ML24193A128
| ML24193A128 | |
| Person / Time | |
|---|---|
| Issue date: | 02/20/2025 |
| From: | Christian Araguas NRC/RES/DE |
| To: | |
| Chris Nellis 301-415-5973 | |
| Shared Package | |
| ML25036A025 | List: |
| References | |
| Download: ML24193A128 (24) | |
Text
1 Internal and External Elicitation Summary 1
Introduction The transition break size (TBS) was originally developed for the revision of the emergency core cooling system (ECCS) requirements in the proposed Risk-Informed Changes to Loss-of-Coolant Accident Technical Requirements (10 CFR 50.46a), as described in SECY-10-0161.
The technical basis for the TBS is principally based on the results in NUREG-1829, NUREG-1903, and the analyses articulated within the Statements of Considerations contained in the proposed final rule. While this rule was not enacted, the TBS concept is also being used in the current Increased Enrichment (IE) rulemaking. Both internal and external elicitations were conducted to evaluate both the completeness and continued validity of the TBS technical basis since its initial development in the 2007 to 2010 timeframe. These elicitations are meant to complement the other activities described in the White Paper on Continued Applicability of NUREG-1829 (ML24205A015). This will be referred to as the NUREG-1829 White Paper throughout the remainder of this report.
1.1 Motivation NUREG-1829 was based on an expert elicitation process to develop LOCA frequencies. Expert elicitation is a formal process for providing quantitative estimates for the frequency of physical phenomena when the required data is sparse and when the subject is too complex to accurately model. Elicitation has been used at the NRC on many occasions in various applications, such as developing seismic hazard curves, performance assessments associated with the high-level radioactive waste repository, and determining reactor pressure vessel flaw distributions. The NUREG-1829 effort gathered a panel of external panelists who had broad ranging expertise in relevant technical specialties, such as probabilistic fracture mechanics (PFM), piping design, probabilistic risk assessment (PRA), piping fabrication, operating experience, materials, full-scale component testing, degradation mechanisms, degradation mitigation practices, stress analysis, and nondestructive evaluation.
The elicitation approach used for NUREG-1829 was piloted using an internal panel of NRC staff. This pilot was essential for identifying weaknesses and necessary refinements for the formal process. The internal responses and results were also used to develop questions and topics for the external panel to consider. In this way, the internal and external elicitations were both synergistic and complementary. A similar combination of internal and external elicitations was conducted in this recent effort to evaluate both the completeness and continuing validity of the TBS technical basis for the IE rulemaking.
1.2 Objective of Current Elicitation One objective of both the current internal and external elicitations was to identify possible scenarios not considered, or possibly underestimated, in NUREG-1829 and NUREG-1903 that could result in reactor coolant pressure boundary (RCPB) breaches that are larger than the TBS in both PWR and BWR plants. The external elicitation enlisted two of the original NUREG-1829 panelists and thus had an additional objective to have those panelists compare their current expectations about the likelihood of a LOCA larger than the TBS with their assessment of this likelihood from the NUREG-1829 analysis.
2 2
Approach The approach consisted of the following five principal steps:
selecting appropriate internal and external panelists, formulating an initial set of questions and topics for the panelists to consider, holding a kick-off meeting with the panelists to present the objectives, background and motivation of the effort and discuss the elicitation topics and questions, conducting evaluations with each panelist of the selected topics and questions and developing the initial responses, and holding a series of follow-on meetings to collectively discuss the individual responses and determine the path forward for dispositioning any open issues revealed in the responses.
More details associated with each of these steps follows.
2.1 Panel Selection The internal panel was selected from senior NRC staff representing a diverse population of relevant subject matter expertise and organizations impacted by the IE rulemaking. The panelists possess expertise in thermal hydraulics, fuels, nucleonics, piping, structural integrity, PFM, PRA, operations and maintenance, integrity of large active components (e.g., pumps, valves, and cranes), nondestructive evaluation, aging management, materials, and seismic events. These technical areas comprise the breath of topics considered when originally developing the TBS basis and could be associated with hypothetical LOCA scenarios for break sizes greater than the TBS. The panelists also represented all relevant technical organizations in RES and NRR (i.e., engineering, risk assessment, and plant systems). The members were Steve Bajorek, Jay Collins, Matt Mitchell, John Wise, Andy Johnson, Andrew Prinaris, John Lehning, Ben Parks, Kevin Coyne, Marty Stutzke, Tom Scarborough, Amitava Ghosh, and Patrick Raynaud.
The external panel was limited to a subset of the 12 participants from the original NUREG-1829 panel. This narrow population was selected so that direct comparisons could be made between the original and current elicitation responses. Another important consideration was that each panelist needed to be active in their field of study so that they could properly assess the effect of contributing factors that have evolved since completion of NUREG-1829. Finally, it was important for the external panelists to have complementary and diverse expertise and to apply different approaches for estimating the likelihood of LOCA frequencies greater than the TBS.
This diversity was important to gauge uncertainty associated with such rare events. The external panel was composed of Dr. Gery Wilkowski and Mr. Bengt Lydell. Dr. Wilkowski has expertise in PFM; piping integrity under quasi-static and seismic loading; piping materials and fabrication; piping aging mechanisms; LBB analyses; ASME Section XI pipe flaw evaluations; and related operating experience. Mr. Lydell has expertise in PRA; passive-system reliability assessment; passive-system aging mechanisms; and related operating experience.
2.2 Elicitation Topic and Question Formulation The elicitation asked internal and external panelists to identify and describe possible failure scenarios not considered, or possibly underestimated, in NUREG-1829 and NUREG-1903 that could result in RCPB breaches that are larger than the TBS in both PWR and BWR plants. The panelists were asked to focus only on those scenarios that have the potential to lead to such large breaks and to primarily consider the impacts of knowledge, events, and related attributes
3 that have become evident since the NUREG-1829 and NUREG-1903 studies were completed in the mid-2000s. Panelists were asked to consider the possibility of direct RCPB breaks due to normal operating conditions or operational transients [e.g., associated transients without scram (ATWS), water hammer, and pressurized thermal shock (PTS)], as well as indirect RCPB breaks caused by other failures within the plant (e.g., crane drops, pump overspeed or impeller failures, and secondary-side failures).
The internal and external panelists were asked to consider both independent and possible common-cause failures and incorporate the effects of age-related degradation, improper maintenance, and human factors as causal factors, as appropriate. They were asked to consider potential failure scenarios up to 80 years of operation but focus on those scenarios that could occur over the next 10 to 15 years. This nearer-term time frame provides a more reasonable focus given the increased uncertainty associated with longer forecasts, but also because it is planned to periodically evaluate the continued efficacy of the TBS technical basis, particularly if future operating experience challenges this basis or if significant time has passed since the last evaluation. Therefore, subsequent reevaluations of the technical basis can focus on the impact of events and research since the prior evaluation.
In addition to identifying and describing possible LOCA failure scenarios, the internal panelists were asked whether each scenario is novel or whether it has been previously evaluated by the NRC and to identify internal expertise that could be useful for further evaluation. Finally, if the internal panelists provided multiple possible LOCA failure scenarios, they were asked to rank their perceived likelihood of the scenarios from highest to lowest and to provide the supporting rationale. The internal panelist questions are provided in Appendix A.
The external panelists were also asked to describe the scenarios and identify important causal factors, discuss the importance of age-related degradation, and identify the operating time associated with each scenario. They were also tasked with assessing the generic applicability of each scenario by determining if the scenario is associated with both PWR and BWR plants or if there are specific plant attributes that could lead to that scenario. The panelists were also asked to rank the relative likelihood of each scenario.
