ML15104A361
| ML15104A361 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 04/13/2015 |
| From: | Jim Barstow Exelon Generation Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML15104A361 (20) | |
Text
Exelon Generation 200 Exelon Way Kennett Square, PA 19348 www.exeloncorp.com 10 CFR 50.90 April 13, 2015 U.S. Nuclear Regulatory Commission ATIN: Document Control Desk Washington, DC 20555-0001 Peach Bottom Atomic Power Station, Units 2 and 3 Renewed Facility Operating License Nos. DPR-44 and DPR-56 NRC Docket Nos. 50-277 and 50-278
Subject:
Response to Request for Additional Information - License Amendment Request to Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies
References:
- 1) Letter from J. Barstow (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, "License Amendment Request- Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies," dated November 7, 2014
- 2) E-mail from R. Ennis (U.S. Nuclear Regulatory Commission) to T. Loomis (Exelon Generation Company, LLC), "Draft RAI - Peach Bottom Units 2 and 3 - Primary Containment Leakage Rate Testing Program (TACs MF5172 &
73)," dated March 18, 2015 In the Reference 1 letter, Exelon Generation Company, LLC (EGC) requested changes to modify the Technical Specifications. The proposed amendment revises the Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3 Technical Specification 5.5.12, "Primary Containment Leakage Rate Testing Program" to allow for the permanent extensions of Type A Integrated Leak Rate Testing and Type C Leak Rate Testing frequencies for both Units 2 and 3.
In the Reference 2 e-mail, the U.S. Nuclear Regulatory Commission requested additional information. Attached is our response.
Exelon has reviewed the information supporting a finding of no significant hazards consideration and the environmental consideration provided to the U.S. Nuclear Regulatory Commission in Reference 1. The additional information provided in this response does not affect the bases for concluding that the proposed license amendment does not involve a significant hazards consideration. In addition, the additional information provided in this
U.S. Nuclear Regulatory Commission LAR - Revise Technical Specifications Section 5.5.12 April 13, 2015 Page2 response does not affect the bases for concluding that neither an environmental impact statement nor an environmental assessment needs to be prepared in connection with the proposed amendment.
Should you have any questions concerning this letter, please contact Tom Loomis at (610) 765-5510.
I declare under penalty of perjury that the foregoing is true and correct. Executed on the 13th day of April 2015.
Respectfully, 21~~
James Barstow Director - Licensing & Regulatory Affairs Exelon Generation Company, LLC Attachments: 1) Response to Request for Additional Information - License Amendment Request to Revise Technical Specifications Section 5.5.12
- 2) Response to APLA-RAl-1 and APLA-RAl-2 cc: USNRC Region I, Regional Administrator USNRC Senior Resident Inspector, PBAPS USNRC Senior Project Manager, PBAPS R.R. Janati, Commonwealth of Pennsylvania S. T. Gray, State of Maryland
Attachment 1 Response to Request for Additional Information License Amendment Request to Revise Technical Specifications Section 5.5.12
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page 1 By letter dated November 7, 2014 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML14315A084), Exelon Generation Company, LLC (Exelon, the licensee) submitted a license amendment request for Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3. The proposed amendment would revise the Technical Specifications associated with the primary containment leakage rate-testing program. Specifically, the amendment would extend the frequencies for performance of the Type A containment integrated leakage rate test (ILRT) and the Type C containment isolation valve leakage rate test, required by 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors."
The Nuclear Regulatory Commission (NRC) staff has reviewed the information the licensee provided that supports the proposed amendment and has the following questions.
APLA-RAl-1:
See Attachment 2.
APLA-RAl-2:
See Attachment 2.
EMCB-RAl-1:
Please discuss the highlights of IWE inspections of the accessible surface areas of the PBAPS Units 2 and 3 containments, performed after the last Type A test, and any corrective action taken to disposition the findings.
Response
One hundred percent (100%) IWE inspections are performed per ASME Section XI every inservice inspection period. As such, full IWE inspections were performed in P2R20 (2014) and P3R19 (2013).
