting Integrity AMP..........................38 Change # 10 Addition of AMR Line Item for Traveling Screen Bolting.................................42 Change # 10 Changes to AMR Lines 3.1.1-062, 3.4.1-007, and SLRA Table 3.1.2-2..........45 Change # 11 - Clarification of the Scope of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems AMP................................................................49 Change # 12 - Exception for Use of BWRVIP-48 Revision 2....................................................52 Change # 13 - Fatigue Monitoring Program Enhancement.......................................................63 Change # 15 - Correction to HELB System List........................................................................67 Change # 17-Clarifications of BWRVIP Revisions and Usage.................................................69 Change # 18 - Revisions to A.2.1.21 and B.2.1.21, Selective Leaching....................................78 Change # 21 - Correction of TLAA and Fatigue Related AMR Line Items and Associated Plant Specific Notes...........................................................................................................................83 Change # 23 Clarification to SLRA Section 3.2.2.2.2........................................................ 117 Change # 23 Clarification to SLRA Section 3.4.2.2.7........................................................ 119 Change # 25 - Clarification to Address the Aging of Insulation for Fuse Holders..................... 121 Change # 26 - Clarifications to SLRA B.2.1.36, Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements........... 125 Change # 27 Revision to Plant Specific Notes for Buried Polymeric Piping....................... 128 Change # 29 - Revision to Reactor Building Aging Management Review............................... 130 Change # 31 - In-Situ Attenuation Testing of the Unit 2 Spent Fuel Pool Racks...................... 135 Change # 32 - Revision to Aging Management Review for the ECCS Suction Strainers........ 140 Change # 33 - Flow Blockage of Stainless Steel Nozzles in the Fire Protection System........ 144
February 20, 2025 Enclosure A Page 3 of 165 Change # 34 - Updates to Fire Water System Program Appendix A and B............................. 146 Change # 44 - Limiting Shell Weld Fluence Clarification......................................................... 152 Change # 45 - Update to Aging Effects for Components in the Cranes, Hoists, and Refueling Equipment System.................................................................................................................. 155 Change # 46 - Fire Protection AMR Updates.......................................................................... 158 Change # 47 -Evaluation of Stainless Steel Diesel Exhaust Components.............................. 160 Change # 60 - Clarification of Fire Protection Program Description........................................ 162 Change # 62 - Loss of Preload of HVAC Closure Bolting........................................................ 164
February 20, 2025 Enclosure A Page 4 of 165 Change # 01 - ASME Code Class 1 Small-Bore Piping Affected SLRA Sections: A.2.1.22, B.2.1.22 Affected SLRA Page Numbers: A-26, B-126, B-127, B-129 Description of Change:
Following submittal of the Dresden SLRA, additional operating experience relevant to the ASME Code Class 1 Small-Bore Piping Aging Management Program was identified. Review of this newly identified operating experience resulted in changes to the inspection requirements in the ASME Code Class 1 Small-Bore Piping Aging Management Program.
Specifically, review of this operating experience resulted in a change to the classification of the Unit 3 socket weld population from Category A to Category B. As such, the number of one-time inspections of the Unit 3 socket welds is increased from 10 to 25.
Additionally, the NRC identified a typo on page B-129 which incorrectly stated Unit 2 instead of Unit 3.
Accordingly, SLRA Appendix A Section A.2.1.22 and Appendix B Section B.2.1.22 are revised.
February 20, 2025 Enclosure A Page 5 of 165 SLRA Appendix A, Section A.2.1.22, ASME Code Class 1 Small-Bore Piping, page A-26 is revised as shown below:
A.2.1.22 ASME Code Class 1 Small-Bore Piping The ASME Code Class 1 Small-Bore Piping aging management program is a new condition monitoring program that augments the existing ASME Code,Section XI requirements and is applicable to ASME Code Class 1 small-bore piping and systems with a NPS diameter less than 4 inches and greater than or equal to 1 inch.
This program provides for volumetric examination of a sample of full penetration (butt) welds and partial penetration (socket) welds in Class 1 piping to manage cracking due to stress corrosion cracking or thermal or vibratory fatigue loading. Volumetric examinations will employ techniques that have been demonstrated to be capable of detecting flaws and discontinuities in the examination volume of interest. Destructive examination methods may be performed in lieu of volumetric examination. The program examinations are performed to verify that degradation is not occurring and to validate the effectiveness of existing programs and practices, thereby, confirming that no additional aging management is required for the subsequent period of extended operation.
The extent and schedule for volumetric examination is based on Dresden plant-specific operating experience which demonstrates reveals that cracking of Class 1 small-bore welds has occurred and is not occurring and that actions have been implemented to effectively mitigate the causes of the single instance of past cracking.
The program provides for a one-time examination of a sample of the population of butt welds and socket welds at Dresden.
The only instance of butt weld cracking of Class 1 small-bore piping identified during a review of Dresden operating experience occurred at a butt weld heat affected zone (HAZ) on Unit 2 in 2003. The cause of the cracking condition was effectively mitigated by a design change and through improved station chemical control processes. A review of station operating experience has also not identified any Class 1 small-bore cracking events involving Unit 3 2 socket welds or Unit 3 socket welds or butt welds. The failures all occurred on the recirculation pump flow sensing lines and were attributed to mechanically induced residual pipe stresses coupled with sensing line vibration, caused by resonance frequency with the recirculation pump speed. The implementation of 2-1 axial leg socket welds, removal of elbows, enhanced fit-up process and minimization of mechanically induced stresses by proper tie-back support and alignment has mitigated the occurrence of cracking on these lines. One-time examinations of 10 socket welds will be performed for both Unit 2 and Unit 3 and 25 socket welds for Unit 3. One-time examinations will be performed on eight Class 1 butt welds for Unit 2 and three Class 1 butt welds for Unit 3. If destructive examination is used, then each weld receiving a destructive examination can be credited as equivalent to two volumetric examinations.
If one-time inspections identify unacceptable age-related cracking based on evaluation of the flaw performed in accordance with ASME Code,Section XI, IWB-3132, then periodic examinations will be performed on 10 percent of the applicable weld population, up to a maximum of 25 welds per population. If required, periodic examinations will be performed on a 10-year frequency.
February 20, 2025 Enclosure A Page 6 of 165 The new aging management program will be implemented no later than six months prior to the subsequent period of extended operation. Inspections will be completed within the six years prior to the subsequent period of extended operation and no later than the last refueling outage prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 7 of 165 SLRA Appendix B, Section B.2.1.22, ASME Code Class 1 Small-Bore Piping, pages B-126, B-127, and B-129 are revised as shown below:
B.2.1.22 ASME Code Class 1 Small-Bore Piping Program Description The ASME Code Class 1 Small-Bore Piping aging management program is a new condition monitoring program that augments the existing ASME Code,Section XI requirements and is applicable to ASME Code Class 1 small-bore piping and systems with a NPS diameter less than 4 inches and greater than or equal to 1 inch. This program provides for volumetric examination of a sample of full penetration (butt) welds and partial penetration (socket) welds in Class 1 piping to manage cracking due to stress corrosion cracking or thermal or vibratory fatigue loading. The program examinations are performed to verify that degradation is not occurring and to validate the effectiveness of existing programs and practices, thereby, confirming that no additional aging management is required for the subsequent period of extended operation.
The extent and schedule for volumetric examination is based on Dresden plant-specific operating experience which demonstrates that when cracking of Class 1 small-bore welds is has not occurring occurred and that actions have been implemented to effectively mitigate the causes of the single instance of past cracking.
The program provides for a one-time examination of a sample of the population of butt welds and socket welds at Dresden.
Review of DNPS operating experience identified one failure of an ASME Code Class 1 small-bore piping butt weld heat affected zone (HAZ) on Unit 2 in 2003. Analysis using destructive examination methods showed that the weld contained a through-wall crack that was typical of transgranular stress corrosion cracking (TGSCC). The failed weld likely began to crack early in plant life due to halogen exposure. The unique design of the line where through-wall cracking occurred resulted in high residual stress because of the close proximity of a fillet weld to the butt weld. The butt weld was relocated further away from the bulkhead during repair to reduce stress concentrations. Dresden Unit 3 has experienced socket weld failures associated with Reactor Recirculation pump flow sensing lines. The failures were attributed to mechanically induced residual pipe stresses coupled with sensing line vibration, caused by resonance frequency with the recirculation pump speed. The sensing line issues were isolated to Unit 3 and were mitigated by means of modification of welds to 2-1 axial leg socket welds, removal of elbows, enhanced fit-up process and minimization of mechanically induced stresses by proper tie-back support and alignment. An extensive review of Dresden operating experience identified no instances of Class 1 small-bore piping cracking or leak events on Unit 2 socket welds or on Unit 3 socket welds or butt welds.
Volumetric examinations will employ techniques that have been demonstrated to be capable of detecting flaws and discontinuities in the examination volume of interest.
Because more information can be obtained from a destructive examination than from a nondestructive volumetric examination, any weld that is destructively examined can be credited as equivalent to having volumetrically examined two welds.
February 20, 2025 Enclosure A Page 8 of 165 If cracking is revealed by a one-time inspection, the condition will be entered into the corrective action program and additional one-time inspections will be performed for the population of welds (butt welds or socket welds) that have experienced cracking in accordance with ASME Code,Section XI, IWB-2420. In addition, periodic examinations will be performed of 10 percent of the applicable weld population, up to a maximum of 25 welds per population, if one-time inspections identify unacceptable age-related cracking based on evaluation of the flaw performed in accordance with ASME Code,Section XI, IWB-3132. If required, periodic examinations will be performed on a 10-year frequency.
The following table provides a summary of the number of one-time inspections required for Unit 2 and Unit 3 butt welds and socket welds:
Table B.2.1.22-1 ASME Code Class 1 Small-Bore Piping Inspection Summary Unit Type of Weld (Butt or Socket)
Category per Table XI.M35-1 Percent/Number Requiring One-Time Inspection Number of Welds in the Population Number of One-Time Weld Inspections Required 2
Butt B
10% up to 25 72 8
2 Socket A
3% up to 10 More than 1000 10 3
Butt A
3% up to 10 83 3
3 Socket A B 3% up to 10 10% up to 25 More than 1000 10 25 The new ASME Code Class 1 Small-Bore Piping program will be implemented in accordance with fleet procedures and the program requirements are expected to be applicable to all Constellation plants for operation beyond 60 years. The equivalent new ASME Code Class 1 Small-Bore Piping program for Peach Bottom Atomic Power Station (PBAPS) has been previously evaluated by the NRC, as documented in the Safety Evaluation Report Related to the Subsequent License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3 Docket Nos.50-277 and 50-278 (ADAMS Accession Number ML20044D902). The DNPS commitment for the new ASME Code Class 1 Small-Bore Piping program is comparable to the associated PBAPS commitment. Based on the NRCs evaluation of the PBAPS program, the NRC has determined that the new ASME Code Class 1 Small-Bore Piping program will adequately manage the effects of aging such that intended function(s) are maintained consistent with the CLB for the subsequent period of extended operation, as required by 10 CFR 50.54(a)(3). The new aging management program will be implemented no later than six months prior to the subsequent period of extended operation.
Inspections will be completed within the six years prior to the subsequent period of extended operation and no later than the last refueling outage prior to the subsequent period of extended operation.
NUREG-2191 Consistency
February 20, 2025 Enclosure A Page 9 of 165 The ASME Code Class 1 Small-Bore Piping aging management program will be consistent with the ten elements of aging management program XI.M35, "ASME Code Class 1 Small-Bore Piping," specified in NUREG-2191.
Exceptions to NUREG-2191 None.
Enhancements None.
Operating Experience The following examples of operating experience provide objective evidence that the ASME Code Class 1 Small-Bore Piping program will be effective in assuring that intended functions are maintained consistent with the current licensing basis for the subsequent period of extended operation:
- 1. In 2003, during the Unit 2 fall refueling outage, a through-wall leak was detected during the Class 1 system leakage test. The through-wall indication was observed to be from the reactor head spray 2.5 line where the toe of the bulkhead sleeve fillet weld coincided with the toe of a flanged transition section to pipe butt weld.
The flaw was categorized as transgranular stress corrosion cracking (TGSCC) based on the orientation of crack branching. The pitting on the surface of the weld region would also be indicative of halogen exposure (e.g., chlorides) in an aqueous environment. The crack initiated from the external surface of the sample.
The cracking was in the overlapping heat-affected zones of the butt and fillet welds, which is a unique configuration. The cracking followed the butt weld heat affected zone toward the inner half of the pipe. The heavily branched nature of the observed cracking is usually indicative of slow crack propagation, which suggests the external halogen exposure occurred a long time ago. Since the external surface of the pipe is normally dry during unit operation, it is unlikely that crack propagation occurred during service. The conditions which affected the exterior of this pipe and eventually led to the TGSCC through wall flaw were unique and are not indicative of the conditions of the remaining butt-weld population for Dresden Unit 2. Halogen exposure is limited and evaluated per site procedural guidance.
The section of pipe containing the flaw was removed and replaced with a new flange and pipe piece. The location of the pressure boundary weld was moved to avoid the bulkhead fillet weld from being in close proximity to the butt weld heat affected zone. Radiography and die penetrant tests were performed on the replacement weld. A VT-2 inspection was performed on the replaced components during a system pressure test and the results were satisfactory.
Extent of condition inspections were performed for similar piping configurations on the reactor head. The wide range level instrument line and the head vent line are similarly configured where the line is fillet welded to a bulkhead penetration sleeve. A comprehensive visual examination was performed on these lines to assess the internal conditions of the piping at the flanged connections after they were disconnected and removed from the cavity. This inspection revealed no anomalies or indications.
February 20, 2025 Enclosure A Page 10 of 165 Additionally, the piping-to-penetration sleeve fillet weld for the wide range level instrument line was examined using the dye penetrant (PT) method. The weld was evaluated and found to be acceptable. However, since scattered pitting was identified, the line was replaced during the fall refueling outage in 2005 (D2R19).
The Unit 3 head spray, wide range level instrument and head vent lines were also examined using PT exams. These examinations revealed no anomalies or indications.
A similar failure was identified on the same line on 4/26/1981. During an ASME Class 1 system leakage test in progress, water was observed seeping from cracks in the Dresden Unit 2 2.5" reactor head spray line. The cracks were located several pipe diameters from the nearest weld. Failure was attributed to chloride induced stress corrosion cracking. The residual stresses resulted during strengthening of the pipe by the manufacturer. The cracks were cut out and approximately 100 inches of piping was replaced with low carbon stainless steel.
This operating experience example provides objective evidence that the Dresden operating history does not indicate any widespread issues associated with the ASME Code Class 1 small-bore piping welds and that, when leakage is detected, appropriate corrective actions are performed to prevent recurrence and determine extent of condition.
- 2. In 1997 and 1999, failures occurred on the Dresden Unit 3 Reactor Recirculation loop B high pressure sensing line tee socket weld. The cause of the 1997 event was attributed to fatigue failure of the subject socket weld. It is postulated that a flaw was present in the socket root weld which led to a premature failure of the weld in the presence of vibration.
The system vibration then acted on the defect in the root weld, resulting in premature failure of the joint due to fatigue. These conclusions were not confirmed through laboratory analysis because the failure was perceived to be an isolated event, resulting in the decision to perform a weld repair verses a replacement and subsequent weld failure analysis.
In March 1999, during an inspection of the Dresden Unit 3 drywell for the source of a previously detected increase in unidentified leakage, a steam leak was discovered on a socket weld at a 1-inch tee fitting on the high pressure instrument line for the Reactor Recirculation pump loop B venturi flow element. A detailed analysis for the failed tee weld indicated the root cause of the weld failure was attributed to fatigue crack propagation resulting from low amplitude, high cycle vibration which was accelerated by the presence of a lack of fusion root weld defect. Corrective actions for the 1999 event included the new socket welds being installed with a 2-1 axial leg socket weld and replacement of the tee, two adjacent elbows, the pipe between the elbows, and approximately 5 inches of the pipe welded to the branch side of the tee with type 304 stainless steel. The original material was type 316L stainless steel, which has a lower allowable stress. In addition, tie-back supports were subsequently installed to reduce the vibration induced stresses.
February 20, 2025 Enclosure A Page 11 of 165 In October 2002, a leak was identified on a one inch diameter piping socket weld associated with the Reactor Recirculation (RR) A loop low pressure flow venturi differential pressure sensing line. A Dresden Unit 3 shutdown was performed as required by Technical Specifications for primary pressure boundary leakage. The root cause of the failure was attributed to an inadequate 1-1 axial leg socket weld application in a system experiencing flow induced vibration. The 1-1 axial leg socket weld was installed in 1985 during a major piping replacement modification.
Corrective actions included replacement of the Dresden Unit 3 RR loop A high and low pressure venturi sensing line elbows and piping with a bent pipe configuration with no elbows and replacement of sixteen 1-1 axial leg socket welds with 2-1 axial leg socket welds. Dresden also modified twenty-six 1-1 axial leg socket welds on the Dresden Unit 3 RR loop B high and low pressure venturi sensing lines to achieve 2-1 axial socket weld configurations.
In December 2002, during an inspection of the Dresden Unit 3 drywell for the source of a previously detected increase in unidentified drywell sump input, a leak was identified on a RR loop A Loop Low Pressure Flow Venturi Differential Pressure Sensing Line socket weld. The root cause was attributed to mechanically induced residual pipe stresses due to the installation techniques performed on the reactor recirculation sensing line repair during the October 2002, Dresden Unit 3 refueling outage (D3R17) coupled with sensing line vibration, caused by resonance frequency with the RR pump speed. The residual pipe stresses were attributed to welding techniques used during the socket weld fit-up, piping configuration misalignment during socket weld fit-up and tie-back support misalignment during piping installation.
Corrective actions include minimizing the welding induced residual stresses by enhanced fit-up process (i.e., four tack welds during fit-up) and minimizing the mechanically induced stresses by proper tie-back support and alignment in the repaired sensing line. Additionally, due to the subsequent failures of the A Loop low pressure sensing line weld in October and December of 2002 the installation of an additional tie back support was executed.
There have been no subsequent failures of the Unit 3 RR sensing line socket welds. The implementation of 2-1 axial leg socket welds, removal of elbows, enhanced fit-up process and minimization of mechanically induced stresses by proper tie-back support and alignment has mitigated the occurrence of cracking on these lines.
The Dresden Unit 2 RR flow element sensing lines each have only one high and low pressure tap. This arrangement greatly improves system flexibility and reduces thermal, vibrational, and residual stresses. Reliable operation of the Dresden Unit 2 RR sensing lines demonstrate that the Unit 2 configuration does not operate near resonance frequencies since high cycle fatigue failures occur within a relatively short period of time. Therefore, it is
February 20, 2025 Enclosure A Page 12 of 165 concluded that the Dresden Unit 2 RR sensing lines are not susceptible to failure modes experienced on Dresden Unit 3.
- 23. One-time inspections on Class 1 small-bore piping were performed prior to entering the first period of extended operation for DNPS. Inspections were performed of a sample of 10% of the high and medium risk welds from each unit.
For Unit 2, there was a combined total of 19 medium and high-risk welds.
Therefore, a sample of two welds were selected for inspection. The two welds selected for Unit 2 were on the control rod drive capped return line. These welds were ultrasonically examined during refueling outage D2R18 (2003). The examinations identified no recordable indications.
For Unit 3, there were a combined total of 26 medium and high-risk welds.
Therefore, a sample of three welds were selected for inspection. The three welds selected for Unit 2 3 included one weld on the RPV level instrument line and the two welds on the CRD capped return line. The ultrasonic exams were performed during refueling outages D3R18 (2004), D3R19 (2006), and D3R20 (2008) with no recordable indications identified.
This operating experience example provides objective evidence that inspections performed in accordance with first license renewal commitments have confirmed that the ASME Code Class 1 small-bore piping remain in excellent material condition and that the measures in place to prevent cracking of Class 1 small-bore piping have been effective, including the design of the plant piping systems to prevent cracking caused by fatigue and effective water chemistry controls to mitigate stress corrosion cracking.
The operating experience relative to the ASME Code Class 1 Small-Bore Piping program did not identify an adverse trend in performance. The inspection methods being implemented by the program have been proven effective in detecting aging effects including cracking. Appropriate guidance for evaluation, repair, or replacement is provided for locations where degradation is found.
Periodic assessments of the ASME Code Class 1 Small-Bore Piping program are performed to identify the areas that need improvement to maintain effective performance of the program. The program is informed and enhanced, when necessary, through the systematic and ongoing review of both plant-specific and industry operating experience. Therefore, there is confidence that continued implementation of the ASME Code Class 1 Small-Bore Piping program will effectively manage the effects of aging and initiate corrective actions prior to loss of intended function during the subsequent period of extended operation.
Conclusion The new ASME Code Class 1 Small-Bore Piping program will provide reasonable assurance that the cracking aging effect will be adequately managed so that the intended functions of components within the scope of license renewal are maintained consistent with the current licensing basis during the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 13 of 165 Change # 02 - Reactor Vessel System AMR Update Affected SLRA sections: Table 3.1.2-2 Affected SLRA Page Numbers: 3.1-75 and 3.1-76 Description Change:
SLRA Table 3.1.2-2 has three line items under the component N-12 Core Delta P and SLC Nozzle Safe Ends and Welds which were inadvertently duplicated (line items associated with NUREG-2191 items IV.A1.R-04 and IV.A1.RP-157).
Accordingly, SLRA Table 3.1.2-2 is revised as shown below to delete the duplicate line items.
February 20, 2025 Enclosure A Page 14 of 165 SLRA Table 3.1.2-2, Summary of Aging Management Evaluation of the Reactor Vessel, pages 3.1-75 and 3.1-76 is revised as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes N-12 Core Delta P
& SLC Nozzle Safe Ends and Welds Pressure Boundary Stainless Steel Reactor Coolant (Internal)
Cracking BWR Stress Corrosion Cracking (B.2.1.5)
IV.A1.R-68 3.1.1-128 A
Water Chemistry (B.2.1.2)
IV.A1.R-68 3.1.1-128 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20) IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20) IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
February 20, 2025 Enclosure A Page 15 of 165 Change # 03 - Reactor Coolant Pressure Boundary System AMR Update Affected SLRA sections: Table 3.1.2-1 Affected SLRA Page Numbers: 3.1-72 Description Change:
The first three AMR lines on page 3.1-72 inadvertently identified the internal environment for the component type Valve Body (Class 1) as Treated Water (Internal). The correct internal environment for these lines is Steam (Internal). The Steam (Internal) environment is defined in SLRA Table 3.0-1 as dry steam such as main steam up to the turbine. As such, portions of the Reactor Coolant Pressure Boundary System are exposed to Steam (Internal). Steam (Internal) is considered a match to the NUREG-2192 environment of Reactor Coolant which is defined as treated water in the reactor coolant system and connected systems at or near full operating temperature, including steam associated with BWRs.
