RA-23-0199, Response to Request for Additional Information (RAI) Regarding Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1) for Inservice Inspection of the Torus Metallic Liner
| ML23232A000 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 08/18/2023 |
| From: | Ellis K Duke Energy Progress |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| RA-23-0199 | |
| Download: ML23232A000 (1) | |
Text
Kevin M. Ellis General Manager Nuclear Regulatory Affairs, Policy &
Emergency Preparedness Duke Energy 13225 Hagers Ferry Rd., MG011E Huntersville, NC 28078 843-951-1329 Kevin.Ellis@duke-energy.com Serial: RA-23-0199 10 CFR 50.55a August 18, 2023 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Brunswick Steam Electric Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 Docket Nos. 50-325 and 50-324
SUBJECT:
Response to Request for Additional Information (RAI) Regarding Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1) for lnservice Inspection of the Torus Metallic Liner
REFERENCES:
- 1. Duke Energy letter, Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1) for lnservice Inspection of the Torus Metallic Liner, dated December 15, 2022 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML22349A655)
- 2. NRC email, Request for Additional Information - Brunswick Torus ISI Alternative L-2022-LLR-0089, dated July 19, 2023 (ADAMS Accession No. ML23202A065)
Ladies and Gentlemen:
In Reference 1, Duke Energy Progress, LLC (Duke Energy) requested U.S. Nuclear Regulatory Commission (NRC) approval of a proposed alternative to certain requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI for Brunswick Steam Electric Plant (BNP) Units 1 and 2. Specifically, Duke Energy proposed an alternative to examination requirements found in the ASME Code, subsection IWE for visual examination of the metallic liner surrounding the Suppression Chamber (torus) containment for Units 1 and 2. In Reference 2, the NRC staff requested additional information regarding Reference 1. Enclosure 1 provides Duke Energys response to the Reference 2 RAI. supports the response provided in Enclosure 1.
U.S. Nuclear Regulatory Commission RA-23-0199 Page 2 No new regulatory commitments have been made in this submittal. If you have additional questions, please contact Ryan Treadway, Director - Nuclear Fleet Licensing , at (980) 373-5873.
Kevin M. Ellis General Manager - Nuclear Regulatory Affairs , Policy & Emergency Preparedness
Enclosures:
- 1. Response to Request for Additional Information
- 2. Calculation 0RIP-1009 , Revision 0, "Torus Liner Revised Acceptance Criteria" cc:
L. Dudes, Regional Administrator USNRC Region II L. Haeg, USNRC NRR Project Manager for BNP G. Smith , USN RC Senior Resident Inspector for BNP RA-23-0199 Enclosure 1 Response to Request for Additional Information RA-23-0199 Page 1 NRC NVIB-RAI-1 Issue The licensee submitted the alternative request pursuant to 10 CFR 50.55a(z)(1). The regulation of 10 CFR 50.55a(z)(1) states that the proposed alternative would provide an acceptable level of quality and safety. It is not evident that the proposed alternative will provide an acceptable level of quality and safety.
Request Discuss how the proposed alternative satisfies 10 CFR 50.55a(z)(1).
Duke Energy Response to NRC NVIB-RAI-1 Duke Energys position is that the alternative submitted meets the threshold for providing an acceptable level of quality and safety under 10 CFR 50.55a(z)(1). Engineering calculation 0RIP-1009 (Enclosure 2) establishes the minimum thickness required by design for the torus metallic liner. With acceptance of this proposed alternative, Duke Energy will establish a new acceptance criteria that will apply 145% of the design minimum allowable thickness to disposition general area corrosion and substrate pitting degradation discovered during inservice inspection of the torus metallic liner. Discovered relevant conditions that exceed this new acceptance criteria will be dispositioned in accordance with the acceptance standards of IWE-3122.2 or IWE-3122.3 prior to continued service. This proposed alternative provides sufficient margin between the new proposed acceptance criteria and the design minimum allowable thickness; thereby, the proposed alternative provides reasonable assurance the integrity of the torus metallic liner is maintained. Since the engineering calculation demonstrates that the proposed new acceptance criteria provides an acceptable level of quality and safety, the 10 CFR 50.55a(z)(1) path was pursued.
RA-23-0199 Page 2 NRC NVIB-RAI-2 Issue Section 4.1 of the relief request states that The Brunswick Unit 1 and 2 Suppression Chamber (torus) containment metallic liner plate is 3/8-inch (375 mils) nominal thickness and backed by reinforced concrete. Attachment 1 to the relief request presents two diagrams of the torus arrangement. However, the diagrams do not show how the reinforced concrete is joined with the torus wall metal plates. Thus, it is not clear how the torus liner plates are joined with the reinforced concrete.
Requests (1) Discuss whether a gap or annulus exists between the torus wall and the reinforced concrete such that leaking coolant could be drained away from the torus.
(2) If a through wall leak does occur at a torus wall, discuss how the leakage can be detected and how soon the operator would be notified.
(3) Discuss the consequence if the torus coolant leaks into the annulus between the metal wall and the reinforced concrete without timely detection.
Duke Energy Response to NRC NVIB-RAI-2 (1) There is no gap or annulus area between the liner plate and the concrete structure. If leakage were to occur through the liner plate it would migrate along the liner concrete interface until a path through the concrete was encountered (concrete defect or piping penetration).
(2) Considering the torturous path from the through-wall leak location to the reactor building environment, it is indeterminant how long it would take any leakage to migrate to the reactor building and become detectable to operations. This torturous path would begin as a pinhole in the torus liner then migrate along the liner to concrete interface until an opening is encountered in the concrete that allows a flow path into secondary containment. It is anticipated that this leakage would be small and not be detected by monitoring torus water level for change in elevation.
(3) Technical Specification and Technical Requirements Manual Section 5.5.2 describe the program for control to minimize leakage from those portions of systems outside primary containment that could contain highly radioactive fluids during serious transients or accidents. These systems are periodically tested and inspected to determine the system leakage rates. The leakage rates of all the systems are added together to obtain a total Engineered Safety Feature (ESF) leakage. Duke Energy procedure AD-MN-ALL-0006, Fluid Leak Management, provides a management standard acceptance criteria 1 gpm total ESF leakage. Leakage between 1 and 20 gpm can be accepted with Management approval.
20 gpm is leakage rate used as input to the various radiological dose calculations.
RA-23-0199 Page 3 NRC NVIB-RAI-3 Issue Section 4.1 of the relief request states that The torus metallic liner remains fully capable of performing its intended design function with local substrate pit corrosion that does not result in a remaining wall thickness of less than 187 mils (tmin=3/16 or 50% nominal wall thickness) and with general area corrosion that does not result in a remaining wall thickness of less than 250 mils (tmin = 1/4" or 66% nominal wall thickness) . The proposed alternative does not provide technical basis to support the claim that 50% and 66% nominal wall thickness for the local substrate pit corrosion and the general area corrosion, respectively, would maintain the design function. Also, the proposed alternative does not provide the definition of a local pit corrosion and general corrosion e.g., what is the dimension of the surface area that would be considered as a local pit corrosion vs. a general area corrosion.
Requests (1) Provide the Calculation that provides the minimum acceptable liner thickness for pitting and general corrosion that supports the design function of the torus.
(2) Define the general area corrosion and local substrate pit corrosion in term of surface area of the torus.
(3) Discuss the technical basis that demonstrates the acceptability of the proposed acceptance criteria.
Duke Energy Response to NRC NVIB-RAI-3 (1) Calculation 0RIP-1009, Torus Liner Revised Acceptance Criteria, is provided as Enclosure 2.
Calculation 0RIP-1009 establishes the minimum allowable thickness required by design of the torus metallic liner in general areas as 1/4 and the minimum allowable thickness required by design in pitted areas as 3/16. For general area thickness, the calculation assumes the anchor bolts are loaded to their design capacity. These anchor reaction loads are used to establish maximum bending moment on a uniformly loaded plate section. Using this maximum bending moment on the plate and the plate material allowable stress, the minimum acceptable plate thickness was calculated as 1/4.
This 1/4 plate thickness was used to verify that ASME Code allowable for stud displacement and liner strain due to an assumed buckled panel were satisfied. The stud diameter to liner thickness ratio was also checked to be within design limits for liner tearing.
(2) General Area Corrosion is defined as an area with uniform material loss.
Substrate pit corrosion is defined in the 0RIP-1009 calculation as a 1 diameter area with a minimum thickness in the pit area of 3/16 and the average thickness in the pit area of 1/4.
The 3/16 maximum pit remaining wall thickness is established based on keeping the stud diameter to liner thickness ratio to less than 2.7 to prevent liner tearing. Having an average thickness of at least 1/4 in the pitted area is acceptable based on the evaluation of the general area minimum acceptable wall thickness described above.
RA-23-0199 Page 4 (3) Calculation 0RIP-1009 provides the minimum allowable thickness required by design at a pit location as 0.1875. The 145% of tmin proposed acceptance criteria is 0.2719 (1.45 X 0.1875). This leaves approximately 0.0844 (0.2719 - 0.1875) of torus base material allowable for future pitting corrosion.