The external panelists were further asked to assess the current likelihood of RCPB failures that are both smaller than and larger than the TBS and compare these estimates with their original NUREG-1829 elicitation responses. The objective was to solicit their opinion concerning the direction and magnitude of LOCA frequency trends over the last 20 years and identify the principal contributing factors supporting these opinions. Here, trends in LOCA frequencies both smaller and larger than the TBS were of interest to determine if the experts believe there are any reasons to support such perceived differences. The external panelist questions are provided in Appendix A.
2.3 Kick-off Meetings Separate internal and external panel kick-off meetings were held. The internal panel kick-off meeting was more extensive, because most of the staff participants were not familiar with the TBS technical basis or the proposed IE rulemaking that utilized the TBS concept. Therefore, the objectives of the internal panel kick-off meeting were as follows:
provide an overview of the proposed IE rulemaking effort, summarize the technical basis supporting the TBS,
4 articulate the objective and scope of the internal elicitation, present and discuss the elicitation questions, solicit responses to the elicitation questions, and describe the path forward.
The bulk of the meeting summarized the proposed rulemaking effort and the TBS technical basis. The NUREG-1829 and NUREG-1903 studies were described along with other supporting rationale used to select the TBS. The use of the TBS within the proposed rulemaking was also described along with the premise that a similar TBS concept is employed for the proposed IE rulemaking. The original draft regulatory guidance (i.e., DG-1216) was also summarized. This DG provides acceptable approaches for plants to demonstrate applicability of the TBS technical basis and assess the effects of proposed plant changes. The path forward required panelists to provide their responses within a few weeks and to participate in wrap-up meetings to summarize responses and solicit feedback on dispositioning responses.
The external panelists had prior knowledge of both the TBS technical basis along with its use within the initially proposed 10 CFR 50.46a risk-informed rulemaking (i.e., SECY-10-0161).
Therefore, their kick-off meeting focused solely on discussing the elicitation questions and path forward as in the internal panel meeting. The external panelists also provided some initial thoughts on the elicitation questions during the meeting.
2.4 Individual evaluations After the kick-off meeting, the internal panelists completed their individual evaluations. The responses were collated by the elicitation facilitators (Rob Tregoning and Eric Palmer), who also provided some initial proposals for dispositioning each response. The proposed dispositions were used to spur discussion among the panelists during the wrap-up meetings. The collated responses and proposed dispositions were provided to the panelists in advance of the wrap-up meetings to support this discussion. The external panelists also conducted individual evaluations, and their responses were shared with the other panelists in advance of the wrap-up meetings.
2.5 Wrap-up meetings The internal wrap-up meetings collectively reviewed each individual response and its proposed disposition. The panelists provided more insights on their responses; associated causal and mitigative considerations were also discussed. The proposed disposition was then reviewed and modified as needed. The final disposition plan for each response was determined through general group consensus and agreement by the response submitter. The external wrap-up meetings were also used to discuss each individual response in more detail. Each external panelist also provided feedback and some additional considerations pertaining to the other panelists responses. There was no discussion on how best to disposition responses at the external wrap-up meetings as this is an essential NRC staff function.
3 Summary of Responses 3.1 Internal Elicitation Responses and Disposition There are 21 separate topics or scenarios that were identified for consideration by the internal panelists. Several of these topics or scenarios have sub-issues or contributing factors. These topics or scenarios are subsequently described and, if appropriate, causal factors are identified.
5 Disposition of the issue is then provided along with any implications on the proposed IE rulemaking. Any open items requiring additional technical evaluation are also identified.
Piccolo Breaks Issue description: A piccolo break describes when a small pipe whips and causes ruptures in nearby piping such that the resulting break is larger than the TBS. Examples would be a residual heat removal (RHR) break causing an accumulator line rupture or a pressurizer line rupture causing a failure in a nearby line.
Disposition: Such dynamic effects are required to be considered and addressed under GDC 4.
This requirement will not be modified by the proposed IE rulemaking. Additionally, SRP 3.6.2 provides guidance for both design and analysis considerations to provide assurance that such breaks will not occur unless the line is approved for LBB under SRP 3.6.3. While this is not a generic concern, it is recognized that entities implementing the proposed IE rule need to continue to meet existing requirements. Therefore, although this issue does not impact the proposed rulemaking or the technical basis associated with the TBS, the draft applicability guidance (DG-1428) contains provisions to ensure that GDC 4 requirements continue to be met once this rule is implemented. Indirect failures are also addressed in Section 3 of the NUREG-1829 White Paper.
Pilot-Operated Relief-Valve Failure Issue description: The feedwater pump fails on a B&W plant and a pilot-operated relief valve (PORV) sticks open and either cannot be closed or the operators do not realize that its open.
Disposition: Stuck-open valve scenarios are considered in plant PRAs and the proposed rule will not affect either the likelihood, consequence, or the mitigation of those types of LOCAs.
Stuck-open valves also remain bounded by the TBS such that these events will remain within current licensing basis of plants. No further action on this issue is required.
Reactor Pressure Vessel Embrittlement Issue description: The development of a fast hardening late blooming phase at some neutron fluence level leads to a dramatic change in RPV embrittlement which is unidentified due to the sparse number of capsules being tested. Power uprates and load following at some plants also increases the possibility for subcritical crack growth of preexisting RPV defects which also increases the failure likelihood.
Disposition: RPV integrity is governed by 10 CFR 50.61 (or 10 CFR 50.61a), and Appendices G and H to Part 50, which require an industry surveillance program providing lead-time embrittlement information, and analysis of that information to provide assurance that RPV integrity is met. In addition, periodic RPV inspections provide assurance that preexisting flaw growth is not significant such that the RPV integrity is further challenged. Management of RPV embrittlement is unchanged by the proposed rule. However, the implications of this topic are addressed in Section 2.2.4 of the NUREG-1829 White Paper which concludes that underpredicting the embrittlement of the RPV, coupled with a lack of surveillance testing, may eventually impact the staffs confidence in RPV integrity for certain plants as they approach the end of the subsequent license renewal period, and beyond. SECY-22-0019 proposes rulemaking which provides mitigative measures to address this issue. If the rulemaking plan is
6 not approved, entities wishing to implement 10 CFR 50.46a will still need to demonstrate that their RPV integrity remains acceptable over the plants licensing period and it may trigger a need to reconsider the efficacy of the TBS for certain plants.
Stress Corrosion Cracking Mechanisms in the Main Loop Piping Issue description: A stress corrosion cracking (SCC) mechanism emerges in the larger, main loop piping and advances without detection until it challenges piping integrity. This situation is envisioned to occur over longer periods of time and could be exacerbated if inspections of these systems are significantly reduced or eliminated. Large undocumented repair welds or welding processes which introduce inner surface tensile stresses also contribute to the significance of this issue.
Disposition: SCC in dissimilar metal welds (DMWs) in PWR main loop piping is addressed by ASME CC N-770 while BWR-75A addresses SCC in BWR recirculation loop piping. These documents cover the initial and continued inspection for these welds for each approved mitigation technique. Therefore, it is only welds that are deemed to not be susceptible to degradation mechanisms (i.e., stainless steel PWR welds and Category A BWR welds) that could be susceptible to an emergent mechanism. Section 2.1.2 of the NUREG-1829 White Paper addresses SCC in PWRs and while there has been evidence of SCC in safety injection system welds in French plants, there has been no evidence of such cracking in either U.S. or international main loop piping systems. If a large-scale problem emerges in the future, the periodic TBS reevaluation effort will determine if there are any generic implications associated with the use of the TBS within this rule. Additionally, plant-specific concerns associated with this issue are addressed within the proposed IE rule by requiring an initial risk-informed inspection of a sample (e.g., 10%) of the highest-failure-potential main loop piping welds (in PWRs) or main recirculation loop piping welds (in BWRs) before the rule is implemented, and also requiring periodic inspection of this weld sample for continued performance monitoring.