Additional changes are being made to Table 3.1.2-1 under a different change number have no impact on the changes applied herein.
Accordingly, SLRA Table 3.1.2-1 is revised as shown below.
February 20, 2025 Enclosure A Page 16 of 165 SLRA Table 3.1.2-1, Summary of Aging Management Evaluation of the Reactor Coolant Pressure Boundary System, page 3.1-72 is revised, additional changes are being made under a different change number and have no impact on the changes applied, as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Stainless Steel Treated Water (Internal)
Steam (Internal)
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
VIII.B2.SP-155 3.4.1-084 A
Water Chemistry (B.2.1.2) VIII.B2.SP-155 3.4.1-084 B
Treated Water (Internal)
Cumulative Fatigue Damage TLAA VII.E3.A-62 3.3.1-002 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-73 3.2.1-022 A
Water Chemistry (B.2.1.2)
V.D2.EP-73 3.2.1-022 B
February 20, 2025 Enclosure A Page 17 of 165 Change # 04 - Reactor Vessel Internals System AMR Update Affected SLRA sections: Table 3.1.2-3 Affected SLRA Page Numbers: 3.1-97 Description Change:
The component Jet Pump Assemblies: Thermal sleeve inlet header, Riser brace arm, Holddown beams, Inlet elbow, Wedge, Mixing assembly, with material Nickel Alloy and environment Reactor Coolant and Neutron Flux, the aging effect Loss of Material is managed by the BWR Vessel Internals (B.2.1.7) program and the Water Chemistry (B.2.1.2) program.
However, the Water Chemistry (B.2.1.2) program was inadvertently omitted as a program credited for managing loss of material of this component.
Additional changes are being made to Table 3.1.2-3 under a different change number have no impact on the changes applied herein.
Accordingly, SLRA Table 3.1.2-3 is revised as shown below to correct this discrepancy.
February 20, 2025 Enclosure A Page 18 of 165 SLRA Table 3.1.2-3, Summary of Aging Management Evaluation of the Reactor Vessel Internals System, page 3.1-97 is revised, additional changes are being made under a different change number and have no impact on the changes applied, as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Jet Pump Assemblies:
Thermal sleeve inlet header, Riser brace arm, Holddown beams, Inlet elbow, Wedge, Mixing assembly Direct Flow Nickel Alloy Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-100 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-100 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 19 of 165 Change # 05 - Isolation Condenser AMR Update Affected SLRA sections: Table 3.2.2-4 Affected SLRA Page Numbers: 3.2-89, 3.2-90, 3.2-91, 3.2-97 Description Change:
The radioactivity and temperature monitoring of the isolation condenser shell side water is implemented through the Water Chemistry (B.2.1.2) program. However, the Water Chemistry (B.2.1.2) program was inadvertently omitted as an aging management credited for the isolation condenser tubesheets and tubes. The plant-specific notes for SLRA Table 3.2.2-4 were revised to include these details.
Accordingly, SLRA Table 3.2.2-4 is revised as shown below to correct these discrepancies.
February 20, 2025 Enclosure A Page 20 of 165 SLRA Table 3.2.2-4, Summary of Aging Management Evaluation for the Isolation Condenser System, page 3.2-89, is revised as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Heat Exchanger -
(Isolation Condenser) Tube Sheets Pressure Boundary Carbon or Low Alloy Steel with Stainless Steel Cladding Treated Water (External)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.R-225 3.1.1-021 A, 1 Water Chemistry (B.2.1.2)
IV.C1.R-225 3.1.1-021 E, 1, 3 Long-Term Loss of Material One-Time Inspection (B.2.1.20)
V.D2.E-434 3.2.1-090 A
Loss of Material ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.RP-39 3.1.1-031 A
Water Chemistry (B.2.1.2)
IV.C1.RP-39 3.1.1-031 B
Treated Water > 140°F (Internal)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.R-225 3.1.1-021 A, 1 IV.C1.R-15 3.1.1-017 A, 1 Water Chemistry (B.2.1.2)
IV.C1.R-225 3.1.1-021 E, 1, 3 IV.C1.R-15 3.1.1-017 B, 1 Loss of Material ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.RP-39 3.1.1-031 A
Water Chemistry (B.2.1.2)
IV.C1.RP-39 3.1.1-031 B
February 20, 2025 Enclosure A Page 21 of 165 SLRA Table 3.2.2-4, Summary of Aging Management Evaluation for the Isolation Condenser System, pages 3.2-90 and 3.2-91, are revised as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Heat Exchanger -
(Isolation Condenser) Tubes Pressure Boundary Stainless Steel Treated Water >
140°F (External)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.R-225 3.1.1-021 A, 1 IV.C1.R-15 3.1.1-017 A, 1 Water Chemistry (B.2.1.2)
IV.C1.R-225 3.1.1-021 E, 1, 3 IV.C1.R-15 3.1.1-017 B, 1 Cumulative Fatigue Damage TLAA VII.E4.A-62 3.3.1-002 A, 2 Loss of Material ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.RP-39 3.1.1-031 A
Water Chemistry (B.2.1.2)
IV.C1.RP-39 3.1.1-031 B
Treated Water >
140°F (Internal)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.R-225 3.1.1-021 A, 1 IV.C1.R-15 3.1.1-017 A, 1 Water Chemistry (B.2.1.2)
IV.C1.R-225 3.1.1-021 E, 1, 3 IV.C1.R-15 3.1.1-017 B, 1 Cumulative Fatigue Damage TLAA VII.E4.A-62 3.3.1-002 A, 2 Loss of Material ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.RP-39 3.1.1-031 A
Water Chemistry (B.2.1.2)
IV.C1.RP-39 3.1.1-031 B
February 20, 2025 Enclosure A Page 22 of 165 SLRA Table 3.2.2-4, Summary of Aging Management Evaluation for the Isolation Condenser System, page 3.2-97, is revised as shown below.
Plant Specific Notes:
- 1. The TLAA designation in the Aging Management Review Program column indicates that fatigue of this component is evaluated in Section 4.3.
- 1. Augmented testing of the isolation condenser tubes and tube sheet includes radioactivity and temperature monitoring of the isolation condenser shell side water and eddy current testing of the isolation condenser tubes.
- 2. The TLAA designation in the Aging Management Review Program column indicates that fatigue of this component is evaluated in Section 4.3.
- 3. The radioactivity and temperature monitoring of the isolation condenser shell side water is implemented through the Water Chemistry (B.2.1.2) program.
February 20, 2025 Enclosure A Page 23 of 165 Change # 06 - Addition of Loss of Material as an Aging Effect for Stainless Steel Valve Bodies Affected SLRA Section: Table 3.3.2-15 Affected SLRA Page Number: Page 3.3-254 Description of Change:
Loss of material was inadvertently omitted as an applicable aging effect for stainless steel valve bodies that perform a pressure boundary intended function in the Radwaste System.
Accordingly, Table 3.3.2-15 is revised as shown below to add loss of material for this component, intended function, material, and environment combination.
February 20, 2025 Enclosure A Page 24 of 165 SLRA Table 3.3.2-15, Radwaste System, Summary of Aging Management Evaluation, page 3.3-254 is revised as shown below:
Table 3.3.2-15 Radwaste System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body Pressure Boundary Stainless Steel Air - Indoor, Uncontrolled (External)
Cracking One-Time Inspection (B.2.1.20)
VII.C1.AP-209a 3.3.1-004 A
Loss of Material One-Time Inspection (B.2.1.20)
VII.C1.AP-221a 3.3.1-006 A
Waste Water (Internal)
Flow Blockage Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24)
VII.E5.AP-278 3.3.1-095 A
Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24)
VII.E5.AP-278 3.3.1-095 A
February 20, 2025 Enclosure A Page 25 of 165 Change # 07 - Reactor Vessel System AMR Update Affected SLRA sections: Table 3.1.2-2 Affected SLRA Page Numbers: 3.1-85 Description Change:
Table 3.1.2-2 inadvertently identified the aging effect as Loss of Material for the component N-5B Isolation Condenser Nozzle Safe End and Welds (U2) with material Stainless Steel and environment Reactor Coolant (Internal) for the AMR line referencing NUREG-2191 item IV.A1.R-68. The intended aging effect for this line is Cracking.
Accordingly, SLRA Table 3.1.2-2 is revised to correct this discrepancy.
February 20, 2025 Enclosure A Page 26 of 165 SLRA Table 3.1.2-2, Summary of Aging Management Evaluation of the Reactor Vessel, page 3.1-85 is revised as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes N-5B Isolation Condenser Nozzle Safe End and Welds (U2)
Pressure Boundary Stainless Steel Reactor Coolant (Internal)
Cracking BWR Stress Corrosion Cracking (B.2.1.5)
IV.A1.R-68 3.1.1-128 A
Loss of Material Cracking Water Chemistry (B.2.1.2)
IV.A1.R-68 3.1.1-128 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20) IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
February 20, 2025 Enclosure A Page 27 of 165 Change # 08 - Reactor Vessel System AMR Update Affected SLRA sections: Table 3.1.2-2 Affected SLRA Page Numbers: 3.1-77 Description Change:
The first four AMR lines on page 3.1-77 inadvertently identified the internal environment for the component type N-18 Head Spray Nozzle as Air - Indoor, Uncontrolled (External). The correct internal environment for these lines is Reactor Cooling (Internal).
Accordingly, SLRA Table 3.1.2-2 is revised as shown below to identify the correct internal environment for these AMR lines.
February 20, 2025 Enclosure A Page 28 of 165 SLRA Table 3.1.2-2, Summary of Aging Management Evaluation of the Reactor Vessel System, page 3.1-77 is revised as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes N-18 Head Spray Nozzle Pressure Boundary Carbon or Low Alloy Steel with Stainless Steel Cladding Air - Indoor, Uncontrolled (External)
Reactor Coolant (Internal)
Cracking Water Chemistry (B.2.1.2)
IV.A1.R-68 3.1.1-128 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20)
IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2) IV.A1.RP-157 3.1.1-085 B
February 20, 2025 Enclosure A Page 29 of 165 Change # 09 - Addition of Halon Storage Tanks and Diesel Fire Water Pump Cooler.
Affected SLRA Sections: Tables 2.3.3-8, 3.3.1, and 3.3.2-8 Affected SLRA Page Numbers: 2.3-75, 2.3-76, 3.3-63, 3.3-64, 3.3-66, 3.3-67, 3.3-187, and 3.3-198.
Description of Change:
Halon storage tanks and diesel fire water pump cooler heat exchangers are added as components subject to aging management review for the Fire Protection System. These components are being added to Table 2.3.3-8 and Table 3.3.2-8. Associated changes are also being made to Table 3.3.1 item numbers 3.3.1-038, 042, 046 and 050.
Accordingly, SLRA Tables 2.3.3-8, 3.3.1, 3.3.2-8 are revised as shown below.
February 20, 2025 Enclosure A Page 30 of 165 SLRA Table 2.3.3-8, Fire Protection System, Components Subject to Aging Management Review, page 2.3-75 is revised as shown below.
Component Type Intended Function Heat Exchanger (Diesel Fire Water Pump Cooler) Shell Side Components Pressure Boundary Heat Exchanger (Diesel Fire Water Pump Cooler) Tube Sheet Pressure Boundary Heat Exchanger (Diesel Fire Water Pump Cooler) Tube Side Components Pressure Boundary Heat Exchanger (Diesel Fire Water Pump Cooler) Tubes Heat Transfer Pressure Boundary SLRA Table 2.3.3-8, Fire Protection System, Components Subject to Aging Management Review, page 2.3-76 is revised as shown below.
Component Type Intended Function Tanks (Halon Storage Tank)
Pressure Boundary
February 20, 2025 Enclosure A Page 31 of 165 SLRA Table 3.3.1, Summary of Aging Management Evaluations for the Auxiliary Systems, page 3.3-63 is revised as shown below.
Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/
Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.3.1-038 Copper alloy, steel heat exchanger components exposed to raw water Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling AMP XI.M20, "Open-Cycle Cooling Water System" No Consistent with NUREG-2191. The Open-Cycle Cooling Water System (B.2.1.11) program will be used to manage flow blockage and loss of material of the carbon steel and copper alloy heat exchanger components exposed to raw water in the Closed Cycle Cooling Water System, Control Room Ventilation System, Diesel Generator and Auxiliaries System, Fire Protection System, Low Pressure Coolant Injection System, Nonsafety-Related Ventilation System, and Safety-Related Ventilation System.
February 20, 2025 Enclosure A Page 32 of 165 SLRA Table 3.3.1, Summary of Aging Management Evaluations for the Auxiliary Systems, page 3.3-64 is revised as shown below.
Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/
Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.3.1-042 Copper alloy, titanium, stainless steel heat exchanger tubes exposed to raw water, raw water (potable),
treated water Cracking due to SCC (titanium only),
reduction of heat transfer due to fouling AMP XI.M20, "Open-Cycle Cooling Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" No Consistent with NUREG-2191. The Open-Cycle Cooling Water System (B.2.1.11) program will be used to manage reduction of heat transfer of the copper alloy and stainless steel heat exchanger tubes exposed to raw water in the Closed Cycle Cooling Water System, Control Room Ventilation System, Diesel Generator and Auxiliaries System, Fire Protection System, Low Pressure Coolant Injection System, and Safety-Related Ventilation System.
February 20, 2025 Enclosure A Page 33 of 165 SLRA Table 3.3.1, Summary of Aging Management Evaluations for the Auxiliary Systems, page 3.3-66 is revised as shown below.
Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/
Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.3.1-046 Steel, copper alloy heat exchanger components, piping, piping components exposed to closed-cycle cooling water Loss of material due to general (steel only), pitting, crevice corrosion, MIC AMP XI.M21A, "Closed Treated Water Systems" No Consistent with NUREG 2191. The Closed Treated Water Systems (B.2.1.12) program will be used to manage loss of material of carbon or low alloy steel with nickel alloy cladding, carbon steel, cast iron, and copper alloy heat exchanger components, piping, piping components, and valve bodies exposed to closed cycle cooling water in the Closed Cycle Cooling Water System, Compressed Air System, Containment Atmospheric Control System, Diesel Generator and Auxiliaries System, Fire Protection System, Fuel Pool Cooling System, Isolation Condenser System, Nonsafety Related Ventilation System, Process Sampling and Radiation Monitoring System, Radwaste System, Reactor Water Cleanup System, Safety Related Ventilation System, Shutdown Cooling System, and Station Blackout Diesel Generator System.
February 20, 2025 Enclosure A Page 34 of 165 SLRA Table 3.3.1, Summary of Aging Management Evaluations for the Auxiliary Systems, page 3.3-67 is revised as shown below.
Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/
Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.3.1-050 Stainless steel, copper alloy, steel heat exchanger tubes exposed to closed-cycle cooling water Reduction of heat transfer due to fouling AMP XI.M21A, "Closed Treated Water Systems" No Consistent with NUREG-2191. The Closed Treated Water Systems (B.2.1.12) program will be used to manage reduction of heat transfer of copper alloy and stainless steel heat exchanger tubes exposed to closed cycle cooling water in the Closed Cycle Cooling Water System, Diesel Generator and Auxiliaries System, Fire Protection System, Isolation Condenser System, Shutdown Cooling System, and Station Blackout Diesel Generator System.
February 20, 2025 Enclosure A Page 35 of 165 Table 3.3.2-8, Fire Protection System, Summary of Aging Management Evaluation, page 3.3-187 is revised as shown below.
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Heat Exchanger (Diesel Fire Water Pump Cooler)
Shell Side Components Pressure Boundary Carbon Steel Air - Indoor, Uncontrolled (External)
Loss of Material External Surfaces Monitoring of Mechanical Components (B.2.1.23)
VII.I.A-77 3.3.1-078 A
Closed Cycle Cooling Water (Internal)
Loss of Material Closed Treated Water Systems (B.2.1.12)
VII.C2.AP-189 3.3.1-046 A
Heat Exchanger (Diesel Fire Water Pump Cooler)
Tube Sheet Pressure Boundary Carbon Steel Closed Cycle Cooling Water (External)
Loss of Material Closed Treated Water Systems (B.2.1.12)
VII.C2.AP-189 3.3.1-046 A
Raw Water (Internal)
Flow Blockage Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-183 3.3.1-038 B
Long-Term Loss of Material One-Time Inspection (B.2.1.20)
VII.H2.A-532 3.3.1-193 A
Loss of Material Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-183 3.3.1-038 B
Heat Exchanger (Diesel Fire Water Pump Cooler)
Tube Side Components Pressure Boundary Carbon Steel Air - Indoor, Uncontrolled (External)
Loss of Material External Surfaces Monitoring of Mechanical Components (B.2.1.23)
VII.I.A-77 3.3.1-078 A
Raw Water (Internal)
Flow Blockage Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-183 3.3.1-038 B
February 20, 2025 Enclosure A Page 36 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Heat Exchanger (Diesel Fire Water Pump Cooler)
Tube Side Components Pressure Boundary Carbon Steel Raw Water (Internal)
Long-Term Loss of Material One-Time Inspection (B.2.1.20)
VII.H2.A-532 3.3.1-193 A
Loss of Material Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-183 3.3.1-038 B
Heat Exchanger (Diesel Fire Water Pump Cooler)
Tubes Heat Transfer Copper Alloy with 15% Zinc or less Closed Cycle Cooling Water (External)
Reduction of Heat Transfer Closed Treated Water Systems (B.2.1.12)
VII.C2.AP-205 3.3.1-050 A
Raw Water (Internal)
Reduction of Heat Transfer Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-187 3.3.1-042 B
Pressure Boundary Copper Alloy with 15% Zinc or less Closed Cycle Cooling Water (External)
Loss of Material Closed Treated Water Systems (B.2.1.12)
VII.C2.AP-199 3.3.1-046 A
Raw Water (Internal)
Flow Blockage Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-179 3.3.1-038 B
Loss of Material Open-Cycle Cooling Water System (B.2.1.11)
VII.C1.AP-179 3.3.1-038 B
February 20, 2025 Enclosure A Page 37 of 165 Table 3.3.2-8, Fire Protection System, Summary of Aging Management Evaluation, page 3.3-198 is revised as shown below.
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Tanks (Halon Storage Tank)
Pressure Boundary Carbon Steel Air - Indoor Uncontrolled (External)
Loss of Material Fire Protection (B.2.1.15)
VII.G.AP-150 3.3.1-058 C
Gas (Internal)
None None VII.J.AP-6 3.3.1-121 C
February 20, 2025 Enclosure A Page 38 of 165 Change # 10 Revision to Enhancements 1 and 5 of Bolting Integrity AMP Affected SLRA sections: A.2.1.10, Table A.5, B.2.1.10 Affected SLRA Page Numbers: A-16, A-17, A-73, A-74, B-65, B-67, and B-68 Description Change:
Enhancement 1 in SLRA Sections A.2.1.10, B.2.1.10, and Table A.5, Item 10 is being revised to specify that use of molybdenum disulfide as a bolting lubricant will be prohibited. The original enhancement erroneously references EPRI TR-104213 which is not specified in GALL-SLR, AMP XI.M18, Element 2. The selection of bolting materials guidance on installation torque and tension is already adequately addressed by station procedures.
Enhancement 5 in SLRA Sections A.2.1.10, B.2.1.10, and Table A.5, Item 10 is being deleted.
Aging management reviews performed during development of the DNPS SLRA did not identify high strength bolting that is greater than 2 inches within the scope of the Bolting Integrity program. Enhancement 5 was conservatively included to address the potential for future installation of high strength bolting; however, it is unnecessary since the existing Constellation process for design changes includes a comprehensive design change impact screening and evaluation.
Accordingly, SLRA section Appendix A Section A.2.1.10 and Table A.5, and Appendix B Section B.2.1.10 are revised as shown below.
February 20, 2025 Enclosure A Page 39 of 165 The second paragraph of SLRA Appendix A Section A.2.1.10, on page A-16 is revised as shown below:
The program includes periodic visual inspections of closure bolting on pressure-retaining components for indication of loss of preload, cracking, and loss of material as evidenced by pressure-retaining joint leakage. In addition, the program manages aging of submerged mechanical bolting for the traveling screens. Closure bolting on pressure-retaining components and mechanical bolting that are submerged or closure bolting on pressure-retaining components located in piping systems that contain air or gas is inspected by alternative means, such as by sample based periodic inspections. The program also includes preventive measures provided in the EPRI guidance documents to preclude or minimize loss of preload and cracking. There is no high strength bolting material with actual yield strength of 150 ksi or greater on pressure-retaining components with bolt diameters greater than 2 inches within the scope of this program.
Therefore, sampling based volumetric examinations of closure bolting to detect indications of cracking is not applicable. Engineering procedures will be enhanced to require volumetric examination in accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, regardless of the code classification of the bolting, should high strength bolting greater than 2 inches in diameter be installed.
SLRA Appendix A Section A.2.1.10, Enhancement 1 on page A-16, is revised as shown below:
- 1. Revise procedure guidance to clarify that the use of lubricants that contain molybdenum disulfide (MoS2) is prohibited at DNPS for bolts in the scope of license renewal. Clarify that the recommended guidance for proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength bolting is a requirement at DNPS in accordance with the guidelines provided in EPRI TR 104213.
SLRA Appendix A Section A.2.1.10, Enhancement 5 on page A-17 is revised as shown below:
- 5. Revise engineering procedures to require volumetric examination in accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, regardless of the code classification of the bolting, should high strength bolting greater than 2 inches in diameter be installed during the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 40 of 165 Enhancement 1 in SLRA Table A.5, Subsequent License Renewal Commitment List, Item Number 10, Bolting Integrity, page A-73, is revised as shown below:
TABLE A.5 - SUBSEQUENT LICENSE RENEWAL COMMITMENT LIST NO.
PROGRAM OR TOPIC COMMITMENT IMPLEMENTATION SCHEDULE SOURCE 10 Bolting Integrity Bolting Integrity is an existing program that will be enhanced to:
- 1.
Revise procedure guidance to clarify that the use of lubricants that contain molybdenum disulfide (MoS2) is prohibited at DNPS for bolts in the scope of license renewal. Clarify that the recommended guidance for proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength bolting is a requirement at DNPS in accordance with the guidelines provided in EPRI TR 104213.
Program will be enhanced no later than six months prior to the subsequent period of extended operation.
Section A.2.1.10 Enhancement 5 in SLRA Table A.5, Subsequent License Renewal Commitment List, Item Number 10, Bolting Integrity, page A-74, is revised as shown below:
TABLE A.5 - SUBSEQUENT LICENSE RENEWAL COMMITMENT LIST NO.
PROGRAM OR TOPIC COMMITMENT IMPLEMENTATION SCHEDULE SOURCE 10 Bolting Integrity (continued)
- 5.