IWE inspections are used to address several program requirements. The response to EMCB-RAl-1 provides the inspection results for the coating inspections, moisture barrier inspections, and highlights of the inspection of the internal structures. Other inspection areas are further detailed in this response as follows:
- Torus pitting (see response to EMCB-RAl-3)
- PBAPS Structural Monitoring Program of reinforced concrete (see response to EMCB-RAl-5)
- Inspection of the immersion zones (below the Torus water line) since recoating in 2012 and 2013 (see response to EMCB-RAl-7)
The inspection results below date back to 2005 for Unit 3 and 2014 for Unit 2, which are the most recent Type A tests for each unit:
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page2 Unit2:
P2R18 (2010) -The Inspector identified localized corrosion on the bio-shield wall near the window for the N4B nozzle. The bio-shield is not part of the containment pressure boundary. This condition was evaluated by Engineering and added to the Unit 2 unqualified coatings calculation. No coating repair was required.
P2R19 (2012)-Coating damage on drywell floor-Two areas were evaluated. The coating on the drywell floor elevation 116' was worn off, and the wall at elevation 116' exposed areas of bare metal. These areas were dispositioned as acceptable.
P2R20 (2014)-The moisture barrier was torn away from the wall - During performance of the CISI visual inspections of the drywell moisture barrier, it was identified that part of the moisture barrier had pulled away from the wall. While performing the VT-3 examination of the moisture barrier on elevation 119' 11" at Azimuth 180 degrees, it was determined that the moisture barrier had pulled away for a length of 7 feet. The moisture barrier was repaired and the final visual inspection was performed.
Unit3:
P3R17 (2009)- Moisture barrier required repair-A visual examination (VT-3) of Unit 3 drywall moisture barrier was performed as a part of the required P3R17 ASME Section XI Containment lnservice Inspection (CISI) inspection scope. This examination revealed that the moisture barrier had peeled away from the containment at Azimuth 010. The peeled area was 20 inches long. The moisture barrier had a gouge 4 inches long at Azimuth 202. The moisture barrier is located at the junction of the drywall floor to drywall wall. The condition was repaired, reinspected, and determined to be acceptable.
P3R19 (2013)-Coating damage was identified in the subpile room floor- During a CISI drywall/ reactor building containment visual examination, a damaged area of coating in the subpile room floor was noted. The area measured approximately 3" x 14". This condition was evaluated by Design Engineering and determined to not exceed acceptance criteria. No repair was required.
P3R19 (2013)- Containment coating degradation - During a general visual examination on the accessible interior portion of the drywall closure head, a damaged area of coating was noted.
The estimated damaged area was approximately forty percent (40%) of the inside diameter surface of the N-4 penetration. This condition was evaluated by Design Engineering and determined to not exceed acceptance criteria. No repair was required.
P3R19 (2013)- 10 Drywall Downcomers were identified as having minor coating damage on the interior. This condition was evaluated by Engineering. No coating repair was required.
EMCB-RAl-2:
As stated in the LAR, the PBAPS inservice inspection programs contain requirements to evaluate the acceptability of the inaccessible areas, if such conditions were identified, in accordance with 10 CFR 50.55a(b)(2)(ix)(A).
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page 3 Please provide information of instances, during implementation of the PBAPS inservice inspection programs, where existence of or potential for degraded conditions in inaccessible areas were identified and evaluated based on conditions found in accessible areas, as required by 10 CFR 50.55a(b)(2)(ix)(A). If there were any instances of such conditions, discuss the findings and corrective actions taken to disposition the findings. Also, please identify the specific areas of the PBAPS Units 2 and 3 containments that are inaccessible and susceptible to degradation.
Response
There were no identified areas of degradation that require additional investigation of inaccessible areas. All identified areas were repaired, if needed. Table 3.4-5 of the License Amendment Request identified potentially inaccessible areas; however, no indications of degradation have been identified in locations that would suggest that these inaccessible areas were affected. This confirms that the areas of inaccessibility are not degraded.
EMCB-RAl-3:
It is stated in the LAA that in the second containment in-service inspection interval, the wetted and submerged suppression chamber (Torus) surface areas are designated as augmented examination areas and will require 100 percent visual examination during each inspection period. It is also stated that the Torus submerged areas were coated in 2012 for Unit 2 and 2013 for Unit 3 in order to arrest further pitting. Please provide the results of recent inspections of the Torus and discuss any corrective action taken to disposition the findings.
Response
This response discusses the Torus pitting inspection results since 2006 for Unit 2 (P2R16) and 2007 for Unit 3 (P3R16).
In order to ensure that the Torus pressure boundary remained acceptable, PBAPS, Units 2 and 3 established a defined threshold to assure that no pit would threaten the Torus minimum wall thickness prior to the Torus recoat. The threshold included a corrosion allowance for all uncoated pits based on actual corrosion data and the planned recoat schedule. All pits with depths exceeding the defined threshold were evaluated by Engineering and were coated to assure no further degradation. The following are the results of the Torus inspections. Following each evaluation, the Torus was determined to be acceptable for continued operation.