Common-Cause Maintenance Errors Issue description: Poor maintenance practices coupled with deficient quality assurance provisions could lead to failure of a large, bolted connection (e.g., manway) or multiple relief valves failing simultaneously. A causal factor which could contribute to this issue is that licensees may continue to modify maintenance procedures to increase efficiency, and this could result in ingrained, procedural errors, similar to the reactor pressure vessel head incident at Davis Besse.
Disposition: Bolting failures have historically been a concern as evidenced by its evaluation under the generic issues program as GSI-29 during the 1980s. The early focus was on bolting degradation but the scope quickly expanded to address design, materials, fabrication, installation, in-service inspection, and quality assurance. The industry formed a task group on bolting to address these issues and developed a two-volume summary of these efforts (EPRI NP-5769), good bolting practice reference manuals, and training videos. The NRC closed the generic issue in 1991 and summarized the technical basis supporting this action in NUREG-1339. The staff concluded that while leakage of bolted pressure joints was possible, catastrophic reactor coolant pressure boundary joint failure leading to significant accident sequences was highly unlikely. Since closing this GSI, staff has developed review guidance on threaded fasteners in Section 3.13 of NUREG-0800 and the GALL reports contains aging
7 management programs for bolts in XI.M3 (Reactor Head Closure Stud Bolting) and XI.M18 (Bolting Integrity). This accumulated knowledge and guidance provides assurance that bolting design, materials, fabrication, installation, in-service inspection, and quality assurance is generically acceptable.
While plant-specific deviations and hence bolting failures remain possible, it should be recognized that bolted connections have significant redundancy such that multiple, if not all, of the bolts need to fail in larger reactor pressure boundary components (e.g., steam generator manway or reactor pressure vessel head) to cause a LOCA greater than the TBS. Leakage testing and monitoring requirements during start up make it highly unlikely that such failures would progress to such a LOCA even if a common cause bolting failure occurs. Such a scenario is described in IN 2012-021 (ML12264A518).
The scenario of common-cause maintenance errors leading to multiple relief valve failures or openings is even more unlikely because it requires consistent errors during several maintenance activities on separate components. Therefore, such multiple failures are deemed to be highly unlikely. Even though such scenarios are not expected to increase the likelihood of LOCAs greater than the TBS, the proposed rulemaking requires that plant changes implemented under the rule be risk-informed such that they result in acceptable changes in plant risk. Associated guidance (i.e., DG-1426) provides acceptable methods for performing this analysis. This plant change requirement should continue to ensure that common-cause failures which could result in a LOCA that is greater than the TBS remain highly unlikely.
Degraded Supports and Snubbers During Seismic Events Issue description: Loss of piping support or snubber functionality due to aging or improper maintenance leads to much larger piping loads than have been previously analyzed during seismic events. This loss of functionality and higher seismic loads, coupled with component aging - which can cause cracking and/or loss of fracture toughness - results in a complete pipe rupture that is greater than the TBS.
Disposition: The White Paper on Continued Applicability of NUREG-1903 (ML24323A205),
hereafter referred to as NUREG-1903 White Paper, addresses seismic risk and the likelihood that a seismic event could lead to a LOCA greater than the TBS. Licensees wishing to implement the IE rulemaking will need to demonstrate that the seismic risk associated with both direct and indirect piping failures (e.g., those resulting from support or snubber failures) that could lead to a LOCA greater than the TBS is less than an acceptable risk increase (i.e.,
significantly less than 10-5/year). This demonstration will require them to conduct a plant-specific seismic assessment accounting for any such degradation effects. Plant-walkdowns and required aging management programs are implemented to provide assurance that the seismic assessment accurately reflects the as-built and as-operated plant state, and that component aging has not significantly affected either component structural integrity or fragility. Additionally, the inspections of risk-significant welds will provide assurance that those piping welds with the most seismic risk do not have unacceptable degradation.
Increased Seismic Risk since NUREG-1903 publication Issue description: The seismic hazard curves have been revised since NUREG-1903 was published in response to the 10 CFR 50.54(f) letters related to Fukushima Near-Term Task
8 Force Recommendation 2.1. Material degradation could increase the component fragility as these effects are not typically considered. Operating time may contribute as well, as seismic fragility could decrease over time due to undetected or unmitigated degradation. It is recognized, however, that the seismic-induced likelihood of a primary coolant pressure boundary breach larger than the TBS is a plant-specific consideration and not a generic issue.
Disposition: The NUREG-1903 White Paper addresses seismic risk and the likelihood that a seismic event could lead to a LOCA greater than the TBS. Generic review of the updated seismic hazard curves information indicates that the principal NUREG-1903 results remain applicable. However, as indicated previously, licensees wishing to implement the IE rulemaking will need to demonstrate for their plants that the seismic risk associated with both direct and indirect piping failures (e.g., those resulting from support or snubber failures) that could lead to a LOCA greater than the TBS is less than an acceptable risk increase (i.e., significantly less than 10-5/year). This demonstration will require licensees to use the updated and approved seismic hazard information. The plant-specific seismic assessment shall also appropriately represent the as-built and as-operated plant state. Plant-walkdowns and required aging management programs are implemented to provide assurance that the seismic assessment accurately reflects the as-built and as-operated plant state, and that component aging has not significantly affected the fragility of passive components whose failure could result in a LOCA that exceeds the TBS. Additionally, the inspections of risk-significant welds will provide assurance that those piping welds with the most seismic risk do not have unacceptable degradation.
NRC Rulemaking Language Issue description: There is a potential inability for licensees to demonstrate that higher burnup and accident tolerant fuels are acceptable using standard design basis assumptions. There are also limited safety benefits from deployment of accident tolerant fuel. Therefore, the NRC needs to clearly state how the proposed IE rulemaking maintains a similar level of safety given that LOCA mitigation is more challenging for high burnup fuels.
Disposition: It is agreed that the motivation behind the IE rulemaking is to facilitate the use of higher burnup, increased enrichment, and accident tolerant fuels and eliminate the need to apply for exemptions to 10 CFR 50.46. However, the technical basis supporting the TBS is independent of its application within the proposed IE rulemaking and the rule has requirements to demonstrate that proposed plant changes will not invalidate this technical basis. Further, the proposed rule will contain provisions to ensure that any changes implemented under the rule result in, at most, a very small risk increases consistent with the Commission direction in SRM-SECY-97-287, which approved RG 1.174. The proposed rule contains a requirement to monitor and evaluate cumulative effects of changes implemented under to rulemaking to provide assurance that both the individual and combined changes remain acceptable. Moreover, vendors and licensees will need to receive NRC approval of their fuel design and methods to implement higher burnup and increased enrichment. The NRC has already begun topical report reviews for higher burnup and increased enrichment. During these reviews, the NRC still requires that specified acceptable fuel rod design limits are met during steady state and normal operation.
The existing design basis requirements are not being revised by this proposed rule (other than the control room dose criterion in GDC-19) and must continue to be met. For example, though high burnup and increased enrichment are expected to result in higher accident doses, the
9 existing exclusionary boundary and low population zone dose limits still must be met.
Therefore, the NRC will still provide assurance that adequate protection of safety exists for high burnup and increased enrichment fuel whether they are implemented via 50.46a or 50.46.
However, to address this concern, the staff has ensured that the motivation for this rulemaking is clearly articulated in the rulemaking package and, has highlighted that both the application review to implement the rule and the change control process to provide assurance that an adequate level of safety is maintained.
Evolution of In-service Inspection and ASME Code Relief Requests since Initially Proposed 10 CFR 50.46a Rulemaking in 2010 Issue description: This issue is concerned about the potential effects of changes in licensees in-service inspection (ISI) programs and an increase in relief request that would connote that performance monitoring has eroded since the TBS was proposed which could erode its technical basis.