Considering a pitting corrosion rate of 7.5 mil/year (see NVIB-RAI-6 Response (4) for basis for corrosion rate) and 0.0844 of torus base material available for future corrosion, an uncoated pitted area with a depth equal to the proposed acceptance criteria would not be expected to violate the design minimum wall thickness for approximately 11.25 years (0.0844/0.0075) if left uncoated.
Considering an inspection interval of 10 years, uncoated pits (either left uncoated or due to coating failure) would not be expected to violate the design minimum wall thickness prior to the next inservice inspection date.
The plant standard practice is to restore the protective coating during the outage of discovery.
RA-23-0199 Page 5 NRC NVIB-RAI-4 Issue Section 4.2.2 of the relief request states, in part, that the licensee applied protective coating on the submerged surface of all 16 torus bays at Unit 2 during the second CISI [containment inservice inspection] interval inspection in March 2015. Section 4.3.2 of the relief request states, in part, that in the third CISI interval inspection which began in May 2018, a corroded area that exceeded the 10% metal loss acceptance criterion was detected in a torus bay. It appears that the protective coating that applied to the torus interior surface in 2015 did not arrest the corrosion at that corroded area. In addition, the proposed alternative does not provide data on the corrosion rate (mils per month or year).
Request (1) Discuss the effectiveness of the protective coating restoration, e.g., how many years the protective coating can protect the torus wall from growth of an existing corroded area or from new corrosion to occur?
(2) Provide the maximum and average corrosion rate (mils per month or year) of the corroded areas detected in torus wall at Units 1 and 2.
(3) Specify the corrosion rate in torus wall used in the proposed acceptance criteria.
Duke Energy Response to NRC NVIB-RAI-4 (1) Repairs are performed by a specialty vendor using qualified Service Level 1 coating Bio-Dur 561. When coating defects are identified and repaired, the corroded area and adjacent coating is cleaned and prepared for spot application of Bio-Dur 561. Bio-Dur 561 performance exceeds other available underwater coatings with proven industry success of greater than 20 years without failure.
(2) The observed pitting corrosion rate is discussed in detail in NVIB-RAI-6 Response (4). The maximum observed corrosion rate is approximately 4.9 mil/year.
(3) The corrosion rate used in this proposal to establish the proposed acceptance criteria is 7.5 mil/year. This provides a factor of safety of greater than 1.5 on the maximum observed corrosion rate.
RA-23-0199 Page 6 NRC NVIB-RAI-5 Issue Section 4.4.2 of the relief request states, in part, that For Brunswick Unit 1 torus submerged surfaces with substrate pit corrosion areas left uncoated during the second inspection interval (Brunswick Unit 1, March 2016), the engineering evaluation, proposed alternative visual (VT-3) examination acceptance criteria (Section 5.1), and the scheduled visual examinations during the next two refueling outages of the current third containment inspection interval It is not clear why the corroded areas have not been applied with protective recoating restoration during the second CISI interval at Unit 1 even though protective coating restoration was applied on the torus bays at Unit 2. It is not clear whether the uncoated corroded areas will be visually examined during each of the next two refueling outages or will be divided between the next two refueling outages in the third CISI interval.
Requests (1) Discuss why protective coating was not applied during the second CISI interval to minimize further corrosion to the uncoated corroded areas at the Unit 1 torus.
(2) If the uncoated corroded areas on the Unit 1 torus walls were to further degrade during the next two refueling outages of the third CISI interval, discuss the corrective actions.
(3) Discuss whether all the uncoated corroded areas in Unit 1 torus will be visually examined in each of the next two refueling outages or will be divided between the two refueling outages in the third CISI interval.
Duke Energy Response to NRC NVIB-RAI-5 (1) Calculation 0RIP-1009 (Enclosure 2) established the acceptance criteria for torus metallic liner thickness to ensure containment integrity. For a general area, the minimum permissible liner wall thickness at general corroded areas, tmin, is 1/4". For a pitted area, the minimum permissible liner wall thickness is set to one half of the plate thickness, i.e. 3/16.
The nominal torus metallic liner wall thickness is 3/8 inch. Using the minimum thickness required by design in the 0RIP-1009 calculation, a threshold of less than 90 mils (appx. 24%
of nominal wall thickness) of torus metallic liner metal loss was established as providing conservative design margin. This threshold of 90 mils was applied as the IWA-3500 Acceptance Criteria (ref: ASME Section XI, 2001 Edition / 2003 Addenda) during the 2016 Brunswick Unit 1 CISI second-interval third-period refueling outage.
During the 2016 Brunswick Unit 1 CISI second-interval third-period refueling outage, a total of 4,727 exposed substrate indications were identified on the torus metallic liner plating randomly distributed throughout the immersion area. Most of these exposed substrate indications (67%) exhibited greater than 37 mils metal loss. Four (4) of these indications exhibited greater than 90 mils metal loss (131 mils max). None of the exposed substrate indications exceed the acceptance criteria for minimum thickness required by design established in calculation 0RIP-1009. At the direction of plant engineering, underwater coating repair was performed on a total of 9 indications, including the four (4) indications with a measured metal loss of >90 mils. Based on the available design margin at locations that did not have coatings restored during the outage, the decision was made to reduce the impact to overall outage duration and address these locations at a future outage when resources and scheduling could be appropriately arranged.
RA-23-0199 Page 7 (2) With acceptance of the proposed alternative, Duke Energy will apply the new acceptance criteria to discovered exposed substrate areas and corrosive pit indications in the torus metallic liner submerged surfaces. This new acceptance criteria will be applied to exposed substrate areas and corrosive pit indications discovered in torus submerged surfaces with previously restored protective coatings and to the areas of exposed substrate corrosion left uncoated during the second inspection interval (2016 Brunswick Unit 1 Refueling Outage).
Any discovered corrosive pit indications that exceed the proposed new acceptance criteria will be dispositioned in accordance with the requirements of IWE-3122.2 or IWE-3122.3 prior to continued service.
(3) During the 2022 Brunswick Unit 1 refueling outage, four (4) of sixteen (16) torus submerged metallic liner bays were inspected. During this refueling outage, protective coating was re-applied to all discovered areas of exposed substrate corrosion within these four (4) torus bays.
During the upcoming 2024 Brunswick Unit 1 refueling outages, six (6) of the twelve (12) remaining torus bays with uncoated corroded areas from the 2016 refueling outage are currently scheduled for examination and protective coating restoration. During the next 2026 Brunswick Unit 1 refueling outage, the six (6) remaining torus bays with uncoated corroded areas from the 2016 refueling outage are scheduled for examination and protective coating restoration.
If the torus submerged surfaces examinations during the 2024 and 2026 Brunswick Unit 1 refueling outages reveal that the uncoated corroded areas remain bounded by the current engineering calculation (ref. 0RIP-1009), then Duke Energy may apply additional analysis of the remaining uncoated corroded areas which may support extending torus submerged surfaces examinations until the 2028 Brunswick Unit 1 refueling outage.
RA-23-0199 Page 8 NRC NVIB-RAI-6 Issue Section 4.4.2 of the relief request states, in part, that During Brunswick Unit 1 third containment inspection interval, there are three (3) remaining refueling outages. With the conservatism applied by the engineering evaluation to establish visual (VT-3) examination acceptance criteria and design minimum allowable thickness for the torus metallic liner, additional remaining service life may be attained and applied through additional design analysis.
This additional analysis may allow extending the current scheduled visual examinations and protective coating restorations to the third remaining refueling outage of the current Brunswick Unit 1 current third containment inspection interval.
Section 5.2 of the relief request states, in part, that On Brunswick Unit 1, visual (VT-3) examinations and protective coatings restoration of submerged surfaces in the remaining twelve (12) torus bays will continue during the current third inspection interval in accordance with Table IWE-2500-1, Examination Category E-A, Item Number E1.12. These twelve torus bays did not receive protective coating restoration during the third period of the previous second containment inspection interval. Visual (VT-3) examinations during the current third containment inspection interval and engineering evaluation facilitate the monitoring of degradation of these torus metallic liner submerged surfaces. Duke Energy proposes that the engineering evaluation provides reasonable assurance that these torus submerged surfaces remain fully capable of performing its intended design function(s) during the current third containment inspection interval and until the next visual (VT-3) examination during the next two refueling outages of the current inspection interval.
The staff is not clear on the following items:
(1) whether a third remaining refueling outage is scheduled in the third CISI interval, (2) whether corroded areas were or were not detected in the 12 torus bays at Unit 1 such that protective coating restoration was not needed, or there were corroded areas detected but the licensee decided not to restore the coating, (3) whether the 16 torus bays, including the 12 bays mentioned above, have received applied protective coating restoration at Unit 1 torus, (4) whether the proposed torus examination extension at Unit 1 is predicated on the application of the protective coating restoration of the Unit 1 torus bays, (5) whether the entirety of Unit 1 torus bays have been restored with protective coating, (6) whether the proposed torus examination extension is requested for approval before the protective coating is being restored in the Unit 1 torus.