Unit2:
P2R16 (2006)-12 isolated pits were evaluated by Engineering as acceptable. A total of 349 pits, including the 12 evaluated by Engineering, were coated to assure no further degradation.
P2R17 (2008)- No pit inspections were performed.
P2R18 (2010)- 14 isolated pits were evaluated by Engineering as acceptable. A total of 56 pits, including the 14 evaluated by Engineering, were coated to assure no further degradation.
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page4 P2R19 (2012)- 5 isolated pits were evaluated by Engineering as acceptable. The entire Torus submerged area was recoated.
P2R20 (2014)-2 isolated pits were evaluated by Engineering as acceptable. A total of 746 indications, including the 2 pits, were coated to assure no further degradation.
Unit3:
P3R16 (2007)- 60 isolated pits were evaluated by Engineering as acceptable. A total of 174 pits, including the 60 evaluated by Engineering, were coated to assure no further degradation.
P3R17 (2009) - No pit inspections were performed.
3R18 (2011)-198 isolated pits were evaluated by Engineering as acceptable. A total of 395 pits, including the 198 evaluated by Engineering, were coated to assure no further degradation.
3R19 (2013)- 47 isolated pits were evaluated by Engineering as acceptable. The entire Torus submerged area was recoated.
EMCB-RAl-4:
Please provide PBAPS operating experience relative to the inspection of the drywall internal moisture barrier at the juncture of the containment wall and the concrete floor.
Response
Instances of moisture barrier damage since the last Type A test for both units is discussed in the response to EMCB-RAl-1 above.
EMCB-RAl-5:
PBAPS Updated Final Safety Analysis Report (UFSAR), Section 12.2.1 states that (1) the foundation of the reactor building consists of a monolithic concrete mat supported on sound rock; and (2) this foundation mat also supports the primary containment and its internals, including the reactor vessel pedestal.
PBAPS UFSAR, Appendix Q, Section Q.1.16, states that the PBAPS structural monitoring program complies with 10 CFR 50.65 and utilizes visual inspections in managing aging effects for concrete and grout in accessible areas. Please provide PBAPS operating experience, including inspection intervals, relative to the inspection of concrete components, and any corrective action taken to disposition the findings. Also, please discuss whether existence of or potential for degraded conditions in inaccessible concrete areas were identified and evaluated based on conditions found in accessible areas.
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page 5
Response
The PBAPS Bottom Structural Monitoring Program requires inspection of plant structural features in the scope of the Maintenance Rule on a 4-year frequency. This encompasses reinforced concrete throughout the plant, including the reactor building bottom floor slab and reactor pedestal. Based on a review of the Maintenance Rule Structural Monitoring Program findings for both Units 2 and 3, since the start of the program in 1997, PBAPS experience with concrete deficiencies has been limited to the following types:
Edge spalling of a wall, where a floor slab or beam moves relative to the wall key or corbel that supports the floor Shallow depth surface spalling at joints, corners or in exterior applications Cracks in exterior, exposed walls Physical damage due to vehicular impact or overloading The above areas have been either repaired, planned to be repaired, or are being monitored at an increased frequency to determine if they are active and warrant repair. Additionally, normal shrinkage cracks are observed during structural monitoring but are not tracked or described in the inspection records. Only issues determined to be beyond the normal level expected for reinforced concrete, which could potentially develop into something of structural consequence, would be documented. No issues having significant structural impact have been noted.
Extent-of-condition inspections and evaluations were not deemed necessary for the above conditions due to the fact that in-scope areas having similar features are all accessible and are all inspected (rather than relying on a sample population) under the PBAPS Structural Monitoring Program.
None of the collected data or identified deficiencies is concluded to indicate the potential for degradation of concrete in inaccessible areas, nor in the reactor building base mat or reactor pedestal. No significant damage or degradation has been noted in interior monolithic concrete structures.
EMCB-RAl-6:
Section 9.2.3.2 of NEI 94-01, Revision 2-A, and Condition 2 in Section 4.1 of the NRC Safety Evaluation for Topical Report NEI 94-01, Revision 2 require supplemental general visual inspections of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity. These inspections must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years.