Disposition: Section 2.1.3 in the NUREG-1829 White Paper addresses the generic impact of reduced inspection frequencies. As indicated in this section, there are less inspections due to the maturation of risk-informed ISI since the early 2000s and an industry effort starting in the mid-2010s to eliminate certain low-value, high-impact NDE inspections. Each of these efforts are evaluated by staff to provide assurance that remaining inspections provide acceptable performance monitoring, especially to identify general degradation issues. Section 2.4.1 of the NUREG-1829 White Paper provides an example of staffs considerations associated with a specific proposal to reduce pressurizer weld inspection frequency. As stated previously, the proposed IE rule requires an initial risk-informed inspection of a sample (e.g., 10%) of the highest-failure-potential welds in those piping systems where LOCA failures greater than the TBS are possible (i.e., the main loop piping in PWRs and the recirculation loop piping in BWRs),
and also requires periodic inspections within these systems to provide continued performance monitoring for plants implementing the proposed IE rule.
Ensuring Consistency between the Operating and Analyzed Plant Conditions Issue description: Adequate assurance is needed to demonstrate that the as-built and as-operated plant matches the plant analyzed in the risk evaluation. This may require modeling of passive system degradation and additional one-time or periodic inspections to ensure that the risk-evaluation models are acceptable.
Disposition: The elicitation supporting NUREG-1829 and the NUREG-1903 evaluation considered the effects of plant aging on LOCA frequencies. The reevaluation described in the NUREG-1829 and NUREG-1903 white papers document the continued representativeness of the results from these studies and continued efficacy of the TBS concept for use in this proposed IE rulemaking. Periodic reevaluation of the TBS technical basis is planned, particularly if future operating experience challenges this basis or if significant time has passed since the last evaluation of the TBS. Therefore, subsequent reevaluations of the TBS technical basis will be used to provide assurance that this concept remains acceptable. Concerns about the representativeness required for the risk evaluation are not unique to the IE rulemaking as this issue was extensively considered during the initially proposed 10 CFR 50.46a rulemaking (i.e., SECY-10-0161). The same provisions initially proposed in 10 CFR 50.46a to provide assurances that the risk evaluation is sufficiently representative of both the current plant
10 configuration and operating practices have been retained within this proposed IE rulemaking.
These provisions include ensuring the acceptability of the risk evaluation, as discussed in RG 1.200, and continually updating the plant risk evaluation to reflect plant changes. DG-1426 recommends that the updating periodicity not exceed five years.
Effects of Future Plant Changes on LOCA Frequencies Issue description: Future plant operational and maintenance changes could result in LOCA frequency increases that would undermine the TBS technical basis. For example, power uprates could further degrade the available margin for typical accident scenarios that challenge reactor pressure boundary as well as impact plant temperatures such that passive system degradation is accelerated. Additionally, plants could face increasing rates of loss of offsite power (LOOP) events and other upset conditions that increase the risk associated with LOCAs.
Disposition: The impact of future plant changes is not always apparent, especially for a rule like the proposed IE rule which enables broad, unprescribed plant changes. This is why one of the proposed IE rulemaking tenets requires licensees to evaluate the impact of plant changes enacted under this rule to provide assurance that they have an insignificant effect on LOCA frequencies and the TBS technical basis. Additional guidance has also been developed for demonstrating plant-specific applicability for implementing the proposed rule and evaluating the effects of plant changes to ensure that these risk-informed changes are acceptable and that the TBS remains applicable after the proposed changes. Further, as discussed previously, the proposed rule also contains provisions to provide assurances that the risk evaluation is sufficiently representative of the current plant configuration and operating practices. These provisions include ensuring the acceptability of the risk evaluation, as discussed in RG 1.200, and continually updating the Plant risk assessment to reflect plant changes. DG-1426 recommends that the updating periodicity not exceed five years.
Margin Associated with TBS Technical Basis Issue description: A concern was raised about the efficacy of the margin associated with the TBS basis given that changing it will be difficult since it will be subjected to backfit considerations once the proposed rule is in place. A related concern is how performance monitoring will be used to indicate potential erosion of the TBS technical basis.
Disposition: The TBS was selected to have appropriate margin to accommodate the possibility for future LOCA frequency increases as only a small subset of the largest and most robust piping systems will be outside of the design basis if the proposed rule is enacted. Large ruptures of these pipes are generically expected to be well below the 10-5/year acceptance criteria. The impact of general LOCA frequency increases will continue to be addressed by existing regulations and the reactor oversight process. As mentioned previously, the frequencies of LOCAs larger than the TBS will be periodically reassessed. Also, it is planned to insert a provision into the LIC-504 process to consider the impact of emergent events on the frequency of LOCAs larger than the TBS. Finally, as also discussed previously, the proposed rule requires additional inspections of a sample of circumferential welds deemed to not be susceptible to degradation mechanisms in the main loop piping in PWRs and the recirculation piping in BWRs to provide assurance that unexpected degradation isnt challenging the integrity of these systems. If these performance monitoring measures indicate that the technical basis
11 supporting the proposed TBS is no longer adequate, the backfit process will be exercised to implement appropriate changes to the TBS or the proposed rule.
Uncertainties in NUREG-1829 Issue description: The concern is that uncertainties associated with the NUREG-1829 frequencies have increased since that work was completed and that continued operation of the plant to 80 years or beyond will further increase uncertainties and erode the confidence in the TBS technical basis.
Disposition: The biggest NUREG-1829 uncertainties are driven by the expected rarity of breaks greater than the TBS. There is always significant uncertainty associated with rare event frequencies. However, as discussed in the disposition of the previous issue, there are performance monitoring activities planned under this proposed rule that are intended to provide reasonable assurances that these uncertainties remain tenable in the future. Additionally, it is expected that the uncertainties are somewhat reduced since the development of the original NUREG-1829 basis due to the currently implemented performance monitoring and mitigation programs. The extensive OE that has occurred since the 2008 timeframe has demonstrated that the current performance monitoring programs have been successful at revealing degradation before it challenges component integrity and the industry-led mitigation programs have been successful at mitigating the impacts of this degradation. Additionally, the license renewal process is predicated on demonstrating that the plants have adequate aging management programs in place to maintain their current licensing basis at an acceptable level of safety. These programs are continuously evaluated and updated to provide assurance that they remain effective regardless of the plant age.
BWR Applicability Issue description: Standardized plant analysis risk (SPAR) models on the NRC SPAR dashboard site indicate some BWRs use 1.2x10-5/year as their large break (LB) LOCA break frequency while PWRs appear to have LB LOCA less than 10-5/year. These BWR estimates are higher than the 10-5/year acceptance criterion used as the starting point for the TBS which makes it unclear how BWR plants can benefit from the rule.
Disposition: The TBS is significantly bigger than a LB LOCA break size, as defined in NUREG-1829 which can be as small as a 3 to 3 1/4 effective break diameter1. Therefore, the TBS frequency is expected to be significantly less than an LB LOCA break frequency used in a conventional plant PRA. The TBS frequency is also expected to remain well below the 10-5/year acceptance criterion which, as seen in the SPAR dash results, is associated with much smaller breaks. Based on the NUREG-1829 results, operating experience, and piping system design, the PWR TBS was selected to be approximately 12 while the BWR TBS is approximately 20.
The exact size depends on the sizes of the plant-specific piping systems used to delineate the TBS. Because the BWR TBS is greater, BWRs are anticipated to derive less benefit from the proposed IE rulemaking. This feedback was provided by industry during the original 10 CFR 50.46a rulemaking in the late 2000s. No further action on this issue is required.
1 Each plant has a unique LB LOCA size, largely arising from the fundamental differences in ECCS system design among the Nuclear Steam Supply System (NSSS) vendors. PWR LB LOCA sizes greater than equivalent 6 diameter openings are typical, but these sizes are substantially less than the TBS.
12 Maintaining Mitigative Capabilities Issue description: A principal feature of risk-informed regulation is the philosophy to maintain a balance between mitigation and prevention. PWR and BWR large loss of coolant accident conditional core damage probabilities (CCDP) can currently be as high as approximately 10-2 for PWRs and 10-3 for BWRs. Elimination of the single failure criterion and reduced quality assurance may increase the CCDPs such that there becomes an imbalance between mitigation and prevention under this proposed rule.
