ML20178A671
| ML20178A671 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 06/26/2020 |
| From: | Ameren Missouri, Framatome, Union Electric Co |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20178A668 | List: |
| References | |
| ULNRC-06586 | |
| Download: ML20178A671 (16) | |
Text
Attachment 1 to ULNRC-06586 Page 1 ci 16 Discussion of Change to ULNRC-06586 Page 2 of 16 Discussion of Change Table of Contents 1.0
SUMMARY
DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 System Design and Operation 2.2 Current Technical Specification Requirements 2.3 Reason for Proposed Change 2.4 Description of Proposed Change
3.0 TECHNICAL EVALUATION
3.1 General Evaluation of Proposed Change 3.2 Callaway Specific Evaluation of Proposed Change 3.3 Discussion of Callaway Primary-to-Secondary Leakage Program
4.0 REGULATORY EVALUATION
4.1 Applicable Regulatory Requirements 4.2 Precedent 4.3 No Significant Hazards Consideration Determination 4.4 Conclusions
5.0 ENVIRONMENTAL CONSIDERATION
S
6.0 REFERENCES
to ULNRC-06586 Page 3 of 16 1.0
SUMMARY
DESCRIPTION This proposed License Amendment would revise Callaway Technical Specification (TS) 5.5.9, Steam Generator (SG) Program, in order to defer the SG inspection scope currently required to be performed during Refuel Outage (RFO) 24, which is scheduled to start in the fall of 2020, to REQ 25, which is scheduled for the spring of 2022. The purpose of this change is to minimize Coronavirus Disease 2019 (COVID-19) exposure at Callaway during RFO 24.
The proposed change involves the addition of a note (i.e., asterisk and footnote) to part d.2 of TS 5.5.9 where the frequency of the required SG tube inspections is specified. The note would be effective on a one-time basis since it would specifically refer to the SG inspection currently scheduled for Refueling Outage 24 (fall 2020) and point out that the inspection is to be deferred to Refueling Outage 25 (spring 2022).
No changes to the Callaway Final Safety Analysis Report or TS Bases are anticipated as a result of this License Amendment Request.
2.0 DETAILED DESCRIPTION 2.1 System Design and Operation The Steam Generator (SG) tubes have a number of important safety functions.
SG tubes are an integral part of the reactor coolant pressure boundary (RCPB),
and as such, they are relied on to maintain reactor coolant system (RCS) pressure and inventory. As part of the RCPB, SG tubes are unique as they transfer heat from the primary system RCS to the secondary system, i.e., the Main Feedwater (MEW) system. In addition, SG tubes isolate radioactive fission products in the RCS fromthe secondary system.
The steam generator tube rupture (SGTR) accident is the only design basis event where SG tube failure is postulated to occur. The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture).
In these analyses, (i.e.,
non-LOCA events, including steam line break) the primary-to-secondary leakage is assumed to increase from the Technical Specification operational limit to one gpm. All of the leakage is assumed to occur in the faulted SG, thus maximizing discharge of reactor coolant to the atmosphere as steam.
For accidents that do not involve fuel damage, the reactor coolant activity level is assumed to be equal to IS limits. For accidents that assume fuel damage, reactor coolant activity is a function of the amount of activity released from damaged fuel.
Steam generator tube integrity is necessary to ensure SG tubes are capable of performing their intended safety functions. Concerns relating to integrity of SG tubes stem from the fact that SG tubes are subject to a variety of degradation mechanisms. Steam generator tubes have experiencedtube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as wear. These degradation mechanisms can impair tube to ULNRC-06586 Page 4 of 76 integrity if they are not managed effectively. When degradation of the tube wall reaches a prescribed criterion for action, the tube is considered defective and corrective action is taken, such as plugging or repair.
2.2 Current Technical Specification Requirements The current Technical Specification proposed to be changed is TS 5.5.9, Steam Generator (SG) Program.
TS 5.5.9.a establishes provisions for the performance of condition monitoring assessments with respect to the performance criteria for structural integrity and accident induced leakage.
TS 5.5.9.b establishes performance criteria for SG tube integrity, including structural integrity, accident induced leakage, and operational leakage.
