SBK-L-22003, Inservice Inspection Examination Report
| ML22024A383 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 01/24/2022 |
| From: | Levander M NextEra Energy Seabrook |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| SBK-L-22003 | |
| Download: ML22024A383 (13) | |
Text
Docket No. 50-443 SBK-L-22003 United States Nuclear Regulatory Commission Attn.: Document Control Desk Washington, D.C. 20555-0001 Seabrook Station NEXTera ENERGY~
SEABROOK January 24, 2022 Inservice Inspection Examination Report Enclosed is the NextEra Energy Seabrook, LLC Inservice Inspection Examination Report for inspections conducted prior to and during the twenty-first refueling outage that concluded on November 05, 2021.
The enclosed report is submitted pursuant to the requirements of paragraph IWA-6240 of the 2013 Edition of Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code and approved ASME Code Case N-532-5, N-722-1, N-729-6, N-770-5, N-789-2 and N-716-1. Additionally, a copy of this letter and the enclosed report are being submitted to the State of New Hampshire.
Should you have any questions regarding this information, please contact Mr. Brian O'Callahan, Engineering Site Manager - Programs, at (603) 773-7046.
Sincerely, Matthew Levander Licensing Manager NextEra Energy Seabrook, LLC, P.O. Box 300, Lafayette Road, Seabrook, NH 03874
United States Nuclear Regulatory Commission SBK-L-22003/Page 2 cc:
NRC Region I Administrator NRC Project Manager, Project Directorate 1-2 NRC Senior Resident Inspector Brian Oliver New Hampshire Department of Labor Inspection Division PO Box2076 Concord, NH 03302-2076
Enclosure to SBK-L-22003 OR21 OAR-1 Summary Report
Report Number: ISI-SBK-OR21-2021 Plant:
NextEra Energy Seabrook, LLC P.O. Box 300 Seabrook, NH 03874 Commercial Service Date: August 19, 1990 Enclosure to SBK-L-22003 Refueling Outage No.: OR21 Current Inspection Interval: ISi-Fourth Interval and IWE-Third Interval Current Inspection Period: ISi-First Period and IWE-First Period Edition and Addenda of Section XI applicable to the inspection plans:
ISi First lnterval-2013 Edition No Addenda and IWE Third lnterval-2013 Edition No Addenda Date and Revision of inspection plans: ISi Fourth Interval September 30, 2021 Rev. 0 and IWE Third Interval - September 21, 2021 Rev. O Edition and Addenda of Section XI applicable to repairs and replacements, if different than the inspection plan:
Same Code Cases Used: N-532-5, N-722-1, N-729-6, N-770-5 and N-716-1 CERTIFICATE OF CONFORMANCE I certify that (a) the statements made in this report are correct; {b) the examinations and tests meet the fnspection Plan as required by the ASME Code.Section XI; and (c} the repair/replacement activities and evaluations supporting the completion of OR21 conform to the requirements of Section XL A~dAJ?A R...._
~. * ~,,
1/'1.6t21..
Signed ~gn~; ;J'~ ~
Data ______. __
CERTIFl~IE OF INSERVICE IN$PECT.l~N I, the undersigoed, holding a valid oommissbn issued by the National Board of Boiler and Pressure Vessel Inspectors and the State or Province of New Hampshire and employed by The Hartford Steam Boiler Inspection and Insurance Company of Hartford. CT have inspected the items described in this Owners Activity Report, and state that. to the best of my knowledge and befief, the owner has performed all activities represented by this report in accordance with the requirements of section XI.
By signing tills certificate neither the Inspector nor his employer makes any warranty, expressed or imJjted, concerning the repair/replacement activities and evaluation described in this report. FurtherrnCJ"8, neithef the Inspector nor: is e player shall be liable in any manner for any personal ifljury or property damage or loss of any kind g fii or connected with this inspection.
-=---:_ ___________ Commissions
/).71 ~ L (National Board Number and Endorsements)
Enclosure to SBK-L-22003 TABLE 1 ITEMS WITH FLAWS OR RELEVANT CONDITIONS THAT REQUIRED EVALUATION FOR CONTINUED SERVICE Examination Category and Item Number E-A E1.30 Item Description Moisture barrier Leak Chase Evaluation Description AR02406338, 02406759, 02406943, 02406971, 02407463-Water identified in Leak Chase The outer debris cover for the containment leak chase zone for HL5-11, HL 1-4, HL5-2, HL 1-22, HL2-20, HL 1-6, HL 1-24 and the inner plugs have conditions that require evaluation. The leak chase test connections (LCTCs) are functioning as moisture barriers as defined by ASME Section XI 2013 Edition, Subsection IWE. The LCTCs consist of the cover plate, inner plug, and the access box.