Requests (1) For the Unit 1 torus, discuss whether corroded areas were detected in the 12 torus bays during the inspection performed in the third period of the second CISI interval. If yes, discuss why the protective coating restoration was not applied to the corroded areas in the 12 torus bays.
(2) Clarify whether these remaining 12 torus bays at Unit 1 were re-examined during the first period of the third CISI interval. If yes, discuss whether the existing corroded areas have grown and whether new corroded areas were detected. If not examined, discuss when the next examination of the 12 bays will be performed.
(3) Discuss whether the protective coating restoration will be applied to all 16 torus bays or only the corroded locations at Unit 1 during the remaining refueling outages of the third CISI interval.
If not, provide justification.
RA-23-0199 Page 9 (4) Discuss and/or provide the design analysis and corrosion test data that allow examination extension and protective coating restorations of the uncoated corroded areas for the remaining refueling outages of the third CISI interval for the Unit 1 torus.
(5) Discuss why the examination extension (inspection every three periods) could be applied to the Unit 1 torus bays that have not had protective coating restoration applied.
Duke Energy Response to NRC NVIB-RAI-6 (1) A reply to this request is provided in NVIB-RAI-10, Response (1) and Attachment 1.
(2) The general surface areas of Brunswick Unit 1 Torus Bays 01 thru 04 and 09 thru 16 (12 bays) were not examined during the CISI third-interval first-period refueling outages. The current schedule for examination of these remaining torus bays is provided in response to NVIB-RAI-5 (Part 3) and Attachment 1 Brunswick Unit 1 CISI Third Interval Inspection Timeline. This current schedule to reapply protective coating to these remaining twelve (12) torus bays is supported by the projected corrosion rate presented in NVIB-RAI-6, Response (4) and the projected time-period for future corrosion to exceed torus liner design minimum allowable thickness presented in NVIB-RAI-3 Response (3).
The below examinations were performed during the 2022 Brunswick Unit 1 third-interval first-period refueling outage.
Category E-A, Item Number E1.12, scheduled visual (VT-3) examinations were performed on submerged surfaces of torus bays 05, 06, 07, and 08. During this inspection, protective coating restoration was applied to the areas of corrosion observed within these four (4) torus bays to arrest further substrate corrosive degradation.
Category E-C, Item Number E4.11, augmented visual (VT-1) examinations were performed on five (5) submerged surface areas listed below in this NVIB-RAI-6 Response (4). The protective coating was reapplied to these substrate pit corrosion areas during the 2016 Brunswick Unit 1 refueling outage. During the 2022 examination, the 2016 applied protective coating was found intact; thereby, confirming the reapplied protective coating is effective at arresting further corrosive degradation.
(3) Before the end of the Brunswick Unit 1 CISI third interval, protective coating restoration will be applied to the discovered exposed substrate areas and corrosive pit indications in the submerged surfaces of the torus metallic liner in all 16 torus bays. For submerged surfaces of the torus metallic liner where the previously applied protective coating is verified intact, the reapplication of protective coating to these surface areas will not be required.
(4) In 1998 the Carolina Power & Light Co. (now Duke Energy) Material Services Section was asked to project the depth of the deepest pit measured during the 1995 torus recoating project if that pit was to remain uncoated for an additional 10 years. The deepest pit measured was 84 mils deep and the prediction assumed that the pit had been forming for 10 years. After 20 years of service the evaluation predicts a pit depth of approximately 123 mils.
RA-23-0199 Page 10 During the 2016 inspection of the Unit 1 torus the following are the recorded values for the 5 pits that were repaired by applying a protective coating. The remainder of the pits were measured to be less than 90 mils.
- Torus Bay 2 / Shell Plate SP-02-04 (pit depth 125.7 mils)
- Torus Bay 5 / Shell Plate SP-05-02 (pit depth 90.7 mils)
- Torus Bay 7 / Shell Plate SP-07-05 (pit depth 120 mils)
- Torus Bay 8 / Shell Plate SP-08-05 (pit depth 131.3 mils)
- Torus Bay 10 / Shell Plate SP-10-02 (pit depth 87.7 mils)
The deepest pit was measured to be approximately 131.3 mils deep. Considering that the entire torus was recoated in 1995, it is not unreasonable to assume that the deepest of these pits were associated with a coating defect and that the pitting initiated soon after refilling the torus. Considering 21 years between the application of the coating and the 2016 inspection, the measured pitting correlates well with the above predicted 20 year corrosion depth within 8 mils of the original prediction.
For the pits that were left uncoated during the 2016 inspection the maximum metal pit depth measured was less than 82 mils (measured depth minus coating thickness). Considering an additional 10 years of service prior to repair, it is anticipated (using the model above adjusted for the 2016 inspection data) that the maximum pit depth would be less than 131 mils. This averages to a liner corrosion rate of 4.9 mils per year. Considering the uncertainty associated with the date of pit initiation used, the calculated pit corrosion rate is increased to 7.5 mil per year for evaluation purposes, which provides a factor of safety of greater than 1.5.
(5) With this proposed alternative, Duke Energy proposes that discovered exposed substrate areas and corrosive pit indications in the submerged surfaces of the torus metallic liner which have received protective coating restoration during a refueling outage will be examined in accordance with Table IWE-2500-1, Examination Category E-A, Item Number E1.12, applying a time-period not to exceed three inspection periods (maximum time-period of no more than 10 years). Duke Energy proposes that this examination and time-period only apply to exposed substrate and corrosive pit indications that receive protective coating restoration.
This proposed alternative does not apply to discovered exposed substrate areas and corrosive pit indications in the Brunswick Unit 1 torus bays that have not received protective coating restoration. The disposition of exposed substrate areas and corrosive pit indications left uncoated is further discussed in NVIB-RAI-5 Response (2) and NVIB-RAI-6 Response (4).
RA-23-0199 Page 11 NRC ESEB/NVIB-RAI-7 Issue Section 5.1 states, in part, that As an alternative to the 10% loss of nominal wall thickness specified in IWE-3513(a), Duke Energy proposes visual (VT-3) examinations revealing substrate pitting or other corrosive degradation that results in a remaining wall thickness of less than 145% of the design minimum allowable for substrate pit corrosion of the metallic liner nominal wall thickness will be considered relevant conditions Subarticle IWE-3513(a) of the 2007 Edition of the ASME Code,Section XI discusses relevant conditions include corrosion that exceeds 10% of the nominal wall thickness. The NRC staff notes that 10% loss of nominal torus wall thickness is 0.0375 inches for the torus at Units 1 and
- 2. The NRC staff notes that the relief request does not provide the design minimum allowable thickness. Therefore, it is not clear how the proposed alternative acceptance criteria criterion of 145% of the design minimum allowable thickness is compared to the acceptance criterion of IWE-3513(a).
Requests (1) Provide the acceptance criteria in terms of the percentage of material loss of the torus nominal wall thickness.
(2) Provide the technical basis in detail, including analyses and corrosion test data, of the acceptance criterion of 145% of the design minimum allowable.
(3) Provide the minimum allowable thicknesses of torus wall (e.g., general, and pitting corrosions).
(4) Discuss the corrective actions that will be taken if a corroded area exceeds the proposed acceptance criterion.
(5) If the size (depth and surface corroded area) of an indication is within the proposed acceptance criterion, discuss whether any actions will be taken.
Duke Energy Response to NRC ESEB/NVIB-RAI-7 (1) Calculation 0RIP-1009 (Enclosure 2) identifies that the nominal wall thickness is 0.375 and the design minimum allowable wall thickness is 0.1875at pitted areas. With this proposed alternative, applying the new acceptance criteria 145% to the minimum wall thickness is 0.2719. This represents 72.5% of the nominal wall thickness or a remaining thickness of 27.5% for allowable metal loss. It should be noted that the actual wall thickness may vary from the nominal value of 0.375 due to manufacturers tolerance.
(2) A reply to this request is provided in NVIB-RAI-3.
(3) Calculation 0RIP-1009 establishes the minimum thickness required by design for the general area of the torus metallic liner as 1/4" and the minimum thickness required by design of pitted areas as 3/16. See Response to NVIB-RAI-3 for description of calculation.
(4) Corrective actions would typically be to apply protective coating to the pitted areas that are within or exceed the proposed alternate acceptance criteria. If protective coating were not able to be applied, the condition would be entered into the corrective action program and an engineering evaluation performed in accordance with IWE-3122.3.
RA-23-0199 Page 12 (5) For discovered indications within the proposed acceptance criteria, the inspection results will be accepted by examination in accordance with IWE-3122.1. For these discovered indications, the protective coating will typically be reapplied and corrective measures or evaluation in accordance with IWE-3122.2 or IWE-3122.3, respectively, is not required.