Revise engineering procedures to require volumetric examination in accordance with ASME Code Section XI, Table IWB 2500-1, Examination Category B-G-1, regardless of the code classification of the bolting, should high strength bolting greater than 2 inches in diameter be installed during the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 41 of 165 The fourth paragraph of SLRA Appendix B Section B.2.1.10, page B-65 is revised as shown below:
Aging management reviews have determined that high strength bolting material with actual yield strength of 150 ksi or greater is not used for closure bolting with bolt diameters greater than 2 inches on pressure-retaining components within the scope of this program. Therefore, sample based volumetric inspection of closure bolting to detect indications of cracking is not applicable.
Engineering procedures will be enhanced to require volumetric examination in accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, regardless of the code classification of the bolting, should high strength bolting greater than 2 inches in diameter be installed.
SLRA Appendix B Section B.2.1.10, Enhancement 1 on page B-67, is revised as shown below:
- 1. Revise procedure guidance to clarify that the use of lubricants that contain molybdenum disulfide (MoS2) is prohibited at DNPS for bolts in the scope of license renewal. Clarify that the recommended guidance for proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength bolting is a requirement at DNPS in accordance with the guidelines provided in EPRI TR 104213. Program Elements Affected: Preventive Actions (Element 2)
SLRA Appendix B Section B.2.1.10, Enhancement 5 on Page B-68, is revised as shown below:
- 5. Revise engineering procedures to require volumetric examination in accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, regardless of the code classification of the bolting, should high strength bolting greater than 2 inches in diameter be installed during the subsequent period of extended operation. Program Element Affected: Detection of Aging Effects (Element 4).
February 20, 2025 Enclosure A Page 42 of 165 Change # 10 Addition of AMR Line Item for Traveling Screen Bolting Affected SLRA sections: Table 2.3.3-12, Table 3.3.2-12 Affected SLRA Page Numbers: 2.3-90 and 3.3-223 Description Change:
SLRA Tables 2.3.3-12 and 3.3.2-12 are being revised to explicitly identify the traveling screen bolting as components subject to aging management review.
Accordingly, SLRA Table 2.3.3-12 and Table 3.3.2-12 are revised as shown below.
February 20, 2025 Enclosure A Page 43 of 165 SLRA Table 2.3.3-12, Open Cycle Cooling Water System Components Subject to Aging Management Reviews, page 2.3-90 is revised as shown below:
Component Type Intended Function Bolting (Traveling Screens)
Structural Support
February 20, 2025 Enclosure A Page 44 of 165 SLRA Table 3.3.2-12, Open Cycle Cooling Water System, page 3.3-223 is revised as shown below:
Table 3.3.2-12 Open Cycle Cooling Water System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Bolting (Traveling Screens)
Structural Support Carbon and Low Alloy Steel Bolting Raw Water (External)
Loss of Material Bolting Integrity (B.2.1.10)
VII.I.A-423 3.3.1-142 D
Loss of Preload Bolting Integrity (B.2.1.10)
VII.I.AP-124 3.3.1-015 D
February 20, 2025 Enclosure A Page 45 of 165 Change # 10 Changes to AMR Lines 3.1.1-062, 3.4.1-007, and SLRA Table 3.1.2-2 Affected SLRA sections: SLRA Table 3.1.1, Table 3.4.1, and Table 3.1.2-2 Affected SLRA Page Numbers: 3.1-43, 3.1-74, and 3.4-26 Description Change:
AMR item 3.4.1-007 refers to high-strength steel closure bolting, and since there are no existing high strength bolting within the steam and power conversion system grouping, this AMR item is not applicable.
Additionally, an error was identified with AMR item 3.1.1-062 and component type Bolting (Head Spray, Head Vent, Spare Nozzle) in Table 3.1.2-2, which references AMR item 3.1.1-062. This component type incorrectly lists the material type as High Strength Low Alloy Steel Bolting with Yield Strength of 150 ksi or greater, and is managed by the Bolting Integrity Program. The correct material for this component is Carbon and Low Alloy Steel Bolting, therefore Table 3.1.2-2 is revised to correct the material type and remove Cracking as an aging effect managed by this program since cracking is not applicable for carbon and low alloy steel bolting.
AMR item 3.1.1-062 is therefore revised as not applicable since there is no high strength bolting used within the Reactor Vessel and managed by the Bolting Integrity program.
Additional changes are being made to Table 3.1.2-2 under a different change number but said changes have no impact on the changes applied within.
Accordingly, SLRA Table 3.1.1, Table 3.4.1, and Table 3.1.2-2 are revised.
February 20, 2025 Enclosure A Page 46 of 165 SLRA Table 3.1.1, Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System, page 3.1-43, is revised as shown below:
Table 3.1.1 Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Number Component Aging Effect/Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.1.1-062 High-strength steel, stainless steel closure bolting; stainless steel control rod drive head penetration flange bolting exposed to air-indoor uncontrolled Cracking due to SCC AMP XI.M18, "Bolting Integrity" No Not Applicable There are no High-strength steel, stainless steel closure bolting; stainless steel control rod drive head penetration flange bolting exposed to air-indoor uncontrolled in the Reactor Vessel, Internals, and Reactor Coolant System.
Consistent with NUREG-2191 with exceptions. The Bolting Integrity (B.2.1.10) program will be used to manage cracking of high strength low alloy steel bolting exposed to air-indoor in the Reactor Vessel.
An exception applies to the NUREG-2191 recommendations for Bolting Integrity (B.2.1.10) program implementation.
February 20, 2025 Enclosure A Page 47 of 165 SLRA Table 3.1.2-2, Reactor Vessel Summary of Aging Management Evaluation, page 3.1-74 is revised, additional changes are being made under a different change number and have no impact on the changes, as shown below:
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Bolting (Head Spray, Head Vent, Spare Nozzle)
Mechanical Closure Carbon and Low Alloy Steel Bolting High Strength Low Alloy Steel Bolting with Yield Strength of 150 ksi or Greater Air - Indoor, Uncontrolled (External)
Cracking Bolting Integrity (B.2.1.10)
IV.C1.R-11 3.1.1-062 B
Cumulative Fatigue Damage TLAA IV.C1.RP-44 3.1.1-011 A, 2 Loss of Material Bolting Integrity (B.2.1.10)
IV.C1.RP-42 3.1.1-063 B
Loss of Preload Bolting Integrity (B.2.1.10)
IV.C1.RP-43 3.1.1-067 B
February 20, 2025 Enclosure A Page 48 of 165 SLRA Table 3.4.1, Summary of Aging Management Evaluations for the Steam and Power Conversion, page 3.4-26, is revised as shown below:
Table 3.4.1 Summary of Aging Management Evaluations for the Steam and Power Conversion Item Number Component Aging Effect/Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.4.1-007 High-strength steel closure bolting exposed to air, soil, underground Cracking due to SCC; cyclic loading AMP XI.M18, "Bolting Integrity" No Not Applicable.
There are no High-strength steel closure bolting exposed to air, soil, or underground in the Steam and Power Conversion System.
Consistent with NUREG-2191 with exceptions. The Bolting Integrity (B.2.1.10) program will be used to manage cracking of the carbon and low alloy steel bolting exposed to air - indoor uncontrolled in the Reactor Vessel.
Exceptions apply to the NUREG-2191 recommendations for the Bolting Integrity (B.2.1.10) program implementation.
February 20, 2025 Enclosure A Page 49 of 165 Change # 11 - Clarification of the Scope of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems AMP Affected SLRA sections: 2.3.3.5, B.2.1.13 Affected SLRA Page Numbers: 2.3-60, 2.3-61, B-82 Description Change:
Editorial changes are being made to clarify the scope of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems aging management program as described in SLRA Section B.2.1.13. A formatting adjustment is also being made to the list of cranes in SLRA Section 2.3.3.5.
Accordingly, SLRA Section 2.3.3.5 and B.2.1.13 are revised, as shown below.
February 20, 2025 Enclosure A Page 50 of 165 SLRA Section 2.3.3.5, Cranes, Hoists, And Refueling Equipment System, pages 2.3-60 and 2.3-61 is revised as shown below:
Reactor Building Reactor Building Reactor Building Overhead Crane Unit 2 Refuel Platform Hoists Unit 3 Refuel Platform Hoists Unit 2 Reactor Building (613 Elevation) Hatch Jib Crane Unit 3 Reactor Building (613 Elevation) Hatch Jib Crane Unit 2 Reactor Building (545 Elevation) Hatch Jib Crane Reactor Building (613 Elevation) New Fuel Storage Vault Jib Crane Reactor Service Platform Jib Crane Turbine Building Turbine Building Unit 2 Turbine Building Overhead Crane Unit 3 Turbine Building Overhead Crane Unit 2 Diesel Generator Room Monorails (2)
Unit 3 Diesel Generator Room Monorails (2)
Diesel Generator Room Monorail Crane Primary Containment Primary Containment Unit 2 Drywell Equipment Hatch Monorails Unit 2 Drywell CRD Pit Jib Monorails Unit 2 Drywell Ground Floor Continuous Monorails Unit 2 Drywell 2nd Floor Jib Monorails Unit 3 Drywell Equipment Hatch Monorails Unit 3 Drywell CRD Pit Jib Monorails Unit 3 Drywell Ground Floor Continuous Monorails Unit 3 Drywell 2nd Floor Jibs Monorails Miscellaneous Buildings Miscellaneous Buildings 2/3 Diesel Generator Room Monorails (3)
Unit 2 HPCI Room Trolley Chain Hoist
February 20, 2025 Enclosure A Page 51 of 165 Unit 3 HPCI Room Trolley Chain Hoist 2/3 Crib House Service Water Pump Electric Hoist (a single monorail that is used to move and position the stop logs for set up of the ultimate heat sink)
Circulating water pump monorails and trolleys (4) (these nonsafety-related monorails pass over the safety-related diesel generator cooling water pumps The second paragraph of SLRA Appendix B.2.1.13, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, page B-82 is revised as shown below:
The scope of cranes, hoists, trollies, monorails, and refueling equipment within the scope of license renewal is based on those that must comply with NUREG-0612, Control of Heavy Loads at Nuclear Power Plants. Overhead lifting equipment that operates over safety-related equipment is included within the scope of license renewal. Approximately There are 33 cranes and hoists managed by the program, with a complete list provided in SLRA Section 2.3.3.5, including the reactor building overhead cranes, turbine building overhead cranes, numerous equipment handling cranes, hoists, trollies, and monorails are managed by the program. Also, within the scope of the program are handling systems that lift light loads including equipment, tools, and fuel, over fuel and safety-related equipment within the spent fuel pool and reactor cavity.
February 20, 2025 Enclosure A Page 52 of 165 Change # 12 - Exception for Use of BWRVIP-48 Revision 2 Affected SLRA sections: Table 3.1.1, Table 3.1.2-2, A.2.1.4, B.2.1.4 Affected SLRA Page Numbers: 3.1-47, 3.1-90, A-12, B-33, B-34 Description Change:
SLRA Section B.2.1.4 is being revised to add an exception and technical justification for the use of BWRVIP-48 Revision 2 in lieu of BWRVIP-48-A as specified in NUREG-2191. Associated changes to Table 3.1.1 and 3.1.2-2 are also being made.
Accordingly, SLRA Table 3.1.1, Table 3.1.2-2, Section A.2.1.4 and Section B.2.1.4 are revised as shown below.
February 20, 2025 Enclosure A Page 53 of 165 SLRA Table 3.1.1, Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System, page 3.1-47 is revised as shown below:
Table 3.1.1 Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Number Component Aging Effect/Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.1.1-094 Stainless steel and nickel alloy vessel shell attachment welds exposed to reactor coolant Cracking due to SCC, IGSCC, cyclic loading AMP XI.M4, "BWR Vessel ID Attachment Welds,"
and AMP XI.M2, "Water Chemistry" (SCC, IGSCC mechanisms only)
No Consistent with NUREG-2191 with exceptions. The BWR Vessel ID Attachment Welds (B.2.1.4) and Water Chemistry (B.2.1.2) program will be used to manage cracking of the stainless steel vessel shell attachment welds exposed to reactor coolant and neutron flux in the Reactor Vessel.
An exception applies to the NUREG-2191 recommendations for Water Chemistry (B.2.1.2) and BWR Vessel ID Attachment Welds (B.2.1.4) program implementation.
February 20, 2025 Enclosure A Page 54 of 165 SLRA Table 3.1.2-2, Reactor Vessel, page 3.1-90 is revised as shown below:
Table 3.1.2-2 Reactor Vessel (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Reactor Vessel Shell ID Attachment Welds Structural Support to maintain core configuration and flow distribution Stainless Steel Reactor Coolant Cracking BWR Vessel ID Attachment Welds (B.2.1.4)
IV.A1.R-64 3.1.1-094 A B Water Chemistry (B.2.1.2)
IV.A1.R-64 3.1.1-094 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20)
IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
Reactor Coolant and Neutron Flux Cracking BWR Vessel ID Attachment Welds (B.2.1.4)
IV.A1.R-64 3.1.1-094 A B Water Chemistry (B.2.1.2)
IV.A1.R-64 3.1.1-094 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20)
IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
February 20, 2025 Enclosure A Page 55 of 165 SLRA Section A.2.1.4, BWR Vessel ID Attachment Welds, page A-12 is revised as shown below:
A.2.1.4 BWR Vessel ID Attachment Welds The BWR Vessel ID Attachment Welds aging management program is an existing condition monitoring program that manages cracking of the reactor vessel interior attachment welds. This program relies on visual examinations to detect cracking.
The examination scope, frequencies, and methods are in accordance with ASME Code,Section XI, Table IWB 2500-1, Examination Category B-N-2 and BWRVIP-48 Revision 2. Additional inspections and evaluation of the core spray piping brackets are performed in accordance with BWRVIP-18 Revision 2-A. Additional inspections and evaluation of the jet pump riser brace are performed in accordance with BWRVIP-41 Revision 4-A. Additional inspections of the steam dryer support brackets are performed in accordance with vendor guidance. The scope of the examinations is expanded when flaws are detected.
Any indications are evaluated in accordance with ASME Code,Section XI, or the guidance in BWRVIP-48 Revision 2. Crack growth evaluations follow the guidance in BWRVIP-14-A, BWRVIP-59-A, or BWRVIP-60-A, as appropriate. The acceptance criteria are in BWRVIP-48 Revision 2 and ASME Code,Section XI, Subarticle IWB-3520. Repair and replacement activities are conducted in accordance with BWRVIP-52-A.
February 20, 2025 Enclosure A Page 56 of 165 The first paragraph of SLRA Section B.2.1.4, BWR Vessel ID Attachment Welds, page B-33 is revised as shown below:
B.2.1.4 BWR Vessel ID Attachment Welds Program Description The BWR Vessel ID Attachment Welds aging management program is an existing condition monitoring program that manages cracking of reactor vessel internal attachment welds due to stress corrosion cracking (SCC), intergranular stress corrosion cracking (IGSCC), or cyclic loading in a reactor coolant environment. The program monitors for cracks induced by SCC, IGSCC, and cyclic loading on the reactor vessel interior attachment welds by detection and sizing of cracks using visual techniques in accordance with the guidelines of BWRVIP-48 Revision 2. Inspections are performed in accordance with the guidance in BWRVIP-48 Revision 2 and the requirements in ASME Code,Section XI, Table IWB-2500-1, Examination Category B-N-2 to interrogate the components for discontinuities that may indicate the presence of cracking. The potential for cracking due to SCC and IGSCC is mitigated by maintaining high water purity as described in the Water Chemistry (B.2.1.2) program.
The scope of the program includes the attachment welds for the steam dryer wall support lugs, guide rod brackets, feedwater sparger brackets, jet pump riser braces, core spray piping brackets, and surveillance sample holder brackets. Additional inspections and evaluation of the core spray piping brackets are performed in accordance with BWRVIP-18 Revision 2-A. Additional inspections and evaluation of the jet pump riser brace are performed in accordance with BWRVIP-41 Revision 4-A. Additional inspections of the steam dryer support brackets are performed in accordance with vendor guidance.
February 20, 2025 Enclosure A Page 57 of 165 The Exceptions to NUREG-2191 Subsection of SLRA Section B.2.1.4, BWR Vessel ID Attachment Welds, page B-34 is revised as shown below:
Exceptions to NUREG 2191 None.
- 1. The BWR Vessel ID Attachment Welds aging management program is based on the inspection, evaluation, and repair guidelines contained in BWRVIP-48 Revision 2, rather than BWRVIP-48-A as specified in NUREG-2191. Program Elements Affected: Scope of Program (Element 1), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5)
Justification for Exception:
The DNPS BWR Vessel ID Attachment Welds aging management program is based on the inspection, evaluation, and repair guidelines contained in BWRVIP-48 Revision 2, rather than BWRVIP-48-A as specified in NUREG-2191.
Per BWRVIP-94, Revision 4, Program Implementation Guide, when BWRVIP guidelines are approved by the Executive Committee and are initially distributed, or subsequently revised, each utility shall modify their vessel and internals program documentation to reflect the new requirements and shall implement the guidelines within two refueling outages, unless a different schedule is identified by the BWRVIP at the time of document distribution. If new guidelines approved by the Executive Committee includes revisions to NRC approved BWRVIP guidelines (e.g., BWRVIP-48 Revision 2 revised the guidelines contained in BWRVIP-48-A), and the revised guidelines are less conservative than those approved by the NRC, these less conservative guidelines shall be implemented only after the NRC reviews and approves the changes. NRC approved generally means the document was submitted to the NRC for review and approval and a final Safety Evaluation Report (SER) has been issued and is incorporated into publication of a -A document or equivalent. Alternatively, if the revised guidelines are screened out from submittal to the NRC in accordance with NEI 03-08, Guidelines for the Management of Materials Issues, Appendix C, utilities may implement the revised guidelines subject to any licensing restrictions at the site (e.g., commitments to use previous revisions under license renewal or with ASME Code relief requests). Revision 2 of BWRVIP-48 received a screening evaluation performed in accordance with Appendix C of NEI 03-08, Rev. 4, Document Screening. The evaluation considered all of the elements typically included within inspection optimization evaluations (i.e., field performance, NDE capability, residual stress state, and flaw tolerance), included a level of rigor consistent with prior inspection optimization evaluations and applied risk principles consistent with precedent inspection optimization evaluations used to provide technical bases for modifications to inspection program requirements. It was noted that the general methodology was consistent with the approach taken to optimize BWRVIP requirements for other reactor internals components found not to have significant SCC susceptibility. The screening evaluation concluded that BWRVIP-48 Revision 2 could be generically released for implementation by the
February 20, 2025 Enclosure A Page 58 of 165 United States BWRVIP members without prior NRC review and approval. The Qualitative Risk Assessment performed per Appendix C of NEI 03-08, Revision 4, is documented in Section G.4 of BWRVIP-48 Revision 2.
The inspection requirements for reactor vessel ID attachment welds contained in BWRVIP-48-A were originally based on the potential susceptibility of attachment welds to SCC given the existing state of knowledge. At the time that BWRVIP-48 was initially issued (1998), SCC of BWR internals was still largely in a discovery phase, with the frequency and ultimate extent of cracking largely unknown. As a result, the inspection program specified by BWRVIP-48 was purposely conservative. Over twenty years have elapsed since the initial issue of BWRVIP-48, and it was therefore reasonable for the BWRVIP to revisit the inspection requirements in BWRVIP-48-A based on the current state of knowledge regarding performance in the field and understanding of the progression of SCC in BWRs, resulting in the issuance of BWRVIP-48 Revision 2.
The changes in inspection scope and frequency between BWRVIP-48 and BWRVIP-48 Revision 2 are shown in the table below:
Component ASME Code Section XI IWB Inspection Requirement BWRVIP-48-A Interval BWRVIP-48 Rev 2 Interval BWRVIP-41 Rev 4-A Interval1 BWRVIP-18 Rev 2-A Interval2 Core Spray Piping Bracket Attachment B-N-2, VT-3
@ 100%
every 10 years EVT-1 @ 100%
every four outages Table G-10, Row 8, Column 5 N/A EVT-1 @
100%
every 10 years Steam Dryer Support Bracket Attachment B-N-2, VT-3
@ 100%
every 10 years EVT-1 @ 100%
every 10 years Table G-10, Row 5, Column 5 N/A N/A Jet Pump Riser Brace Attachment B-N-2, VT-1
@ 100%
every 10 years EVT-1 @ 25%
every 6 years (no additional for Unit 3 secondary brace attachment)
Table G-10, Row 7, Column 5 EVT-1 @
25% every 12 years (no additional for Unit 3 secondary brace attachment)
N/A 1 BWRVIP-41 Rev 4-A provides inspection and evaluation guidance for the jet pumps and further address the jet pump riser brace attachment welds.
2 BWRVIP-18 Rev 2-A provides inspection and evaluation guidance for the core spray piping within the reactor vessel and further address the core spray piping bracket attachment welds.
February 20, 2025 Enclosure A Page 59 of 165 The components that are currently being inspected at a frequency less than that specified in the ASME Code or BWRVIP-48-A are listed in the table above. When periodic inspections specify that only a fraction of the population is required during the specified interval, Dresden selects attachment welds based on accumulated service time since the weld was last inspected. Weld selection is rotated through the entire population before any specific weld is selected a second time for periodic inspections.
The examination guidance for core spray piping bracket attachment welds is provided in BWRVIP-48 Revision 2, Table G-10. This represents a change from BWRVIP-48-A which requires EVT-1 examination of 100 percent of the core spray piping bracket attachment welds every eight years. The technical justification for changing the inspection frequency is detailed in BWRVIP-48 Revision 2, Appendix G, Section G.4, Qualitative Risk Assessment for BWRVIP-48, Rev. 2, and Section G.5, Summary of Inspection Program Revisions. The technical justification supersedes the evaluations from prior versions of BWRVIP-48.
ASME Code,Section XI requires VT-3 examination of 100 percent of the core spray piping bracket attachment welds every ten years. Dresden also implements the NRC-approved guidance in BWRVIP-18, Revision 2-A, which requires EVT-1 examination of 100 percent of core spray piping bracket attachment welds (bracket side) every ten years.
The examination guidance for the steam dryer support bracket attachments is provided in BWRVIP-48 Revision 2, Table G-10. This represents a change from BWRVIP-48-A which requires EVT-1 examination of 100 percent of the steam dryer support bracket attachment welds every ten years. The technical justification for changing the inspection frequency is detailed in BWRVIP-48 Revision 2, Appendix G, Section G.4, Qualitative Risk Assessment for BWRVIP-48, Rev. 2, and Section G.5, Summary of Inspection Program Revisions. The technical justification supersedes the evaluations from prior versions of BWRVIP-48. ASME Code,Section XI requires VT-3 examination of 100 percent of the steam dryer support bracket attachment welds every ten years. Additionally, per vendor guidance, all four of the vessel steam dryer support lugs are VT-1 examined each refueling outage, unless engineering evaluations are performed to extend the frequency. This examination includes the entire lug attachment weld to the vessel, and at least 1/2-inch of adjacent lug weld heat affected zone material. In addition, the top surface of the lug at the inboard end where the dryer weight is supported (bearing area) and at least one inch of the vertical lug surface adjacent to the dryer bearing area is examined.