TS 5.5.9.c establishes SG tube plugging criteria.
Part d of TS 5.5.9 requires periodic SG tube inspections to be performed and specifies provisions to be met for such inspections. TS 5.5.9.d.1 specifies the tube inspection scope that was required to be met during the first refueling outage following SG installation. TS 5.5.9.d.2 states, After the first refueling outage following SG installation, inspect each SG at least every 72 effective full power months or at least every third refueling outage (whichever results in more frequent inspections). Additionally, 1 00% of the tubes are required to be inspected during each sequential period of 144 effective full power months (EFPM), 120 EFPM, 96 EFPM, and 72 EFPM.
In practice, Callaway inspects 1 00% of the SG tubes every third refueling outage.
Additional Technical Specification requirements applicable to steam generator tube integrity are as follows:
Callaway TS 3.4.13, RCS Operational LEAKAGE, requires that leakage be limited to 1 50 gallons per day for primary-to-secondary LEAKAGE through any one steam generator (SG). The corresponding surveillance requirement is implemented in accordance with the Surveillance Frequency Control Program, procedure APA-ZZ-00340 Appendix 4, which states, The Surveillance Frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.
Callaway TS 3.4.17, Steam Generator (SG) Tube Integrity, requires that SG tube integrity shall be maintained AND all SG tubes satisfying the tube plugging criteria shall be plugged in accordance with Steam Generator Program. Each inspected SG tube that satisfies the tube plugging criteria is plugged prior to entering MODE 4 following a SG tube inspection.
Callaway TS 5.6.10 requires a Steam Generator Tube Inspection Report be submitted within 1 80 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG) Program. The most recent report was submitted on October 1 1
, 201 6, following the SG tube inspection during RFO 21 (2016).
to ULNRC-06586 Page 5 of 16 2.3 Reason for Proposed Change Deferral of the required SG tube inspection is needed in order to limit exposure to COVID 1 9 since its emergence and for which a national emergency was declared on March 13, 2020. The upcoming steam generator inspection would require the working together, in close quarters, of numerous employees and vendor personnel from other states and areas. This deferral is being requested in the interest of personnel safety and to preclude the potential for transmittal and spread of the COVID-1 9 virus.
An Operational Assessment (OA), supports deferral to RED 25. The assessment is based in part on recent industry operating experience (section 4.3 of the OA),
which supports a longer inspection period for plants with SG tubes made of thermally treated Alloy 690 (i.e., 690TT), as well as prior inspection condition monitoring results for Callaway. Delaying performance of the current inspection regime for one refueling outage due to COVID-1 9 virus concerns is warranted when the potential for infection is weighed against the conclusions of the attached OA.
2.4 Description of Proposed Change The proposed change to the IS, as shown in Attachment 5 and reflected in, is specifically as follows:
Add an asterisk at the end of the following sentence from TS 5.5.9.d.2:
After the first refueling outage following SC installation, inspect each SC at least every 72 effective full power months or at least every third refueling outage (whichever results in more frequent inspections).
Add an asterisk and the following words (as a footnote) at the bottom of TS page 5.0-12.
As approved by Amendment No. XXX, performance of the steam generator inspection scheduled for Refuel Outage 24 (fall 2020) may be deferred to Refuel Outage 25 (spring 2022) on a one-time basis.
3.0 TECHNICAL EVALUATION
3.1 General Evaluation of Proposed Change The current TS 5.5.9 requirement is to inspect each SC at least every 72 effective full power months or at least every third refueling outage (whichever results in more frequent inspections). Additionally, 1 00% of the tubes are required to be inspected during each sequential period of 1 44 effective full power months (EFPM), 120 EFPM, 96 EFPM, and 72 EFPM.
In practice, Callaway inspects 1 00% of the SC tubes every third refueling outage.
The most recent Steam Generator Tube Inspection Report, generated as required by TS 5.6.1 0, Steam Generator Tube Inspection Report, after the most recent SC tube inspection in REQ 21 indicated that there was reasonable to ULNRC-06586 Page 6 of 16 assurance that the TS performance criteria would be met for the upcoming 3-cycle operating period, consisting of cycles 22 and 23 and current cycle 24.
