ML15349A453
| ML15349A453 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 12/29/2015 |
| From: | Markley M Plant Licensing Branch II |
| To: | Batson S Duke Energy Carolinas |
| Whited J | |
| References | |
| CAC MF6374, CAC MF6375 | |
| Download: ML15349A453 (14) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 December 29, 2015 Mr. Scott Batson Site Vice President Oconee Nuclear Station Duke Energy Carolinas, LLC 7800 Rochester Highway Seneca, SC 29672-0752
SUBJECT:
OCONEE NUCLEAR STATION, UNITS 1 AND 2 - RELIEF REQUEST 15-0N-001 REPAIR OF LOW PRESSURE SERVICE WATER SYSTEM PIPING (CAC NOS. MF6374 AND MF6375)
Dear Mr. Batson:
By letter dated June 12, 2015, as supplemented by letter dated October 16, 2015, Duke Energy Carolinas, LLC (the licensee) requested U.S. Nuclear Regulatory Commission (NRC) authorization to use an alternative to the requirements of Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) for the Oconee Nuclear Station, Units 1 and 2 (ONS Units 1 and 2) as identified in Relief Request No. 15-0N-001.
Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z)(2), the licensee proposed to use an alternative from certain requirements of article IWA-4421 of Section XI of the ASME Code, which requires defects to be removed prior to performing repair/replacement activities on Low Pressure Service Water System (LPSWS) piping. Specifically, the licensee requested to repair a section of degraded LPSWS pipe without removing the existing defect by installing an encapsulation on the basis that compliance with the specified ASME Code repair would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.
The NRC staff has concluded, that the use of the proposed alternative described in request 15-0N-001, will provide reasonable assurance that the structural integrity and leakage tightness of the subject LPSWS piping will be maintained. The NRC staff has also concluded that compliance with the repair/replacement activities required by article IWA-4421 of Section XI of the ASME Code, would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.
Accordingly, the NRC staff concludes, as stated in the enclosed Safety Evaluation, that the licensee has adequately addressed all the regulatory requirements set forth in 10 CFR 50.55a(z)(2). Therefore, the NRC staff authorizes the use of Relief Request 15-0N-001 at ONS Units 1 and 2, for the remaining life of the plant, or until such time that further repair/replacement activities are required for the affected portions of the LPSWS piping, whichever occurs first. All other ASME Code, requirements for which relief was not specifically requested and approved in this relief request remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector.
S. Batson If you have any questions, please contact the ONS Senior Project Manager, Mr. James R. Hall, at rand~all@nrc.gov or 301-415-4032.
Sincerely,
~vw~.f'e-/
Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-269 and 50-270
Enclosure:
Safety Evaluation cc w/encl: Distribution via ListServ
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REGARDING RELIEF REQUEST 15-0N-001 ALTERNATE REPAIR OF LOW PRESSURE SERVICE WATER SYSTEM PIPING DUKE ENERGY CAROLINAS, LLC OCONEE NUCLEAR STATION, UNITS 1 AND 2 DOCKET NOS. 50-269 AND 50-270
1.0 INTRODUCTION
By letter dated June 12, 2015, 1 as supplemented by letter dated October 16, 2015, 2 Duke Energy Carolinas, LLC (Duke, the licensee) requested U.S. Nuclear Regulatory Commission (NRC) authorization to use an alternative to the requirements of Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) for the Oconee Nuclear Station, Units 1 and 2 (ONS Units 1 and 2) as identified in Relief Request No. 15-0N-001.
Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z)(2), the licensee proposed to use an alternative from the requirements of article IWA-4421 of Section XI of the ASME Code, which requires defects to be removed prior to performing repair/replacement activities on Low Pressure Service Water System (LPSWS) piping. Specifically, the licensee requested to repair a section of degraded LPSWS pipe without removing the existing defect by installing an encapsulation on the basis that compliance with the specified ASME Code repair would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.
2.0 REGULATORY EVALUATION
The licensee requested authorization of an alternative to the requirements of article IWA-4421 of the ASME Code,Section XI, pursuant to 10 CFR 50.55a(z)(2).
Adherence to Section XI of the ASME Code is mandated by 10 CFR 50.55a(g)(4), which states, in part, that ASME Code Class 1, 2, and 3 components (including supports) will meet the requirements, except the design and access provisions and the pre-service examination requirements, set forth in the ASME Code,Section XI.