The examination guidance for the jet pump riser brace attachments is provided in BWRVIP-48 Revision 2, Table G-10. This represents a change from BWRVIP-48-A which requires EVT-1 examination of 25 percent of the jet pump riser brace attachment welds every six years. The technical justification for changing the inspection frequency is detailed in BWRVIP-48 Revision 2, Appendix G, Section G.4, Qualitative Risk Assessment for BWRVIP-48, Rev. 2, and Section G.5, Summary of Inspection Program Revisions. The technical justification supersedes the evaluations from prior versions of BWRVIP-48.
ASME Code,Section XI requires VT-1 examination of 100 percent of the jet pump riser brace attachment welds every ten years. Dresden also implements the
February 20, 2025 Enclosure A Page 60 of 165 NRC-approved guidance in BWRVIP-41, Revision 4-A, which requires EVT-1 examination of 25 percent of jet pump riser brace attachment welds (brace side) every twelve years. Precedence exists for expanded intervals via a sampling inspection process, as a similar justification was used in BWRVIP-41 Revision 4-A and BWRVIP-48-A. Both documents are NRC approved and received a safety evaluation for the examination of the jet pump riser brace attachment welds at intervals greater than ten years.
The periodic inspection requirements described in BWRVIP-48 Revision 2, Appendix G, Tables G-10 and G-11, primarily address the potential for SCC and are applicable to all operating conditions without any time-dependent limitations. In addition to the inspections required per the above table, BWRVIP-48 Revision 2 details one-time inspections and scope expansion requirements. The purpose and justification of these inspections and scope expansions are detailed in BWRVIP-48 Revision 2, Appendix G, Section G.5.2, One-Time Inspection Requirements, and Section G.5.3, Scope Expansion Requirements.
DNPS vessel ID attachment welds are composed of stainless steel. Materials having a duplex cast stainless steel microstructure have shown significant resistance to SCC in the BWR environment. This has generally been attributed to the presence of ferrite intermixed with the predominately austenitic structure.
It has been observed that the presence of as little as 3 percent to 4 percent ferrite is sufficient to substantially increase SCC resistance. Most, if not all, stainless steel weld metal used to fabricate the bracket welds may be expected to contain at least that much ferrite because ferrite is also essential to prevent hot cracking of stainless steel weld deposits. This was recognized by the NRC in Regulatory Guide 1.31 and ASME Section III which both require a minimum of 5 percent (or 5 FN) ferrite to prevent hot cracking. The presence of at least some ferrite in stainless steel weld deposits as an SCC deterrent is supported by the fact that no spontaneous SCC initiation has been observed in stainless steel welds in BWR piping or internals. The only exceptions are rare instances of cracking in weld surfaces heavily cold worked by machining. Even in these rare instances, crack initiation occurred in the adjacent stainless steel heat-affected zone (HAZ) material. Heavy grinding of bracket attachment welds would only be plausible in the case of defects that required extensive repairs and associated cracking would have most likely been manifested earlier in plant life.
Consequently, there is no evidence that that the stainless steel weld metal used to fabricate the bracket welds should be considered susceptible to SCC. This position is consistent with the BWRVIP position taken for other internals components in NRC approved BWRVIP guidelines. A directly applicable example of this case is BWRVIP-18, Revision 2-A, the NRC-approved version of the core spray internals I&E guideline, in which the examination requirements specifically state that the inspection of locations where stainless steel welds are used to join fully austenitic stainless steel base materials are applicable only to the HAZs associated with the stainless steel weld base materials (and not the welds themselves).
Furthermore, attachment welds are applied to either a weld buildup pad on the vessel wall, or in some cases directly to the vessel cladding (where the cladding
February 20, 2025 Enclosure A Page 61 of 165 deposition process was qualified to be a structural weld). For the stainless steel attachment welds, the buildup pad or cladding applied to the vessel wall is also stainless steel. This results in the HAZ on the vessel side of the attachment weld being in a stainless steel weld deposit. The discussion above on SCC susceptibility of the stainless steel attachment welds remains generally applicable to these stainless steel HAZs even though the weld buildup pads were subjected to post weld heat treatment. Additionally, defects identified in cladding have been generally attributed to fabrication issues and a limited number of instances have reported as SCC; however, these flaws are self-limiting due to the lack of driving force and have not propagated into the vessel or attachment weld. Further discussion of material conditions and the resulting changes to periodic inspection requirements can be found in BWRVIP-48 Revision 2, Appendix G, Table G-11.
Examination history at Dresden Unit 2 and 3 of vessel ID attachment welds listed in the above table was reviewed to assess whether site-specific data was reflective of the data identified in the conclusions drawn from the qualitative risk assessment in BWRVIP-48, Revision 2, Appendix G. Dresden Unit 2 has performed 195 examinations and Dresden Unit 3 has performed 152 exams between 1995 and 2024. Of these examinations, 99 were EVT-1 examinations of the core spray piping bracket attachment welds, 24 were EVT-1 examinations of the steam dryer support bracket attachment welds, and 170 were EVT-1 examinations of the jet pump riser brace attachment. A complete baseline examination and at least one full reinspection of all components has been performed on the core spray piping bracket attachment welds, jet pump riser brace attachment welds, and steam dryer support bracket attachment welds for both units. For Dresden Unit 2, four full EVT-1 reinspections have been performed on the core spray piping bracket attachment welds, five full EVT-1 reinspections have been performed on the steam dryer bracket attachment welds, and one full EVT-1 reinspection has been performed on the jet pump riser brace attachment welds. For Dresden Unit 3, five full EVT-1 reinspections have been performed on the core spray piping bracket attachment welds, three full VT-1 reinspections have been performed on the steam dryer bracket attachment welds, and one full EVT-1 reinspection has been performed on the jet pump riser brace attachment welds. Dresden Unit 3 does not have exposed FSSS in the steam dryer bracket attachment welds, and therefore VT-1 inspections are performed.
The weld inspection populations are rotated in such a manner that the entire population of the welds are examined, with the welds that were examined the furthest in the past being selected for subsequent inspection campaigns.
Of the examinations performed, minor surface wear, gouges, and scratches on the steam dryer support bracket lug were discovered. None of these indications are associated with any reported degradation of the attachment welds to the vessel. The indications identified are typical surface-to-surface contact wear, which is a common industry occurrence for the steam dryer support bracket lug.
No indications representative of vessel attachment weld degradation have been identified as of November 2024. This review confirms that the data collected by the EPRI is comparable to the specific results at Dresden and supports the
February 20, 2025 Enclosure A Page 62 of 165 technical justification in the qualitative risk assessment of BWRVIP-48, Revision 2, Appendix G.
The qualitative risk assessment in BWRVIP-48 Revision 2, Appendix G, Section G.4 determined that there is not a significant change in risk associated with the proposed changes to inspection requirements. The potential for SCC occurrence in vessel ID attachment welds is now known to be far lower than what was assumed based on the limited set of inspection data available at the time BWRVIP-48 was initially developed. In addition, the initial requirements did not consider key factors such as the resistance of stainless steel weld metal to SCC. The initial requirements also did not provide guidance for managing the potential for fatigue cracking. The addition of one-time inspection requirements and the expansion of scope expansion requirements are key improvements to the program that support the proposed optimization of periodic inspection requirements. Therefore, it is concluded that there is not a substantial change in risk associated with the new recommended requirements in BWRVIP-48 Revision 2.
It can therefore be concluded that the review of the qualitative risk assessment performed in BWRVIP-48, Revision 2 and the site specific data acquired at DNPS demonstrate that the analysis is applicable to Dresden Units 2 and 3. Usage of BWRVIP-48 Revision 2 in lieu of BWRVIP-48-A provides a reasonable assurance of safety and does not challenge the quality of the BWR Vessel ID Attachment Welds program.
February 20, 2025 Enclosure A Page 63 of 165 Change # 13 - Fatigue Monitoring Program Enhancement Affected SLRA Sections: Appendix A, Section A.3.1.1, Appendix B, Section B.3.1.1, and Table A.5 Affected SLRA Page Numbers: A-47, B-240, A-95 Description Change:
SLRA Sections A.3.1.1, B.3.1.1, and Table A.5 are being updated to add an enhancement that reflects that the SI:FatigueProTM software at DNPS is being upgraded to version 4, which uses all six components of the stress tensor addressing the concerns stated in RIS-2008-30, consistent with NRC expectations for Subsequent License Renewal.
Accordingly, SLRA sections A.3.1.1, B.3.1.1, and Table A.5 are revised.
February 20, 2025 Enclosure A Page 64 of 165 SLRA Section A.3.1.1, Fatigue Monitoring, page A-47 is revised as shown below:
The Fatigue Monitoring aging management program will be enhanced to:
- 1. The SI:FatigueProTM software will be updated to monitor for environmentally assisted fatigue at additional plant-specific component locations that may be more limiting than the sample set identified in NUREG/CR-6260. The CUFen values for the additional plant-specific component locations monitored for environmentally assisted fatigue will be calculated in accordance with the methodology in NUREG/CR-6909, Revision 1.
- 2. Procedural direction will be provided to require periodic validation of chemistry parameters used to determine Fen factors used in SI:FatigueProTM.
- 3. Applicable fatigue analyses and monitored component locations will be updated based on operating experience, plant modifications, inspection findings, changes to transient definitions, and unanticipated newly discovered fatigue loading events.
- 4. The SI:FatigueProTM software will be updated to include all six components of the stress tensor as input into stress-based fatigue transfer functions.
The program will be enhanced no later than six months prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 65 of 165 SLRA Section B.3.1.1, Fatigue Monitoring, pages B-239 and B-240 are revised as shown below:
Enhancements In the elements identified below, the Fatigue Monitoring program will be enhanced to:
- 1. The SI:FatigueProTM software will be updated to monitor for environmentally assisted fatigue at additional plant-specific component locations that may be more limiting than the sample set identified in NUREG/CR-6260. The CUFen values for the additional plant-specific component locations monitored for environmentally assisted fatigue will be calculated in accordance with the methodology in NUREG/CR-6909, Revision 1.
Program Element Affected: Scope of Program (Element 1)
- 2. Procedural direction will be provided to require periodic validation of chemistry parameters used to determine Fen factors used in SI:FatigueProTM. Program Elements Affected: Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5)
- 3. Applicable fatigue analyses and monitored component locations will be updated based on operating experience, plant modifications, inspection findings, changes to transient definitions, and unanticipated newly discovered fatigue loading events. Program Elements Affected: Scope of Program (Element 1), Monitoring and Trending (Element 5)
- 4. The SI:FatigueProTM software will be updated to include all six components of the stress tensor as input into stress-based fatigue transfer functions. Program Elements Affected: Scope of Program (Element 1)
The program will be enhanced no later than six months prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 66 of 165 SLRA Table A.5, Subsequent License Renewal Commitment List, Page A-95 is revised as shown below:
TABLE A.5 - SUBSEQUENT LICENSE RENEWAL COMMITMENT LIST NO.
PROGRAM OR TOPIC COMMITMENT IMPLEMENTATION SCHEDULE SOURCE 43 Fatigue Monitoring Fatigue Monitoring is an existing program that will be enhanced to:
- 1.
The SI:FatigueProTM software will be updated to monitor for environmentally assisted fatigue at additional plant-specific component locations that may be more limiting than the sample set identified in NUREG/CR-6260. The CUFen values for the additional plant-specific component locations monitored for environmentally assisted fatigue will be calculated in accordance with the methodology in NUREG/CR-6909, Revision 1.
- 2.
Procedural direction will be provided to require periodic validation of chemistry parameters used to determine Fen factors used in SI:FatigueProTM.
- 3.
Applicable fatigue analyses and monitored component locations will be updated based on operating experience, plant modifications, inspection findings, changes to transient definitions, and unanticipated newly discovered fatigue loading events.
- 4. The SI:FatigueProTM software will be updated to include all six components of the stress tensor as input into stress-based fatigue transfer functions.
Program will be enhanced no later than six months prior to the subsequent period of extended operation.
Section A.3.1.1
February 20, 2025 Enclosure A Page 67 of 165 Change # 15 - Correction to HELB System List Affected SLRA sections: 4.3.5 and A.4.3.5 Affected SLRA Page Numbers: 4.3-21 and A-60 Description Change:
SLRA Sections 4.3.5 and A.4.3.5 inadvertently omitted the Control Rod Drive, Core Spray, Low Pressure Coolant Injection, Recirculation, and Shutdown Cooling Systems as systems analyzed for HELB as identified in UFSAR Sections 3.6.1 and 3.6.2.
Accordingly, SLRA Sections 4.3.5 and A.4.3.5 are revised as shown below.
February 20, 2025 Enclosure A Page 68 of 165 SLRA Section 4.3.5, ASME Section III, Class 2 & 3, and ANSI B31.1 Allowable Stress Analyses And Associated HELB Analyses, page 4.3-21 is revised as shown below:
exceeded 0.8 (Sh + SA) or expansion stresses exceeded 0.8 SA. Sh is the stress calculated by the rules of NC-3600 and ND-3600 of the ASME Section III code, and SA is the allowable stress range for expansion calculated by the rules of NC-3600 of the ASME Section III or ANSI B31.1 code. High energy piping that was analyzed for pipe breaks included piping in the following systems: Control Rod Drive, Core Spray, Main Steam, Feedwater, Low Pressure Coolant Injection, High Pressure Coolant Injection, Recirculation, Reactor Water Cleanup, Shutdown Cooling System, and Isolation Condenser.
SLRA Section A.4.3.5, ASME Section III, Class 2 & 3, and ANSI B31.1 Allowable Stress Analysis and Associated High Energy Line Break (HELB) Analyses, page A-60 is revised as shown below:
In addition, some Non ASME Class 1 high energy piping locations were selected for HELB analyses. High energy piping that was analyzed for pipe breaks included piping in the following systems: Control Rod Drive, Core Spray, Main Steam, Feedwater, Low Pressure Coolant Injection, High Pressure Coolant Injection, Recirculation, Reactor Water Cleanup, Shutdown Cooling System, and Isolation Condenser.
February 20, 2025 Enclosure A Page 69 of 165 Change # 17-Clarifications of BWRVIP Revisions and Usage Affected SLRA Sections: A.2.1.7, B.2.1.7, Appendix C Affected SLRA Page Numbers: A-13, B-45, B-46, B-48, and C-12 Description Change:
SLRA Section B.2.1.7 is being revised to make the following changes:
Explicitly call out the deviations between the BWRVIP report revisions recommended in NUREG-2191 and those being implemented at Dresden Units 2 and 3.
Provide a discussion on the conservatism of BWRVIP-180 Revision 1.
Correct a typographic error where BWRVIP-02-A Revision 2 was incorrectly referred to as BWRVIP-02-A.
Explicitly call out the use of BWRVIP-138 Revision 1-A as part of the BWR Vessel Internals program.
SLRA Appendix C is being revised to correct a typographical error where BWRVIP-100 Revision 1-A was incorrectly referred to as BWRVIP-100-A.
SLRA Section A.2.1.7 and Section B.2.1.7 are being revised to include actions taken when new and revised BWRVIP guidance are implemented at Dresden, including when the revised guidelines are less conservative.
Accordingly, SLRA sections A.2.1.7, B.2.1.7, and Appendix C are revised.
February 20, 2025 Enclosure A Page 70 of 165 SLRA Section A.2.1.7, BWR Vessel Internals, page A-13 and A-14 is revised as shown below:
A.2.1.7 BWR Vessel Internals The BWR Vessel Internals aging management program is an existing condition monitoring and mitigative program that includes inspections and flaw evaluations in conformance with the guidelines of applicable staff-approved BWRVIP documents, and provides reasonable assurance of the long-term integrity and safe operation of BWR vessel internal components that are fabricated of X-750 and nickel alloy, stainless steel including martensitic stainless steel (not used in DNPS reactor vessel internals), cast stainless steel (CASS), and associated welds.
The program manages the effects of cracking due to stress corrosion cracking (SCC),
intergranular stress corrosion cracking (IGSCC), or irradiation assisted stress corrosion cracking (IASCC), cracking due to cyclic loading (including flow-induced vibration), loss of material, loss of fracture toughness due to neutron or thermal embrittlement, and loss of preload due to thermal or irradiation-enhanced stress relaxation.
The program performs inspections for cracking and loss of material in accordance with the guidelines of applicable staff-approved BWRVIP documents and the requirements of ASME Code,Section XI, Table IWB-2500-1. For example, cracking and loss of material due to wear in the steam dryer are managed by performing visual inspections in accordance with applicable NRC approved BWRVIP documents. The impact of loss of fracture toughness on component integrity is indirectly managed by using visual or volumetric examination techniques to monitor for cracking in the components. This program also manages loss of preload by performing visual inspections or stress analyses for adequate structural integrity. In accordance with BWRVIP-315-A Section 4.5.1 Limitation 2, a future version of BWRVIP-47 that addresses extended operations will be implemented as applicable.
Evaluations of reactor vessel internal components determined that supplemental inspections in addition to the existing BWRVIP examination guidelines are not necessary during the subsequent period of extended operation to manage loss of fracture toughness due to thermal aging embrittlement or neutron irradiation embrittlement and the synergistic effect of thermal aging and neutron irradiation as well as cracking due to IASCC. This determination is based on neutron fluence, cracking susceptibility, fracture toughness, and consequences of cracking or failure of the reactor vessel internal components. If evaluations determine that supplemental inspections are necessary for certain components, the program conducts the supplemental inspections for adequate aging management.
February 20, 2025 Enclosure A Page 71 of 165 The BWR Vessel Internals program will be enhanced to:
- 1. Limit the scope expansion exemption detailed in BWRVIP-41, Revision 4-A, to 60 years of operation. The currently allowed scope expansion exemption applies to large diameter jet pump diffuser, adapter and lower ring welds (DF-1, DF-2, DF-3, AD-1, AD-2, and AD-3a,b) that are inspected by UT.
The program will be enhanced no later than six months prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 72 of 165 SLRA Section B.2.1.7, BWR Vessel Internals, pages B-45 through B-48 are revised as shown below:
B.2.1.7 BWR Vessel Internals Program Description The BWR Vessel Internals aging management program is an existing condition monitoring and mitigative program that manages aging of the reactor vessel internals in accordance with the requirements of ASME Code,Section XI and Boiling Water Reactor Vessels and Internals Project (BWRVIP) reports. The program manages the aging effects of cracking, loss of material, and loss of fracture toughness of vessel internal components in a reactor coolant environment. The program includes inspection and flaw evaluation in conformance with the guidelines of applicable BWRVIP reports and ASME Code,Section XI. The program also mitigates these aging effects by managing water chemistry per the Water Chemistry (B.2.1.2) program. The BWR Vessel Internals program includes periodic inspections of components fabricated from X-750 material to provide for timely identification of cracks that may be indicative of degradation due to thermal aging and neutron irradiation embrittlement. Precipitation-hardened (PH) martensitic stainless steel (e.g., 15-5 and 17-4 PH steel), and martensitic stainless steel (e.g., Type 403, 410, 431 steel) are not used within the reactor vessel internal components.
The BWR Vessel Internals program follows applicable and approved BWRVIP guidelines for inspection, evaluation, and repair recommendations for the components listed. When new or revised guidance is issued, it will beis required to be implemented in accordance with BWRVIP-94 Revision 4 and NEI 03-08, per fleet procedures. If new or revised guidelines includes revisions to NRC approved BWRVIP guidelines, and the revised guidelines are less conservative than those approved by the NRC, these less conservative guidelines shall be implemented only after the NRC reviews and approves the changes. Additionally, the program allows for deviation from BWRVIP examination recommendations based on the requirements of NEI-03-08.
The program currently includes the following BWRVIP guidelines for inspection, evaluation, and repair recommendations for the components listed.
Core Shroud: Inspections and flaw evaluations are performed in accordance with BWRVIP-76 Revision 1-A. Required inspections of Unit 2 welds V29 though V32 and Unit 3 weld V20 yielded no credited coverage. A BWRVIP Deviation Disposition was prepared and will remain in place until the welds can be made accessible for the needed examinations. The repair design criteria in BWRVIP-02-A Revision 2 were utilized in preparing the repair plan for the Unit 2 and 3 core shrouds.
February 20, 2025 Enclosure A Page 73 of 165 Core Plate: Inspections and flaw evaluations are performed in accordance with BWRVIP-25 Revision 1-A. The repair design criteria in BWRVIP-50-A would be utilized in preparing a repair plan for the core plate.
Core Spray: Inspections and evaluations are performed in accordance with BWRVIP-18 Revision 2-A. The replacement design criteria in BWRVIP-16-A were utilized in preparing the replacement plan for the Unit 2 and 3 lower sectional line replacement.
BWRVIP-19-A would be used in preparing a repair plan for core spray system components that are internal to the reactor vessel.
Shroud Support: Inspections and evaluations are performed in accordance with BWRVIP-38. The repair design criteria in BWRVIP-52-A would be utilized in preparing a repair plan for the core shroud support.
Jet Pump Assembly: Inspections and evaluations are performed in accordance with BWRVIP-41 Revision 4-A and BWRVIP-138 Revision 1-A. The repair design criteria in the latest revision of BWRVIP-51-A would be used in preparing a repair plan for jet pump components.
LPCI Coupling: DNPS Unit 2 and 3 reactor vessel internals do not include a LPCI coupling therefore inspections, flaw evaluations, and repairs performed in accordance with BWRVIP-42 Revision 1-A and BWRVIP-56-A do not apply.
Top Guide: DNPS does not have top guide wedges installed. Inspections and evaluations are performed in accordance with BWRVIP-26-A and BWRVIP-183-A. The repair design criteria in BWRVIP-50-A would be utilized in preparing a repair plan for the top guide. In accordance with BWRVIP-183-A, DNPS inspects ten percent of the grid beam cells containing control rod blades every 12 years, with at least 5 percent inspected within 6 years of the start of the BWRVIP-183 inspection cycle. The top guide inspection locations are those that have high neutron fluence exceeding the IASCC threshold. Top guide aligner pins and sockets are also inspected. Accessible rim weld locations are inspected using EVT-1 every two (2) refuel outages. The extent of the examination and its frequency will be based on a 10 percent sample of the total population, which includes all grid beam and beam to-beam crevice slots. Top guide grid beams were inspected from 18 cells on Unit 2 and Unit 3 during D2R22 (2011) and D3R22 (2012) respectively with no indications identified. The 18 cells exceeded the 10% requirement and, therefore, no additional exams are required for 12 years.
Inspections are performed using the EVT-1 method. The program also allows for inspections to be performed using UT once it becomes available. This inspection schedule will continue through the subsequent period of extended operation.
Control Rod Drive Housing and Lower Plenum Components: Inspections and evaluations were performed in accordance with BWRVIP-47-A. The inspections required by BWRVIP-47-A relative to CRD housings, instrument penetrations, and components within the lower plenum are further discussed in the BWR Penetrations (B.2.1.6) program. The repair design criteria in BWRVIP-55-A and BWRVIP-58-A would
February 20, 2025 Enclosure A Page 74 of 165 be utilized in preparing a repair plan for the control rod drive housings and instrument penetrations.