Additionally, the Condition Monitoring report (required by TS 5.5.9.a) concluded that the Callaway steam generator tubes satisfied the structural integrity performance, accident-induced leakage and operational leakage performance criteria in accordance with Technical Specifications 5.5.9, 3.4.13, and 3.4.17.
Most recently, an updated Operational Assessment (OA) was performed by Framatome and issued in May 2020. The OA assessed the potential to skip the upcoming SG inspection for REQ 24 (fall 2020) due to COVID-1 9 concerns and defer it to the next refuel outage (REQ 25). The OA determined that the Technical Specification performance criteria would continue to be satisfied not only for the remainder of the current cycle but throughout upcoming Cycle 25.
3.2 Callaway Specific Evaluation of Proposed Change 3.2.1 Recent Callaway operational experience is summarized as follows:
1 Primary-to-secondary leakage The Condition Monitoring (CM) assessment performed following REQ 21 confirmed that structural and leakage performance criteria were satisfied based on the REQ 21 inspection results.
Since the time when the SGs were replaced in REQ 14 (2005), there has been no measured pri mary-to-secondary leakage.
The OA, which considered all existing, potential, and relevant degradation mechanisms for the Callaway SGs, shows that the structural and leakage integrity performance criteria will continue to be satisfied until the next planned inspection in spring 2022 (REQ 25).
2.
Most recent primary and secondaryinspections, degradation description and location The most recent full-cope SG inspection was performedduring RFO 21
. The inspection scope that was implemented and the degradation mechanisms that were identified during the inspection are described in Section 4 of the OA. Primary side workscope included 100%
testing of all in-service tubes, as-found and as-left visual inspections of primary channel heads for both hot and cold legs, visual inspections of all installed plugs, and enhanced visual testing (EVT-1) on the SG-A primary nozzle inner radius. Secondary side workscope included top of tubesheet water lancing and foreign object search and retrieval in all four SGs, as well as visual inspection of the steam drums in the A and D SGs.
- 3. Degradation Mechanisms Identified during RFO 21 During the REQ 21 inspections, the following degradation mechanisms were reported:
to ULNRC-06586 Page 7 of 16 Wear at Anti-Vibration Bars (AVBs).
Wear at tre-foil broached Tube Support Plates (TSPs).
Visual inspections of the Top of Tube Sheet (TTS) (all four SGs) and the upper steam drum (SG-A and SG-D) identified no degradation.
4.
Number oftubes pluQQed and reason for pluciQing During REQ 21, 25 tubes were plugged. There were no tubes that met the Technical Specification plugging criteria of an indication greater than 39% through wall (TW). All tube plugging during REQ 21 was preventative to address AVB wear.
Currently the cumulative total number of plugged SG tubes in all four SGs is 55 (all for AVB wear) which is equal to 0.23% of the total number of tubes.
5.
Relevant operating experience that may have impacted SG tube integrity There have been no thermal, hydraulic, chemistry, or foreign material exclusion (EME) events at Callaway that would have impacted SG tube integrity since REQ 21.
3.2.2 Previous inspection condition monitoring is summarized as follows:
1
. Comparison of the most limiting as-found condition to tube performance criteria for each detected degradation mechanism AVB Wear The maximum depth of all AVB wear was 38%TW from bobbin eddy current testing (ECT). The corresponding upper 95/50 depth after accounting for the ECT technique uncertainty is 47%TW. The appropriate structural limit for the Callaway SG tubes at 3 times the normal operating pressure differential (NQPD) is 59.2%TW for a 1.0 length flaw that bounds the AVB width of 0.5.
TSP Wear The maximum depth of all TSP wear was 1 7%TW from +Point eddy current testing (ECT). The corresponding upper 95/50 depth after accounting for the ECT technique uncertainty is 32.5%TW. The appropriate structural limit for the Callaway SG tubes is 57.6%TW for a 1.5 length flaw that bounds the TSP thickness of 1.18.