RA-23-0199 Page 13 NRC NVIB-RAI-8 Issue Section 5.1 of the relief request states, in part, that This visual (VT-3) reexamination shall be performed during the successive inspection interval at a frequency not to exceed every third inspection period from the previously visual (VT-3) examination. The submerged torus walls at Units 1 and 2 contain corroded areas that have been and have not been recoated, and potential new corroded areas. It is not clear whether inspecting the torus wall every third inspection period (i.e., every 10 years) is adequate to monitor corroded areas with various degree of degradation. In addition, the relief request does not provide the corrosion test and operating experience data and analyses to justify the proposed examination extension.
Requests (1) Discuss the technical basis to support the proposed inspection frequency (VT-3) of every third period for each of the following degradations:
(a) previously detected corroded areas that are not repaired (e.g., no coating restoration),
(b) the repaired of corroded areas, (c) the new detected corroded areas and, (d) areas that may degrade during every third period.
The technical basis should include analyses, corrosion test, and operating experience data to demonstrate the adequacy of the proposed every three periods.
(2) Clarify whether the proposed examination extension (every three periods) applies only to the recoated corroded areas that have been repaired with the protective coating restoration or applies to all areas (i.e., cases in items a, b, c, and d).
(3) During the upcoming Unit 1, 2026 refueling outage and Unit 2, 2025 refueling outages, will the licensee examine previously detected indications in torus bays to determine whether those indications have degraded further?
(4) Provide the inspection frequency for the detected indications that do not receive protective coating restoration under the proposed alternative?
(5) Discuss whether any indications that have not been repaired with the protective coating restoration. If yes, discuss whether coating will be restored at those indications during the Unit 1, 2026 refueling outage and Unit 2, 2025 refueling outage of the third CISI interval.
Duke Energy Response to NRC NVIB-RAI-8 (1) The technical basis for the proposed reinspection by visual (VT-3) examination over a time-period not to exceed three inspection periods (10 years) is supported by the projected pitting growth rate (7.5 mils per year) and the proposed new acceptance criteria (145% of minimum allowable thickness) which are presented above in NVIB-RAI-3 Response. Considering the acceptable minimum thickness of the torus metallic liner at pitted areas (tmin = 0.1875 inches), the Duke Energy proposed acceptance criteria of 145% tmin provides material allowance for future pitting corrosion. Specifically, this material allowance for future pitting corrosion is 0.084 inches (0.1875 x 0.45).
Scenario a - Considering the 0.084 of base material available for future corrosion and a corrosion rate of 7.5 mil/year, an uncoated pitted area (i.e. protective coating was not applied or the applied protective coating failed) would not be expected to violate the design minimum wall thickness for approximately 11.2 years (0.084/0.0075) if left uncoated. The RA-23-0199 Page 14 projected time-period (11.2 years) exceeds the proposed reinspection over a time-period that does not exceed three inspections periods (10 years).
Scenario b - If a corrosive pitted area met the proposed new acceptance criteria and its protective coating was restored (i.e. successfully applied), then the restored protective coating will arrest the corrosion and pit depth would not change.
Scenario c and d - With protective coatings restored during the scheduled inspections of the torus metallic liner, it is not anticipated that any new corrosive pits developed during the subsequent inspection periods would violate the design minimum wall thickness.
This paragraph provides Brunswick specific operating experience for submerged surfaces of the torus metallic liner that have received protective coating restoration during a previous refueling outage. During the 2015 Brunswick Unit 2 refueling outage, protective coating was applied to all discovered substrate pitting areas. During the 2021 Brunswick Unit 2 inspection of torus bays 01, 02, 03, 04, and 05, only one (1) discovered corrosion pitting indication exceeded the 2021 acceptance criteria (10% nominal wall thickness). During the subsequent 2023 Brunswick Unit 2 inspection of torus bays 06, 07, 08, and 09, again only one (1) corrosion pitting indication exceeded the 2021 acceptance criteria (10% nominal wall thickness). The limited number of discovered relevant conditions (greater than 10% nominal wall thickness) during these 2021 and 2023 Brunswick Unit 2 torus inspections support the above scenario responses that restoration of protective coatings is effective at arresting future corrosive degradation.
(2) The Duke Energy proposed alternative that reinspection will be performed at a time-period not to exceed three inspection period (10 years) is applicable to specific areas where the protective coating has been restored. This proposed alternative shall be a visual (VT-3) examination in accordance with Table IWE-2500-1, Examination Category E-A, Item Number E1.12.
This proposed alternative does not apply to discovered corrosive areas of the torus metallic liner that have not been recoated to prevent further corrosion degradation. The disposition of exposed substrate areas and corrosive pit indications left uncoated is provided in NVIB-RAI-5 Response (2) and NVIB-RAI-6 Response (4).
(3) During the Brunswick CISI third interval inspections, methods will not be applied to determine whether corrosive pit indications have grown between the previous CISI second-interval inspection and the current third-interval inspection. With acceptance of the proposed alternative, Duke Energy will apply the new acceptance criteria during CISI third interval inspections as described in NVIB-RAI-5 Response (2).
(4) For discovered indications that do not receive protective coating restoration and are determined acceptable by engineering evaluation in accordance IWE-3122.3, the inspection frequency will be in accordance with IWE-2420.
(5) For Brunswick Unit 1, a reply is provided in NVIB-RAI-5 Response (3). For Brunswick Unit 2, protective coating was reapplied to all previously discovered exposed substrate and corrosive pit indications in submerged surfaces of the torus metallic liner during their previous CISI inspections.
RA-23-0199 Page 15 NRC NVIB-RAI-9 Issue Section 5.2 of the relief request states, in part, that On Brunswick Unit 2, visual (VT-3) examinations and protective coating restoration were performed on five (5) torus bays during the first period of the third containment inspection interval. Augmented visual (VT-1) examinations were neither required nor performed during these containment liner inspections For these five torus bays on Brunswick Unit 2, Duke Energy proposes that successive visual (VT-1) examination during the next inspection period will not be performed, and the next scheduled visual (VT-3) examination will be performed during the fourth containment inspection interval.
The NRC staff notes that:
(1) The 2007 edition of the ASME Code,Section XI, Table IWE-2500-1, Examination Category E-C, Item No. E4.11 requires a VT-1 examination be performed for the surface areas identified by IWE-1242 which refers to surface areas identified by IWE-1240, Surface Areas Requiring Augmented Examination. It is not clear why the VT-1 examination is not performed when a detected corroded area exceeds the 10% metal loss acceptance criterion of IWE-3513(a) during the first period of the third CISI interval at Unit 2.
(2) It is not clear why the VT-1 examination will not be performed on the corroded areas during the inspection that will be performed in the fourth CISI interval at Unit 2.
Requests (1) Discuss why augmented VT-1 examinations were not performed during the first period of the third CISI interval when corrosion areas were detected on the torus bays at Unit 2.
(2) Discuss why the VT-1 examination will not be performed on the corroded areas during the inspection for the fourth CISI interval at Unit 2.
Duke Energy Response to NRC NVIB-RAI-9 (1) During the CISI second inspection interval, Brunswick Units 1 and 2 Torus Submerged Surface examinations were performed using the 2001 Edition and 2003 Addenda of ASME Boiler and Pressure Vessel Code,Section XI, Table IWE-2500-1, Examination Category E-A, Item Number E1.12. In this earlier edition and addenda of ASME Section XI, the examination requirements in IWE-3510.1 states, The Owner shall define acceptance criteria for visual examination of containment surfaces. For the Brunswick CISI second interval, the Owner (Duke Energy) established the acceptance criteria that substrate corrosion area and pitting degradation less than 90 mils was bounded by the current calculation of design minimum wall thickness. Therefore, substrate corrosion areas and pitting degradation less than the owner established acceptance criteria of 90 mils metal loss were accepted by examination in accordance with IWE-3122.1 with no requirement for successive inspections in accordance with IWE-2420.
During the CISI second-interval third-period, Brunswick Unit 2 Torus Submerged Surfaces visual (VT-3) examinations were performed on all sixteen (16) torus bays during the B2R22 (March 2015) refueling outage. During these examinations, there were no (0) discovered corrosive areas with substrate material loss that exceed 90 mils established as the acceptance criteria. During this Brunswick Unit 2 (March 2015) refueling outage, protective RA-23-0199 Page 16 coating restoration was applied to all discovered areas of substrate corrosion to arrest any further corrosive degradation.
Given that no substrate corrosion areas or pitting exceeded the Owner (Duke Energy) established acceptance criteria (90 mils) during visual (VT-3) examination in the Brunswick Unit 2 CISI second-interval third-period, augmented visual (VT-1) examinations in accordance with IWE-2420(b) were neither required nor performed during the Brunswick Unit 2 third-interval first-period.