Steam Dryer: The DNPS, Unit 2 and Unit 3 original equipment General Electric steam dryers were replaced with General Electric steam dryers in 2007 and 2006, respectively. DNPS inspections and evaluations are performed in accordance with the BWRVIP-139 Revision 1-A and GEH 0000-0085-8689 R0. The repair design criteria in BWRVIP-181-A would be utilized in preparing a repair plan for the steam dryer.
Access Hole Covers: Inspections and evaluations are performed in accordance with BWRVIP-180 Revision 1. BWRVIP-180 Revision 1 received a screening evaluation in accordance with Appendix C of NEI 03-08, Rev. 4, Document Screening. The screening evaluation concluded that BWRVIP-180 Revision 1 could be generically released for implementation by the United States BWRVIP members without prior NRC review and approval as the updated guidelines were not less conservative than BWRVIP-180. Given that the guidelines in BWRVIP-180 Revision 1 do not establish less conservative requirements than BWRVIP-180, its use in the Dresden BWR Vessel Internals Program was deemed acceptable. The repair design criteria in BWRVIP-217 would be utilized in preparing a repair plan for the access hole covers.
The BWR Vessel Internals program specifies the necessary examinations to be performed during each outage based on the BWRVIP guidelines. BWRVIP-03 specifies VT-1 and EVT-1 examinations to detect surface discontinuities and imperfections such as cracks. Volumetric examinations are performed as specified by BWRVIP guidelines.
VT-3 examinations are specified to determine the general condition of components by verifying parameters, such as clearances and displacements, and by detecting discontinuities and imperfections, such as loss of integrity of bolted or welded connections, or loose or missing parts, debris, corrosion, wear, or erosion. The examination procedures also identify the type and location of examination required for each component, as well as the basis for the examination.
Evaluations of reactor vessel internal components determined that supplemental inspections in addition to the existing BWRVIP examination guidelines are not necessary to manage loss of fracture toughness due to thermal aging embrittlement or neutron irradiation embrittlement and cracking due to IASCC during the subsequent period of extended operation. This determination is based on neutron fluence, cracking susceptibility, fracture toughness, and consequences of cracking or failure of the reactor vessel internal components.
The program allows for deviation from BWRVIP examination recommendations based on the requirements of NEI-03-08. Any relief request from the requirements of ASME Code,Section XI is submitted to the NRC for approval in accordance with 10 CFR 50.55a.
February 20, 2025 Enclosure A Page 75 of 165 Evaluation of indications or flaws identified by examination is conducted consistent with the applicable and approved BWRVIP guideline or ASME Code,Section XI, as appropriate for the affected component. Additional general guidelines per BWRVIP A, BWRVIP-59-A, and BWRVIP-60-A are applied for flaw evaluation of crack growth in stainless steels, nickel alloys, and low-alloy steels. Repair and replacement activities, if needed, are performed in accordance with ASME Code,Section XI requirements for code components, consistent with the recommendations of the appropriate BWRVIP repair and replacement guidelines. For nickel alloy repairs, BWRVIP-44-A would be used for weld repairs of irradiated structural components.
BWRVIP License Renewal Applicant Action Items listed in the NRC Safety Evaluation Reports for BWRVIP reports are addressed in Appendix C.
The BWR Vessel Internals program is implemented in accordance with procedures that are common across Constellation and is considered a fleet program. The program requirements are applicable to all Constellation BWR plants. The equivalent BWR Vessel Internals program for Peach Bottom Atomic Power Station has been previously evaluated by the NRC, as documented in the Safety Evaluation Report Related to the Subsequent License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3 Docket Nos.50-277 and 50-278 (ADAMS Accession Number ML20044D902). Based on this evaluation, the NRC determined that the BWR Vessel Internals program will adequately manage the effects of aging such that intended function(s) are maintained consistent with the CLB for the subsequent period of extended operation, as required by 10 CFR 50.54(a)(3).
NUREG-2191 Consistency The BWR Vessel Internals aging management program will be consistent with the ten elements of aging management program XI.M9, "BWR Vessel Internals," specified in NUREG-2191.
There are a few differences in the BWRVIP report revisions recommended in NUREG-2191 and those being implemented at DNPS. These include BWRVIP-03 Revision 20 versus BWRVIP-03 Revision 1, BWRVIP-18 Revision 2-A versus BWRVIP-18-A, BWRVIP-25 Revision 1-A versus BWRVIP-25 Revision 0, BWRVIP-41 Revision 4-A versus BWRVIP-41 Revision 0, BWRVIP-76 Revision 1-A versus BWRVIP-76-A, BWRVIP-100 Revision 1-A versus BWRVIP-100-A, BWRVIP-139 Revision 1-A versus BWRVIP-139-A, BWRVIP-180 Rev. 1 versus BWRVIP-180 Rev.
0, and BWRVIP-183-A versus BWRVIP-183. These deviations are deemed acceptable as they are either NRC approved, the NRC determined future revisions do not need Safety Evaluations (BWRVIP-03), or are not less conservative than the recommended guidelines (BWRVIP-180, Revision 1).
Exceptions to NUREG-2191 None.
February 20, 2025 Enclosure A Page 76 of 165 Enhancements In the elements identified below, the BWR Vessel Internals program will be enhanced to:
- 1. Limit the scope expansion exemption detailed in BWRVIP-41, Revision 4-A, to 60 years of operation. The currently allowed scope expansion exemption applies to large diameter jet pump diffuser, adapter and lower ring welds (DF-1, DF-2, DF-3, AD-1, AD-2, and AD-3a,b) that are inspected by UT. Program Elements Affected:
Scope of Program (Element 1) and Parameters Monitored or Inspected (Element 3)
The program will be enhanced no later than six months prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 77 of 165 SLRA Appendix C, BWRVIP-76 Revision 1-A, BWR Core Shroud Inspection and Flaw Evaluation Guidelines (AAI 4), page C-12 is revised as shown below:
BWRVIP-76 Revision 1-A, BWR Core Shroud Inspection and Flaw Evaluation Guidelines Action Item Description Dresden Response BWRVIP-76 Revision 1-A (AAI 4)
The applicant shall reference the NRC staff-approved TRs BWRVIP-14-A, BWRVIP-99 (when approved) and BWRVIP-100-A in their RVI AMP. The applicant shall make a statement in their LRA that the crack growth rate evaluations and fracture toughness values specified in these reports shall be used for cracked core shroud welds that are exposed to the neutron fluence values that are specified in these TRs. The applicant shall confirm that they will incorporate any emerging inspection guidelines developed by the BWRVIP for these welds.
The BWR Vessel Internals (B.2.1.7) program implements BWRVIP-76 Revision 1-A requirements including guidance within BWRVIP-76 Revision 1-A Section D to use current NRC-approved BWRVIP guidance to determine crack growth rates and fracture toughness values. The BWR Vessel Internals program includes reference to BWRVIP-14-A, BWRVIP-99-A, and BWRVIP-100-A Revision 1-A for evaluation of crack growth. The current guidance references BWRVIP-14-A and BWRVIP-99-A for crack growth rates and BWRVIP-100-A Revision 1-A for fracture toughness values. The implementing procedures for the BWR Vessel Internals program include guidance to incorporate new guidance within new or revised BWRVIP reports. This assures that any emerging inspection guidelines developed by the BWRVIP for these core shroud welds will be incorporated into the program.
February 20, 2025 Enclosure A Page 78 of 165 Change # 18 - Revisions to A.2.1.21 and B.2.1.21, Selective Leaching Affected SLRA sections: A.2.1.21 and B.2.1.21 Affected SLRA Page Numbers: A-25, B-122, B-123, and B-124 Description Change:
Malleable iron was inadvertently omitted from the sentence addressing inspection acceptance criteria in SLRA Section B.2.1.21. This sentence is being revised to add malleable iron. In addition, SLRA Section B.2.1.21 is being revised to clarify that the multi-unit sample size reduction provision is not applicable to the components exposed to soil populations.
Finally, SLRA Sections A.2.1.21 and B.2.1.21 are being revised to include additional information on the Constellation process for demonstrating a volumetric nondestructive examination technique to perform selective leaching inspections at Dresden.
Accordingly, SLRA Section A.2.1.21 and Section B.2.1.21 are revised as shown below.
February 20, 2025 Enclosure A Page 79 of 165 The second paragraph of SLRA Section A.2.1.21, Selective Leaching, page A-25 is revised as shown below:
Inspections are conducted on a representative sample of components in each material and environment population. Inspections consist of visual and mechanical examination techniques (for gray cast iron, malleable iron, and ductile iron components) as well as periodic non-destructive and destructive examinations for determining physical properties (i.e., degree of dealloying, depth of dealloying, through-wall thickness, and chemical composition) for components exposed to raw water, waste water, and soil environments. Volumetric non-destructive examinations will employ techniques that have been demonstrated to be capable of detecting and characterizing selective leaching degradation. The volumetric technique will be qualified equivalent to an Intermediate Rigor level of qualification of ASME Code Section V, Nondestructive Examination, Article 14, Examination System Qualification, and the qualification documentation will include the applicability and limitations of the technique including the specific material type susceptible to selective leaching that may be inspected using the specified technique. Two volumetric non-destructive examinations will be performed when the non-destructive examination is credited in lieu of a destructive examination. Inspections and tests will be conducted to determine whether loss of material will affect the ability of the components to perform their intended function through the subsequent period of extended operation. Inspections will be conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset, and surface conditions as appropriate. When the acceptance criteria are not met such that it is determined that the affected component should be replaced prior to the end of the subsequent period of extended operation, additional inspections will be performed.
The fourth and fifth paragraphs of SLRA Section B.2.1.21, Selective Leaching, page B-122 are revised as shown below:
For the one-time and periodic/opportunistic portions of the program, visual inspections will be conducted on a representative sample of components of each material and environment combination of components. Ductile iron and malleable iron are considered a single material with respect to defining sample populations due to the similar morphology of these materials. A representative sample consists of three percent of each material and environment population per unit or a maximum of 8 components per population per unit. Additionally, for the periodic/opportunistic portion of the program, two destructive examinations will be performed for copper alloy with greater than 15 percent zinc populations, per unit, for sample populations with greater than or equal to 35 susceptible components. When there are less than 35 susceptible components in a population, one destructive examination will be performed for that population.
For gray cast iron, malleable iron, and ductile iron populations, non-destructive ultrasonic or
February 20, 2025 Enclosure A Page 80 of 165 electromagnetic examination techniques may be performed in lieu of destructive examinations.
The number of visual and mechanical inspections may be reduced by two for each component that is destructively or non-destructively examined beyond the minimum number of destructive examinations recommended for each sample population subject to periodic inspections. Since DNPS is a two-unit site, a reduced periodic visual inspection sample size of eight components per population per unit will be adopted for sample populations that are not percentage-based.
This sample size reduction is acceptable because, for the components in the scope of the periodic program, environmental conditions between the units are similar enough such that the aging effects are not occurring differently. Changes to water chemistry practices and to plant equipment and operating conditions (including power rerates) have been performed on both units at approximately the same time. Water chemistry programs monitor various chemistry parameters and require out-of-spec conditions to be corrected under the corrective action program in a timely manner. Raw water systems for both units draw from the same source, the Kankakee River. Therefore, a reduced sample size will provide a representative sample of the condition of the plant and equipment and the existence of the aging effects involved. This sample reduction provision is not applicable for sample populations in a soil environment at DNPS. The sample population size of components in a soil environment is limited such that the percentage-based sampling methodology will be utilized for these populations.
Inspections are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset and surface conditions as appropriate. Results will be evaluated against acceptance criteria to confirm that the sampling basis (e.g., selection, size, frequency) will maintain the components intended function throughout the subsequent period of extended operation based on the projected rate and extent of degradation. The acceptance criteria are: (a) for copper-based alloys, no noticeable change in color from the normal yellow color to the reddish copper color or green copper oxide; (b) for gray cast iron, malleable iron, and ductile iron, the absence of a surface layer that can be easily removed by chipping or scraping or identified in the destructive examinations, (c) the presence of no more than a superficial layer of dealloying, as determined by removal of the dealloyed material by mechanical removal, and (d) the components meet system design requirements such as minimum wall thickness, when extended to the end of the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 81 of 165 Exception 1 and the associated justification in SLRA Section B.2.1.21, Selective Leaching, pages B-123 and B-124 are revised as shown below:
Exceptions to NUREG-2191
- 1. NUREG-2191, aging management program XI.M33, Selective Leaching, Element 4 states for sample populations with greater than 35 susceptible components, two destructive examinations are performed in each material and environment population in each 10-year period at each unit. When there are less than 35 susceptible components in a sample population, one destructive examination is performed for that population.
The DNPS program will allow performance of volumetric non-destructive examinations in lieu of destructive examinations for gray cast iron, malleable iron, and ductile iron populations. The number of non-destructive examinations will follow the guidelines for the required number of destructive examinations for each material and environment combination based on the number of components in the respective population. When this option is used, two (2) volumetric examinations will be performed for each examination for which the new NDE technique is credited in lieu of a destructive examination recommended in NUREG-2191. Program Elements Affected:
Detection of Aging Effects (Element 4).
Justification for Exception While destructive examinations provide more definite means to detect the presence and depth of dealloying in susceptible components compared to visual and mechanical examination techniques, these examinations eliminate the ability to periodically re-examine and monitor components undergoing selective leaching and trend these findings for materials in similar environments and under similar operating conditions.
A component that has undergone selective leaching will develop a substrate that exhibits degraded mechanical properties, reduced density, changes in thermal conductivity, and different electrical and magnetic properties. Such changes in component material properties allow for NDE methods to detect and/or characterize the extent of selective leaching in components.
EPRI research has demonstrated NDE as viable inspection method for the purpose of examining selective leaching degradation. Field-deployable ultrasonic and electromagnetic techniques have been shown capable of detecting and characterizing selective leaching in susceptible components, including cast iron pipe and valve samples. Demonstrated techniques which provide volumetric examination capability and where the technique has been optimized for the purpose of examining for selective leaching, have been shown to provide comparable results to those provided by destructive examinations.
NDE techniques will allow for in-situ examinations for detecting and characterizing the depth of dealloying in susceptible components. This non-destructive methodology will provide the opportunity to re-inspect components experiencing this aging effect through subsequent inspections, providing enhanced understanding of degradation rate and projection of remaining component life through the subsequent period of extended operation as recommended by Element 5 of NUREG-2191, AMP XI.M33. Use of data encoders in these examinations will allow for storage of data and monitoring of degradation by comparing and analyzing degradation rates and behaviors through multiple inspections on the same component. Such techniques
February 20, 2025 Enclosure A Page 82 of 165 also allow for inspecting greater area of sampled components easier than through destructive examinations, which are limited to the section of component believed to be affected by selective leaching through visual indications. Furthermore, NDE provides a faster means of examining greater surface area and in analyzing the extent of condition in a component/population. Such inspection results through NDE will provide valuable input for station personnel to better understand extent of condition in similar material and environment combinations and operational conditions. Thus, future sample methodology can also be improved to select components in populations more prone to selective leaching based on plant-specific environmental and operating conditions.
Volumetric non-destructive examinations performed as part of this program will employ techniques that have been demonstrated to be capable of detecting and characterizing selective leaching degradation. The Constellation process for use and implementation of a new technique will be followed prior to implementation of a new technique to meet inspection commitments for the Selective Leaching aging management program. This process will include a proof-of-concept (open or blind) demonstration to validate that the extent of selective leaching degradation is accurately characterized by the examination technique, a technical justification, and development of a technique specific procedure to conduct selective leaching examinations. This qualification methodology is equivalent to an Intermediate Rigor level of qualification of ASME Code Section V, Nondestructive Examination, Article 14, Examination System Qualification, however the technique will be qualified for non-ASME Code components. This process will ensure that a new technique is capable of detecting and sizing dealloying within susceptible components prior to implementation of a new technique.
The inspection technique qualification process and documentation will include the applicability and limitations of the technique including the specific material type susceptible to selective leaching that may be inspected via the selected technique as well as other examination limitations (e.g. thickness, geometry). Therefore, while a specific technique is not specified herein, the technique qualification documentation will provide the applicability and limitations of the technique to ensure it is only used where supported by technical justification.
The use of volumetric NDE will be implemented for selective leaching inspections where appropriate and justified as described above; however, destructive examinations may still be preferred by the site based on several factors, including planned component replacements and the feasibility of inspecting components within certain sample populations through NDE (e.g., due to accessibility issues). Therefore, while the program will allow for the performance of volumetric NDE in lieu of all destructive examinations, the DNPS program is expected to rely on destructive examinations for certain populations.
Performance of two (2) volumetric examinations as an alternative to each replaced destructive examination provides further assurance that selective leaching will be adequately managed.
February 20, 2025 Enclosure A Page 83 of 165 Change # 21 - Correction of TLAA and Fatigue Related AMR Line Items and Associated Plant Specific Notes Affected SLRA sections: Tables 3.1.2-1, 3.1.2-2, 3.1.2-3, 3.3.2-5, 3.4.2-5 and 3.5.2-9 Affected SLRA Page Numbers: 3.1-59, 3.1-67, 3.1-69, 3.1-70, 3.1-71, 3.1-72, 3.1-74, 3.1-87, 3.1-92, 3.1-93, 3.1-95, 3.1-96, 3.1-97, 3.1-98, 3.1-99, 3.1-100, 3.1-101, 3.3-156, 3.4-94, 3.4-101, 3.5-161, 3.5-162, 3.5-163, 3.5-164, 3.5-165, and 3.5-167 Description Change:
AMR line items identifying TLAAs were inadvertently included for components in SLRA Tables 3.1.2-1, 3.1.2-2, 3.1.2-3, 3.4.2-5 and 3.5.2-9 that do not have existing CLB TLAAs. These tables are being revised to delete the unnecessary TLAA line items. In addition, the plant specific notes for SLRA Tables 3.1.2-3, 3.3.2-5, and 3.4.2-5 cited the incorrect section of the SLRA for evaluation of the subject components associated TLAA. The affected plant specific notes are being revised to reference the correct SLRA sections for the TLAAs of the associated components. Finally, Table 3.5.2-9 is being revised to add cracking as an applicable aging effect requiring management for components that are within the scope of the fatigue waiver analysis described in SLRA Section 3.5.2.2.1.5.
Additional changes are being made to Tables 3.1.2-1, 3.1.2-2 and 3.1.3-2 under a different change number but said changes have no impact on the changes applied within.
Accordingly, SLRA Tables 3.1.2-1, 3.1.2-2, 3.1.2-3, 3.3.2-5, 3.4.2-5 and 3.5.2-9 are revised as shown below.