Disposition: The proposed rule does not include any quantitative requirement to limit CCDP.
There is no existing precedent for such limitations in other NRC risk-informed regulations.
However, the rule does enact a requirement for plant changes enabled under this rule. The rule requires that the total increases in core damage frequency and large early release frequency due to proposed plant changes that are enabled by the rulemaking be very small2, while the overall risk remains small2. This is consistent with other risk-informed rulemaking and licensing changes enacted under RG 1.174. The rule also requires that proposed plant changes demonstrate that adequate defense-in-depth is maintained, adequate safety margins are retained, and adequate performance monitoring provisions are implemented to provide reasonable assurance that the changes retain adequate mitigation against both design basis and beyond design basis events. No further action on this issue is required.
RPV Through Wall Cracking Issue description: If RPV through-wall cracking estimates are significantly above the default PRA value of 10-7/year such that, when considering the associated uncertainty, they could challenge the initial 10-5/year criterion used as the starting point for the TBS.
Disposition: Screening criteria are currently established in 10 CFR 50.61 and 10 CFR 50.61a for analyzing RPV embrittlement. These screening criteria have associated risk that is less than 10-6/year. Further, ASME Appendix G analysis specifies a conservative treatment of RPV embrittlement effects that is also expected to result in failure risks on the order of 10-6/year or less. Section 2.2.4 in the NUREG-1829 White Paper address current RPV embrittlement issues more completely and the plans in place so that these issues do not significantly impact the technical basis for the TBS. No further action on this issue is required.
Defining and Treating Piping and Non-Piping Failures Issue description: Two issues were raised pertaining to addressing passive system breaks in non-piping RCPB components within the proposed IE rulemaking. 10 CFR 50.46 currently requires consideration of unisolable piping system breaks of sizes up to and including a double-ended guillotine break (DEGB) of the largest unisolable pipe in the plant. The first issue recognizes that there is risk associated with non-piping passive system failures, which was estimated in NUREG-1829, and risks from these breaks should be addressed as part of implementing the proposed IE rulemaking. The second issue has arisen as some nuclear power plant applicants have tried to redefine which passive components are considered to be a pipe in an effort to claim that the current 50.46 break requirements are not applicable to these components. It may therefore be beneficial to more clearly delineate a requirement that non-2 The terms small and very small are defined in RG 1.174.
13 piping RCPB breaks need to be considered under the proposed IE rulemaking to address both of these issues.
Disposition: For breaks that are smaller than the TBS, the design basis requirements remain unchanged so additional consideration of breaks in other RCPB components would be inconsistent with their current treatment under 10 CFR 50.46. More importantly, the risks associated with piping failures smaller than the TBS, as estimated in NUREG-1829, bound the non-piping risk contributions for BWR plants and are more likely than piping failures only for smaller breaks due to steam generator tube ruptures and potential control rod drive mechanism (CRDM) failures in PWR plants. Steam generator failures are already addressed separately in plant PRA models and CRDM cracking has been successfully mitigated since the completion of NUREG-1829.
For breaks that are larger than the TBS (up to an including the DEGB), NUREG-1829 estimates that BWR piping failures are more likely than non-piping failures while PWR piping and non-piping failures have similar likelihood. There is only a small population of manways, component bodies and vessels within the RCPB that can result in such breaks. The integrity of these components, including the RPV, are governed by separate regulations and requirements which are unchanged by the proposed IE rulemaking. These component bodies have larger safety margins than commensurate piping and they are also more leak-before-break tolerant.
Manways also have larger safety margins than piping and large failures, as discussed previously, require common cause bolting failures which are more likely to result in leaks which lead to their discovery. The RPV has separate inspection and analysis requirements to provide assurance that failures remain highly unlikely. The proposed rule requires that an entity must still demonstrate that the ECCS can mitigate unisolable pipe breaks up to the DEGB, although the rule allows use of best estimate models, credit for non-safety related equipment, and relaxation of the single failure and coincident loss-of-offsite power assumptions for performing this demonstration. For the reasons above, piping failures provide an appropriate proxy for conducting this demonstration.
The second issue has been addressed within the proposed IE rulemaking by clarifying the applicable RCPB piping systems that remain within the current 10 CFR 50.46 licensing basis.
Fortunately, this terminology is well established in existing light-water reactor plants and misuse of this terminology is not expected for such plants. New plants that propose to implement this rule will need to both develop a basis for the TBS and also clearly define the piping systems where breaks remain within 10 CFR 50.46 as part of plant design and during operation.
Indirect Piping Failure and Treatment of Leak-Before-Break Piping Systems Issue description: This first part of this issue questioned if the impact of indirect failures (e.g.,
failures from non-RCPB piping, reactor coolant pump flywheels, or smaller RCPB pipes that cause a failure in an RCPB pipe that is greater than the TBS) on the TBS has been appropriately considered within the TBS technical basis. The second part of this issue questioned if piping systems having approved leak-before-break (LBB) analyses receive any special treatment under the proposed IE rulemaking.
Disposition: The consideration and implications of indirect failures on the TBS technical basis is addressed in Section 3 of the NUREG-1829 White Paper. There is also related discussion on the piccolo break issue in this document. While the implications of indirect failure have been
14 considered as part of the TBS technical basis development, IE rulemaking applicants will need to demonstrate that their plant design is compliant with GDC 4 requirements prior to implementing the rule. There is currently no special treatment for systems with LBB approval within the proposed IE rulemaking. However, the draft associated guidance allows use of approved LBB analyses to be credited as part of the plants basis for demonstrating plant-specific TBS applicability.
Effect of Water Chemistry Excursions Issue description: Water chemistry is important for controlling passive component degradation.
However, it is not clear if chemistry excursions during normal operations (including startup and shutdown) could lead to degradation that could erode the technical basis of the TBS. This is largely a plant-specific and not a generic concern.
Disposition: Plants tightly control water chemistry during startup, shutdown, and normal operations within both the primary and secondary systems to manage degradation. The industry maintains generic water chemistry guidelines that are periodically updated based on operating experience. Plant monitoring of water chemistry is performed at critical locations to provide assurance that these guidelines are met. Component inspections of degradation rates also provide assurance that the water chemistry protection remains effective. Chemistry excursions do occur, but they are relatively short-lived, and only long-term deviations would significantly impact the mitigative effects of water chemistry. Staff has confidence in the water chemistry measures in place to manage degradation within the piping systems that would be impacted by the proposed IE rulemaking. All other piping systems will remain within the current regulatory framework. Therefore, no further action on this issue is required.
Impact on Plant Security Issue description: A technical basis has not been established to support using the proposed IE rulemaking to relax security requirements or modify the treatment of critical digital instrumentation and control (DI&C) systems that are needed either to mitigate a large LOCA or are otherwise characterized as critical digital assets.
Disposition: The technical basis used to develop the TBS, and the associated proposed IE rulemaking, did not consider explicitly consider implications associated with plant security or treatment of critical DI&C systems. However, both 10 CFR Part 50 and Part 52 licensees are required to satisfy 10 CFR 73.55, Requirements for physical protection of licensed activities in nuclear power reactors against radiological sabotage. This regulation requires each licensee to implement the 10 CFR 73.55 requirements through its Commission-approved Physical Security Plan, Training and Qualification Plan, Safeguards Contingency Plan, and Cyber Security Plan.
This requirement will not be affected by the proposed IE rulemaking. The rulemaking will also not allow unsupported changes to requirements for critical digital assets, which are digital computer, communication system, or networks that could be compromised and have a negative impact on the plant's safety, security, or emergency preparedness functions.