1 Agencywide Documents Access and Management System (ADAMS) Accession No. ML15169A860.
2 ADAMS Accession No. ML15295A309.
Enclosure
10 CFR 50.55a(z) states, in part, that alternatives to the requirements of paragraph 10 CFR 50.55a(g) may be used, when authorized by the NRC, if the licensee demonstrates that: (1) the proposed alternative provides an acceptable level of quality and safety, or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.
Based on the above, and subject to the following technical evaluation, the NRC staff finds that regulatory authority exists for the licensee to request the use of an alternative and the NRC to authorize the proposed alternative.
3.0 TECHNICAL EVALUATION
3.1 Relief Request No. 15-0N-001 3.1.1 ASME Code Component Affected The affected component is the 3-inch nominal pipe size, schedule 40 (wall thickness of 0.216 inches), piping between valve LPSW-30 and the 36-inch header of the LPSWS. This piping was constructed to USAS 831.1-1967, is classified as ASME Class 3, and is subject to the repair/replacement requirements of the ASME Code,Section XI, IWA-4000, Repair/Replacement Activities. The 3-inch pipe is made of carbon steel, SA-106, Grade 8. The design pressure and temperature for the subject pipe are 100 pounds per square inch gage (psig) and 100 degrees Fahrenheit (°F), respectively.
This piping is shared between ONS Units 1 and 2 and supplies cooling water to the motor driven emergency feedwater pumps (MDEFWP) for both units. Cooling water is required for these pumps to be operable. Technical Specification 3.7.5, "Emergency Feedwater (EFW) System,"
requires that if two MDEFWPs are inoperable, one pump must be restored to operable within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, or the plant enters into MODE 3.
3.1.2 Applicable Code Edition and Addenda The 2007 Edition with the 2008 Addenda of Section XI of the ASME Code, is used for the 5th lnservice Inspection (ISi) Interval at ONS Units 1 and 2. The 5th ISi Interval began on July 15, 2014, and is scheduled to end on July 14, 2024.
The licensee will use ASME 831.1-2007 as the construction code for the design of the piping encapsulation. The licensee selected this code edition to represent the Construction Code for present day construction/modifications. The licensee stated that use of more current editions in lieu of the original construction code is allowed by sub-article IWA-4221 (c) of the ASME Code,Section XI.
The licensee will use ASME 831.1-2004 to perform the visual examination of the welds because this is the Code edition incorporated into the Duke nondestructive examination (NOE) program for construction code NOE inspections of Oconee Duke Class F welding.
As stated above, the piping system was constructed to USAS 831.1-1967 which represents the original construction code used at ONS Units 1 and 2 for Class F (QA-1) piping.
3.1.3 Applicable Requirements Article IWA-4421, General Requirements, of Section XI of the ASME Code, requires that defects be removed or mitigated in accordance with IWA-4340, IWA-4411, IW A-4461, or IWA-4462. The licensee noted that 10 CFR 50.55a(b)(2)(xxv) prohibits the use of IWA-4340, Mitigation of Defects By Modification.
3.1.4 Reason for Request The licensee proposed the request to install pressure retaining parts to encapsulate locally thinned areas of the subject 3-inch LPSWS piping. The licensee noted that installation of replacement pressure retaining parts, without first removing the degraded portions of the piping does not comply with the requirement of IWA-4421.
The licensee proposed the alternative because other repair/replacement options that fully comply with IWA-4421 would create a hardship or unusual difficulty without a compensating increase in the level of quality and safety.
The licensee stated that to perform the required ASME Code repair, removal of defective portions of the subject 3-inch piping would require that the piping be isolated and depressurized; however, the subject piping cannot be isolated for the following reasons, as stated in the licensee's request for an alternative:
Previous attempts to close valves LPSW-30, LPSW-32, LPSW-33, and LPSW-34 and drain through valve LPSW-970 have not provided adequate isolation of this piping. Oconee believes that the source of valve leakage preventing isolation is from one or both of valves LPSW-33 and LPSW-34.
System isolation using upstream valves is not possible due to requirements of Technical Specification 3.7.7.