February 20, 2025 Enclosure A Page 84 of 165 SLRA Table 3.1.2-1, Reactor Coolant Pressure Boundary System Summary of Aging Management Evaluation, page 3.1-59 is revised as shown below:
Table 3.1.2-1 Reactor Coolant Pressure Boundary System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Bolting (Class 1) Mechanical Closure Carbon and Low Alloy Steel Bolting Air - Indoor, Uncontrolled (External)
Cumulative Fatigue Damage TLAA IV.C1.RP-44 3.1.1-011 A, 1 Loss of Material Bolting Integrity (B.2.1.10)
IV.C1.RP-42 3.1.1-063 B
Loss of Preload Bolting Integrity (B.2.1.10)
IV.C1.RP-43 3.1.1-067 B
Bolting (Closure) Mechanical Closure Carbon and Low Alloy Steel Bolting Air - Indoor, Uncontrolled (External)
Cumulative Fatigue Damage TLAA IV.C1.RP-44 3.1.1-011 A, 1 Loss of Material Bolting Integrity (B.2.1.10)
IV.C1.RP-42 3.1.1-063 B
Loss of Preload Bolting Integrity (B.2.1.10)
IV.C1.RP-43 3.1.1-067 B
Flow Device (Class 1)
Pressure Boundary Carbon Steel Air - Indoor, Uncontrolled (External)
Loss of Material External Surfaces Monitoring of Mechanical Components (B.2.1.23)
IV.C1.R-431 3.1.1-124 A
Steam (Internal)
Cumulative Fatigue Damage TLAA VIII.B2.S-08 3.4.1-001 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
VIII.B2.SP-160 3.4.1-014 A
Water Chemistry (B.2.1.2)
VIII.B2.SP-160 3.4.1-014 B
Wall Thinning Flow-Accelerated Corrosion (B.2.1.9)
V.D2.E-07 3.2.1-011 A
February 20, 2025 Enclosure A Page 85 of 165 SLRA Table 3.1.2-1, Reactor Coolant Pressure Boundary System Summary of Aging Management Evaluation, page 3.1-67 is revised as shown below:
Table 3.1.2-1 Reactor Coolant Pressure Boundary System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Pump Casing (Reactor Recirculation)
Pressure Boundary Cast Austenitic Stainless Steel (CASS)
Reactor Coolant (Internal)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.E.R-444 3.1.1-114 A
Water Chemistry (B.2.1.2)
IV.E.R-444 3.1.1-114 B
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1 Loss of Fracture Toughness Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) (B.2.1.8)
IV.C1.R-52 3.1.1-050 A
Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.RP-158 3.1.1-079 A
Water Chemistry (B.2.1.2)
IV.C1.RP-158 3.1.1-079 B
February 20, 2025 Enclosure A Page 86 of 165 SLRA Table 3.1.2-1, Reactor Coolant Pressure Boundary System Summary of Aging Management Evaluation, page 3.1-69 is revised as shown below:
Table 3.1.2-1 Reactor Coolant Pressure Boundary System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body Pressure Boundary Carbon Steel Treated Water (Internal)
Cumulative Fatigue Damage TLAA VIII.B2.S-08 3.4.1-001 A, 1 Long-Term Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-448 3.1.1-133 A
Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-60 3.2.1-016 A
Water Chemistry (B.2.1.2)
V.D2.EP-60 3.2.1-016 B
Stainless Steel Air - Indoor, Uncontrolled (External)
Cracking One-Time Inspection (B.2.1.20)
V.D2.EP-103b 3.2.1-007 A
Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-452a 3.1.1-136 A
Treated Water (Internal)
Cumulative Fatigue Damage TLAA VII.E3.A-62 3.3.1-002 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-73 3.2.1-022 A
Water Chemistry (B.2.1.2)
V.D2.EP-73 3.2.1-022 B
Valve Body (Class 1)
Pressure Boundary Carbon Steel Air - Indoor, Uncontrolled (External)
Loss of Material External Surfaces Monitoring of Mechanical Components (B.2.1.23)
IV.C1.R-431 3.1.1-124 A
Reactor Coolant (Internal)
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1 Long-Term Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-448 3.1.1-133 A
February 20, 2025 Enclosure A Page 87 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Carbon Steel Reactor Coolant (Internal)
Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-60 3.2.1-016 A
Water Chemistry (B.2.1.2)
V.D2.EP-60 3.2.1-016 B
February 20, 2025 Enclosure A Page 88 of 165 SLRA Table 3.1.2-1, Reactor Coolant Pressure Boundary System Summary of Aging Management Evaluation, page 3.1-70 is revised as shown below:
Table 3.1.2-1 Reactor Coolant Pressure Boundary System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Carbon Steel Steam (Internal)
Cumulative Fatigue Damage TLAA VIII.B2.S-08 3.4.1-001 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
VIII.B2.SP-160 3.4.1-014 A
Loss of Material Water Chemistry (B.2.1.2)
VIII.B2.SP-160 3.4.1-014 B
Treated Water (Internal)
Cumulative Fatigue Damage TLAA VIII.B2.S-08 3.4.1-001 A, 1 Long-Term Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-448 3.1.1-133 A
Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-60 3.2.1-016 A
Water Chemistry (B.2.1.2)
V.D2.EP-60 3.2.1-016 B
Cast Austenitic Stainless Steel (CASS)
Air - Indoor, Uncontrolled (External)
Cracking One-Time Inspection (B.2.1.20)
V.D2.EP-103b 3.2.1-007 A
Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-452a 3.1.1-136 A
Reactor Coolant (Internal)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.E.R-444 3.1.1-114 A
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1
February 20, 2025 Enclosure A Page 89 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Cast Austenitic Stainless Steel (CASS)
Reactor Coolant (Internal)
Loss of Fracture Toughness ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.R-08 3.1.1-038 A
Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.RP-158 3.1.1-079 A
Water Chemistry (B.2.1.2)
IV.C1.RP-158 3.1.1-079 B
February 20, 2025 Enclosure A Page 90 of 165 SLRA Table 3.1.2-1, Reactor Coolant Pressure Boundary System Summary of Aging Management Evaluation, page 3.1-71 is revised as shown below:
Table 3.1.2-1 Reactor Coolant Pressure Boundary System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Cast Austenitic Stainless Steel (CASS)
Steam (Internal)
Cracking One-Time Inspection (B.2.1.20)
VIII.B2.SP-98 3.4.1-011 A
Water Chemistry (B.2.1.2)
VIII.B2.SP-98 3.4.1-011 B
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1 Loss of Fracture Toughness ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.C1.R-08 3.1.1-038 A
Loss of Material One-Time Inspection (B.2.1.20)
VIII.B2.SP-155 3.4.1-084 A
Water Chemistry (B.2.1.2)
VIII.B2.SP-155 3.4.1-084 B
Stainless Steel Air - Indoor, Uncontrolled (External)
Cracking One-Time Inspection (B.2.1.20)
V.D2.EP-103b 3.2.1-007 A
Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-452a 3.1.1-136 A
Reactor Coolant (Internal)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.E.R-444 3.1.1-114 A
Water Chemistry (B.2.1.2)
IV.E.R-444 3.1.1-114 B
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1
February 20, 2025 Enclosure A Page 91 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Stainless Steel Reactor Coolant (Internal)
Loss of Material ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.E.R-444 3.1.1-114 A
February 20, 2025 Enclosure A Page 92 of 165 SLRA Table 3.1.2-1, Reactor Coolant Pressure Boundary System Summary of Aging Management Evaluation, page 3.1-72 is revised, additional changes are being made under a different change number and have no impact on the changes applied, as shown below:
Table 3.1.2-1 Reactor Coolant Pressure Boundary System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Valve Body (Class 1)
Pressure Boundary Stainless Steel Treated Water (Internal)
Cumulative Fatigue Damage TLAA IV.C1.R-220 3.1.1-006 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
VIII.B2.SP-155 3.4.1-084 A
Water Chemistry (B.2.1.2)
VIII.B2.SP-155 3.4.1-084 B
Cumulative Fatigue Damage TLAA VII.E3.A-62 3.3.1-002 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-73 3.2.1-022 A
Water Chemistry (B.2.1.2)
V.D2.EP-73 3.2.1-022 B
Treated Water > 140°F (Internal)
Cracking One-Time Inspection (B.2.1.20)
V.D2.E-457 3.2.1-114 A
Water Chemistry (B.2.1.2)
V.D2.E-457 3.2.1-114 B
Cumulative Fatigue Damage TLAA VII.E3.A-62 3.3.1-002 A, 1 Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-73 3.2.1-022 A
Water Chemistry (B.2.1.2)
V.D2.EP-73 3.2.1-022 B
February 20, 2025 Enclosure A Page 93 of 165 SLRA Table 3.1.2-2, Reactor Vessel Summary of Aging Management Evaluation, page 3.1-74 is revised, additional changes are being made under a different change number and have no impact on the changes applied, as shown below:
Table 3.1.2-2 Reactor Vessel Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Bolting (Head Spray, Head Vent, Spare Nozzle)
Mechanical Closure High Strength Low Alloy Steel Bolting with Yield Strength of 150 ksi or Greater Air - Indoor, Uncontrolled (External)
Cracking Bolting Integrity (B.2.1.10)
IV.C1.R-11 3.1.1-062 B
Cumulative Fatigue Damage TLAA IV.C1.RP-44 3.1.1-011 A, 2 Loss of Material Bolting Integrity (B.2.1.10)
IV.C1.RP-42 3.1.1-063 B
Loss of Preload Bolting Integrity (B.2.1.10)
IV.C1.RP-43 3.1.1-067 B
February 20, 2025 Enclosure A Page 94 of 165 SLRA Table 3.1.2-2, Reactor Vessel Summary of Aging Management Evaluation, page 3.1-87 is revised as shown below:
Table 3.1.2-2 Reactor Vessel Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes N-9 Control Rod Drive Return Line Nozzle (Capped)
Pressure Boundary Carbon or Low Alloy Steel with Stainless Steel Cladding Reactor Coolant (Internal)
Cracking ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1)
IV.A1.R-66 3.1.1-096 A
IV.E.R-444 3.1.1-114 A
Water Chemistry (B.2.1.2)
IV.E.R-444 3.1.1-114 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20)
IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
N-9 Control Rod Drive Return Line Nozzle Safe End and Welds (including cap)
Pressure Boundary Stainless Steel Air - Indoor, Uncontrolled (External)
Cracking One-Time Inspection (B.2.1.20)
IV.A1.R-61a 3.1.1-016 C
Loss of Material One-Time Inspection (B.2.1.20)
IV.C1.R-452a 3.1.1-136 A
Reactor Coolant (Internal)
Cracking BWR Stress Corrosion Cracking (B.2.1.5)
IV.A1.R-412 3.1.1-097 A
Water Chemistry (B.2.1.2)
IV.A1.R-412 3.1.1-097 B
Cumulative Fatigue Damage TLAA IV.A1.R-04 3.1.1-007 A, 2 Loss of Material One-Time Inspection (B.2.1.20)
IV.A1.RP-157 3.1.1-085 A
Water Chemistry (B.2.1.2)
IV.A1.RP-157 3.1.1-085 B
February 20, 2025 Enclosure A Page 95 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-92 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Control Rod Drive Guide Tube Structural Support to maintain core configuration and flow distribution Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-104 3.1.1-102 A
Water Chemistry (B.2.1.2)
IV.B1.R-104 3.1.1-102 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Control Rod Drive Guide Tube Base Structural Support to maintain core configuration and flow distribution Cast Austenitic Stainless Steel (CASS)
Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-104 3.1.1-102 A
Water Chemistry (B.2.1.2)
IV.B1.R-104 3.1.1-102 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Fracture Toughness BWR Vessel Internals (B.2.1.7)
IV.B1.R-416 3.1.1-099 A
Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Core Plate DP/SLC Line Direct Flow Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-99 3.1.1-103 C
Water Chemistry (B.2.1.2)
IV.B1.R-99 3.1.1-103 D
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1
February 20, 2025 Enclosure A Page 96 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-93 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Core Plate, Core Plate Bolts Structural Support to maintain core configuration and flow distribution Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-93 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-93 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 97 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-95 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Core Spray Lines and Spargers:
Core spray lines (headers), Spray rings, Spray nozzles, Support brackets Spray Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-99 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-99 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Structural Support Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-99 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-99 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Core Spray Sparger Nozzle Elbows Structural Support Cast Austenitic Stainless Steel (CASS)
Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-104 3.1.1-102 A
Water Chemistry (B.2.1.2)
IV.B1.R-104 3.1.1-102 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Fracture Toughness BWR Vessel Internals (B.2.1.7)
IV.B1.R-417 3.1.1-099 A
February 20, 2025 Enclosure A Page 98 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Core Spray Sparger Nozzle Elbows Structural Support Cast Austenitic Stainless Steel (CASS)
Reactor Coolant and Neutron Flux Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 99 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-96 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Fuel Supports and Control Rod Drive Assemblies:
Orificed Fuel Support Structural Support to maintain core configuration and flow distribution Cast Austenitic Stainless Steel (CASS)
Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-104 3.1.1-102 A
Water Chemistry (B.2.1.2)
IV.B1.R-104 3.1.1-102 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Fracture Toughness BWR Vessel Internals (B.2.1.7)
IV.B1.RP-220 3.1.1-099 A
Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Throttle Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-104 3.1.1-102 A
Water Chemistry (B.2.1.2)
IV.B1.R-104 3.1.1-102 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 100 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Instrumentation:
Wide range neutron monitor system (WRNMS) dry tubes, incore neutron flux monitor guide tubes Structural Support to maintain core configuration and flow distribution Stainless Steel Gas (Internal)
None None IV.E.RP-07 3.1.1-107 C
Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-105 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-105 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 101 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-97 is revised, additional changes are being made under a different change number and have no impact on the changes applied, as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Jet Pump Assemblies:
Castings Direct Flow Cast Austenitic Stainless Steel (CASS)
Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-100 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-100 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Fracture Toughness BWR Vessel Internals (B.2.1.7)
IV.B1.RP-219 3.1.1-099 A
Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Jet Pump Assemblies: Hold-down beam bolts Mechanical Closure Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-100 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-100 3.1.1-103 B
Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Loss of Preload BWR Vessel Internals (B.2.1.7)
IV.B1.R-421 3.1.1-121 A
February 20, 2025 Enclosure A Page 102 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Jet Pump Assemblies:
Thermal sleeve inlet header, Riser brace arm, Holddown beams, Inlet elbow, Wedge, Mixing assembly Direct Flow Nickel Alloy Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-100 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-100 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2
February 20, 2025 Enclosure A Page 103 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-98 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Jet Pump Assemblies:
Thermal sleeve inlet header, Riser brace arm, Holddown beams, Inlet elbow, Wedge, Mixing assembly Direct Flow Stainless Steel Reactor Coolant and Neutron Flux Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
BWR Vessel Internals (B.2.1.7)
IV.B1.RP-377 3.1.1-100 A
February 20, 2025 Enclosure A Page 104 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-99 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Shroud Support Access hole cover (mechanical covers for Unit 2)
Direct Flow Nickel Alloy Reactor Coolant and Neutron Flux Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Mechanical Closure Nickel Alloy Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-95 3.1.1-041 A
Water Chemistry (B.2.1.2)
IV.B1.R-95 3.1.1-041 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-92 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-92 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 105 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Shroud support access hole cover (welded covers for Unit 3)
Direct Flow Nickel Alloy Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-94 3.1.1-029 A
Water Chemistry (B.2.1.2)
IV.B1.R-94 3.1.1-029 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 106 of 165 SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-100 is revised as shown below:
Table 3.1.2-3 Reactor Vessel Internals Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Steam Dryers Structural Support Nickel Alloy Reactor Coolant Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-94 3.1.1-029 A
Water Chemistry (B.2.1.2)
IV.B1.R-94 3.1.1-029 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Stainless Steel Reactor Coolant Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.RP-155 3.1.1-101 A
Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-155 3.1.1-101 A
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
Top Guide Structural Support to maintain core configuration and flow distribution Stainless Steel Reactor Coolant and Neutron Flux Cracking BWR Vessel Internals (B.2.1.7)
IV.B1.R-98 3.1.1-103 A
Water Chemistry (B.2.1.2)
IV.B1.R-98 3.1.1-103 B
Cumulative Fatigue Damage TLAA IV.B1.R-53 3.1.1-003 A, 1 Loss of Material BWR Vessel Internals (B.2.1.7)
IV.B1.RP-26 3.1.1-043 E, 2 Water Chemistry (B.2.1.2)
IV.B1.RP-26 3.1.1-043 B
February 20, 2025 Enclosure A Page 107 of 165 The plant specific notes for SLRA Table 3.1.2-3, Reactor Vessel Internals Summary of Aging Management Evaluation, page 3.1-101 are revised as shown below:
Plant Specific Notes:
- 1. The TLAA designation in the Aging Management Programs column indicates that cumulative fatigue damage due to fatigue for this component is evaluated in Sections 4.3.6.1, 4.3.6.2 or 4.7.5.
- 2. The BWR Vessel Internals (B.2.1.9) program is substituted to manage the aging effect(s) applicable to this component type, material and environment combination.
The plant specific notes for SLRA Table 3.3.2-5, Cranes, Hoists, and Refueling Equipment System Summary of Aging Management Evaluation, page 3.3-157 are revised as shown below:
Plant Specific Notes:
- 1. The Inspection of Overhead Heavy Load and Light Load (Related to Fuel Handling) Systems (B.2.1.13) program is substituted to manage the aging effect(s) applicable to this component type, material and environment combination.
- 2. The TLAA designation in the Aging Management Program column indicates that fatigue of this component is evaluated in Section 4.37.1.
February 20, 2025 Enclosure A Page 108 of 165 SLRA Table 3.4.2-5, Main Turbine and Auxiliaries System Summary of Aging Management Evaluation, page 3.4-94 is revised as shown below:
Table 3.4.2-5 Main Turbine and Auxiliaries System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Piping, piping components Leakage Boundary Carbon Steel Steam (Internal)
Cumulative Fatigue Damage TLAA VIII.B2.S-08 3.4.1-001 A, 2 Loss of Material One-Time Inspection (B.2.1.20)
VIII.A.SP-71 3.4.1-014 A
Water Chemistry (B.2.1.2)
VIII.A.SP-71 3.4.1-014 B
Wall Thinning Flow-Accelerated Corrosion (B.2.1.9)
VIII.A.S-408 3.4.1-060 A
VIII.A.S-15 3.4.1-005 A
Treated Water (Internal)
Cumulative Fatigue Damage TLAA VIII.B2.S-08 3.4.1-001 A, 2 Long-Term Loss of Material One-Time Inspection (B.2.1.20)
VIII.A.S-432 3.4.1-081 A
Loss of Material One-Time Inspection (B.2.1.20)
VIII.B2.SP-73 3.4.1-014 A
Water Chemistry (B.2.1.2)
VIII.B2.SP-73 3.4.1-014 B
Wall Thinning Flow-Accelerated Corrosion (B.2.1.9)
VIII.D2.S-408 3.4.1-060 A
VIII.D2.S-16 3.4.1-005 A
February 20, 2025 Enclosure A Page 109 of 165 The plant specific notes for SLRA Table 3.4.2-5, Main Turbine and Auxiliaries System Summary of Aging Management Evaluation, page 3.4-101 is revised as shown below:
Plant Specific Notes:
- 1. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24) program is used to manage the aging effects applicable to this component type, material, and environment combination. The internally coated turbine oil reservoir tank meets the six criteria in GALL-SLR AMP XI.M42, Element 4, to use the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24) program in lieu of the Internal Coatings/Linings for In-Scope Piping, Piping Component, Heat Exchangers, and Tanks (B.2.1.28) program.
- 2. The TLAA in the Aging Management Program column indicates that cumulative fatigue damage due to fatigue for this component is evaluated in Section 4.3
February 20, 2025 Enclosure A Page 110 of 165 SLRA Table 3.5.2-9, Primary Containment Summary of Aging Management Evaluation, page 3.5-161 is revised as shown below:
Table 3.5.2-9 Primary Containment Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Penetration -
Containment Sleeves Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel Air - Indoor, Uncontrolled Cracking ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1 Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-36 3.5.1-035 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-36 3.5.1-035 B
Drywell Electrical HELB/MELB Shielding Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel Air - Indoor, Uncontrolled Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-36 3.5.1-035 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-36 3.5.1-035 B
Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
February 20, 2025 Enclosure A Page 111 of 165 SLRA Table 3.5.2-9, Primary Containment Summary of Aging Management Evaluation, page 3.5-162 is revised as shown below:
Table 3.5.2-9 Primary Containment Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Penetration -
Drywell Mechanical HELB/MELB Shielding Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel; dissimilar metal welds Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1 Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-36 3.5.1-035 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-36 3.5.1-035 B
Stainless Steel Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-38 3.5.1-010 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-38 3.5.1-010 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1
February 20, 2025 Enclosure A Page 112 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Penetration -
Drywell Mechanical (flued heads, bellows)
Expansion/Separatio n
Stainless Steel Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-38 3.5.1-010 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-38 3.5.1-010 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1
February 20, 2025 Enclosure A Page 113 of 165 SLRA Table 3.5.2-9, Primary Containment Summary of Aging Management Evaluation, page 3.5-163 is revised as shown below:
Table 3.5.2-9 Primary Containment Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Penetration -
Drywell Mechanical (flued heads, bellows)
Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel; dissimilar metal welds Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1 Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-36 3.5.1-035 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-36 3.5.1-035 B
Stainless Steel Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-38 3.5.1-010 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-38 3.5.1-010 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1
February 20, 2025 Enclosure A Page 114 of 165 SLRA Table 3.5.2-9, Primary Containment Summary of Aging Management Evaluation, page 3.5-164 is revised as shown below:
Table 3.5.2-9 Primary Containment Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Steel Elements:
Drywell - shell, head, embedded and sandpocket regions (accessible areas)
HELB/MELB Shielding Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B1.1.CP-43 3.5.1-035 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B1.1.CP-43 3.5.1-035 B
February 20, 2025 Enclosure A Page 115 of 165 SLRA Table 3.5.2-9, Primary Containment Summary of Aging Management Evaluation, page 3.5-165 is revised as shown below:
Table 3.5.2-9 Primary Containment Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Steel Elements:
Drywell - shell, head, embedded and sandpocket regions (inaccessible areas)
HELB/MELB Shielding Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B1.1.CP-43 3.5.1-035 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B1.1.CP-43 3.5.1-035 B
February 20, 2025 Enclosure A Page 116 of 165 SLRA Table 3.5.2-9, Primary Containment Summary of Aging Management Evaluation, page 3.5-167 is revised as shown below:
Table 3.5.2-9 Primary Containment Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Torus access hatches Shelter/Protection Structural Pressure Barrier Structural Support Carbon Steel Air - Indoor, Uncontrolled Cracking 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.CP-37 3.5.1-027 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.CP-37 3.5.1-027 B
Cumulative Fatigue Damage TLAA II.B4.C-13 3.5.1-009 A, 1 Loss of Material 10 CFR Part 50, Appendix J (B.2.1.31)
II.B4.C-16 3.5.1-028 A
ASME Section XI, Subsection IWE (B.2.1.29)
II.B4.C-16 3.5.1-028 B
February 20, 2025 Enclosure A Page 117 of 165 Change # 23 Clarification to SLRA Section 3.2.2.2.2 Affected SLRA sections: 3.2.2.2.2 Affected SLRA Page Numbers: 3.2-13 Description Change:
SLRA Section 3.2.2.2.2 is being revised to eliminate reference to SLRA Table 3.2.1, Item 107 in the first paragraph since this line item is addressed separately in the fourth paragraph of the further evaluation response.
Accordingly, SLRA Section 3.2.2.2.2 is revised as shown below.
February 20, 2025 Enclosure A Page 118 of 165 The first paragraph of SLRA Section 3.2.2.2.2, Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and Nickel Alloys, page 3.2-13 is revised as shown below:
Table 3.2.1 Item Numbers 3.2.1-004, and 3.2.1-048, and 3.2.1-107: These items evaluate loss of material due to pitting and crevice corrosion in stainless steel and nickel alloy piping, piping components, and tanks exposed to air or condensation environments. There are no nickel alloy piping, piping components, or tanks exposed to the air or condensation environments in the Engineered Safety Features Systems at DNPS. Plant-specific operating experience (OE) from 2013 to 2023 associated with stainless steel components in the Engineered Safety Features Systems has been evaluated to determine if prolonged exposure to air-indoor uncontrolled, air-outdoor, and condensation environments has resulted in loss of material due to pitting and crevice corrosion. Loss of material has not been identified through this review as an aging effect that has been experienced at DNPS for stainless steel components in these environments. This provides objective evidence that the external surfaces of components in these environments are not experiencing significant halide (e.g., chloride) contamination in the presence of moisture that would result in loss of material. Accordingly, the One-Time Inspection (B.2.1.20) program will be implemented to demonstrate that the aging effect of loss of material is not occurring in stainless steel piping, piping components, and tanks exposed to air-indoor uncontrolled, air-outdoor, and condensation. Deficiencies will be documented in accordance with 10 CFR Part 50, Appendix B Corrective Action Program. The One-Time Inspection (B.2.1.20) program is described in Appendix B.
February 20, 2025 Enclosure A Page 119 of 165 Change # 23 Clarification to SLRA Section 3.4.2.2.7 Affected SLRA sections: 3.4.2.2.7 Affected SLRA Page Numbers: 3.4-19, 3.4-20 Description Change:
SLRA Section 3.4.2.2.7 is being revised to clarify that Table 3.4.1, Item Number 109 is not used rather than not applicable and to specify that Item Number 102 is used for the associated component, material, environment, and aging effect combination.
Accordingly, SLRA Section 3.4.2.2.7 is revised as shown below.
February 20, 2025 Enclosure A Page 120 of 165 The third paragraph in SLRA Section 3.4.2.2.7, Cracking Due to Stress Corrosion Cracking in Aluminum Alloys, pages 3.4-19 and 3.4-20 are revised as shown below:
Table 3.4.1 Item Number 3.4.1-109: Not used Applicable. This item evaluates cracking due to SCC in aluminum alloy piping, piping components, and tanks exposed to air, condensation, raw water, and waste water environments. There are no aluminum alloy piping or piping components exposed to the air-indoor controlled, air-indoor uncontrolled, raw water, or waste water environments in the Steam and Power Conversion Systems at DNPS. The aluminum alloy piping and piping components exposed to air-outdoor and condensation environments in the Steam and Power Conversion Systems includes the Condensate System piping components. These piping components are constructed of ASTM 6061-T6 series aluminum alloy which is not susceptible to SCC. Therefore, SCC is not a predicted aging effect and aging management of these components for SCC is not required. The aluminum alloy tanks within the Condensate System exposed to air and condensation are addressed in Item 3.4.1-102.
February 20, 2025 Enclosure A Page 121 of 165 Change # 25 - Clarification to Address the Aging of Insulation for Fuse Holders Affected SLRA sections: 3.6.2.3.1 Affected SLRA Page Numbers: 3.6-14, 3.6-16 Description Change:
SLRA Section 3.6.2.3.1 is being revised to include evaluation of the potential aging effects for insulation for fuse holders that are not part of active equipment similar to the existing evaluation for the fuse holder metallic components. In addition, a typographical error in the Unit 2 fuse panel component ID is being corrected.