Based on the information provided in the LAA, the last Unit 3 Type A test was performed in October 2005, and the upcoming Unit 2 Type A test will be performed no later than October 2015. Please provide a schedule for a typical 15 year interval (between the last Type A test and the proposed next Type A test), in a tabular format, of the in-service inspections of PBAPS, Units 2 and 3 containments that were, and will be performed, and explain how it meets the requirements in Section 9.2.3.2 of NEI 94-01, Revision 2-A, and Condition 2 in Section 4.1 of the NRC Safety Evaluation for Topical Report NEI 94-01, Revision 2.
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page6
Response
Per ASME Section XI, IWE Table IWE-2500-1, inspection of the containment vessel pressure retaining boundary, accessible surface areas, and moisture barriers is required during each inspection period. The current ASME Section XI, IWE schedule, provided below, demonstrates how PBAPS will meet the requirement of three containment inspections between each Type A test, as well as an inspection in the same outage as the Type A test.
The next Type A tests for each unit, under a 15 year frequency, would occur in P2R27 (2028) and P3R22 (2019). P2R27 is the 2nd outage of the 3rd period of the 3rd CISI interval. PBAPS is currently in the 3r period of the 2nd CISI interval. Therefore, a 100% IWE inspection will be performed in each CISI period, as shown below:
Interval Period U/2 Outage(s) U/3 Outage(s) 1st Interval 3rd P2R16,P2R17 *P3R15, P3R16 1st P2R18, P2R19 P3R17,P3R18 2nd Interval 2nd *P2R20 P3R19 3rd P2R21, P2R22 P3R20, P3R21 1st P2R23,P2R24 *P3R22,P3R23 3rd Interval 2nd P2R25 P3R24 3rd P2R26, *P2R27 P3R25,P3R26
- Indicates Type A test performed/scheduled Based on the schedule above, four (4) 100% IWE inspections will be performed between each Type A test. For Unit 2, a full IWE inspection will be performed in either P2R26 or in P2R27 prior to initiation of the Type A test. For Unit 3, a full IWE inspection will be scheduled under the CISI program for P3R22. This ensures a fourth complete inspection.
EMCB-RAl-7:
Section 3.4.1 of the LAA discusses the PBAPS safety-related coating inspection program.
Please discuss the highlights of findings from the PBAPS recent inspections of the primary containment protective coating and any actions taken to disposition them.
Response
See response to ECMB-RAl-1 above for the highlights of the coating inspections for Units 2 and
- 3. Response to ECMB-RAl-3 above discussed the pitting results. The following is a discussion of the immersion zone inspections (below Torus water line) following the recent recoating.
The Unit 2 and Unit 3 Torus immersion zones were recoated during P2R19 (2012) and P3R19 (2013). Unqualified coatings were identified for both units during the recoating. This was due to issues encountered during surface preparation and coating application.
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page7 After the initial operating cycle, a 100% visual inspection of the Unit 2 Torus immersion zone was performed during P2R20 (2014). A qualified contractor performed these inspections and the following is excerpted from their inspection report:
"Coating condition in the inspected immersion areas is generally good. Coating deficiencies in immersion include random spot corrosion, pinpoint corrosion and random areas of light to moderate surface staining likely from embedded particulate from blast-media in the topcoat dating back to original application in 2012 (P2R19). Staining appears limited to the topcoat and is typically found within 1O feet either side of the invert weld seam in most bays. Pinpoint corrosion was noted within the 4" to 5" band across each bay just below the water line in the transition area of old/new principal coatings. Isolated indications of spot corrosion were randomly distributed throughout the torus."
The P2R20 containment inspection results were captured in the corrective action program. The newly identified degraded coating areas on the Torus pressure boundary within the immersion zone were repaired using a qualified repair coating during P2R20. Coating degradation areas associated with the non-pressure boundary components and the "belly band" area near the surface had been previously identified during coating application and inspection. A separate corrective action was generated for the "belly band" area during P2R20 and Engineering has an assignment to develop a contingent repair plan should future inspections determine repair is warranted.
An inspection of the Unit 3 immersion zone will be performed during the upcoming fall 2015 refueling outage.
EMCB-RAl-8:
Please provide the following information:
a) Percent of the total number of Type B tested components that are on a 120-month extended performance-based test interval.
b) Percent of the total number of Type C tested components that are on a 60-month extended performance-based test interval.
Response
a) The percent of the total number of Type B tested components that are on a 120-month extended performance-based test interval is 28 of 35 for Unit 2, and 30 of 35 for Unit 3 for a station total of 82.8%. The total number of Type B tested components is 36 for each unit.