However, the proposed rule does alter the requirements associated with those systems and equipment needed to mitigate LOCAs greater than the TBS. In particular, risk-informed changes to these systems and equipment are allowed under the proposed rule, and the population of safety-related, or important-to-safety, systems and equipment could subsequently
15 change within a particular nuclear power plant after implementing the rule. Any such classification changes could also eliminate requirements associated with critical digital assets.
Such changes, however, are highly plant specific and will require NRC staff review and approval before they can be implemented under the proposed rulemaking. This position is clarified in the Federal Rulemaking Notice, which states that (u)sing these alternative ECCS requirements would provide some entities with opportunities to change various aspects of their facility design and operation, although potential impacts of the changes pertaining to plant physical security or cybersecurity would be evaluated during license amendment reviews.
Grid Stability Issue description: Grid stability is hypothesized to be worse than in the mid-2000s when the original LOCA rule was proposed. Therefore, the possibility of a LOOP coincident with a LOCA may be significantly greater, and it may not be viable to decouple these events in the analysis of LOCA events that are greater than the TBS.
Disposition: LOOP data is gathered yearly, and their frequencies are updated in the SPAR models every 5 years. The occurrence rate of all LOOPs, but particularly grid-related LOOPs, decreased in the period from 2006 to 2020 compared to the previous period from 1997 to 2004.
However, this trend is largely due to the 2003 northeast blackout events being removed from the current data period.
The proposed IE rule requires the risk evaluation to be representative of the current configuration and operating practices at the plant. The risk evaluation is to be periodically maintained and upgraded. This effort includes updating the initiating event frequencies based on current operating experience and data. The rule also requires re-evaluation of the risk assessments after the periodic maintenance and upgrading are completed, and appropriate actions to be taken to ensure that the acceptance criteria are met.
Although the rule would allow LOCAs larger than the TBS to be recategorized as beyond-design-bases and mitigation analyses for LOCAs larger than the TBS would not need to assume a coincident LOOP, this is not true for the risk assessment evaluation. The risk assessment is required to demonstrate that increases in plant risk (if any) meet appropriate risk acceptance criteria, defense-in-depth is maintained, adequate safety margins are maintained, and adequate performance-measurement programs are implemented. Additionally, as stated above, the risk evaluation models need to be representative of the current configuration and operating practices at the plant and LOOP should be reflected within the plants risk evaluation models and evaluated in the risk assessment, along with the updated data, to support specific changes to be adopted under the proposed IE rulemaking.
As an example, many plants are running load monitoring software to predict when offsite power would be unavailable to support LOCA loads and these licensees can currently take action to bolster the grid when needed to provide assurance of offsite power availability. The proposed rulemaking may allow a licensee to cease these efforts if such a change satisfies the aforementioned provisions contained with the rulemaking and guidance.
16 3.2 External Elicitation Responses The external panelists were first asked how the current likelihood of LOCAs smaller than the TBS compares with their responses for NUREG-1829. One panelist expects that such LOCA frequencies are about the same based on the observed propensity for degradation over time in these smaller piping systems. As a result, he believes that the likelihood of a pressure boundary failure producing a signi"cant through-wall cracking rate remains within an order of magnitude of his NUREG-1829 estimates. The principal degradation mechanism, as indicated by the operating experience, is fatigue with underlying contributing factors in"uenced by, for example, operational strategies, on-line maintenance activities, support structure failures, and active component failures.
The other panelist expects such failures to be less likely and possibly as much as several orders of magnitude smaller. This expectation is based on advanced seismic dynamic piping integrity analyses which have demonstrated that DEGB is typically not predicted, even in piping systems as small as 1-inch in diameter, due to secondary load relaxation during hypothetical crack growth. However, this panelist believes that there are scenarios where such DEGB failures are possible. Contributing factors to such scenarios include the presence of a very long (i.e., nearly 360-degree) surface-breaking flaw in a material with very low fracture toughness (e.g., highly aged cast austenitic steel (CASS) piping, carbon steel sensitive to dynamic strain aging, or highly cold-worked Alloy 600 materials). Although this panelist was not aware of any active mechanisms in these materials that could form such long surface cracks, he did caution that the recent French experience3 should be better understood to ensure that SCC cannot form such cracks.
The panelists were next asked how the current likelihood of LOCAs larger than the TBS compares with their responses for NUREG-1829. One panelist stated that such LOCAs are currently at least an order of magnitude less likely than they were in the mid-2000s. This opinion is based on a decrease in the propensity for material degradation in systems where failure could lead to a LOCA larger than the TBS. Cracking is generally expected due to IGSCC in BWRs and PWSCC in PWRs, but mitigative efforts have been fully implemented and proven to be effective. Furthermore, repair and replacement strategies have incorporated more cracking-resistant materials. This opinion supports the continued viability of the existing TBS technical basis.
The other panelist also stated that LOCAs larger than the TBS are several orders of magnitude less likely now as compared to what he believed 20 years ago. This opinion is based on the expectation, as previously expressed, that DEGB is typically not predicted in large piping systems when considering the response of the entire system. This opinion also supports the continued viability of the existing TBS technical basis.
As with smaller piping failures, this panelist stated that scenarios leading to large DEGB failures are only possible with large surface cracks in low toughness materials. This panelist also indicated that there are approximately 12 Westinghouse-designed plants with main loop isolation valves that add significant inertial loads to the main loop piping during a seismic event.
3 ML23236A080 summarizes recent French SCC experience and evaluates the implications for U.S.
nuclear plants.
17 Therefore, the main loop piping in these plants may be more susceptible to LOCA failures greater than the TBS. However, the PWR plants with approved LBB evaluations for the main loop piping have accounted for the increased seismic loading resulting from the loop isolation valves in this analysis.
The external panelists were next asked to identify scenarios that most likely to lead to a passive system failure that is greater than the TBS. One panelist stated that no such credible scenario exists. This opinion is based on more than four decades of piping integrity research and development, research on age-related degradation mechanisms, operating experience, and the many steps taken to proactively mitigate or eliminate crack initiation and crack growth. Furthermore, in his opinion, immense progress has been made in NDE quali"cation and technology. Some international PWR operators have also proactively managed CASS elbow material embrittlement through component replacements. He also indicated that water hammer is highly unlikely in the largest piping systems because they are not subjected to loads due to rapid valve closures.
The other panelist was a bit more expansive in his response to this question. He stated that it is worthwhile to revisit the thermal aging fracture toughness of all materials, not just CASS.
He also stated that degradation in other industries using similar materials should be monitored to identify any adverse trends. He also questioned the propensity for hydrogen accumulation in large piping systems because its presence can affect both crack growth rates and fracture toughness.
He also indicated that weld overlays can induce different residual stress distributions depending on the welding sequence used to make the overlay and whether water cooling was used on the inside of the pipe during overlay deposition4. Water cooling of the inner-wall produces more uniform inner-wall compressive stresses throughout the overlay region.
If water cooling is not utilized, welding sequences from the center to the edge of the overlay could lead to inner-wall compressive stresses in the middle of the overlay and tensile stresses at the edge of the overlay. Welding sequences from the edge to the center could induce tensile stresses in the center of the overlay and compressive stresses at the edge.
This later welding sequence potentially supports continued growth of cracks located within the weld.
His principal concern, however, is the occurrence of an SCC degradation mechanism that would induce very long (i.e., nearly 360 degrees) inner surface cracking. While he stated that PWSCC in dissimilar metal PWR welds is a possible mechanism, he also stated that it is unlikely that such cracks would occur in typical girth or safe end welds, and that such a mechanism is more likely in extensively cold worked stainless steel and nickel alloy elbows. Cold working both increases the susceptibility to both SCC and reduces the materials fracture toughness. He stated that some inspections of elbow and tee bodies may be needed as part of the proposed IE rulemaking.
When ranking his concerns, this panelist indicated that he was most concerned with the likelihood of failures due to long surface cracks in a CASS component or in the associated weld.