Performance Criteria Eor volumetric wear flaws with pressure-only loading condition, tube burst and ligament tearing (i.e., pop-through) are coincident, therefore, satisfaction of the tube burst criteria at 3xNOPD also satisfies the Accident-Induced Leakage Performance Criteria to ULNRC-06586 Page 8 of 16 (AILPC) at Feedwater Line Break differential pressure. Therefore, the SG performance criteria for structural and leakage integrity were demonstrated.
- 2. Demonstration of howcondition monitorinQ was met for all SG tubes that reQuired flaw jrofiling.
Condition monitoring was analytically demonstrated on the basis of maximum reported wear depth for the above degradation mechanisms.
Thus, flaw profiling was not required to demonstrate structural and leakage integrity.
3.2.3 Operational Assessment (OA) for an additional operating cycle (Cycle 25) was performed and is summarized as follows:
1 Degradation mechanisms considered and reason for consideration Existing Degradation Mechanisms a.
Proiected Tube Wear at AVBs The OA for AVE wear was implemented using a fully probabilistic model (1 00,000 Monte Carlo simulations) of all returned-to-service indications (439 total indications, 30%TW max depth) as well as flaws undetected at REQ 21 and newly initiated after RFO 21
. The model assumes a growth rate bounding of growth rates observed at REQ 21, does not include negative growth, and applies it for the entire duration until REQ 25.
The limiting probability of burst (POE) for any SG for all AVE wear (return to service, new and undetected) was 0.9% compared to the maximum criterion from EPRI guidelines of 5%. Thus, deferring SG inspections to REQ 25 will not violate SG tube integrity performance criteria for AVE wear.
b.
Projected Tube Wear at TSPs The OA for TSP wear was implemented using a fully probabilistic model (1 00,000 Monte Carlo simulations) of all returned-to-service indications (130 total indications, 17%TW max depth) as well as flaws undetected at REQ 21 and newly initiated after REQ 21
. The model assumes a growth rate bounding of all growth rates observed at REQ 21, does not include negative growth, and applies it for the entire duration until REQ 25.
The limiting probability of burst (POE) for any SG for all TSP wear (return to service, new and undetected) was 0.1 % compared to the maximum criterion from EPRI guidelines of 5%. Thus, deferring SG inspections to RFO 25 will not violate SG tube integrity performance criteria for TSP wear.
to ULNRC-06586 Page 9 of 16 Potential DeQradation Mechanisms a.
Projected Tube Wear at Appui I V-Shaped Support Pad The Callaway SGs have an AVB bundle support/positioning device (referred to as an appui or V-shaped support pad) located on the outer periphery of the tube bundle which is a design feature unique to Framatome designed SGs. Appui wear has only been identified in two Framatome SGs worldwide.
The OA for appui wear was implemented using a conservative determi nistic approach assu mi ng a maxi mu m beginning-of-cycle (BOC) wear scar depth of 20%TW which bounds the minimum detected appui depth using a qualified ECT technique of 1 6%TW.
The evaluation assumed a growth rate and flaw length that are bounding of the maximum growth rate and flaw length observed for appui wear.
The end-of-cycle (EOC) upper 95/50 depth for an undetected appui wear flaw at REQ 21, accounting for technique sizing uncertainty and growth, is 56.9%TW. Since this value is less than structural limit of 59.2%TW for a 1.0 length flaw, deferral of SG inspections to RED 25 will not violate SG tube integrity performance criteria for appui wear.
b.
Foreicin Object Wear The primary side tube inspections performed at REQ 21 in each SG included 100% full-length bobbin and array probe examinations of the hot leg periphery and no-tube lane, up to the first support structure.
Additionally, water lancing and visual inspections were performed at the TTS on both legs, providing added assurance that no foreign objects were left in service in the SG, specifically in the high flow region (i.e., periphery, no-tube lane).
With respect to foreign object wear, a judgment of the risk can be developed, considering the operating history of the Callaway SGs, as well as the four other Framatome replacement SGs in the U.S. with loose part trapping screens installed. Throughout the entire operating experience (since 2006) and multiple inspections at each unit, no foreign object wear has been detected during that time.