ASME Section XI 2013 Edition, Subsection IWE requirements Visual examination acceptance criterion of the moisture barrier is per IWE-3510.4 which states "Moisture barriers with wear, damage, erosion, tear, surface cracks, or other defects that permit intrusion of moisture against inaccessible areas of the pressure retaining surfaces of the metal containment shell or liner shall be corrected by corrective measures." The moisture barrier degradation has the potential for moisture intrusion and accelerated corrosion in the portion of the liner protected by the moisture barrier -the liner inside the associated leak chase channel.
IWE-3122.3, Acceptance by Engineering Evaluation, allows for continued service of the component without repair/replacement activity for areas of degradation not meeting the acceptance standards of IWE-3500 provided that the engineering evaluation concludes that the flaw or area of degradation is nonstructural in nature or has no unacceptable effects on structural integrity of the containment.
Containment/Liner Design The containment is a seismic Category I reinforced concrete structure. It consists of an upright cylinder topped with a hemispherical dome, supported on a reinforced concrete foundation mat which is keyed into the bedrock by the depression for the reactor pit and by continuous bearing around the periphery of the foundation mat. The inside diameter of the cylinder is 140 feet and the inside height from the top of the base mat to the apex of the dome is approximately 219 feet; the net free volume is approximately 2,704,000 cubic feet.
A welded steel liner plate, anchored to the inside fc,tce of the containment, serves as a leak-tight membrane. The liner on top of the foundation mat is protected by a four feet thick concrete fill mat
Enclosure to SBK-L-22003 which supports the containment internals and forms the floor of the containment.
The containment is designed to assure that the base mat, cylinder, and dome behave integrally to resist all loads. The mat liner plate is 1/4" thick with joints welded to leveling angles that serve as welding backing strips. The liner plate in the cylinder walls is 3/8" thick in all areas except at the penetrations and the junction of the base mat and cylinder. The liner plate is 3/4" thick at these locations. The liner is provided with an anchorage system to assure that it can withstand accident loadings while maintaining leak tightness. In addition, the anchorage system assures that the liner, which is used as a form during construction, can resist the hydrostatic concrete loads while maintaining liner tolerances within allowable values. The dome liner is 1/2" thick and flush with the outside face of the cylindrical liner.
The metallic liner of containment is credited as being a leak-tight membrane. UFSAR 3.8.1.1 states "A welded steel liner plate, anchored to the inside face of the containment, serves as a leak-tight membrane." While the containment liner is not credited for structural capacity in the overall design of containment, Calculation C-S-1-10096 (Ref 4) was developed to determine the minimum containment liner wall thickness that would be acceptable and still maintain the design basis of the liner, i.e. the primary pressure boundary/leakage barrier of the containment building as required by General Design Criterion 16 of 1 0CFR Part 50.
EVALUATION QUANTITATIVE EXAMINATION RESULTS No UT was possible due to the inadequate surface condition of the liner covered by the LCTCs. Specifically, the areas were covered in debris and corrosion products that inhibited the adequate coupling of the transducer. No other quantitative examinations were able to be performed. Qualified visual examinations were unsuccessful as well.
QUALITATIVE EXAMINATION RESULTS The OR21 Detailed Visual Examination (VT-1) via video borescope inspections showed the vertical sections of the risers were in generally good condition with corrosion/scaling of the side walls visible. Generally, more corrosion/scaling of the vertical risers was observed at the entrance, couplings, and nearest the entrance to the chases. No holes or observable material loss in the riser piping were observed. In most of the risers that contained 90 degree elbows, debris was visible at the bottom of the vertical section in the elbow. The risers that entered the leak chase allowed for video to be obtained of the chase in most cases. The chase was observed to be either damp, contain some water, completely filled with water, or dry. The chases observed typically contained some amount of
Enclosure to SBK-L-22003 debris, regardless whether damp, dry, or containing water. The likely source is the corrosion/scaling present on the vertical risers.
Overall, the liner at the locations examined appear to be in good condition with no significant level of corrosion/metal loss identified.
Bare metal walls were present in most risers and, comparatively, the corrosion/scaling present in other sections can be characterized as minor surface corrosion/scaling.