(2) With acceptance of this proposed alternative, successive inspections in accordance with IWE-2420(b) will not be performed on the torus submerged surfaces that have had coatings restored . Duke Energy proposed to perform a VT-3 examination per Table IWE-2500-1, Category E-A, Item No. E1.12 at a time-period not to exceed three inspection periods (10 years) of the torus submerged surfaces where the new proposed acceptance criteria is exceeded on surfaces where protective coatings have been restored.
The duration of this proposed alternative does not extend to the Brunswick Units 1 & 2 CISI Fourth Ten-Year Inspection Interval, which is scheduled to begin on May 11, 2028.
RA-23-0199 Page 17 NRC NVIB-RAI-10 Issue Sections 4 and 5 of the relief-request discuss activities that have been and will be performed in various refueling outages and periods of the third CISI interval. However, it is not clear the exact timing of the activities that have been and will be performed with respect to the refueling outages and periods of the third CISI interval. Also, Section 6 of the request states, in part, that the duration of the relief request is for the third CISI interval only.
Requests (1) For Units 1 and 2, provide a table and/or timeline showing the examination and repair activities with respect to the refueling outages and periods of the third CISI interval. Specifically (a) provide the month and year of every refueling outage in the third CISI interval, (b) indicate activities (examination and/or coating restoration) that have been and will be performed in the refueling outages in the third CISI interval, (c) indicate which refueling outage belongs to which period of the third CISI interval, (d) indicate the examination and potential repair activities that are scheduled for the refueling outage in the first period of the fourth CISI interval, (e) confirm that the torus examination and repair activities beyond the third CISI interval are not covered by the subject relief request.
(2) Clarify whether the protective coating restoration is applied specifically to the corroded areas, not the entire submerged surface of the liners in all 16 torus bays at Units 1 and 2.
(3) Discuss how much material loss at the corroded location will the protective coating restoration be applied.
(4) Discuss whether protective coating restoration will be applied to those corroded areas that were detected in previous refueling outages and whose coating was not restored at the time of the detection.
(5) Discuss whether the protective coating restoration will be applied to the exposed substrate areas even if those areas are not degraded in the Units 1 and 2 torus.
Duke Energy Response to NRC NVIB-RAI-10 (1) For Brunswick Units 1 and 2, the following attachments are provided.
Attachment 1: Brunswick Unit 1 CISI Third Interval Inspection Timeline Attachment 2: Brunswick Unit 2 CISI Third Interval Inspection Timeline Attachment 3: Brunswick Unit 1 Torus Third Interval Inspection Diagram Attachment 4: Brunswick Unit 2 Torus Third Interval Inspection Diagram The duration of this proposed alternative does not extend to the Brunswick Units 1 & 2 Fourth Ten-Year Containment Inservice Inspection Interval, which is scheduled to begin on May 11, 2028.
(2) (3) (5) The plant standard practice is to reapply protective coating to specific areas of exposed substrate and corrosive pit indications throughout the torus metallic liners submerged surfaces during the outage of discovery. This includes reapplying protective coating to corrosion areas with measurable material loss (i.e. both less than or greater than the established inspection criteria) and to any exposed substrate corrosion areas with no measurable material loss. The protective coating restoration is not typically applied to RA-23-0199 Page 18 submerged surface areas of the torus metallic liner where exposed substrate or pitting corrosion through the existing protective coating has not occurred.
(4) A reply to this request is provided in NVIB-RAI-5 Response (3) and NVIB-RAI-8 Response (5).
- Brunswick Unit 1 CISI Third Ten-Year Inspection Interval Timeline Start Date: May 11, 2018 End Date: May 10, 2028 First Period Second Period Third Period May 11, 2018 to May 10, 2022 May 11, 2022 to May 10, 2025 May 11, 2025 to May 10, 2028 Outage 1 (B1R23) Outage 2 (B1R24) Outage 3 (B1R25) Outage 4 (B1R26) Outage 5 (B1R27)
March 2020 March 2022 Spring 2024 Spring 2026 Spring 2028 BNP Torus Submerged BNP Torus Submerged Surfaces BNP Torus Submerged Surfaces BNP Torus Submerged BNP Torus Submerged Surface Metallic Liner Metallic Liner augmented (VT-1) Metallic Liner augmented (VT-1) Surface Metallic Liner Bays Surface Metallic Liner examinations are not examinations performed of the (VT-1) examinations of the over 01, 02, 03, 04, 15, and 16 examinations are not scheduled during this torus submerged surfaces with 500 indications in torus bays 05, examinations and protective scheduled during this refueling outage. metal loss exceeding acceptance 06, 07, and 08 are currently coating restoration of any refueling outage.
(Note 1) criteria (90 mils) during the scheduled. With approval of discovered exposed substrate second-period third interval this proposed alternative, these areas are scheduled.
(2016) refueling outage. For augment (VT-1) examinations This examination will include these specific areas, protective will not be required during the submerged surfaces that did coating was restored during the 2024 refueling outage. not receive protective 2016 refueling outage. The 2022 coating restoration during BNP Torus Submerged Surface augmented VT-1 examinations their previous examination Metallic Liner Bays 09, 10, 11, confirmed protective coating (March 2016).
12, 13, and 14 examinations and remains intact and no substrate protective coating restoration of corrosion. any discovered exposed substrate BNP Torus Submerged Surface areas are scheduled.
Metallic Liner Bays 05, 06, 07, This examination will include and 08 inservice visual (VT-3) submerged surfaces that did not examinations are performed. This receive protective coating includes areas of the submerged restoration during their previous surfaces within these four (4) examination (March 2016).
torus bays that did not receive protective coating restoration during second-period third-interval (2016) refueling outage.
During inspection of Torus Bays 05, 06, 07, and 08, over 500 exposed
substrate indications were discovered with measured metal loss greater than 37 mils (i.e. 10%
nominal wall thickness). In all exposed substrate areas (total 1487 discovered areas), the torus metallic liner protective coating was restored to arrest further degradation.
Note 1: Over the third ten-year inspection interval, Brunswick Unit 1 BNP Torus Metallic Liner Submerged Surface are scheduled for examination during the March 2022 (B1R24), Spring 2024 (B1R25), and Spring 2026 (B1R26) refueling outages.
- Brunswick Unit 2 CISI Third Ten-Year Inspection Interval Timeline First Period Second Period Third Period May 11, 2018 to May 10, 2021 May 11, 2021 to May 10, 2024 May 11, 2024 to May 10, 2028 Outage 1 (B2R24) Outage 2 (B2R25) Outage 3 (B2R26) Outage 4 (B2R27) Outage 5 (B2R28)
March 2019 March 2021 February 2023 Spring 2025 Spring 2027 BNP Torus Submerged BNP Torus Submerged Surface BNP Torus Submerged Surface BNP Torus Submerged BNP Torus Submerged Surface Metallic Liner Metallic Liner Bays 01, 02, 03, 04, Metallic Liner Bays 06, 07, 08, and Surface Metallic Liner Bays Surface Metallic Liner examinations are not and 05 examinations are 09 examinations are performed. 10, 11, 12, 13, 14, 15, and examinations are not scheduled during this performed. 16 examinations and scheduled during this In general, a total of 410 exposed refueling outage. protective coating refueling outage.
In general, a total of 396 exposed substrate indications were (Note 1) restoration of any exposed substrate pit indications were discovered randomly distributed substrate areas are discovered randomly distributed throughout the inspected metallic scheduled.
throughout the inspected metallic liner submerged surfaces. The liner submerged surfaces. The majority of discovered indications Outage work-window majority of discovered indications exhibited less than 37 mil metal duration (i.e. available diver exhibited less than 37 mil metal loss (i.e. less than 10% nominal time to perform submerged loss (i.e. less than 10% nominal wall thickness).
surface inspections) is not wall thickness).
In Torus Bay 09, one (1) exposed established. If the outage In Torus Bay 02, one (1) exposed substrate indication was work-window duration is substrate indication was discovered with measured depth limiting, some of these discovered with measured depth of 58.3 mils. (Note 3) examinations and of 42 mils. (Note 2) protective coatings repairs Metallic Liner Protective Coating may be deferred to B2R28 Metallic Liner Protective Coating was restored to all area of exposed (2027) refueling outage.
was restored to all area of exposed substrate pit indications to arrect substrate pit indications to arrect further degradation.
further degradation.
Note 1: Over the third ten-year inspection interval, Brunswick Unit 2 Torus Metallic Liner Submerged Surface examinations are scheduled to be performed during the March 2021 (B2R25), February 2023 (B2R26), and Spring 2025 (B2R27) refueling outages.
Note 2: During B2R26 (February 2023), the restored protective coating area on the previous discovered exposed substrate pit indication in Torus Bay 02 was re-examined. The protective coating repair confirmed intact. No delamination in the repaired or adjacent area protective coating.
Note 3: During B2R27 (Spring 2025), re-examination of the exposed substrate and restored protective coating area in Torus Bay 09 is scheduled.