Any new foreign material introduced since REQ 21 is unlikely to cause structurally significant tube degradation. However, in the event of such an occurrence, primary-to-secondary leakage monitoring procedures in place at Callaway provide a high degree of confidence of safe unit shutdown without challenging the structural or leakage performance criteria through REQ 25.
to ULNRC-06586 Page 70 of 16 Relevant Degradation Mechanisms a.
PittinQ at the ITS Pitting is usually observed at plants using sea or brackish circulating water systems along with the presence of lead or copper in the secondary system during cold shutdown conditions, and does not grow to large volumes due to the small-localized galvanic differences.
Additionally, there is only one SG with Alloy 690 tubing that has experienced degradation that may have been caused by pitting at the TTS (INPO CE 320427).
The Callaway SGs have a very small sludge pile region and no known chemistry concerns that would be conducive to pitting, as well as no indications identified from the bobbin or sample array inspections; therefore, there is reasonable assurance that pitting will not violate the structural or leakage performance criteria through RED 25.
Leakage Integrity For volumetric wear flaws with pressure-only loading condition, tube burst and ligament tearing (i.e., pop-through) are coincident.
Consequently, satisfaction of the tube burst criteria at 3xNOPD also satisfies the AILPC at Feedwater Line Break differential pressure.
Therefore, the SG performance criteria for structural and leakage integrity are demonstrated for the degradation in this CA.
Additionally, the leakage monitoring program in place at Callaway requires action to be taken, including safe shutdown of the facility if required, when specified leakage limits are exceeded, as further described in section 3.3 of this attachment.
2.
Inspection strategy details at last inspection for each item considered above The inspection strategy for REQ 21 was to perform bobbin probe inspections in 100% ofthe SG tubes, and additional array probe inspections for specified areas on the TTS. Visual inspections were also performed at the TTS and upper steam drum.
The inspection strategy at REQ 25 is to perform a 1 00% tube inspection of all Callaway SGs. The CA reviewed all existing degradation mechanisms and evaluated detected, undetected, and potentially newly initiated flaws.
Potential and relevant degradation mechanisms were also reviewed. The CA supports deferral of Callaway SG inspections until the next refueling outage at REQ 25.
to ULNRC-06586 Page 11 of 16 3.3. Discussion of Callaway Primary-to-Secondary Leakage Program Although the OA provides favorable results in regard to the margins associated with the tube integrity performance criteria, as explained above, the RCS Operational Leakage monitori ng program I n place at Callaway provides assurance that detectable increases in leakage from degradation mechanisms that cause such leakage are recognized and that action is taken when increased leakage exceeds applicable limits. Beyond implementing the requirements of TS 3.4.13 for monitoring OPERATIONAL LEAKAGE, the program includes administrative limits that are more conservative than the TS limit(s), for which actions are required to be taken well before the TS Actions would be entered for exceeding the TS limit(s).
A more in-depth description of Callaways program, in regard to primary-to-secondary leakage, is provided as follows.
1
. Administrative limits versus Technical Specification (TS) limits TS 3.4.13, RCS Operational LEAKAGE, requires that RCS operational LEAKAGE shall be limited to limited to 150 gallons per day primary-to-secondary LEAKAGE through any one steam generator (SG).
Callaway utilizes an administrative limit of a 50 gpd rate of primary-to-secondary leakage in any steam generator, when sustained for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. This threshold requires the plant to be in Mode 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (Action Level 2).
Eurthermore, an admi nistrative Ii mit of 75 gpd primary-to-secondary leakage in any steam generator is procedurally specified. This threshold requires the plant to commence prompt and controlled plant shutdown such that the plant must be at less than or equal to 50% power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and in Mode 3 within the next 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (Action Level 3).
2.
RCS operational LEAKAG E monitori ng during operati ng cycles Primary-to-secondary leakage is monitored in accordance with TS 3.4.13, particularly per SR 3.4.13.2, Verify primary to secondary LEAKAGE is 150 gallons per day through any one 5G. The frequency requirement is once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in accordance with the Surveillance Erequency Control Program (SFCP).
Callaway has adopted the EPRI PWR Primary-To-Secondary Leak Guidelines to apply a constant leakage methodology for responding to power operation primary-to-secondary leakage.
Constant leakage methodology only considers leakage. Callaway uses the constant leakage methodology for primary-to-secondary leakage response.