The containment minimum liner wall calculation establishes a minimum wall thickness of 0.0625 inches for the nominal 0.25-inch-thick base mat liner. For a general wall loss of 0.1875 inch in the liner thickness, the base mat liner would still be capable of maintaining a leak tight barrier for containment during all design basis conditions.
An assessment was performed to address the effects of future corrosion for wetted areas over the life of the plant. Results of the assessment determined a bounding corrosion rate of 0.0025 inches/year based on chemical analysis of water in the leak chase.
A water samples were obtained at LCTC HL 1-22, HL2-20, HL5-2, and HL5-11 as well as other locations within the site for comparison.
Results of the chemical analysis had consistent elevated sample pH values between 12.5 to 13.1 and iron concentration values between 2 to 5 ppm, indicating the water was stagnant and in intimate contact with concrete for a lengthy time period. The steel liner and chase surfaces are protected with a tight adherent iron hydroxide Fe(OH)2 corrosion layer (or film) that is in equilibrium with the water above the metal surface. In addition, for all leak chase samples, chloride and sulfate concentrations are less than several hundred ppm indicating the iron hydroxide passive layer has not been disrupted. Therefore, the base metal has not been adversely impacted and is in a stable condition.
Based on the sample pH values alone, an estimated corrosion rate of 0.0025 inches / year or 0.075 inches for a 30 year exposure is obtained. However, this corrosion rate is likely not indicative of the stagnant water conditions in the leak chases. The corrosion rates that would be experienced in this area should be significantly lower than textbook figures.
The water samples were also analyzed for copper, iron, chloride, sulfate, aluminum, calcium, sodium and potassium. The leak chase results indicate sodium and potassium concentrations significantly greater than any surface or bedrock groundwater, as would be expected for plant related water that has been in contact with concrete and stagnant for many years. The elevated concentrations of sodium and potassium support the alkaline pH values as they are the main pH control agents (as hydroxides) in the concrete formulation (Journal of Automated Methods and ManaQement in
Enclosure to SBK-L-22003 Chemistry Vol. 2011 (2011), Article 742656). The chloride and sulfate values are consistent with internal plant system water that entered unlined (painted) trenches and the Equipment Sump that has been in contact with concrete for a lengthy time period. Potable water is demineralized prior to use in and throughout the plant to minimize the potential for chemical attack of the various plant systems materials of construction. In addition, plant system(s) chemistry control programs have been established in accordance with industry experience to minimize corrosion.
CONCLUSION In summary, based on:
The qualitative visual inspections performed did not show any significant degradation of the liner plate:
Rate of corrosion is minimal.
In 2008, an ILRT was performed on the containment structure and the results of that test showed that the containment structure was performing its specified design function. Examination results indicate that no appreciable corrosion has occurred since the last ILRT in 2008 and the observed water in the channels is consistent with historical leakage. Thus, the condition of the liner plate in 2008 is expected to be representative of the condition today.
Accordingly, there is no reason to expect the liner plate has degraded to a point of loss of containment integrity.
Chemical comparison performed, the leakage source is unlikely to be groundwater.
Observed high pH is indicative of a low corrosive environment.
A minimum liner wall thickness of 1/8" is acceptable. Considering conservative total corrosion based on the observed chemistry from the water samples, the liner wall thickness is greater than the minimum. Therefore, there is no unacceptable effect on the structural integrity of the containment. In summary, based on the examinations, chemistry analysis, design, and the corrosion assessment, and OE from other plants, reasonable assurance exists to conclude that the liner has maintained the ability to perform its specified design function and that the liner plate is capable of performing its specified design function for the next operating cycle.
Code Case N-729-6 Code Case N-722-1 Upper Head Bare Metal Visual Bottom Mounted Instrumentation Nozzles Enclosure to SBK-L-22003 AR02406884 - Evaluation of Upper Head bare Metal Visual Exam Penetration 24 was reported with a relevant condition, curly white substance. A sample was collected to aid in the evaluation of the relevant condition reported at penetration 24 [AR-02406884]. The chemistry results determined that the debris was not boron. The area was puffed with low-pressure air. The debris (white curly substance) was removed freely with the low-pressure air. The VE did not observe any changes from the OR19 VE examination. After post cleaning, the annulus was clearly visible and there was no evidence of corrosion, wastage or adherent residue indicative of RCS pressure boundary leakage.
BASIS and CONCLUSION The evaluation provided above is supported by the following factors:
There is an absence of the normal characteristic conditions when pressure boundary leakage has occurred.