2 System isolation needed to allow repair of valves LPSW-33 and LPSW-34 is not possible due to requirements of Technical Specification 3.7.7 (two LPSW pumps inoperable). As a result, repair of these valves would require a dual Unit 1 and 2 outage, with both cores offloaded to the Unit 1/Unit 2 spent fuel pool. Further complicating this issue is the fact that the Unit 1/Unit 2 spent fuel pool does not have the capacity to simultaneously dissipate the heat load from two recently off-loaded cores for at least 25 days post-shutdown.
3 Installation of a mechanical line stop in the 3-inch piping is possible.
However, because some of the thinned sections of the 3-inch piping are located very close to the 36-inch header, it will not be possible to isolate all of the affected piping to allow removal of defective portions of the pipe. In addition, installation of a line stop will result in a permanent branch connection on the 3-inch piping where stagnant water could lead to further corrosion of the 3-inch piping.
4 Installation of mechanical line stops in the 36-inch piping is possible.
However, this is not desirable because this activity could result in metal shavings or the removed portion of the pipe wall dislodging, entering the system, and becoming debris that could hinder system operation and make it difficult to retrieve the loose material.
5 Use of a freeze seal to isolate the 3-inch pipe has been performed successfully to allow replacement of approximately four feet of the 3-inch piping just upstream of valve LPSW-30. However, there is very little piping left that can be replaced using a freeze seal. Therefore, this request would still be needed for any of the remaining piping that will require repair.
The licensee considered but rejected using ASME Code Cases N-562-2, N-661-2, N-786, and N-789-1 to repair the subject piping because of the potential for "burn through" the wall of the subject pipe as a result of welding.
3.1.5 Proposed Alternative and Basis In lieu of removing the defective portion of the subject piping before repair by welding in accordance with article IWA-4421 of Section XI of the ASME Code, the licensee stated that unacceptable wall thickness loss or through-wall leakage caused by localized general or pitting corrosion will be corrected by installation of replacement pressure retaining parts that fully encapsulate the degraded piping.
The licensee stated that the proposed alternative shall be designed, constructed, and examined in accordance with all applicable requirements of the Construction Code. All welds shall be visually examined in accordance with ASME 831.1-2004. The encapsulation shall be pressure tested and VT-2 visually examined in accordance with article IWA-4540 of Section XI of the ASME Code, to confirm the absence of leakage from the replacement pressure retaining parts and their connecting welds.
The licensee noted that the encapsulation has already been installed at the subject pipe location in accordance with the ONS Engineering Change process. The as-built modification has several unplugged openings in the outer pipe to ensure it cannot function as a pressure boundary until the NRG approves the subject relief request. At that time, threaded plugs can be installed to establish the outer pipe as the "repair" pressure boundary.
The licensee provided the following requirements as discussed in the June 12, 2015, and October 16, 2015 submittals:
General Requirements The proposed alternative requires that encapsulation of the defective or locally thinned area(s) at this location be performed only once.
The proposed repair is to encapsulate the entire 3-inch pipe with a 6-inch nominal pipe size outer pipe. The 6-inch outer pipe has an outside diameter of 6.625 inches, nominal thickness of 0.280 inches (schedule 40), and is made of SA-106 carbon steel. The licensee stated that the total length of the subject 3-inch pipe is approximately 8 feet 6 inches, with approximately 4 feet 3 inches of that piping being newly installed in November 2014. Therefore, only 4 feet 3 inches of the encapsulated piping is degraded. The replacement pressure retaining parts include not only the 6-inch outer pipe, but also two couplings with plugs on the outer pipe, an 8-inch by 6-inch reducer, a 6-inch by 3.5 inch reducer, and a reinforcement pad. The design drawings and bill of materials are shown in Attachment 1 to the licensee's letter dated June 12, 2015.
Design The proposed alternative requires that replacement pressure retaining parts comply with the Construction Code (ASME 831.1-2007) and Owner's requirements. The modification is designed such that the piping system no longer relies on the degraded 3-inch pipe for structural integrity or leak tightness.