The following actions are taken in response to increasing primary-to-secondary leakage:
. Increased Monitoring: Mode 1 normal operation plant condition entered when to ULNRC-06586 Page 12 of 16 leakage has been detected but is not in a range that can be accurately monitored by most online radiation monitors, does not necessarily indicate imminent risk to steam generator tube integrity, but warrants additional attention. This condition is entered when the total primary-to-secondary leakage is greater than or equal to 5 gpd.
. Action Level 1 : The plant condition entered when leakage has increased to a condition that requires frequent monitoring by the radiation monitoring system with periodic bench marking by laboratory analyses. Action Level 1 is entered when primary-to secondary leakage is greater than or equal to 25 gpd.
. Action Level 2: The plant condition entered when primary-to-secondary leakage is greater than or equal to 50 gpd in any steam generator AND is sustained for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Entering Action Level 2 requires the plant to be in Mode 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of entering Action Level 2.
. Action Level 3: The plant condition entered when primary-to-secondary leakage in any steam generator is greater than or equal to 75 gpd. Entering Action Level 3 requires commencing a prompt and controlled plant shutdown such that the plant is at less than or equal to 50% power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and in Mode 3 within the next 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (total of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />).
4.0 REGULATORY EVALUATION
4.1 Applicable Regulatory Requirements Section 1 82a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include Technical Specifications as part of the license. The Commissions regulatory requirements related to the content of the Technical Specifications are contained in Title 1 0, Code of Federal Regulations (10 CFR), Section 50.36, Technical Specifications, of 10 CFR Part 50 Domestic Licensing of Production and Utilization Facilities. The Technical Specification requirements in 1 0 CFR 50.36 include the following categories: (1) safety limits, limiting safety systems settings and control settings, (2) limiting conditions for operation, (3) surveillance requirements, (4) design features, and (5) administrative controls.
As stated in 10 CFR 50.59(c)(1)(i), a licensee is required to submit a license amendment pursuant to 1 0 CFR 50.90 if a change to the Technical Specifications is required. Furthermore, the requirements of 1 0 CFR 50.59 necessitatethat the NRC approve Technical Specification changes before the changes are implemented. Callaways submittal meets the requirements ofi 0 CFR 50.59(c)(1)(i) and 10 CFR5O.90.
General Design Criterion (GDC) 1 4 Reactor Coolant Pressure Boundary (RCPB), of Appendix A General Design Criteria for Nuclear Power Plants, to 1 0 CFR Part 50 requires, among other things, that the reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture. The proposed change, i.e., deferral of the required SG tube inspection for one additional operating cycle, has been evaluated per an Operational Assessment, taking into account the most recent testing results as to ULNRC-06586 Page 13 of 16 well as plant-specific and industry operating experience, from which it was determined that the integrity of the RCPB (SG tubes) will be maintained with sufficient margins in regard to the operational performance criteria specified in TS 5.5.9.b, consistent with the intent of the GDC.
GDC 1 5, Reactor Coolant System (RCS) Design, the reactor coolant system and associated auxiliary, control, and protection systems shall be designed with sufficient margin to assure that the design conditions of the reactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operational occurrences. The proposed change does not negatively impact steam generator tube integrity during normal operation or anticipated operational occurrences.
GDC 30, Quality of reactor coolant pressure boundary, requires that components which are part of the RCPB shall be designed, fabricated, erected, and tested to the highest quality standards practical. The proposed change does not reduce quality standards for steam generator design, fabrication, or testing.
GDC 31, Fracture prevention of reactor coolant pressure boundary, requires the ROPE be designed with sufficient margin to assure that when stressed under operating, maintenance, testing, and postulated accident conditions (1) the boundary behaves in a nonbrittle manner and (2) the probability of rapidly propagating fracture is minimized. The proposed change does not alter the fracture prevention design of the steam generatortubes.
GDC 32, Inspection of reactor coolant pressure boundary, the steam generator tubes are designed to permit periodic inspection and testing to assess their structural and leaktight integrity. The proposed change does not eliminate periodic inspection or testing of the steam generatortubes.