One test in each unit cannot be placed in the Option B program (Personnel Air Lock door seal test).
b) The percent of the total number of Type C tested components that are on a 60-month extended performance-based test interval is 30 of 45 for Unit 2, and 28 of 47 for Unit 3 for a station total of 63.0%. The total number of Type C tested components is 78 for each unit.
Unit 2 total components tested includes 33 components, and 31 total components for Unit 3, which cannot be in the Option B program due to either restrictions on test interval (i.e., Main
Response to Request for Additional Information License Amendment Request to Attachment 1 Revise Technical Specifications Section 5.5.12 Page 8 Steam Isolation valves, Feedwater valves, Containment Atmosphere Control valves) or performance of specific lnservice Testing (IST) requirements (i.e., verification of closed position of a check valve).
Attachment 2 Response to APLA*RAl-1 and APLA-RAl-2
RM Documentation Approval Form RM DOCUMENTATION NO. PB..u\R-14 REV: 0 PAGE NO. 1 STATION: Peach Bottom Atomic Power Station UNIT(s) AFFECTED: 2&3 TITLE: Raaponses to Request for Additional lnfonnation Regarding LAR for Primary Containment Leakage Rate Testing Program
SUMMARY
The purpose of this evaluation is to provide responses to APLA-RAl-1 and APLA-RAl-2 as received from the NRC.
This ls a Category I RM Document IAW ER-M-600-1012, which requires Independent review and approval.
[ ) Review required after periodic update
[ X) Internal RM Documentation [ ] External RM Documentation Electronic CalculatJon Data Flies: NIA Mllbml of Beview: [ X ] Detailed [ ]Alternate [ ] Review of External Document This RM documentation supersedes: NIA In Ha entirety.
Prepared by: Donald E. Vanover I ZJo--L.t F. v~ I 3/Z6/J~
Print siiiii Date Reviewed by: Joshua A. Meisel I
~~ I 3/u/1'0
~
Print Date Approved by: Brandon T. INin Print I ~~fo-Dal9
APLA Branch Questions APLA*RAl-1 Section 4.2.7 of EPRI TR-1009325, Revision 2-A states that "[w]here possible, the analysis should include a quantitative assessment of the contribution of external events (for example, fire and seismic) in the. risk impact assessment for extended ILRT intervals." EPRI TR-1009325, Revision 2-A further states that the "assessment can be taken from existing, previously submitted and approved analyses or another alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval."
Section 5.7.1 in Attachment 3 of the license amendment request (LAR) assesses the fire risk and states that "the reported fire PRA CDF value is 4.4E-5/yr or approximately a factor of 11.9 higher than the current internal events CDF values." Section 5.7.1 further states that "a better estimate of the LERF from scenarios more applicable to the fire PRA results would be about 43% [ATWS scenarios contribute 23.0% to the LERF total and ISLOCA scenarios contribute 19.7% to the LERF total] less than the total internal events value of 4.74E-7/yr, or 2.72E-07/yr.
If the multiplier of 11.9 is used on this LERF value, then the total LERF estimate for the Fire PRA model is 3.22E-06/yr." The licensee's approach to estimate the total LERF due to fire is the same as the following:
- 1) Multiplying the fire PRA CDF (i.e., 4.4E-5/yr) by a conditional containment failure probability (CCFP) representative of the fire scenarios.
- 2) The CCFP is equal to the internal events LERF (excluding ATWS and ISLOCA scenarios) (i.e., 2.72E-07/yr) divided by the total internal events CDF (which includes the ATWS and ISLOCA scenarios) (i.e., 3.69E-6/yr). In this case the CCFP would be about 0.073.
However, the associated CCFP in the licensee's approach does not seem to be appropriate in that if the ATWS/ISLOCA scenarios are excluded in the numerator of CCFP, then the same scenarios should be excluded from the denominator of CCFP. By including the ATWS/ISLOCA scenarios in the denominator of CCFP, the CCFP is artificially reduced, resulting in an underestimation of total fire LERF. If the ATWS/ISLOCA scenarios were excluded from the denominator of CCFP, then the increase in CCFP could potentially, considering ATWS's significant contribution to CDF in NUREG-1150, cause total LERF in Table 5.7-4 in Attachment 3 of the LAR to exceed the Regulatory Guide 1.174 criterion of less than 1.0E-5/yr. This issue is also applicable to the calculation of the seismic LERF in Section 5. 7.2 in Attachment 3 of the LAR. Considering the NRC staff comments above, justify that the total LERF in Table 5.7-4 in of the LAR is less than the Regulatory Guide 1.174 criterion of 1.0E-5/yr for total LERF due to internal and external events.