The chemistry sample taken at penetration 24 supports that there is no pressure boundary leakage from the RCS, no detectable boron.
In conclusion, the BMV performed in accordance with CC N-729-6 are acceptable, no evidence of pressure boundary leakage exists.
The condition reported at penetration 24 is considered non-relevant by evaluation. Therefore, the requirements of ASME CC N-729-6, Para -3142.l(a) have been met.
AR02406337 - Evaluation of Bottom Mounted Instrumentation Bare Metal Visual Exam Light boric acid, decolorization and staining was identified on 24 penetrations. The examinations met the intent of Code Case N-722-1; no relevant conditions indicative of pressure boundary leakage was detected. The relevant conditions reported at the penetrations have been evaluated as non-relevant based on the results of a direct comparison of the images from the prior CC N-722-1 examinations and the absence of any of the characteristics of RCS boundary leakage: splatter, streaming, spaghetti, popcorn, stalagmites, wastage, etc.
Penetration 51 had residue not previously mentioned in the previous examination.
A chemical sample was obtained and concluded not to be pressure boundary leakage.
BASIS and CONCLUSION The evaluation provided above is supported by the following factors:
There is an absence of the normal characteristic conditions when pressure boundary leakage has occurred.
The chemistry sample taken at penetration 51 supports that there is no pressure boundary leakage from the RCS, no detectable gamma activity. This sample is consistent with
B-P B15.10 Canopy Seal Enclosure to SBK-L-22003 the other samples taken at the BMls in OR17 (penetration 48, 53) and in OR19 (Pen 56).
Although one additional area was identified with relevant conditions when comparing the OR21 results to previous data, the areas are not indicative of pressure boundary leakage. The camera position and angle, along with the supplemental lighting can influence the observation of relevant conditions, but will not overlook true pressure boundary leakage which takes the form of splatter, streaming, spaghetti, popcorn, stalagmites, etc. The relevant conditions reported on the N-722-1 components this outage and prior outages is likely from either previous cavity seal leakage and/or and high temperature paint remnants in annulus and are not the result of active pressure boundary leakage.
In conclusion, the BMI performed in accordance with CC N-722-1 are acceptable, no evidence of pressure boundary leakage exists.
The conditions reported are considered non-relevant by evaluation.
Therefore, the requirements of IWB-2420(b) do not apply. The requirements of IWA-5240(b) have been met as there are no areas of general corrosion present and the conditions reported were previously observed and remain unchanged.
AR02409708 - Potential Leak at Canopy Seal for Penetration 13 During the RC-FT-101 ISi system pressure test, apparent boric acid residue and build up were observed at the canopy seal region of the CROM housing at Penetration 13.
Seabrook's Reactor Head Design The Seabrook Station reactor vessel was fabricated as an ASME Code Class 1 component in accordance with the ASME Boiler and Pressure Vessel Code Section Ill, Subsection NB - 1971 edition through the Winter 1972 Addenda.
The Control Rod Drive Mechanisms (CROM) were also fabricated as ASME Code Class 1 components in accordance with the ASME Boiler and Pressure Vessel Code Section Ill, Subsection NB -1974 edition through the Summer 1974 Addenda.
The reactor vessel head contains seventy-eight (78) CROM housing penetrations. Fifty-seven (57) of these contain Control Rod Drive Mechanisms. Twenty-one (21) are spare penetrations. Sixteen (16) of these spare penetrations have cooling shroud dummy can assemblies attached to them (see FP53698) and five (5) have head adapter plugs. Penetration no. 13 is a spare penetration with a cooling shroud dummy can assembly. The threaded head adapter plug is torqued to 300 to 400 ft. lbs. This threaded joint is the mechanical mechanism that forms the pressure boundary and the canopy seal weld only provides the means for a leak tight joint.
Enclosure to SBK-L-22003 The canopy seal welds are not pressure boundary welds and are designed to provide a means to control leaks through the threads.
These canopy welds were designed for 2500 psia pressure using ASME Section Ill Code equations. The canopy welds were sized using ASME Code equations to assure that the canopy welds would not crack when the system was pressurized. The calculated minimum size of the canopy weld for the latch housing weld was 0.027", and the drawing weld size is detailed as 0.07".