Accordingly, SLRA section 3.6.2.3.1 is revised as shown below.
February 20, 2025 Enclosure A Page 122 of 165 SLRA Section 3.6.2.3.1, Fuse Holders, page 3.6-14, 3.6-15, and 3.6-16 is revised as shown below:
3.6.2.3.1 Fuse Holders Table 3.6.1 - Item Numbers 3.6.1-016, 3.6.1-017, and 3.6.1-018 Fuse holders (not part of active equipment) metallic clamps: Potential aging effects for the metallic clamps of fuse holders not part of active equipment were evaluated to determine if the GALL-SLR report XI.E5, Fuse Holders aging management program was to be implemented for DNPS subsequent license renewal.
Table 3.6.1 - Item Numbers 3.6.1-022 Fuse holders (not part of active equipment) insulation material: Potential aging effects for the insulation materials of fuse holders not part of active equipment were evaluated to determine if the GALL-SLR report XI.E5, Fuse Holders aging management program was to be implemented for DNPS subsequent license renewal.
Fuse holders are in scope of license renewal at DNPS by meeting (a)(1), (a)(2) functional, or (a)(3) license renewal 10 CFR 54.4 scoping criteria. In accordance with the bounding approach described in NEI 17-01, the fuse holders are an electrical commodity group and are assessed for aging management review by applying the criteria of 10 CFR 54.21(a)(1)(i). The resulting fuse holder population evaluated for aging effects are those that are passive and long lived; i.e., those that are not part of active equipment or assembly. The passive, long lived fuse holders that screen in are evaluated to determine if they are subject to:
Adverse environmental conditions that could cause an increase in electrical resistance of connection.
Fatigue from ohmic heating, thermal cycling, or electrical transients, or Fatigue from frequent fuse removal/manipulation or vibration.
Adverse environmental conditions that could cause a reduction in electrical insulation resistance.
A systematic review of fuse holders: metallic clamps and electrical insulation was performed for DNPS, considering the above scoping and screening criteria and aging effects and mechanisms.
The list of fuse holders for consideration was compiled from fuse and fuse holder components identified in the plant equipment database and on controlled drawings.
The population of fuse holders for consideration totaled 9695. The systematic review applied the above criteria in parallel. The results of the review identified 708 fuse holders that required aging management review. The subject fuse holders are located in the SCRAM solenoid fuse panels and are part of the Local Panels and Racks System. The 16 fuse panels are located in the Reactor Building and are identified below:
2-22023-22A through H
February 20, 2025 Enclosure A Page 123 of 165 3-2203-22A through H The potential aging effects as discussed in NUREG-2192 are not applicable to these fuse holders. The evaluation of aging effects is discussed below.
Chemical Contamination, Corrosion, and Oxidation The fuse holders at DNPS that require aging management review are protected from external sources of moisture by both location and design. The panels in which the subject fuse holders are installed are located in an area of the reactor building where they do not see high relative humidity during normal conditions. This area is protected from weather variations and is not subject to any significant temperature variations. The subject fuse holders are located in closed enclosures.
The fuse holders are protected from chemical contamination by both location and design as described above. There are no sources of uncontrolled chemicals in close proximity of the enclosures during normal conditions.
A walkdown of the panels containing the subject fuse holders confirmed that the operating conditions for these fuse holders are clean and dry, with no evidence of moisture intrusion, chemical contamination, oxidation, or corrosion.
Based on the location, design, and walkdown results of the subject fuse holders and panels which contain them chemical contamination, corrosion, and oxidation are not considered applicable aging mechanisms for these fuse holders.
Ohmic Heating, Thermal Cycling, and Electrical Transients Fuse holders for circuits that carry significant current in power applications could potentially be exposed to thermal fatigue in the form of high resistance caused by thermal cycling and ohmic heating. The subject fuse holders provide power to SCRAM solenoids that are normally energized during normal operation and do not experience frequent cycling. The SCRAM solenoids operate at low current, drawing approximately 10 watts. Therefore, ohmic heating and thermal cycling is not considered an applicable aging mechanism for these fuse holders.
Mechanical stress due to forces associated with electrical faults and transients are mitigated by the fast action of the circuit protective devices at high currents. Also, mechanical stress due to electrical faults is not considered a credible aging mechanism since such faults are infrequent and random in nature. The corrective action program is used to document adverse conditions and provides corrective actions associated with electrical faults and transients that cause the actuation of circuit protective devices. Therefore, electrical transients are not considered an applicable aging mechanism for these fuse holders.
Frequent Manipulation and Vibration Wear and fatigue are caused by repeated insertion and removal of fuses. The fuses in these fuse holders are not subject to frequent manipulation (i.e. removal and
February 20, 2025 Enclosure A Page 124 of 165 reinsertion) because they are neither clearance nor isolation points which support periodic testing or preventative maintenance. Additionally, if fuses are manipulated for non-routine inspection or maintenance, proceduralized good work practices would identify any abnormal condition such as loose or corroded fuse clips.
These fuse holders are in electrical panels that are not mounted on moving or rotating equipment such as compressors, fans, or pumps. Vibration is not an applicable aging mechanism because the electrical panels are mounted with no attached sources of vibration. Therefore, the metallic clamps of these fuse holders will not exhibit the aging effects/mechanisms of fatigue due to frequent manipulation or vibration.
Thermal/Thermoxidative Degradation, Radiolysis, Photolysis, Radiation-Induced Oxidation, and Moisture Intrusion The environment the subject fuse holders are installed in at DNPS does not subject them to environmental aging mechanisms. The panels that the subject fuse holders are installed in are located in an area where they are not subjected to elevated temperatures, high radiation levels, or moisture during normal conditions. A walkdown of the panels containing the subject fuse holders confirmed there was no indication of insulation surface anomalies.
Therefore, based on location and walkdown results aging management activities for fuse holder insulation material is not required.
Summary of Aging Management Review Results:
There are 708 fuse holders in scope for license renewal that are not part of active equipment at DNPS that are subject to aging management review. Based on installed location, design configuration, and operating service conditions the 708 fuse holders inside the electrical panels located in the DNPS reactor building are not susceptible to the aging effects and mechanisms associated with metallic clamps or insulation material. Therefore, aging management activities are not required for these 708 fuse holders (not part of active equipment): metallic clamps or the associated insulation material for these fuse holders at DNPS.
==
Conclusion:==
Aging management activities for DNPS Fuse holders (not part of active equipment):
metallic clamps and associated insulation material are not required for the subsequent period of extended operation; therefore, the GALL-SLR report XI.E5 Fuse Holders aging management program is not applicable for DNPS.
February 20, 2025 Enclosure A Page 125 of 165 Change # 26 - Clarifications to SLRA B.2.1.36, Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Affected SLRA sections: B.2.1.36 SLRA Page Numbers: B-208 Description Change:
SLRA Section B.2.1.36 is being revised to include a description of the how the adverse localized environments will be identified at DNPS. In addition, a description (factors considered and methodology for sampling) of the component sampling process for cable and connection electrical insulation testing is also being added to SLRA Section B.2.1.36.
Accordingly, SLRA section B.2.1.36 is revised as shown below.
February 20, 2025 Enclosure A Page 126 of 165 The Program Description in SLRA Section B.2.1.36, Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements, page B-208 is revised as shown below:
B.2.1.36 Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description The Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is an existing condition monitoring program that manages the effects of reduced insulation resistance of accessible electrical cable and connection insulation within the scope of license renewal subjected to an adverse localized environment during the subsequent period of extended operation.
In most areas of DNPS, the actual ambient environments (e.g., temperature, radiation, or moisture) are less severe than the plant design environment. An adverse localized environment (ALE) is a condition in a limited plant area that is significantly more severe than the specified service environment for the cable or connection. Electrical insulation used in electrical cables and connections may degrade more rapidly than expected in these adverse localized environments.
Adverse localized environments are identified through an integrated approach.
This approach includes but is not limited to: the review of EQ program temperature, radiation, and moisture levels; recorded information from equipment or plant instrumentation; as-built and field walk down; plant spaces scoping and screening methodology; and the review of industry and plant specific operating experience.
Accessible cables and connections located in adverse localized environments are managed by visual inspection. These cables and connections are visually inspected at least once every 10 years for cable jacket and connection insulation surface anomalies, such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination that could indicate incipient conductor insulation aging degradation from temperature, radiation, or moisture. This is an adequate inspection frequency to preclude failures of the cable and connection insulation since operating experience shows that aging degradation is a slow process. Plant specific OE will be evaluated for previously identified and mitigated adverse localized environments cumulative aging effects applicable to in scope cable and connection electrical insulation.
When deemed applicable, testing will be performed for identified occurrences of age degradation. Factors to be considered for selecting a sample include environmental parameters, voltage level, circuit loading, connection type, location, and the electrical insulation composition. The component sampling
February 20, 2025 Enclosure A Page 127 of 165 methodology utilizes a population that includes a representative sample of in scope cable and connection types regardless of whether the component was included in a previous aging management or maintenance program. The technical basis for sample selection will be documented.
The first inspection for subsequent license renewal will be completed prior to the subsequent period of extended operation. Testing will be considered as a follow up action if visual inspections identify degraded or damaged conditions for in scope cables and connections. When a large number of cables are identified as potentially degraded, a sample population will be tested. Testing may include thermography and other proven condition monitoring test methods applicable to cable and connection insulation. Testing as part of an existing maintenance, calibration or surveillance program may be credited. Electrical cable and connection insulation material test results are to be within the acceptance criteria, as identified in the stations procedures.
Unacceptable visual indications of cable and connection electrical insulation anomalies are subject to an engineering evaluation under the corrective action program. Corrective actions include, but are not limited to, testing; shielding or otherwise mitigating the environment; relocating; or replacing affected cables or connections. When an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situation is applicable to additional in scope accessible and inaccessible cables or connections.
February 20, 2025 Enclosure A Page 128 of 165 Change # 27 Revision to Plant Specific Notes for Buried Polymeric Piping.
Affected SLRA Sections: Table 3.3.2-8, Table 3.4.2-1 Affected SLRA Page Numbers: 3.3-202, 3.4-68 Description of Changes:
Plant specific notes 5 and 8 for SLRA Tables 3.3.2-8 and 3.4.2-1 respectively, are being revised to provide the basis for why cracking and blistering are not applicable aging effects requiring management for buried polymeric piping at DNPS.
Accordingly, Tables 3.3.2-8 and 3.4.2-1 are revised as shown below.
February 20, 2025 Enclosure A Page 129 of 165 Plant specific note 5 for SLRA Table 3.3.2-8, Fire Protection System Summary of Aging Management Evaluation, page 3.3-202 is revised as shown below.
- 3. The Buried and Underground Piping and Tanks (B.2.1.27) program will be used to manage this component, material, environment, and aging effect combination. Exposure to ultraviolet light, ozone, radiation or chemical attack is not applicable and, therefore, the aging effect of cracking or blistering for buried polymeric piping in the fire protection system does not apply. Buried piping is not exposed to ultraviolet light, ozone, or radiation. The polymeric piping in the Fire Protection system is polyurethane based cured-in-place-polymer-pipe liner. While polyurethane is susceptible to chemical attack from certain chemicals (e.g., concentrated acids, oils, acetone and certain other solvents, turpentine, etc.), it is generally resistant to chemical species expected in a soil environment.
Further, as a liner, the potential exposure of the polyurethane to the soil environment is limited.
Plant specific note 2 for SLRA Table 3.4.2-1, Condensate System Summary of Aging Management Evaluation, page 3.4-68 is revised as shown below.
- 2. Buried and Underground Piping and Tanks aging management (B.2.1.27) program is substituted for External Surfaces Monitoring of Mechanical Components (B.2.1.23) program to manage this component type. Exposure to ultraviolet light, ozone, radiation or chemical attack is not applicable and, therefore, the aging effect of cracking or blistering for buried polymeric piping in the condensate system does not apply. Buried piping is not exposed to ultraviolet light, ozone, or radiation. The buried polymeric piping in the Condensate System is carbon fiber reinforced polymer (CFRP) piping. The CFRP piping resin is a modified bisphenol A based epoxy resin. Chemical resistant testing (pickle jar testing) of the piping material has demonstrated its chemical resistance to species it could be potentially exposed to during its service life.
February 20, 2025 Enclosure A Page 130 of 165 Change # 29 - Revision to Reactor Building Aging Management Review Affected SLRA sections: Table 3.3.1, Section 3.5.2.1.11, Table 3.5.1, Table 3.5.2-11 Affected SLRA Page Numbers: 3.3-87, 3.5-15, 3.5-93, 3.5-175, 3.5-182 Description Change:
SLRA Table 3.5.2-11 is being revised to credit the One-Time Inspection (B.2.1.20) program for stainless steel bolting exposed to treated water in addition to the Water Chemistry (B.2.1.2) program which is currently credited. This AMR line will be aligned to NUREG-2192 Table 1 Item Number 3.3.1-125 rather than Item Number 3.5.1-085. Associated changes to Table 3.3.1, Table 3.5.1, and Section 3.5.2.1.11 are also being made.
Accordingly, SLRA Tables 3.3.1, 3.5.1, and 3.5.2-11 and SLR Section 3.5.2.1.11 are revised as shown below.
February 20, 2025 Enclosure A Page 131 of 165 SLRA Table 3.3.1, Summary of Aging Management Evaluations for the Auxiliary Systems, page 3.3-87 is revised as shown below:
3.3.1-125 Stainless steel, steel (with stainless steel cladding),
nickel alloy spent fuel storage racks (BWR),
spent fuel storage racks (PWR), piping, piping components exposed to treated water, treated borated water Loss of material due to pitting, crevice corrosion, MIC AMP XI.M2, "Water Chemistry," and AMP X.M32, "One-Time Inspection" No Consistent with NUREG-2191 with exceptions. The One-Time Inspection (B.2.1.20) and Water Chemistry (B.2.1.2) program will be used to manage loss of material of the stainless steel fuel storage racks and stainless steel bolting for structural applications in the spent fuel pool (i.e., liner structures and gates) exposed to treated water in the Reactor Building and Fuel Pool Cooling System.
Exceptions apply to the NUREG-2191 recommendations for the Water Chemistry (B.2.1.2) program implementation.
February 20, 2025 Enclosure A Page 132 of 165 The Aging Management Programs list in SLRA Section 3.5.2.1.11, Reactor Building, page 3.5-15 is revised as shown below:
Aging Management Programs The following aging management programs manage the aging effects for the Reactor Building components:
Masonry Walls (B.2.1.32)
One-Time Inspection (B.2.1.20)
Structures Monitoring (B.2.1.33)
Water Chemistry (B.2.1.2)
February 20, 2025 Enclosure A Page 133 of 165 SLRA Table 3.5.1, Summary of Aging Management Evaluations for the Structures and Component Supports, page 3.5-93 is revised as shown below:
3.5.1-085 Structural bolting Loss of material due to pitting, crevice corrosion AMP XI.M2, "Water Chemistry," and AMP XI.S3, "ASME Section XI, Subsection IWF" No Consistent with NUREG-2191 with exceptions. The Water Chemistry (B.2.1.2) program will be used to manage loss of material of stainless steel bolting for structural applications in the spent fuel pool (i.e., liner structures and gates) exposed to treated water in the Reactor Building.
Exceptions apply to the NUREG-2191 recommendations for Water Chemistry (B.2.1.2) program implementation.
Not Used.
This component, material, environment, and aging effect combination is addressed by Item Number 3.5.1-090.
February 20, 2025 Enclosure A Page 134 of 165 SLRA Table 3.5.2-11, Reactor Building Summary of Aging Management Evaluation, page 3.5-175 is revised as shown below:
Table 3.5.2-11 Reactor Building Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Bolting (Structural) Structural Support Stainless Steel Bolting Treated Water Loss of Material One-Time Inspection (B.2.1.20)
VII.A2.A-98 3.3.1-125 C
Water Chemistry (B.2.1.2)
III.B1.2.TP-232 VII.A2.A-98 3.5.1-085 3.3.1-125 B D, 1 Loss of Preload Structures Monitoring (B.2.1.33)
III.A2.TP-261 3.5.1-088 A
Plant specific note 1 for SLRA Table 3.5.2-11, Reactor Building Summary of Aging Management Evaluation, page 3.5-182 is revised as shown below:
Plant Specific Notes:
- 1. The spent fuel pool water level and chemistry are monitored in accordance with Technical Specifications. Leakage from the spent fuel pool is monitored in accordance with procedures. Therefore, the One-Time Inspection (B.2.1.21) program is not required with the Water Chemistry (B.2.1.2) program for this component type.
February 20, 2025 Enclosure A Page 135 of 165 Change # 31 - In-Situ Attenuation Testing of the Unit 2 Spent Fuel Pool Racks Affected SLRA Sections: A.2.1.26, Table A.5, B.2.1.26 Affected SLRA Page Numbers: A-29, A-80, B-143 Description of Change:
SLRA Sections A.2.1.26, B.2.1.26 and Table A.5 are being revised to include an enhancement to perform in-situ attenuation testing on the Unit 2 spent fuel pool racks in accordance with NEI 16-03-A Revision 1 guidance.
Accordingly, SLRA Appendix A, Section A.2.1.26, Appendix A, Section A.5, and Appendix B, Section B.2.1.26 are revised.
February 20, 2025 Enclosure A Page 136 of 165 SLRA Appendix A, Section A.2.1.26, Monitoring of Neutron-Absorbing Materials Other than Boraflex, page A-29 is revised as shown below:
A.2.1.26 Monitoring of Neutron-Absorbing Materials Other Than Boraflex The Monitoring of Neutron-Absorbing Materials Other Than Boraflex aging management program is an existing condition monitoring program that includes periodic inspection, testing, monitoring, and analysis of test coupons of the neutron-absorbing material in the spent fuel storage racks to ensure that a 5% sub-criticality margin in the spent fuel pool is maintained during the subsequent period of extended operation. The program consists of inspecting the physical condition of the neutron-absorbing material, such as visual appearances, dimensional measurements, weight, geometric changes (e.g., formation of blisters, pits, and bulges) and boron areal density as observed from coupons or in-situ techniques to monitor for loss of material, changes in dimension, and loss of neutron-absorption capacity of the material. Spent fuel pool neutron absorbing material that does not have test coupons will have in-situ attenuation testing performed to identify whether loss of B10 is occurring.
The Monitoring of Neutron-Absorbing Materials Other Than Boraflex aging management program will be enhanced to:
- 1. Perform in-situ attenuation testing per NEI 16-03-A Rev 1 guidance at a frequency not to exceed 10 years on the Unit 2 spent fuel pool rack (Boral material) during the subsequent period of extended operation to identify whether loss of B10 is occurring. The first in-situ attenuation test of Boral material will be performed within three years of entering the subsequent period of extended operation. In-situ test results found outside of the established criteria will be entered into the corrective action program for engineering evaluation.
The program will be enhanced no later than six months prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 137 of 165 SLRA Appendix B, Section B.2.1.26, Monitoring of Neutron-Absorbing Materials Other than Boraflex, page B-143, is revised as shown below:
B.2.1.26 Monitoring of Neutron-Absorbing Materials Other Than Boraflex Program Description The Monitoring of Neutron-Absorbing Materials Other than Boraflex aging management program is an existing condition monitoring program that includes periodic inspection, testing, monitoring, and analysis of test coupons of the neutron-absorbing material in the spent fuel storage racks to ensure that the required 5% sub-criticality margin is maintained. This program consists of inspecting the physical condition of the neutron-absorbing material for visual appearance, dimensional measurements, weight, geometric changes (e.g., blistering, corrosion, and pitting), and boron areal density as observed from coupons or in-situ techniques, to monitor for reduction of neutron absorbing capacity, loss of material, and change in dimension.
The Monitoring of Neutron-Absorbing Materials Other than Boraflex aging management program monitors changes in physical characteristics of the material in the spent fuel storage racks through visual inspections, dimensional measurements, neutron-attenuation testing, weight, and density measurements of test coupons. The test coupons are made from the same material as used in the spent fuel racks.
Results of each coupon surveillance are documented and retrievable. Acceptance criteria thresholds are established as indicators of potential adverse trends in the condition of the neutron-absorbing material to ensure corrective actions are taken prior to compromising the 5% sub-criticality margin as contained within the spent fuel pool criticality analysis.
Spent fuel pool Boral neutron absorbing material that does not have test coupons will have in-situ attenuation testing performed to identify whether loss of B10 is occurring.
NUREG-2191 Consistency The Monitoring of Neutron-Absorbing Materials Other Than Boraflex aging management program iswill be consistent with the ten elements of aging management program XI.M40, Monitoring of Neutron-Absorbing Materials Other Than Boraflex, specified in NUREG-2191.
Exceptions to NUREG-2191 None.
February 20, 2025 Enclosure A Page 138 of 165 Enhancements None.
In the elements identified below, the Monitoring of Neutron-Absorbing Materials Other Than Boraflex program will be enhanced to:
- 1. Perform in-situ attenuation testing per NEI 16-03-A Rev 1 guidance at a frequency not to exceed 10 years on the Unit 2 spent fuel pool rack (Boral material) during the subsequent period of extended operation to identify whether loss of B10 is occurring. The first in-situ attenuation test of Boral material will be performed within three years of entering the subsequent period of extended operation. In-situ test results found outside the established criteria will be entered into the corrective action program for engineering evaluation. Program Elements Affected: Scope of Program (Element 1), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), and Acceptance Criteria (Element 6).
The program will be enhanced no later than six months prior to the subsequent period of extended operation.
February 20, 2025 Enclosure A Page 139 of 165 SLRA Table A.5, Subsequent License Renewal Commitment List, Item 26, Monitoring of Neutron-Absorbing Materials Other than Boraflex, on page A-80 is revised as shown below:
Table A.5 SUBSEQUENT LICENSE RENEWAL COMMITMENT LIST NO.
PROGRAM OR TOPIC COMMITMENT IMPLEMENTATION SCHEDULE SOURCE 26 Monitoring of Neutron-Absorbing Materials Other than Boraflex Existing program is credited.
Monitoring of Neutron-Absorbing Materials Other than Boraflex is an existing program that will be enhanced to:
- 1. Perform in-situ attenuation testing per NEI 16-03-A Rev 1 guidance at a frequency not to exceed 10 years on the Unit 2 spent fuel pool rack (Boral material) during the subsequent period of extended operation to identify whether loss of B10 is occurring. The first in-situ attenuation test of Boral material will be performed within three years of entering the subsequent period of extended operation. In-situ test results found outside the established criteria will be entered into the corrective action program for engineering evaluation.
Ongoing Program will be enhanced no later than six months prior to the subsequent period of extended operation.