Response to APLA-RAl-1 The analysis in Section 5.7 of Attachment 3 of the PBAPS submittal has been re-performed to address the concern identified above. That is, the ATWS/ISLOCA contribution is excluded from the denominator as well as to the numerator in the determination of the LERF estimate from the 2
fire and seismic hazard groups. Excluding ATWS/ISLOCA from the internal events CDF reduces the CDF to 3.5E-06 I yr (from 3. 7E-06/yr). So instead of a multiplier of 11.9 for fire and 6.5 for seismic, the multipliers are 12.6 for fire and 6.9 for seismic. Using the applicable internal events LERF value of 2.72E-07/yr as noted in the RAI and the updated multipliers specified here, the revised fire LERF contribution is estimated to be 3.42E-06/yr (compared to 3.22E-06/yr previously assumed), and the seismic LERF contribution is estimated to be 1.87E-06/yr (compared to 1.76E-06/yr previously assumed). In addition, the combination of the seismic and fire CDF values results in an external event bounding multiplier of 19.5 compared to the 18.4 multiplier used previously.
The remaining portion of the analysis is then updated accordingly. Although the RAI question was focused on Table 5.7-4 of Attachment 3 of the submittal, the RAI response includes making adjustments to Table 5.7-2 and 5.7-3 for completeness since arguably the same logic would apply to those portions of the analysis as well.
Revised External Events Impact on ILRT Extension Assessment The EPRI Category 3b frequency for the 3-per-10 year, 1-per-10 year, and 1-per-15 year ILRT intervals are shown in Table 5.6-1 of Attachment 3 of the PBAPS submittal as 8.65E-09/yr, 2.97E-08/yr, and 4.64E-08/yr, respectively. Using an external events multiplier of 19.5 for PBAPS, the change in the LERF risk measure due to extending the ILRT from 3-per-10 years to 1-per-15 years, including both internal and external hazards risk, is estimated as shown in Table 1-1. Note that Table 1-1 represents an updated version of Table 5. 7-2 from Attachment 3 of the PBAPS submittal.
Table 1-1 PBAPS 3b (LERF/YR) as a Function of ILRT Frequency for Internal and External Events (Including Age Adjusted Steel Liner Corrosion Likelihood) 3b Frequency 3b 3b LERF (3-per-10 yr Frequency Frequency lncreasel1>
ILRT) (1-per-10 year (1-per-15 ILRT) year ILRT)
Internal Events 8.65E-09 2.97E-08 4.64E-08 3.78E-08 Contribution External Events Contribution (Internal 1.69E-07 5.BOE-07 9.05E-07 7.36E-07 Events x 19.5)
Combined (Internal+
1.77E-07 6.09E-07 9.51 E-7 7.74E-07 External)
<1> Associated with the change from the baseline 3-per-10 year frequency to the proposed 1-per-15 year frequency.
3
The other acceptance criteria for the ILRT extension risk assessment can be similarly derived using the multiplier approach. The results between the 3-in-10 year interval and the 15 year interval compared to the acceptance criteria are shown in Table 1-2. As can be seen, the impact from including the external events contributors would not change the conclusion of the risk assessment. That is, the acceptance criteria are all met such that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years has been demonstrated to be small. Note that a bounding analysis for the total LERF contribution follows Table 1-2 to demonstrate that the total LERF value for PBAPS is less than 1.0E-05/yr consistent with the requirements for a "Small Change" in risk of the RG 1.174 acceptance guidelines. Note that Table 1-2 represents an updated version of Table 5.7-3 from Attachment 3 of the PBAPS submittal.