Attachment 3: Brunswick Nuclear Plant Unit 1 Suppression Chamber (aka Torus) Inspection Diagram CISI Third Inspection Interval (May 11, 2018 thru May 10, 2028)
CISI Third-Interval Third-Period Brunswick Unit 1 Torus Metallic Liner Bays 15, 16, 01, 02, 03, and 04 inservice visual (VT-3) examinations and protective coating restoration scheduled for the B1R26 (Spring 2026) refueling outage.
CISI Third-Interval Second-Period CISI Third-Interval First-Period Brunswick Unit 1 Torus Metallic Liner Bays 09, 10, 11, 12, Brunswick Unit 1 Torus Metallic Liner Bays 05, 06, 07, 13, and 14 inservice visual (VT-3) examinations and and 08 inservice visual (VT-3) examinations and protective coating restoration scheduled for the B1R25 protective coating restoration performed during the (Spring 2024) refueling outage. B1R24 (March 2022) refueling outage.
Attachment 4: Brunswick Nuclear Plant Unit 2 Suppression Chamber (aka Torus) Inspection Diagram CISI Third Inspection Interval (May 11, 2018 thru May 10, 2028)
CISI Third-Interval Third-Period CISI Third-Interval First-Period Brunswick Unit 2 Torus Metallic Liner Bays 10, 11, Brunswick Unit 2 Torus Metallic Liner Bays 01, 02, 03, 12, 13, 14, 15, and 16 inservice visual (VT-3) 04, and 05 inservice visual (VT-3) examinations examinations and protective coating restoration and protective coating restoration performed during currently scheduled for the B2R27 (Spring 2025) the B2R25 (March 2021) refueling outage.
refueling outage.
CISI Third-Interval Second-Period Brunswick Unit 2 Torus Metallic Liner Bays 06, 07, 08, and 09 inservice visual (VT-3) examinations and protective coating restoration performed during the B2R26 (February 2023) refueling outage.
RA-23-0199 Enclosure 2 Calculation 0RIP-1009, Revision 0, Torus Liner Revised Acceptance Criteria (20 Pages Follow)
SYSTEM No. 8020 TYPE ESMISC CAROLINA POWER & LIGHT COMPANY P. 0. BOX 1551 RALEIGH, NORTH CAROLINA 27602 0RIP-1009 (CALCULATION#)
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-t:
B. Pi'ttcd Area
-the pitted area a"'1d is acl..Jre sscci be loi..J,
Form 5007 (Rev. ~/93) CP~L CALC.,OR. IP-/oo-=i
-~ *Raytheo n GENERAL
~"!'"'- - CALCULATION SET NO. REV. COMP. BY CHK'D BY Engineet"S & Constructors A CoiisohdationolSacigei-*ancfUE&C COMPUTATION ,qq 2. '2 35 .1. SC- LA.02 AAo fl.. L SHEET PRELIU FINAL VOID 0 DATE DATE
,,.... 3. '21-9A .., I'-, la, i..,
PAOJECT _ _ _ C_P__,~_L_-_B_l-.l_P_-=#_l....:~-'2_ _ _ _ _ __
SHEET 5 OF I~ DATE DATE SUBJECT TOK'LJS L1NER REvl.5ED Ac.c.EPTAN( E CR1T1=RIA ever the pirtcci ar.:a) t ;;ve > :::,h2II not be le.:-:s -tl-'lEJYI -thi: m;l"i;V'YJut"V] li°VICf" t"h/ckll'le!.'5 of "th~ 1 3eY1-er.;,L ,2rea 11 (1*.e.t/4)
I.t ,.s -to be f"lo"tecl -tlri~ t :
- T h-e. 1 di'a~et"er pitt cd .E,ea c,:;, 1...J!d oc.<.wr pt" a.n:::J lo c.2-t I oh. 1......)/*c-h II I
_ rnic.f<n<:5S between 3> ar1d.. ..!.. 1* .;re. al:sc ~cc.ept2b/ e ;:;s l 0 >?j as tvi-c
/l::, 4 ,,
.5;,ti.slj the '/4 thtc.kY1ess JI
.?\JC(~s e .2 t 2nj f chJyYI t:te:.r p/ t tccl ~rt::a.
criteria.
FOfm 5007 (Rev. 4/93) C.P ~ L CALC. o R 1P- 1009
- Raytheon GENERAL
..."! ....... - CALCULATION SET NO. REV COMP. BY CHK'D BY Engineers & Constructors COMPUTATION 799'2 .2 35 .. I. SC.- LA_O AAo (! <) , '
A Cortsclidation of Badger ard UE&C SHEET PREUM. FINAL VOID 0 DATE DATE 3.11 .94 \)17 'l'-,
PROJECT _ _ _ C_P_{.,__L_-_8_N_P_:tt_l _~_2_ _ _ _ __
SHEET G OF lb DATE DATE SUBJECT TORUS LINER. REVISED AUE:PTAN( E JO. 79~'2.235 CRITERIA Ll- 13A.Sl.:S oF THE GEt-JcRAL AREA _LINER M1t-Jlt--1LlM THICKNESS is :su!Jec.1"~d. -t"o a... cencric. rcri~;/e uniforn'? wt:/d ,,-,,,,e. lo2d,w-:::: _.!:__
4L*
5-r-ud5 LDi3d !=or I.so /2te.d P~Ylel direction. l.I 211d. Jr_JI i.e.)
ISOLATE() PANEL Gase:: rs:
A.rr:: Prr L3 /19'2. E.I Pr. _ 3,a4 = 2 PJI. - I 9 ~
R. 1 =R 3 =2R 2 From eac.h 150/ated.. p2t'1C L 4
L..R.-P z_-4 :. R + R+ ~ -t 13.. = P
{:I 2 2. ,4
~------.
-- IR= P/,2
Form 5007 (Aov. 4/93) CP\L CAL C.. o RI.P_ 1ooq
-~- Raytheon -*4 - CAI..CI.A..A T10N SET NO. REV. COMP.BY CHK'D BY GENERAL Engineers & ConstnJCtors A Consohdation of Badger and UE&C COMPUTATION 7'lqz_ '235--1. Sl'-L A-02 AAo /20 i[
SHEET PRELIU FINAL VOID 0 DATE DATE 3.17.94 3/ 11/f1 PAOJECT _ _ _ C_P_f;.._L_-_B_N_P_#_l_~_2_ _ _ __
SHEET -:7 OF Ih DATE OATE SUBJECT c roRUS RI rE RII\ LIN ER l<.£VISED Ac.t:.E:PTANC~ J.O. 79C,Z.23S
_ _ _ _ _ _ _ _ _...____..__ ___.__ _--+
R,= R3 = 2 (P~y'l d .s) x R = '2.R. : '2.. )( £ =
12
-p (o
p p R2= 4 (p;;it"'le/s) X R == 4X -- -:::. -
2 '2 .XI 2 I (Pc:1"1el)XE_=:
p =- _e_
R4=
- 2. '2 )(. I 2. Q4 t-e. Anchor5 No. I, 2. a11d 3 lllJ llJJi.,._J-
~ . ~
1,-.L-~L..../ -X l,'25 u.Jl-
.. p = 4.25 or P= '=,x 4-25: 2.5.5 Kip:s l<si ( Ref. [ 11 Sht. 1. '3)
... p - 2 p.rr pl -t prr =
p t J J J I 1 I - )
4
- . pi = p 25-5 1,5 ')(. 4
- 1.s. x4
4.'25 K1pS
.. Fb -- M s =
~M,.,,c::.)( .. -t ::.
I to MM<')(
i l'l,'IW1.
6 .I. t
'2 II bl. Fb or -t . = c., x S.'3l3 :.=- o.254 1/A 11
,....,,,;'} 15 X 3'2.-'1 i.e. t-he.
- Gene,2 L Area " m/,,,,.muvYJ L ir?er rhi c./<.nt:5~ of 1/4 i 5 o, K.
Form 5007 (Rev. 4193) CP~L CALC ORIP-JOOG
- - .Raytheon GENERAL ~4- -
CALCULATION SET NO. REV. COMP. BY CHl<'O BY Engineers & Constructon COMPUTATION 7qq'2. 2 3 5 .1. SC.*L A.O AAO A Consolidation ol Badger ana UE&C SHEET PRalM FINAL VOIO 0 DATE
~., 1.q4 PROJECT _ _ _C P_~....._L_._B_N_P_=#_l_~-'--2_ _ _ _ __
SHEET 8 OF lh DATE OATE SUBJECT TORUS LINER REvrsEC> Ac:.c.EPTAtJ(.i:° J.O. 1Cf9'2.. "2 35 CRITERIA
~
"L= 10.C.. "
From ReF. [2] ,Table 2fo, case S;
~
t,llc x. bendir1'1 stre-s:s 11'1.. 1:he 1/t?er pl~ t~
/3,wt'.2
~~x;::
r 2.
wl1e.re : For£.:!:..-=
b fa,= o. 3o75 w-- _4p____e_-z For "t ,..,..,,*.,....