Repair As a permanent fix for the leaking canopy seal welds, a mechanical seal was installed. The canopy seal clamp assembly (CSCA) provides a non-welded mechanical method of stopping leakage in the canopy seal weld. The canopy seal clamp assembly seals the leaking weld and introduces a compressive load into the canopy seal, which tends to close and arrest the crack propagation. The canopy seal clamp assembly seals the leaking weld by compressing a flexible graphite material (Grafoil) seal over the entire canopy seal weld area.
A mechanical seal of the threaded connection using a canopy seal clamp assembly complies with ASME Boiler and Pressure Vessel Code. ASME Code, Section Ill requirements (NB-3671.3 Threaded Joints) support the determination that the threads provide the pressure retention function of the joint. Threaded joints in which the threads provide the only seal cannot be used. These requirements also indicate that a seal weld is not the only means to provide a seal against leakage. Alternate means to provide a seal against leaks include gaskets and packing.
The effect of the use of the clamp on loads and stresses due to seismic and postulated accident conditions has been evaluated.
The stresses in the nozzle adapters and reactor vessel head are not significantly affected by the use of the clamp. The results show that the structural integrity of the head location with a canopy seal clamp assembly installed is maintained. ASME Code, Section Ill requirements are used for design criteria and material selection for the clamp. ASME Code Section XI provides rules for inspection of welds. Flaws found in pressure boundary welds must be repaired in compliance with the rules in Section XI. Since the canopy seal weld is not a pressure retaining weld, requirements of Section XI do not strictly apply and the restoration of the leakage control may be accomplished using a mechanical seal rather than a weld repair.
The canopy seal clamp assembly provides the mechanical seal.
Conclusion Operation of the plant is not altered by installation of the clamp assembly. It therefore can be concluded that there will be no adverse effect from the installation of the clamp assembly on plant
B-P B15.10 B-P B15.10 Valve RC-V-1 Valve RC-V-326 Enclosure to SBK-L-22003 operations or present a challenge to the reactivity control of the primary system. Established guidance and procedures for control rod drive operation are not altered. The procedures used to operate the plant are not changed. Installation of the clamp assembly will not affect the manner in which the plant is operated. Installation of the clamp assembly will not require changing the normal operation of the reactor coolant system or supporting systems. The procedures used for installation of the clamp are maintenance procedures and are addressed separately. The methods and input parameters used in the safety analyses, including control rod drop time parameters, are not changed. The methods used to evaluate the response of the plant to postulated accident conditions are not changed by the installation of the clamp assembly. The methods used to evaluate the reactor coolant pressure boundary are not changed by the installation of the clamp assembly. Installation of the clamp assembly will not invalidate the assumptions and criteria on which the reactor coolant pressure boundary design is based. The plant is not utilized or controlled in a manner that is outside the reference bounds of the design for the plant. The reactivity of the rod control cluster assemblies and the rate they are inserted into the core is not changed. Therefore, installation of the clamp assembly does not involve a test or experiment not described in the UFSAR.
The Technical Specification for control rod drop time is not altered.
Therefore, installation of the clamp assembly does not require a change to the technical specifications.
AR02409792 - Boric Acid Leak at Packing for Valve RC-V-1 Identified as an Inactive/ dry boric acid leak at a non-pressure boundary location (packing area). This condition does not involve a leak at a pressure-retaining boundary and therefore this condition is SAT. However, it does fall under the Boric Acid Corrosion Control (BACC) Program, ER-AP-116. A boric acid screening form was completed, and all six screening questions were answered no. This condition does not require further evaluation under the BACC program.
AR02409793 - Boric Acid Leak at Packing for Valve RC-V-326 Identified as an inactive/ dry boric acid leak at a non-pressure boundary location (packing area). This condition does not involve a leak at a pressure-retaining boundary and therefore this condition is SAT. However, it does fall under the Boric Acid Corrosion Control (BACC) Program, ER-AP-116. A boric acid screening form was completed, and all six screening questions were answered no. This condition does not require further evaluation under the BACC program.
Enclosure to SBK-L-22003 TABLE 2 ABSTRACT OF REPAIR/REPLACEMENT ACTIVITIES REQUIRED FOR CONTINUED SERVICE Code Item Description Date Repair/Replacement Class Description Of Work Completed Plan Number Temp Pressure Pad repair ND SW-1814-005-156-24" of through wall leak per 08/25/2021 40757865-07 EC296405 and Code Case N-789-2.
Removal of Temporary ND SW-1814-005-156-24" Pressure Pad Repair, 10/19/2021 40794564-01 Installation of Flush Patch Code Repair Per EC296785