Table 1-2 Comparison to Acceptance Criteria Including External Events Contribution for PBAPS Contributor t:iLERF t:iPerson-rem/yr t:iCCFP Internal Events 3.78E-8/yr 5.99E-02/yr (0.52%) 1.02%
External Events 7.36E-7/yr 1.17E+OO/yr (0.52%) 1.02%
Total 7.74E-7/yr 1.23E+OO/yr (0.52%) 1.02%
Acceptance <1.0E-6/yr <1.0 person-rem/yr <1.5%
Criteria .Q! <1.0%
The 7.74E-07/yr increase in LERF due to the combined internal and external events from extending the ILRT frequency from 3-per-10 years to 1-per-15 years falls within Region II between 1.0E-7 to 1.0E-6 per reactor year ("Small Change" in risk) of the RG 1.174 acceptance guidelines. Per RG 1.174, when the calculated increase in LERF due to the proposed plant change is in the "Small Change" range, the risk assessment must also reasonably show that the total LERF is less than 1.0E-5/yr. Similar bounding assumptions regarding the external event contributions that were made above are used for the total LERF estimate From Table 4.2-1 of Attachment 3 of the PBAPS submittal, the total LERF due to postulated internal event accidents is 4.74E-07/yr for PBAPS. As discussed at the beginning of this RAI response, the updated total LERF estimate for the Fire PRA model is 3.42E-06/yr, and the total LERF estimate for the Seismic PRA model is 1.87E-06/yr. The total LERF values for PBAPS are then shown in Table 1-3. Note that Table 1-3 represents an updated version of Table 5.7-4 from Attachment 3 of the PBAPS submittal.
4
Table 1-3 Impact of 15-yr ILRT Extension on LERF for PBAPS LERF CONTRIBUTOR (1/YR)
Internal Events LERF 4.74E-07 Fire LERF 3.42E-06 Seismic LERF 1.87E-06 Internal Events LERF due to 4.64E-08 ILRT (at 15 years) (1)
External Events LERF due to 9.05E-07 ILRT (at 15 years) (1> [Internal Events LERF due to ILRT
- 19.5]
Total 6. 72E-06/yr (ll Including age adjusted steel liner corrosion likelihood as reported in Table 5.7-2 of Attachment 3 of the PBAPS submittal.
As can be seen, the revised estimated upper bound LERF for PBAPS is estimated as 6.72E-06/yr (compared to the previous value of 6.36E-06/yr). This value is less than the RG 1.174 requirement to demonstrate that the total LERF due to internal and external events is less than 1.0E-05/yr.
Impact on Conclusions Based on these revisions, there is no substantive impact on the conclusions provided in Section 7 .0 of Attachment 3 of the PBAPS submittals, but the absolute values are different in two of the bullets as noted below.
- To determine the potential impact from external events, a bounding assessment from the risk associated with external events was performed utilizing available information. The total increase in LERF due to internal events and the bounding external events assessment is 7.74E-07/yr. This value is in Region II of the Reg. Guide 1.174 acceptance guidelines.
- The same bounding analysis indicates that the total LERF from both internal and external risks is 6. 72E-06/yr which is less than the Reg. Guide 1.174 limit of 1.0E-05/yr given that the .l\LERF is in Region II (small change in risk).
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APLA*RAl-2 Section 4.4 in Attachment 3 of the LAR uses the Calvert Cliffs Nuclear Power Plant methodology in evaluating the impact of liner corrosion on the extension of ILRT testing intervals. In addition to the two observed corrosion events at North Anna Power Station, Unit 2 and Brunswick Steam Electric Plant, Unit 2, the licensee identifies two more events that "have occurred in recent years (based on a data search covering approximately nine years documented in Reference [21])." It is not clear what date range the nine year data search covers, because Reference 21 in Section 8.0 of Attachment 3 of the LAR seems to be incorrect as it refers to the Individual Plant Examination for External Events dated May 1996. Regarding the data search covering approximately 9 years, please list the correct reference for this report and provide the date range of the data search. Also, indicate if there have been any additional instances of liner corrosion since this data search that could be relevant to this assessment, and, if so, describe its impact on the LAR risk results.
Response to APLA-RAl-2 The reference was inappropriately identified as the Peach Bottom IPEEE when it should have referred to a prior Peach Bottom RAI response as indicated below.
Letter from P. B. Cowan (Exelon Nuclear, Peach Bottom) to U.S. Nuclear Regulatory Commission, Response to Request for Additional Information -
License Amendment Request for Type A Test Extension, Accession Number ML100560433, February 25, 2010.
The previous data search covered a time frame through 2009 and identified two potentially applicable corrosion events. Additional data searches within the INPO operating experience database have been performed to expand the search to include the time frame through the end of 2014. The following information regarding degraded containment liners were found:
- 1. NRC Information Notice 2010-12 (June 2010)-This information notice (IN) documented a 2009 condition identified at Beaver Valley Power Station Unit 1. This event was also identified in the previous data search and was assessed as applicable to the ILRT risk assessment. Two other events are described in IN 2010-12 regarding corrosion findings at Brunswick and at Salem. Both of these other events were indicative of degraded conditions and did not identify any through-wall failures. [This IN did not identify any new events that would impact the risk assessment.]