4 T. Zhang, G. Wilkowski, D. Rudland, F. Brust, H.S. Mehta, D.V. Sommerville, Y. Chen, Weld-Overlay Analysis: An Investigation of the Effect of Weld Sequencing, PVP2008-61560, pp. 565-574, https://doi.org/10.1115/PVP2008-61560.
18 He also indicated that Westinghouse-designed plants with main loop isolation valves might be more susceptible to these contributing factors than generic plants, due to the increased loading induced by these valves during seismic events. His next most highly ranked concern is a failure of carbon steel piping subjected to potential thermal aging and dynamic strain aging. His next most highly ranked concern is the possibility for SCC development and decreased fracture toughness resistance contributing to cracking in a cold-worked nozzle or tee body.
The next question asked about the possibility of common cause failure scenarios. Neither panelist identified any common cause scenarios that they believe are viable. One panelist supported this notion with the rationale that there is ample and well-documented evidence that no common-cause failure scenarios exist. He further stated that degradation mechanisms are random aging processes that occur independently at susceptible locations within a system. A piping system consists of multiple elements (e.g., butt welds) that each undergo pre-service inspections, followed by ISI, and are potentially mitigated through, for example, stress improvement, preemptive full structural weld overlays, or water chemistry modifications. Thus, there are multiple layers of defense against material degradation scenarios that are simultaneously active at multiple locations. While there is some correlation or common factors associated with a particular degradation mechanism, he believes that there are enough plant and component-specific differences such that the failure rates remain independent.
The final question asked the panelists to identify any viable indirect failure scenarios. Neither panelist expects indirect failures to be a concern for those largest piping systems that could have breaks larger than the TBS. One panelist indicated that such failure scenarios have been experienced (e.g., the primary heat transport system LOCA at Pickering-2 in 1994); however, they are primarily of concern for failures less than the TBS. In his opinion, piping integrity research provides ample confirmation of the low possibility of such scenarios leading to ruptures that are greater than the TBS.
3.3 Disposition of External Elicitation Responses The principal conclusion is that both the external panelists expect that the LOCA frequencies associated with ruptures greater than the TBS should be significantly less (i.e., one or more orders of magnitude) than those estimated in NUREG-1829. While these two individuals represent a small sample size of expert opinion, its worth noting that both panelists have very different technical expertise and based their opinions on different, although complementary, technical rationale. They were also intimately familiar with the process used to develop the NUREG-1829 results and the significance of their individual responses on the aggregated final estimates. These opinions, in conjunction with the other evaluations performed in the NUREG-1829 White Paper and the NUREG-1903 White Paper support the continued viability of the TBS concept for use in the proposed IE rulemaking.
Neither expert identified any significant common cause or indirect failure scenarios that should be addressed for the piping systems that can generate a LOCA greater than the TBS. The only somewhat generic concerns that were identified were associated with the possibility that continued fracture toughness decreases due to thermal aging could occur in all materials and that an SCC-like mechanism could develop very-long inner-diameter surface flaws that could challenge integrity of these systems. The NRC staff has continued to study aging effects in these materials and one of the highest research priorities is obtaining ex-plant materials with
19 compositions and thermal histories representative of those in the main loop and recirculation piping to validate the accelerated aging models that have been developed based on laboratory testing. The NRC staff also monitors, and will continue to monitor, both industry-sponsored and publicly available studies and evaluate any adverse effects.
The NRC also continues to research and monitor the possibility of subcritical cracking mechanisms in these systems. Fortunately, many of the materials that are susceptible to thermally induced fracture toughness degradation (i.e., CASS, stainless steel welds, and carbon steels) have thus far been shown to be resistant to SCC-like degradation mechanisms that would cause very long surface-breaking flaws within the nuclear environment. The performance monitoring requirements proposed for the rulemaking, discussed previously, will require periodic inspections to provide assurance that such degradation is not occurring within those plants that are implementing the IE rule.
As indicated previously, one panelist did raise a plant-specific concern that weld-bead sequencing of mitigated overlay welds (i.e., especially welding sequences starting at the center of the overlay) could induce tensile stresses within the upper ~75% of the weld and heat affect zone (HAZ) such that existing cracks may continue to grow or new cracks may form in the base material under residual tensile stresses and grow into this region.
However, even for the most detrimental overlay welding sequences, the weld and HAZ regions at the inner diameter of the pipe remain compressive, which is expected to mitigate any water/environmental effects from getting to the tip of any existing cracks. Additionally, new cracking resulting from overlay tensile stresses appears to only be possible in the base material, which is much more resistant to stress corrosion cracking.
There are two types of overlays that are applied in practice: full structural weld overlays (FSWOLs) or optimized weld overlays (OWOLs). FSWOLs utilize more resistant materials and are designed to meet the ASME Section XI allowable flaw size criteria without crediting the underlying susceptible material. That is, their design thickness assumes that the susceptible material is completely circumferentially cracked. This additional design margin provides defense in depth such that even if preexisting deep flaws exist prior to the overlay, and are not discovered in the pre-overlay inspection, they are unlikely to challenge the systems structural integrity.
OWOLs are the types of overlays most likely to be used for the piping systems that are greater than the TBS as they can be installed in these systems during a typical refueling outage. In PWRs, OWOLs are designed (EPRI MRP-169) to utilize the outer 25 percent of the existing weld thickness and to provide sufficient material over the susceptible material such that the ASME Section XI Appendix C flaw acceptance criteria are met. Therefore, in these systems, it is necessary to avoid cracking in the outer 25 percent of the susceptible material during service. In BWRs, OWOLs (also called design weld overlays) require, as per ASME CC N-504, at least two additional weld layers of high-ferrite weld material if no circumferential cracking is present or, as long as circumferential cracking extends less than 10% of the piping circumference, the overlay thickness is predicated on meeting Section XI flaw acceptance criteria for the intended life of the repair assuming that the flaw is entirely through-thickness. If the circumferential cracking extends more than 10% of the circumference, a FSWOL must be used.
20 While neither MRP-169 nor CC N-504 specify the weld overlay sequence, they both require that the residual stresses induced by the overlay sequence be determined and utilized within the Section XI evaluation demonstrating the acceptability of the design life of the overlay. In-service inspection is also required as specified in ASME CC N-770 for PWRs and BWRVIP-75-A for BWRs. Both N-770 and BWRVIP-75-A require inspection of the entire weld or cracked region. If the weld is cracked, subsequent inspection is performed within two outages as per N-770 or within three outages as per BWRVIP-75-A to determine if any existing cracks have grown or new cracks have formed before moving the weld into the ISI program. Once in the ISI program, N-770, with NRC condition 10 CFR 50.55a(g)(6)(ii)(F)(8),
requires inspection of 25% of the FSWOL population and 100% of OWOL population every 10 years while BWRVIP-75-A requires a sampling of either 25% in plants with normal water chemistry or 10% in plants with hydrogen water chemistry. These requirements are expected to be sufficient to demonstrate that the optimized weld overlay is providing effective mitigation over the plants remaining operating life.
Other potential scenarios that could lead to a LOCA greater than the TBS identified by one of the panelists are typically plant-specific and would rely on some combination of the following: (a) materials potentially most susceptible to loss of fracture toughness (i.e., CASS, stainless steel welds, carbon steels), (b) addition of significant cold work during fabrication (i.e., in elbow or tee components), (c) presence of significantly long surface-breaking flaws, and (d) imposition of higher residual stresses in either unmitigated or mitigated welds (e.g., due to repair welding or weld overlay sequencing), applied loads during normal or seismic events (e.g., Westinghouse-designed plants with main loop isolation valves), or both. The possibility that these, and other, plant-specific factors could undermine the technical basis supporting the TBS are addressed in the entitys evaluation required to implement the proposed IE rule and subsequent evaluations demonstrating that future proposed plant changes do not significantly increase the failure susceptibility due to, for example, system temperature increases. Related guidance provides acceptable methods for performing such evaluations to provide assurance that such effects are appropriately considered. The proposed IE rule also requires that entities perform an risk-informed inspection of a sample of circumferential welds deemed to not be susceptible to degradation mechanisms within the main loop (for PWRs) or recirculation system (for BWRs) piping before implementing the rule, and periodically thereafter. Such plant-specific attributes should be considered when selecting those components within the inspection sample.