.. c.. 1
- er:YYl2X -- Fb -- 3'2.,9 l<Si
',1
- . / o.307B X '2.S.5 -:: o.244 V 342.9 x 4
Form 5007 (Rev. 4/93)
....,. . -Rayllleon GENERAL --'f.r..- -
CALCUL.A 1lON SET NO. REV. COUP. BY CHK'O BY Engineers & Constructors COMPUTATION 79Cj2.'23S*-1-SC-LA .02 A.AO fl~I-A C-onsolidation ot Badger and UE&C SHEET PRELIM. FINAL VOID 0 DATE DATE v 3.17.94 1/17/'ilf PAOJECT _ _ C__P__._g_L_-_5_N_P_#_l_.~.._2.______
SHEET. 9 OF Ih DATE DATE SUBJECT TORUS ut.JER REvrsEO Aa.t=PiAt-Jc.E J.O. 7Cc92. 235 C1<1reRIA
- 5. LINE. R. _A p.J C 1-1 o R.. A NA L- YS I 5 II for th<. ul'?co,,-roc.J-cc/ l/r?(:,r ut?i /orM rhi c.k.r1ess of .3/B to C. ~ku/;,t-e:
the. .2f'H.. hor ( 1/'Z. d1ar>'1-c:tcr by '& /2 ,~;'),J 1 Nt!/~or'l ..Stuels) slip ~ll?d.
the corre~po,.,d/"'.J .str.l'1'1.. -""2. the: //,-,er ca1.,,1sed... /; 1 Gt. i;eA.cklecl p2>?el ( ~c ~- C3J). The a;nt?l.:Jsi.s LJill be. rcpe:..E>t~d ,'rl. -thi~ ~~<-*ti"oYL rhicJ:.nesS of 1/A.
II u:5i'7J t"f/e ~~n,e rYJocleJ t..1sed IYL r~ fere,,,e ~ [3].::?.,., d... (4] * ,a,,-,c<, -t-h e c/o sec/ fo,,-n? Sot,,d-10,z. used /l"f--
f!il.XKLED PANEL
~i--10----'15,..-iJ~-2_;:J----r---1-;::1--~ l:i I ~t 4 ll~
~---'Q 'a) ,d = ,sd'___.,~1 ,~., ..L___ ,o '@,s' = ,so
l..... _j cot-J.Sl=RVATIVE MOOEL Nf:6t.Ec:r,,..u:1 Tl-IE IEFFEC.T oF THE 8tl'-KLEJ) PA"'1EL.
.STJFF"1~SS CLo 5<!Gl Form 5o/ut,ol"2.. of the r,.,'lodel L,L = -°'-1:l_T_ _ _ ,s ,'n h J3 x.
8> co.sh 13 L
Form 5007 (Rev. 4193) CP ~ L CAL'-* o RI.P- 1009
- -Rayllleon GENERAL
~-- _ CALCULATION SET NO. REV'. COUP. BY CHK'O BY Engineerw & ConstNctors A Co!'lsolidalion of BaOger and UE&C COMPUTATION 19Ct2. '.235 ~ I_Sc-LA.02. AAo R.o?l SHEET PREUliA. FINAL VOID 0 DATE DATE v .3-1"1-94 ,)17/-, 'i PROJECT _ _ _ C_P---'~'--L_-_B_N_P_41_1_~_2_ _ __
SHEET IO OF I lo DATE DATE SUBJECT TOJ?US L11JER REv15E D ALC.l:PTANC.E C.l<'ITEl<IA u.. 0-) :. o< 6T tJnh fiL
/3 LL
,1Vt!
= c:,C,. .6. T ( Co Sh f- L - I)
~2. L cosh (3L II L: Mode} lel"lsth = 150 (ReF. (.01)
-G, ex. = col"l .st ant = <o.S X 10 fo = ~ AE K
_ b t C.
E =- Youi19's Mod1.1/us of E..lastic,*t~ :::: 2.1. 4 x10
~_!:S_
f.
K -::. N~l~or'2 srud avere~ e sheer ,5tiff,1e-:.s V~ILle Fror'Y'/ Ref. [2] , K-= Q
- 6. j.
-16A 0.40
= qu. (, _ e ) _ -~u. f - - - - - - - - - - -
fl. 1 I
q '= ro . .3q Ki p.5 I
-K t)..
I
,.., 3 -186 o.4 I
__ K = 10. ~ 7 XIO ( I_ e ) I I '5 6 0 ""'----------~---i- fl~
A ti"'-.)
SHEAR LOA()_ t>tSPLACEME NT
Form 5007 (Rev. 4/93)
-Raytheon GENERAL
-'!"- - CAI.CUL.A TION SET NO. REV. COMP.BY CHK"O BY Engineers & Constructors COMPUTATION ,qq 2 :2 35_ I - SC-LA-02 AAo /l_oll A Consolidalioo of Badger and UE&C SHEET PREUM. FINAL VOID 0 DATE DATE 3..\1. ci4 J/11/ \l PROJECT~_C_P_f_L_-_B_N_P_-#_I_~_2_____
SHEET 11 OF lh DATE DATE SUBJECT 1D'RUS LINER REVISED AlCEPTAtJ<.t J.0. 1 9 9 2 .2 3 5 c1<,,eg1A 0.01 o,os 0.015 o. 10 0 .125 o.,s
'B,QOO 5, '333 So/utiO'l v~/ue. for rhe 3/8 1,*J1?ef pl.;te obt:211?(:d .froM LADTcumpt.Jter for A= .D5 ~ .OSI ( 6 )
e)(.act
. /3 _ {\I >2.t.. 7 - o o I~I (A= ,.Sx '3 = 2.81"25 '""'
,2)
- - ~21.4,c,c"'x "2.8125 -
- 8
~ L; o.Ol'l.Jx 150: /.8137
= Uc- 5
-~ (lAo) tanh /.5137 ::::. 0.011
" II LL(L) XIO ) ) o.oSI o*. o 1'21 ,,
A4_i'us t J<. v21ue -to rt:cluce LL ( L) to -the t:.x3c. t '1/2 /LJe of o. o S / ,
'2. ,,,d. _/("Ii;. L; Try K= 24-,ooo rb/iin /,*IA.
24,000 = o.o 174'5 2.. 1. 4 x,o C x 2.s,z 5 f3L = o,of7b5 x ,so= Q.~411
-h u(L) = (lo.5x10 ) C14c) tanh 1.&:.A,l ~ o.o5I = A ex2c.-t O,K, o.ol7t.,5
_. Use K = 24,ooo lb/i'vz/,*"1.
- For t- = 1/4' 1 A= 1.51-0.-:zs =- ,.s1s
Fo,m 5007 (Rev 4/93) CP~L CALC. ORIP-1009
~-~ Raytheon GENERAL
.,< - CALOJLA TION SET NO REV. COMP. 8Y CHK'D BY Engineers & ConstnJCtOf'S A Consolidation o1 &idger and UE&C COMPUTATION rqc:12. 2 35*_ I-SC- LA.o2 AAo £:>/(_
SHEET PREUM FINAL voio 0 DATE DATE 3.\7 -'14 "'>/n/~1/2 PROJECT _ _ _ C_P_,_L_-_B_N_P____:ft_l-'~-2_ _ _ _ __
SHEET I2 OF I0 DATE DATE SUBJECT TOl<US Lir,.,)£1<. REv/Sl:0 Acc..EPTAN'-1=
Cf<tTfE!<. IA
. . f3 L = o.o21<o1 ,x 1So = 3. 2 A '2 o'=,
( -to
__ U.l.L}= C:..'3)(.10 )x1Ao t.:1.,-ih 3,2420& :: o.oA 2 O,O'2.ICol The (3 J/oWi!b/e s f-ud dispJae,er>1er:t and the ;; //ai.-.J2b/e s-rr.?,*1"15 1...-Z. t:he Div ,*.siol"'Z. 2 .
Allow.;! bl t: .stuc..l cJ-eflec.f1*0Yl. -::::.
2 I Ult,.r"-1.;,te S tucl de//ec..t/oYL.
-:::; I 6 = .1. X o,/fo7:. o.oB4 1"1..
- 2. u.. 2 IJ II
.. U..((.)