- 2. Crystal River Unit 3 (June 2010) - As part of the routine IWE/IWL Containment Liner Inspections, bulges on the containment liner were observed. The identified bulges were determined to represent a degraded condition and not through-wall failures. Note that separate issues regarding delamination of the Crystal River containment were attributed to a redistribution of stresses as a result of the detensioning scope and sequence associated with the steam generator replacement containment opening activities.
[Neither of these conditions would impact the risk assessment.]
- 3. Turkey Point Unit 3 (October 2010) - Containment liner through wall degradation was identified at Turkey Point Unit 3, while performing ASME Section IX subsection IWE inspection during the Cycle 25 refueling outage. The affected section of liner is located in the reactor cavity pit area. Based on UT inspection results, an area measuring 6
approximately 4 inches high from the floor, and 32 inches wide was found to be significantly degraded, including through wall damage. The cause of the degradation appears to be long term corrosion of the carbon steel liner from the containment side of the liner. [This event is applicable to the risk assessment.]
- 4. NRC Information Notice 2011-15 (August 2011) - This IN documented instances of corrosion and pitting in the torus region of the boiling-water reactor (BWR) Mark I containments at Duane Arnold Energy Center and Cooper Nuclear Station. It also identified instances of corrosion in the drywell region at Hope Creek and Dresden. None of these events resulted in through-wall failures. Additionally, the torus submerged areas at Peach Bottom were re-coated in 2012 for Unit 2 and 2013 for Unit 3. [This IN did not identify any new events that would impact the risk assessment.]
- 5. Beaver Valley Unit 1 (October 2013) - During the Beaver Valley Power Station (BVPS)
Unit 1 1R22 Refueling Outage, a through wall defect was discovered during a planned visual examination of the Reactor Containment Building (RCB) steel liner. Investigation and laboratory analysis determined that there were indications of two through wall penetrations with a possible third penetration slightly off-set from the second. The total combined area of the three penetrations was calculated to be approximately 0.4 square inches. [This event is applicable to the risk assessment.]
- 6. NRC Information Notice 2014-07 (May 2014) - This IN documented instances of degradation issues related to the containment floor steel shell and liner plate leak-chase channel systems at several pressurized-water reactor plants. Example were provided from V.C. Summer Nuclear Station, Joseph M. Farley Nuclear Plant Unit 1, and Sequoyah Nuclear Plant Unit 2. These events were indicative of degraded conditions and did not identify any through-wall failures. [This IN did not identify any new events that would impact the risk assessment.]
The supplemental operating experience review indicated that two relevant additional failures have occurred since the original review was performed in 2010 which also identified two relevant additional failures. The methodology to estimate the impact of corrosion-induced leakage was established in the Calvert Cliffs analysis [Ref. 2-1) that has since been utilized in several other ILRT extension requests. The Calvert analysis utilized the information available at that time to establish a historical baseline estimate of corrosion induced liner flaws. The analysis then proceeded to estimate that corrosion induced flaw likelihood will increase due to the change in the ILRT interval to 15 years. The base case assumption was that the historical flaw rate would double every five years. Since the four total additional failures occurred over a longer time period than was used in the original assessment (which accounted for two failures in 5.5 years to establish the historical liner flaw likelihood), accounting for the four additional failures would fall below the base case analysis for corrosion induced flaw likelihood at 15 years that was already performed by Calvert and was duplicated for the PBAPS ILRT extension request. That is, 4 failures in -14 years is less than the 2 failures in 5.5 years used to establish the baseline estimate of flaw likelihood. Additionally, to address the uncertainty associated with such probability estimation, the sensitivity analysis that was performed in Section 6.1 of the risk assessment for PBAPS varied the doubling time for flaw likelihood rate from once every five years to once every two years and once every ten years. The sensitivity case for doubling every two years would be indicative of industry operating experience with several noted liner 7
failures due to corrosion (not just four additional events that have been identified). This case resulted in an increase in LERF due to corrosion of just 1.07E-08/yr (refer to Table 6.1-1 of of the PBAPS submittal). This sensitivity case is bounding for the incorporation of all relevant events identified above and as such would not change the conclusions of the analysis.
Reference
[2-1) Letter from Mr. C. H. Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, Docket No. 50-317, March 27, 2002.
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