Section A.2.1.26
February 20, 2025 Enclosure A Page 140 of 165 Change # 32 - Revision to Aging Management Review for the ECCS Suction Strainers Affected SLRA sections: Table 3.2.2-5 Affected SLRA Page Numbers: 3.2-101, 3.2-102, and 3.2-103 Description Change:
SLRA Table 3.2.2-5 is being revised to credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24) program to perform periodic inspections for loss of material of the ECCS suction strainers.
Accordingly, SLRA Table 3.2.2-5 is revised as shown below.
February 20, 2025 Enclosure A Page 141 of 165 SLRA Table 3.2.2-5 Low Pressure Coolant Injection System Summary of Aging Management Evaluation, page 3.2-101 is revised as shown below:
Table 3.2.2-5 Low Pressure Coolant Injection System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Piping, piping components Pressure Boundary Carbon Steel Treated Water (External)
Loss of Material Water Chemistry (B.2.1.2)
V.D2.EP-60 3.2.1-016 B
Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24)
V.D2.EP-60 3.2.1-016 E, 1 Treated Water (Internal)
Cumulative Fatigue Damage TLAA V.D2.E-10 3.2.1-001 A, 3 Long-Term Loss of Material One-Time Inspection (B.2.1.20)
V.D2.E-434 3.2.1-090 A
Loss of Material One-Time Inspection (B.2.1.20)
V.D2.EP-60 3.2.1-016 A
Water Chemistry (B.2.1.2)
V.D2.EP-60 3.2.1-016 B
Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24)
V.D2.EP-60 3.2.1-016 E, 1
February 20, 2025 Enclosure A Page 142 of 165 SLRA Table 3.2.2-5 Low Pressure Coolant Injection System Summary of Aging Management Evaluation, page 3.2-102 is revised as shown below:
Table 3.2.2-5 Low Pressure Coolant Injection System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Strainer (Element)
Filter Stainless Steel Treated Water (External)
Flow Blockage Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24)
H, 1 Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24)
One-Time Inspection (B.2.1.20)
V.D2.EP-73 3.2.1-022 H, 1 A Water Chemistry (B.2.1.2)
V.D2.EP-73 3.2.1-022 B
February 20, 2025 Enclosure A Page 143 of 165 Plant specific note number 1 for SLRA Table 3.2.2-5 Low Pressure Coolant Injection System Summary of Aging Management Evaluation, page 3.2-103 is revised as shown below:
Plant Specific Notes:
- 1. The ECCS suction strainers and associated flanges will be managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24) program as routine inspections are performed to detect loss of material and flow blockage. Flow blockage due to fouling in the ECCS suction strainers will be managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24) program.
February 20, 2025 Enclosure A Page 144 of 165 Change # 33 - Flow Blockage of Stainless Steel Nozzles in the Fire Protection System Affected SLRA Sections: Table 3.3.1 and Table 3.3.2-8 Affected SLRA Page Numbers: Page 3.3-88 and 3.3-196 Description of Change:
SLRA Table 3.3.2-8 is being revised to add flow blockage as an aging affect for stainless steel spray nozzles in a condensation environment in the Fire Protections System. Associated changes to the SLRA Table 3.3.1, Item Number 130 are also being made.
Accordingly, SLRA Table 3.3.1 and Table 3.3.2-8 are revised as shown below.
February 20, 2025 Enclosure A Page 145 of 165 Table 3.3.2-8, Fire Protection System, Summary of Aging Management Evaluation, page 3.3-196 is revised as shown below.
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Spray Nozzles Spray Stainless Steel Condensation Cracking One-Time Inspection (B.2.1.20)
VII.G.AP-209a 3.3.1-004 C, 2 Flow Blockage Fire Water System (B.2.1.16)
VII.G.A-403 3.3.1-130 B
Loss of Material One-Time Inspection (B.2.1.20)
VII.G.AP-221a 3.3.1-006 C, 2 Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems, Item Number 130, page 3.3-88 is revised as shown below.
Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/
Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.3.1-130 Metallic sprinklers exposed to air, condensation, raw water, raw water (potable),
treated water Loss of material due to general (where applicable), pitting, crevice corrosion, MIC (except for aluminum, and in raw water, raw water (potable),
treated water only);
flow blockage due to fouling AMP XI.M27, "Fire Water System" No Consistent with NUREG-2191 with exceptions. The Fire Water System (B.2.1.16) program will be used to manage flow blockage and loss of material of the copper alloy and stainless steel spray nozzles and sprinkler heads exposed to condensation and raw water in the Fire Protection System.
Exceptions apply to the NUREG-2191 recommendations for the Fire Water System (B.2.1.16) program implementation.
February 20, 2025 Enclosure A Page 146 of 165 Change # 34 - Updates to Fire Water System Program Appendix A and B Affected SLRA Sections: A.2.1.16, B.2.1.16 Affected SLRA Page Numbers: Pages A-20, B-94, B-95, B-99 Description of Change: SLRA Section A.2.1.16 is revised to add condensation as an environment for components managed by the program. In addition, the justification for Exception 1 in SLRA Section B.2.1.16 is revised to provide additional information regarding alternative inspections and tests that are performed in place of the main drain testing recommended in NUREG-2191, AMP XI.M27 and to correct a typographical issue regarding the number of main drain tests that are currently performed. The justification for Exception 2 in SLRA Section B.2.1.16 is also revised to provide information regarding the performance based evaluation (PBE), the NEIL section for using the performance based approach, and the results of the most recent three strainer inspections. Finally, operating experience example number 5 in SLRA Section B.2.1.16 is revised to provide additional information regarding actions taken to ensure DNPS does not have any portions of in scope fire protection systems that are normally dry but periodically wetted that cannot be drained or allow water to collect.
Accordingly, SLRA Section A.2.1.16 and B.2.1.16 are updated.
February 20, 2025 Enclosure A Page 147 of 165 The second paragraph in SLRA Section A.2.1.16 Fire Water System, page A-20 is revised as shown below.
The program applies to water-based fire protection systems that consist of sprinklers, fittings, valves, hydrants, hose stations, standpipes, pumps, and aboveground and buried piping and components. The program manages aging of fire protection system components exposed to raw water and condensation environments. Aging of the external surfaces of buried fire main piping is managed as described in the Buried and Underground Piping aging management program
February 20, 2025 Enclosure A Page 148 of 165 The third and fifth paragraphs of the justification for exception number 1 in SLRA Appendix B, Section B.2.1.16, Fire Water System, page B-94 is revised as shown below:
While NFPA 25 and the NEIL LCM agree that the intent of main drain testing is to identify valve misalignment or other major obstructions, the application of the test differs between the two sources. The NEIL LCM, written specifically for the highly regulated nuclear industry, identifies the potential hazardous and unique challenges associated with performing main drain testing of nuclear power plant fire suppression systems and includes an allowance to omit main drain testing if one of three conditions are met. The allowance requires the performance of various other tests and inspection (e.g., valve position verification and cycling, flow tests, flushes, and suppression system inspection) which, in place of the main drain test, ensures that no major obstructions exist in the fire suppression system piping. The first condition requires the performance of the following tests and inspections: fire water valve position verification, fire protection valve cycling, annual fire protection loop flow test, fire suppression water system flow test, fire protection water system flush, hydrant flush, post indicator valve testing, and wet pipe, deluge, and preaction system inspections. The second condition is if the fire suppression system is fed from two or more directions (dual feed systems) such that the failure of one isolation valve will not impair the system and the long runs of pipe are flow tested under other surveillance. The third condition is that for single feed systems with multiple suppression systems on the same header, a main drain test of the most remote system will satisfy the main drain test for all systems on that header. The Dresden fire protection system is fed from two directions so that any major obstruction in the system would not impact supply to any part of the system. In addition, all of the tests and inspections listed in the first condition are performed with the exception of the annual flow test. The flow test is done on a five year frequency. The multi-direction fire system configuration and the testing and inspections are an acceptable alternative to the main drain test.
By review of the friction loss equations, the capability of main drain testing is limited to identification of major obstructions because the flow rates achieved during main drain testing are relatively low due to the small size of the main drain valves as compared to system supply headers and risers. As such, main drain testing is not an effective method to identify age-related flow blockage which typically results in partial restriction of supply piping and increased hydraulic resistance of the flow path due to fouling. While main drain testing is not an effective method to detect age-related flow blockage, the NRC approved DNPS fire protection program includes full flow testing of the system supply headers which would adequately identify partial restrictions of supply piping and increased hydraulic resistance of the system. The results of the systemwide flow testing are trended and compared to the system hydraulic analysis to ensure that adequate flow is available to fire suppression systems.
Dresden Nuclear Power Station manages the fire water supply and performs testing and inspections in accordance with its NRC approved fire protection program as
February 20, 2025 Enclosure A Page 149 of 165 supplemented by additional NEIL requirements. Systems omitted from main drain testing share a common supply with tested systems. A review of DNPS OE did not identify a history of major obstructions in fire water piping that would be detectable by main drain tests. In addition, flow alarm tests via the inspectors test connections verify these systems are not inadvertently isolated or blocked by a non-system isolation valve closure. Therefore, given the rigorous regime of alternative tests, inspections, and OE, reasonable assurance is provided that major obstructions to the supply of the in scope systems would be identified during the 53 47 main drain tests that are currently performed.
February 20, 2025 Enclosure A Page 150 of 165 The first paragraph of the justification for exception number 2 in SLRA Appendix B, Section B.2.1.16, Fire Water System, page B-95 is revised as shown below:
Since the Fire Protection System is a stagnant system, there is normally no flow through the system strainers. Therefore, buildup of sedimentation or debris on the strainers is unlikely. The system strainers only experience flow during automatic system actuation, periodic flow testing, or flushing and inspections are performed following these activities. In addition, a review of the last eleven (11) years of inspection results for Fire Protection System mainline strainers for the water spray fixed systems (over 60 total inspections) has identified zero instances of flow blockage. Finally, aAny potential flow blockage of the strainers would be identified during periodic testing of systems subject to flow testing. Finally, a Performance Based Evaluation (PBE) was performed in accordance with the requirements of the NEIL Loss Control Manual, section 4.2.8.7, Performance Based Surveillance Frequencies. This PBE extended the frequencies of in-line system strainers from 5 years to 6 years. For each of the applicable strainers that had a 5-year inspection frequency, the last three inspections were reviewed. The inspections were evaluated based on as-found conditions of the strainers. All strainers were either found to be as expected or better than expected condition.
Based on the inspection reviews, the proposed frequency extension was found to be acceptable.
February 20, 2025 Enclosure A Page 151 of 165 The first paragraph of operating experience example number 5 in SLRA Appendix B, Section B.2.1.16, Fire Water System, page B-99 is revised as shown below:
- 5. DNPS performed an extent of condition review in response to Information Notice 2013-06, Corrosion In Fire Protection Piping Due To Air And Water Interaction, and documented the reviews in the corrective action program. Six action requests were generated to investigate the six systems there were potentially affected by this information notice. Of these, three systems were identified as requiring correction to either the slope of piping or a reconfiguration of drainage. In addition, opportunistic internal inspections were performed on each of the three affected systems to validate the health of the preaction systems while the piping was open. The inspections were performed on the limiting locations of the systems (low points) by removal of sprinkler heads and identified satisfactory conditions. As a result of the NEI 13-06 walkdowns and subsequent actions taken to address the issues identified in the three preaction systems, DNPS does not have any portions of in scope fire protection systems that are normally dry but periodically wetted that cannot be drained or allow water to collect.
February 20, 2025 Enclosure A Page 152 of 165 Change # 44 - Limiting Shell Weld Fluence Clarification Affected SLRA Sections: Section 4.2.1.1 Affected SLRA Page Numbers: 4.2-6 and 4.2-7 Description Change:
SLRA Section 4.2.1.1 is being revised to remove the erroneous axial weld in Table 4.2.1.1-1 and Table 4.2.1.1-2.
Accordingly, SLRA Tables 4.2.1.1-1 and 4.2.1.1-2 are revised as shown below.
February 20, 2025 Enclosure A Page 153 of 165 SLRA Section 4.2.1.1, Reactor Pressure Vessel Neutron Fluence Analyses, Pages 4.2-6 and 4.2-7 is revised as shown below:
Table 4.2.1.1-1 Unit 2 - Maximum Neutron Fluence (>1.0 MeV) in RPV Beltline at 67 EFPY (n/cm2)
Component 0T 1/4T Shell Ring 1 Shell Ring 1 Plates:
3.91E+17 2.71E+17 Shell Ring 1 Limiting Axial Weld 3.84E+17 2.66E+17 Shell Ring 1 to Shell Ring 2 Girth Weld Girth Weld 3.91E+17 2.71E+17 Shell Ring 2 Shell Ring 2 Plates:
5.61E+17 3.88E+17 Shell Ring 2 Limiting Axial Weld C2873-1 5.61E+17 3.88E+17
February 20, 2025 Enclosure A Page 154 of 165 Table 4.2.1.1-2 Unit 3 - Maximum Neutron Fluence (>1.0 MeV) in RPV Beltline at 67 EFPY (n/cm2)
Component 0T 1/4T Shell Ring 1 Shell Ring 1 Plates:
3.88E+17 2.69E+17 Shell Ring 1 Limiting Axial Weld 3.80E+17 2.63E+17 Shell Ring 1 to Shell Ring 2 Girth Weld Girth Weld 3.88E+17 2.69E+17 Shell Ring 2 Shell Ring 2 Plates:
5.56E+17 3.85E+17 Shell Ring 2 Limiting Axial Welds C2873-1 5.56E+17 3.85E+17
February 20, 2025 Enclosure A Page 155 of 165 Change # 45 - Update to Aging Effects for Components in the Cranes, Hoists, and Refueling Equipment System Affected SLRA sections: Table 3.3.2-5 Affected SLRA Page Numbers: 3.3-155 Description Change:
SLRA Table 3.3.2-5 is being revised to add the cracking aging effect for component types Crane/Hoist: Refueling Platform and Crane/Hoist: Scorpion II Work Platform.
Accordingly, SLRA Table 3.3.2-5 is revised as shown below.
February 20, 2025 Enclosure A Page 156 of 165 SLRA Table 3.3.2-5, Page 3.3-155 is revised as shown below:
Table 3.3.2-5 Cranes, Hoists, and Refueling Equipment System Summary of Aging Management Evaluation Table 3.3.2-5 Cranes, Hoists, and Refueling Equipment System Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Crane/Hoist:
Refueling Platform Structural Support Carbon Steel Air - Indoor, Uncontrolled (External)
Cracking Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13)
VII.B.A-07 3.3.1-052 A
Deformation Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13)
VII.B.A-07 3.3.1-052 A
Loss of Material Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13)
VII.B.A-07 3.3.1-052 A
February 20, 2025 Enclosure A Page 157 of 165 Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Crane/Hoist:
Scorpion II Work Platform Structural Support Carbon Steel Air - Indoor, Uncontrolled (External)
Cracking Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13)
VII.B.A-07 3.3.1-052 A
Deformation Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13)
VII.B.A-07 3.3.1-052 A
Loss of Material Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13)
VII.B.A-07 3.3.1-052 A
February 20, 2025 Enclosure A Page 158 of 165 Change # 46 - Fire Protection AMR Updates Affected SLRA sections: Table 3.3.2-8 Affected SLRA Page Numbers: 3.3-185 Description Change:
SLRA Table 3.3.2-8 is being revised to include stainless steel as a material for the clamps utilized in ceramic blanket fire stops and to conservatively add the aging effects of cracking and delamination, separation and change in material properties for the gypsum Fire Barriers (Penetration Seals and Fire Stops).
Accordingly, SLRA Table 3.3.2-8 is revised as shown below.
February 20, 2025 Enclosure A Page 159 of 165 SLRA Table 3.3.2-8, Fire Protection Summary of Aging Management Evaluation, page 3.3-185 is revised as shown below:
Table 3.3.2-8 Fire Protection System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Fire Barriers (Penetration Seals and Fire Stops)
Fire Barrier Gypsum Air - Indoor, Uncontrolled (External)
Cracking and Delamination Fire Protection (B.2.1.15)
F, 1 Loss of Material Fire Protection (B.2.1.15)
F, 1 Change in Material Properties Fire Protection (B.2.1.15)
F, 1 Separation Fire Protection (B.2.1.15)
F, 1 Table 3.3.2-8 Fire Protection System (Continued)
Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Programs NUREG-2191 Item NUREG-2192 Table 1 Item Notes Fire Barriers (Penetration Seals and Fire Stops)
Fire Barrier Stainless Steel Air - Indoor, Uncontrolled (External)
Cracking One-Time Inspection (B.2.1.20)
VII.G.AP-209a 3.3.1-004 C
Loss of Material Fire Protection (B.2.1.15)
VII.G.A-789 3.3.1-255 C
February 20, 2025 Enclosure A Page 160 of 165 Change # 47 -Evaluation of Stainless Steel Diesel Exhaust Components Affected SLRA Sections: B.2.1.24 Affected SLRA Page Numbers: B-135 Description Change:
SLRA Section B.2.1.24 is being revised to summarize the evaluation performed to demonstrate that visual inspections for external leakage will identify cracking prior to loss of intended function.
Accordingly, SLRA section B.2.1.24 is revised as shown below.
February 20, 2025 Enclosure A Page 161 of 165 The first paragraph of SLRA Section B.2.1.24 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, page B-135 is revised as shown below:
B.2.1.24 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Description The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new condition monitoring program that will manage loss of material and cracking of metallic components, as well as loss of material, cracking, blistering, hardening and loss of strength of elastomeric materials. Reduction of heat transfer and flow blockage will also be managed. This program will consist of visual inspections of internal surfaces of piping, piping components, ducting, heat exchanger components, polymeric and elastomeric components, and other mechanical components. Applicable environments include air, condensation, closed cycle cooling water, diesel exhaust, lubricating oil, raw water, treated water, and waste water. Visual inspections for leakage or surface cracks will be performed to detect cracking of stainless steel components exposed to a diesel exhaust environment as the detection of staining on the component external surface demonstrates the ability to detect leakage. The function of the exhaust lines is to provide a flow path for discharge of exhaust gases outside the building. This is primarily for personnel protection (which is not an intended function for subsequent license renewal) but also to ensure exhaust gases do not affect operation of the diesels. The diesel engines either draw combustion air from outside of the buildings in which the diesel engines are housed or are located in well-ventilated areas in which an exhaust leak would not challenge the ability of the diesel engine to operate. Further, the in-scope diesel generators and diesel-driven pumps are subject to frequent testing. Exhaust leakage would be detected during periodic testing activities either by visually detectable smoke or by the odor of exhaust leakage. The exhaust line components susceptible to cracking are limited to bellows type expansion joints where internal inspection for cracking would not be feasible. These exhaust lines are not subject to high pressures where rupture would be likely, even if cracking were to go undetected and it is unlikely that even a rupture would impact the operation of the diesels since, as stated above, the diesels either draw combustion air from outside the building or are located in well-ventilated areas. An evaluation will be performed that demonstrates that cracks will be detected prior to challenging the structural integrity or intended function of the component. Except for hardening and loss of strength of elastomers, aging effects associated with components within the scope of the Open-Cycle Cooling Water System (B.2.1.11) program, Closed Treated Water Systems (B.2.1.12) program, and Fire Water System (B.2.1.16) program will not be managed by this program.
February 20, 2025 Enclosure A Page 162 of 165 Change # 60 - Clarification of Fire Protection Program Description Affected SLRA sections: A.2.1.15 and B.2.1.15 Affected SLRA Page Numbers: A-19 and B-89 Description Change:
SLRA Sections A.2.1.15 and B.2.1.15 are being revised to eliminate redundant mention of low-pressure carbon dioxide system visual inspections and functional testing. Additionally, the halon fire suppression system is added to the first paragraph of SLRA Section B.2.1.15 for consistency.
Accordingly, SLRA Sections A.2.1.15 and B.2.1.15 are revised as shown below.
February 20, 2025 Enclosure A Page 163 of 165 SLRA Section A.2.1.15, Fire Protection, page A-19 is revised as shown below:
A.2.1.15 Fire Protection The Fire Protection aging management program is an existing condition monitoring and performance monitoring program that includes fire barrier visual inspections and low-pressure carbon dioxide system visual inspections and functional testing. The fire barrier inspection program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, floors, fire dampers, and other materials that perform a fire barrier function. Periodic visual inspection and functional testing of the fire rated doors is performed to ensure that their functionality is maintained, and aging effects managed. The program also includes visual inspections and periodic functional tests of the low-pressure carbon dioxide and halon fire suppression systems using the National Fire Protection Association Codes and Standards for guidance.
The first paragraph of SLRA Section B.2.1.15, Fire Protection, page B-89 is revised as shown below:
B.2.1.15 Fire Protection Program Description The Fire Protection aging management program is an existing condition and performance monitoring program that manages the identified aging effects for the fire barriers, halon suppression system, and the low-pressure carbon dioxide systems and associated components in air-indoor uncontrolled and air-outdoor environments using periodic inspections and functional testing to detect aging effects prior to loss of intended functions. System functional tests and inspections are performed in accordance with guidance from National Fire Protection Association Codes and Standards. The program applies to piping, piping components, spill retaining curbs, and fire barriers (doors and dampers, penetration seals, walls, and slabs). Fire Protection component materials consist of carbon steel, galvanized steel, concrete, concrete block, grout, subliming and cementitious fireproofing, elastomers, and aluminum silicate.
February 20, 2025 Enclosure A Page 164 of 165 Change # 62 - Loss of Preload of HVAC Closure Bolting Affected SLRA sections: B.2.1.23 Affected SLRA Page Numbers: B-131 Description Change:
Appendix B is being revised to document that loss of preload of HVAC closure bolting is not an applicable aging effect and will not be managed by the External Surfaces Monitoring of Mechanical Components program.
Accordingly, SLRA section B.2.1.23 is revised as shown below.
February 20, 2025 Enclosure A Page 165 of 165 The first paragraph of SLRA Section B.2.1.23, External Surfaces Monitoring of Mechanical Components, Page B-131 is revised as shown below:
B.2.1.23 External Surfaces Monitoring of Mechanical Components Program Description The External Surfaces Monitoring of Mechanical Components aging management program is a new condition monitoring program that will consist of visual inspections that are performed during system inspections and walkdowns.
The program will consist of periodic visual inspections of metallic, elastomeric, and polymeric components such as piping, piping components, ducting, ducting components, and other components within the scope of license renewal. There are no cementitious components in the scope of this program. The program will manage aging effects through visual inspection of external surfaces for evidence of loss of material of metallic components, as well as loss of material, cracking, blistering, hardening and loss of strength for elastomers and polymers, and reduced thermal insulation resistance. Visual inspections will be augmented by physical manipulation to confirm the absence of hardening and loss of strength of elastomers. HVAC closure bolting is typically not associated with gasketed joints or flanges and is not subject to any appreciable preloads. Therefore, loss of preload is not an applicable aging effect for HVAC closure bolting.
This program does not manage reduction of heat transfer due to fouling for heat exchanger internal surfaces exposed to air. This aging effect for this component type and environment will be managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.24) program.