= o.o4f ~ o,oB4 Check s-,.ud Correspo,r;d..,'r1J_s_h_c:_a_r_F_o_r_c_e : *
( <-18)(,042)) 0.4 q= 10.39 1- e 0
A.) e.Ff=ECT oF LOCAL TEMPERATURE oF '2.0o F" f"'7.. -r h c /, i,,i -c r , CJ.L- - -Eo<A"Tj = _ Ee< t::.T2 I - L)
'-----v-' "---v--'
2- D Model G1u; v2knt t-D 0
0 r AT2 = 6 T1 - ( 200 - 1 o) = 1 B 5. 1 F 1-v J_o,3 2 55. 7
- Fotm 5007 (Rev. 4193)
- - -Ray theo n Enginee rs & Constru ctors GENER AL
~..,,__ .._ CALCULA TION SET NO. REV. COMP. BY CHK'D BY A Consolidation DI Badger and UE&C COMP UTATI ON 7Y91.. 235 - I-SC LA.02 AAo 12v ,L SHEET PRELIM. FINAL VOID 0 DATE DATE 3.17-9 4 ::,/n/1 'i PAOJECT _ _ _ C_P___.~_L_-_6_N_P_-# __1_,~'--2:---_ _ __
SHEET I3 OF I /'a DATE DATE SUBJECT TORUS l1NE-R REV/ SE D A (CE PfANC .E CR1TE 1<.tA
- * - For t:,T= /85.7 °,=-
-to u(L) = (~-S.x. 10 ) x16S .l tdr1h 3.24'2 olo
- o. 0 :2. f G,, f
= c,.05 ~ < 0.08 4 "
_ Chec. k .stud. corre: ,pond ,*113 she2 r for<e ,
(-18)( .oSl,) o.4 c;' = /0. 3~ ( J - e ) = 8.Cc,(,,,, < I0-39 kip:, .:.o.K .-
Fo,m 5007 (Rev 4193) CP~L CALC.. oRIP-100 9
,--- *Raytheo n GENERAL ~~ - CALCVLA TlON SET NO. REV. COMP. BY CHK'0 BY Engineers & ConstnJCtors A Consolidation of Badger and UE&C COMPUTATION 799'2,2 35-1. SC-LA .o2 AAo (l"/l SHEET PRELIM. FINAL VOD 0 DATE DATE
- 3. '2.1-9-4 l-/t.,J~'-4 PROJECT _ _C_P_,5_L_._e._i-J_P_-#_l....:.~_2_ _ _ _ _ __
SHEET I4 OF I (o DATE DATE SUBJECT ,oRuS L11-JER REv1.5ED Acc.E PTAN CE JO. 7q92.235 C/?ITC:R.J A S,RIE-555 FOR. 1/4 " L1J...JER.
- 1) The t:e.n~i/e .stress 1Y1. rhe /,',ier is clue -Co pre5.sure a,.,cJ o"ther Loe.A
.So thf: ev2ILAc1t,*or 1 v f -th-e. l/"1er Anchor will he used /or rh-e: 1/4 Liner, 11 1/4 Liner ,s (-)l'LS /(51,
- Form 5007 (Rev. 4/93) cP\L cALC. oRIP-1009
- = Raytheon GENERAL
-'!"-... - CALCULATION SET NO. REV. COi.iP. BY CHK'O BY Engineers & Constructors A~idation oiBadgerandUE&C COMPUTATION 19'9'2. '235.1.SCL A.02 AAo !2_0/L SHEET PREUI.A FINAL VOID 0 DATE DATE 3-11 'l >/1 "7 /1lf PROJEcr _ _ _c_P_~,__L_-_B_N_P_.:#'_1_;~:__Z. _____
SHEIT, I 5 OF l0 DATE DATE SUBJECT ToRL.15 c:. R' TE-RI LINER A RE:\IJSl=t:, AU.6PTAII.JC:.I:: ,__ _ 7992.'23S J.o. _ _ _ _ _ _ _......__..i___ _ _i __ _--1 6 _ C2Jcu/.;ltion of ,he Liner s-trc21Y'l...
From Ref.[h]
-f.. ::- I 5 .:, r = o. 2 s
'2>' U.l.L)
= '2 X. .o4'2 =- .o84 ,n.
+ .0055 From .ReF.C'=>'J;, Sheet: 4 =F 17; Mex. cornpre.:s~;w: s-tre:s:s (or uncrack:ed.. c.ol"lcrere = _ ,q.s K:sl U sin ct
-...J AS HE Cod<:: Se<:.t/ori fil, Div i::. r'o...-i 1. _ Subs~c.t;ol"'l CC) Ta.bk: CC- 3 720-1 ~
tv'\ e !'",I\ b rC I") C Fro fY') RC {. [ 5 J ; E = er ( I - '-J) :: - I q. 5 * ( I - 0. 2. ")
E 27,4x10 3
- - - 0.0005 < t::.SC = 0.005 :. o,K. .
E = 0.0005 + o.ooSS t::
-=. o.ooh < e..sc.= 0.014 .. o-K.
- Note.: rhc;rrn;;,f it'Jdl.)cecl. J/r1cr comprcss,ve .s-tr~sses doe~ J'?o-C- ch2113e 0i"th,. the. rcc11.1c:ecl cor-f'odccl.. t:hickY?e 55,
- Form 5007 (Rt?v. 4/93)
-Raytheo n GENERAL
-* - - CALCULATION SET NO. REV. COUP. BY CHK'D BY Engineers & Constructors A Coflsolidaiion of Badger and UE&C COMPUTATION AAO /(01L SHEET PREUI.A FINAL \1()10 0 DATE DATE 3.1L94 t"3/2.I/~ °'-/
PROJECT _ _ _ _ C_P_~~L_._B_N_P_~_l_~_2______
SHEET 1 /.o OF I0 DATE DATE SUBJECT TORLJ5 L1Ps.JGR REVISE') A(C.EPTAt.Jc E J.O 7'iCj 2.. '2. 3 5 CR.1TERIA A) For 6T = 185. 7 °F ( T:: 200 °F)
+ . ooh4 check ASME Code L/ner .Srrc1ir1 A/101.Jilb/e~
E - 0.0005-t O,DC>b 4 f: -
- 1
- Liner Ar1cho r An?l'j Sis for 10.(o Spacinj d/,1_JoYJa l c1;re.<. tion. 1:s improb.;;b le) the
,,,,.,-er for
= + 0,0093 chec:.I( ASt-1E Cocie Li'vi-cr Str.;!iv'L ALLowc?ble 5
_._ 0-K.
et:"" 0.0005 + o.ooG 3
~
la 0.0098 <: E sc. -- 0.014
Page 1 DISCIPLINE TECHNICAL REVIEW of the COMPLETED DESIGN PACKAGE Plant BSEP Units 1 &2 [Xl Q (Class A)
Project Torus Liner lnse!;ctions and Preservation Q [ ] Seismic (Class B)
Fi Le No. Level I l FP-Q (Class D)
Docunent No. OR(P-1009 Rev 0 [ ] Other Initial each discipline or area of expertise addressed by this Discipline Technical Review of the COflllleted Design Package and forward corrpleted sheet to Lead Engineer. Related discipline reviews may be combined on one sheet, Applicable Applicable Discipline YES NO Initial Discipline YES NO Initial Mechanical [ l [ ) ___ Civil Structural CX] [ J ~
HVAC [ l [ l _ _ _ Seismic Equip. Qual. [ J [ l _ __
Electrical [ l C l ___ Civil Stress [ l Cl I&C [ ] [ ] Fire Protection [ ] Cl ---
Envirorrnental Qualification Cl [ ] ---
Hl.lllan Factors [ l Cl Materiel s Other _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
C]
[ l [ ]
[ ]
Mark each item yes, no, or not applicable and initial each item checked by you.
- 1. Have design docunents or input from your discipline been properly interpreted and/or incorporated by other discipline?
- 2. Does the COflllleted design package indicate that the transfer of design information within your discipline has been accurate, cOfll)lete and proper?
- 3. Are the installation instructions consistent with the intent of design docunents or input from your discipline?
- 4. Are the installation instructions within the COfll)leted design package adequate and correct?
- 5. Are procedures in place to cover installation if step by step instructions were not provided?
- 6. Are supporting disciplines or areas of expertise appropriately marked above? ~{,/,(l..
- 7. Have controlled sources like Aperture cards, NRCS, and Tech Manuals been used for all documents incorporated in the COlll)leted design package? '1J<o, ~
- 8. Is there consistency between drawings above? ~
Indicate additional reviews required. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __
For each question on the check list not answered yes, explain on page 2. If 11 Not Applicable", give reason. Initial those di sci pl ines reviewed. "II--<<.., s ; 1 4 1 13 ~ i ~ ~ c,v...1-µ- .ir., ~ cJ.c.,.l.J.,"""-,o .
+. . . .
Rr No J,,.~q"' 6-1 ~ i.:._~.
COIJlllete Design Package Acceptable: Yes [XJ No [ l - cOlllllents attached Discipline Tech Reviewer ~ A. Date__3;;;</...;;;3"-/.,_/.._9.;..c/-_ _ _ __
Acknowledgement of Discipline Technical Revie:
(OPE) d 'O *3/4~=< $1.c: a. . .
Oate_..,.L\.;;;..-....... -_9).....4_,___ _ __
Resolution of Conments:
Corrrnents Resolved {See Attached):
{RE) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date_ _ _ _ _ _ _ _ _ _ __
Action taken makes Design Documents Acceptable:
Di sci pl ine Tech Reviewer _ _ _ _ _ _ _ _ _ _ _ _ __ Oate_ _ _ _ _ _ _ _ _ _ __
(OPE) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date_ _ _ _ _ _ _ _ _ _ __
/