4 Summary The NRC staff conducted both internal and external elicitations as one of several activities to evaluate the continued adequacy of the technical basis supporting the TBS concept for use in the proposed IE rulemaking. The external experts expect LOCA frequencies associated with ruptures greater than the TBS to be less than those estimated in NUREG-1829, which served as the starting point for the TBS selection. Neither the internal nor external elicitations identified any generic issues or scenarios that either were not considered in the TBS development or have changed since the TBS development that could undermine its technical basis. Therefore, the results from these elicitations support the continued adequacy of the TBS concept for the IE rulemaking.
However, both the internal and external elicitations did identify topics that are being addressed within the proposed IE rulemaking language and associated guidance to demonstrate plant-specific applicability of the TBS in order to implement the IE rule. Topics identified during the
21 elicitation for consideration within the rulemaking package include risk evaluation requirements; impacts of plant changes; SCC in main loop and recirculation piping; indirect piping failures; direct and indirect seismic failure evaluations; maintaining mitigative capabilities; grid stability; common-cause maintenance errors; NUREG-1829 uncertainties; plant security impacts; and other attributes that could increase plant-specific LOCA frequencies. Many of these topics were already being addressed within the rulemaking package, and the elicitations served to refine their proposed treatment as well as identify some novel issues that were not initially considered.
A-1 Appendix A: Elicitation Questions A. Internal Elicitation Questions 1.
Identify possible (i.e., within the realm of possibility) scenarios not considered, or underestimated in NUREG-1829 or NUREG-1903 that could result in a PCPB breach that is greater than the TBS. For each such scenario provide the following information.
a.
List the sequence, or order, of events leading to the breach b.
Identify the causal factors required for the event to occur (e.g., rapid valve closure for water hammer, improper maintenance/installation) c.
Is scenario associated with PWR, BWR, or both, plant types? Is any particular vintage or type of plant (e.g., large dry containment, 4-loop PWR) more prone to such a scenario?
d.
Is material degradation required, or an important contributing factor, for the breach to occur? If so, identify the type of degradation (e.g., PWSCC cracking, thermal embrittlement) and the required extent of the degradation necessary for the breach to occur (i.e., extensive/unusual, normal/expected, minimal).
e.
Are operating time (e.g., by exacerbating material degradation identified in 1d, above) or operating conditions (e.g., power uprates or load following) a causal factor and, if so, please describe its contribution?
For each scenario identified in Question 1, please provide the following additional information.
2.
Is this a scenario that has been studied previously by the NRC/nuclear community or a previously unevaluated scenario? If such a scenario has been previously evaluated, a.
Provide any information that you are aware of associated with the evaluation (e.g., GSI number, supporting NUREGs numbers, open-literature publications, internal or open-literature presentations).
b.
Identify new knowledge or operating experience that you are aware of since the evaluation has been completed. Does this knowledge confirm the results of the prior evaluation or call into question the conservatism of those results?
3.
Can you identify other experts within the NRC that can address Question 2 and provide more information to further evaluate each scenario identified in Question 1?
4.
Can you rank the likelihood of the scenarios identified in Question 1 from highest to lowest likelihood and, if so, provide some rationale for your opinion?
A-2 B. External Elicitation Questions 1.
Consider the opinions you expressed during the prior elicitation (circa 2004) pertaining to the general likelihood of passive (i.e., piping and non-piping primary pressure boundary) system failures that are smaller than the TBS.
a.
Do you generally believe that such passive system failures are more likely, the same, or less likely now (i.e., 20 years later)?
b.
If you expect a difference in the failure likelihood today, what is the relative increase/decrease in the likelihood of failures now compared to your opinion in 2004?
c.
What are the principal contributing factors supporting this opinion?
2.
Now consider the opinions you expressed during the prior elicitation (circa 2004) pertaining to the general likelihood of passive system failures that are larger than the TBS.
a.
Do you generally believe that such passive system failures are more likely, the same, or less likely now (i.e., 20 years later)?
b.
If you expect a difference in the failure likelihood today, what is the relative increase/decrease in the likelihood of failures now compared to your opinion in 2004?
c.
What are the principal contributing factors supporting this opinion?
3.
Consider those scenarios that, in your opinion, are most likely to lead to a passive system failure that is greater than the TBS. If you think no such credible scenarios exist, please just state this opinion.
a.
Describe each scenario, or order of events, leading to the failure, including the following attributes i.
Identify the causal factors required for the scenario to occur (e.g., rapid valve closure for water hammer, improper maintenance/installation, fabrication methods or errors, age-related degradation) ii.
Is scenario associated with PWR, BWR, or both, plant types? Is any particular vintage or type of plant (e.g., large dry containment, 4-loop PWR) more prone to such a scenario?
iii.
Is material degradation required, or an important contributing factor, for the failure to occur? If so, identify the type of degradation (e.g., PWSCC cracking, thermal embrittlement) and the required extent of the degradation necessary for the breach to occur (i.e., extensive/unusual, normal/expected, minimal).
iv.
Are operating time (e.g., by exacerbating material degradation identified in 1d, above) or operating conditions (e.g., power uprates or load following) causal factors and, if so, please describe their contributions?
b.
If you provided more than one scenario in Question 3a, please rank each scenario from most to least likely and provide some rationale associated with your ranking.
c.
How much more likely is each scenario than the least likely scenario in your list?
Please provide some supporting rationale associated with the relative magnitudes that you have assigned.
d.
What is the relative likelihood of your most likely current-day scenario compared to your most likely scenario from 2004? Please provide some rationale supporting this relative likelihood.
4.
Are there any common cause failure scenarios involving several simultaneous (or nearly simultaneous) failures that are individually less than the TBS but collectively are greater
A-3 than the TBS that you did not identify in question 3? A possible example would be the failure of one branch line causing other branch line failures. If you think no such credible scenarios exist, please just state this opinion.
5.
Are there any indirect failure scenarios involving failure of non-pressure boundary component(s) that could lead to a failure that is greater than the TBS. A possible example would be multiple support failures during a seismic event that ultimately causes a failure in the main loop piping. If you think no such credible scenarios exist, please just state this opinion.
6.
For any scenarios identified in Questions 4 and 5, please provide the following information a.
Describe each scenario, or order of events, leading to the failure, including the following attributes i.
Identify the causal factors required for the scenario to occur (e.g., rapid valve closure for water hammer, improper maintenance/installation, fabrication methods or errors, age-related degradation) ii.
Is scenario associated with PWR, BWR, or both, plant types? Is any particular vintage or type of plant (e.g., large dry containment, 4-loop PWR) more prone to such a scenario?
iii.
Is material degradation required, or an important contributing factor, for the failure to occur? If so, identify the type of degradation (e.g., PWSCC cracking, thermal embrittlement) and the required extent of the degradation necessary for the breach to occur (i.e., extensive/unusual, normal/expected, minimal).
iv.
Are operating time (e.g., by exacerbating material degradation identified in 1d, above) or operating conditions (e.g., power uprates or load following) causal factors and, if so, please describe their contributions?
b.
If you provided more than one scenario in Question 3a, please rank each scenario from most to least likely and provide some rationale associated with your ranking.
c.
How much more likely is each scenario than the least likely scenario in your list?
Please provide some supporting rationale associated with the relative magnitudes that you have assigned.
d.
What is the relative likelihood of your most likely current-day scenario compared to your most likely scenario from 2004? Please provide some rationale supporting this relative likelihood.