42 Precedents Comanche Peak Nuclear Power Plant Exigent License Amendment Request (LAR)20-003 Revision to Technical Specification (IS) 5.5.9, Unit 1 Model D76 and Unit 2 Model D5 Steam Generator (SG) Program. License Amendment issued 4/17/2020 (ML20108E878).
Virginia Electric and Power Company Surry Power Station Units 1 and 2 Proposed License Amendment Request, One-Time Deferral of Surry Unit 2 Steam Generator B Inspection. License Amendment issued 5/07/2020 (ML2O1 15E237).
Turkey Point Nuclear Plant, Unit 3 Exigent License Amendment Request 272, One-Time Extension of IS 6.8.4 Steam Generator Inspection Program. License Amendment issued 4/16/2020 (ML20104B527).
Braidwood Station, Unit 2, Emergency License Amendment Request for a One-Time Extension of the Steam Generator Tube Inspections. License Amendment issued 5/01/2020 (ML2O1Y1A000).
to ULNRC-06586 Page 74 of 16 4.3 No Significant Hazards Consideration Determination Ameren Missouri has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 1 0 CFR 50.92, Issuance of amendment, as discussed below:
1 Do the proposed changes involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No The proposed change calls for a one-time change in inspection frequencies for steam generator tube inspections. Inspection frequencies themselves are not an initiator to a steam generator tube rupture accident or any other accident previously evaluated. However, the test frequency can impact the likelihood of a failure going undetected. In this case, the likelihood has been evaluated, as supported by the referenced and described Operational Assessment, and shown to be minimal. As a result, the probability ofany accident previously evaluated is not significantly increased.
The steam generator tubes inspected by the Steam Generator (SG)
Program will continue to be required to meet the SG Program performance criteria and to be capable of performing any functions assumed in the accident analysis. As a result, the consequences of any accident previously evaluated are not significantly increased.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2.
Do the proposed changes create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No The proposed change calls for a one-time change in inspection frequencies for steam generator tube inspections and associated reporting requirements. The proposed change does not alter the design function or operation of the steam generators or the ability of a steam generator to perform the design function. The steam generator tubes continue to be required to meet the Steam Generator (SG)
Program performance criteria. The proposed change does not create the possibility of a new or different kind of accident since the change does not introduce any failure mechanisms, malfunctions, or accident initiators not already considered in the design and licensing bases.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
to ULNRC-06586 Page 15 of 16 3.
Do the proposed changes involve a significant reduction in a margin of safety?
Response: No The proposed change calls for a one-time change in inspection frequencies for steam generator tube inspections and associated reporting requirements. The proposed change does notchange any of the controlling values of parameters used to avoid exceeding regulatory or licensing limits. The proposed change does not affect a design basis or safety limit, or any cqntrolling value for a parameter established in the FSAR or the license.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
Based on the above evaluations, Ameren Missouri concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 1 0 CFR 50.92(c) and, accordingly, a finding of a no significant hazards consideration is justified.
4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be adverse to the common defense and security or to the health and safety of the public.
5.0 ENVIRONMENTAL CONSIDERATION
S Ameren Missouri has determined that the proposed amendment would change requirements with respect to the installation or use of a facility component located within the restricted area, as defined in 1 0 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amount of effluent that may be released offsite, or (iii) a significant increase in the individual or cumulative occupational radiation exposure. Accordingly, the proposed change meetsthe eligibility criterion for categorical exclusion setforth in 10CFR 51.22(c)(9). Therefore, pursuant to 1 0 CFR 51.22(b), an environmental assessment of the proposed change is not required.
6.0 REFERENCES
6.1 Nuclear Energy Institute (NEI) 97-06 Revision 3, Steam Generator Program Guidelines, January 201 1.
6.2 Electric Power Research Institute (EPRI) Report 3002007571, Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 4, June 2016.
to ULNRC-06586 Page 16 of 16 6.3 Ameren Missouri letter ULNRC-06332, Callaway Plant Unit I, Union Electric Co., Results of Steam Generator Tube In-Service Inspection, October 11, 2016.
6.4 TSTF-51 0, Revision 2, Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection, March 1, 201 1 (ADAMS Accession No. ML110610350).