The licensee designed the 6-inch outer piping based on the design pressure and temperature of 100 psig and 100°F, respectively. The licensee used two enveloping computer models to analyze the outer pipe stresses. The first model assumed a normal pipe wall thickness for the 3-inch piping (full of water and pressurized) and modeled the 6-inch piping as empty but pressurized. The second model assumed a corroded wall thickness of 0.15 inches for the 3-inch piping (empty and pressurized) and modeled the 6-inch piping as full of water [including the inner 3-inch portion] and pressurized. This model also considered that any stiffness contribution from the corroded 3-inch piping was insignificant (near zero). In both cases, the 3-inch piping and 6-inch piping were modeled as separate members (elements) and not as a combined composite member. The licensee reported that the maximum stress ratios (actual stresses/allowable stresses) for all ASME Code equations is less than 0.125; therefore, stresses of the 6-inch outer pipe are within ASME Code 831.1 allowable values.
The licensee stated that the original 3-inch pipe run had no external supports in the span between the 36-inch header and valve LPSW-30. The first support along the 3-inch pipe run is a hanger 11 inches downstream of the 3-inch tee where valve LPSW-27 and valve LPSW-30 merge to supply LPSWS flow to the MDEFW Pump Motor Coolers. The licensee stated that the design analysis of the new piping configuration found no need to add any intermediate supports.
In its letter dated June 12, 2015, the licensee stated that following pressure testing, sealant will be injected into the encapsulation to inhibit corrosion that could result from any future through-wall defects in the encapsulated piping. In the October 16, 2015 letter, the licensee stated that sealant will not be used.
Pre-Installation Evaluation The proposed alternative requires that before installing the 6-inch outer pipe, an ultrasonic examination, using the processes contained in generic ultrasonic procedure Performance Demonstration Initiative (POI) UT-1, be performed to characterize the defective and locally thinned area(s) and to confirm the absence of cracks or crack-like indications.
The proposed alternative requires that wall thickness of the 36-inch header be ultrasonically measured where the encapsulation is to be welded to confirm that header wall thickness is adequate for the encapsulation design. Also, the measured wall thickness is used to evaluate circumferential pressure stresses and longitudinal (bending) stresses.
The licensee reported that there were no locations identified on the 36-inch pipe header less than the pitting threshold used for screening purposes (66% of nominal pipe wall thickness).
The 36-inch header has a nominal wall thickness of 0.375 inches.
The minimum required thickness for circumferential pressure stress per the ASME Code 831.1 for the 36-inch header is 0.141 inches (Code T min). The licensee obtained the measured lowest thickness reading of 0.258 inches and minimum average circumferential wall thickness of 0.343 inches on the 36-inch header. Based on the measured wall thickness and analyses, the licensee stated that the 36-inch pipe satisfies the allowable stresses of the ASME Code 831.1.
Installation The encapsulation is installed as shown in the drawings in Attachment 1 of the licensee's letter dated June 12, 2015. The licensee noted that the locations where the encapsulation is to be welded to the system pressure boundary are located sufficiently far from locations of identified wall thinning in the 3-inch pipe to preclude the growth of identified corrosion from challenging the integrity of the encapsulation for the remaining life of the component to which the encapsulation is welded. The 36-inch header pipe will continue to be monitored as part of the service water piping corrosion program.
The licensee stated that ultrasonic test data from the degraded portion of the 3-inch piping upstream of valve LPSW-30, indicated that the pitting corrosion wear rate was 0.004 inches per year.
The licensee welded the 8-inch end of an 8-inch by 6-inch reducer to the 36-inch header where the 3-inch pipe is connected. The reducer covers the junction where 3-inch pipe is attached to the 36-inch header. The reducer creates a 2.24-inch margin around the 3.5-inch outside diameter of the 3-inch pipe. The licensee stated that although there is no basis to assume that corrosion from the 3-inch pipe would migrate to the area of the weld on the 36-inch header, a conservative application of a 0.004 inches per year corrosion rate (as seen in the 3-inch pipe) to the 36-inch header and a safety factor of 10, projects that it would take over 50 years for the identified corrosion to reach the weld area on the 36-inch header. Also, the licensee welded a circular reinforcement pad, 3/8-inch thick and 3-inch wide, around the reducer and to the 36-inch header. At the other end of the encapsulation, the 6-inch outer pipe is welded to the 6-inch by 3.5 inch reducer which is welded to the flange coupling that connects to valve LPSW-30.
Welding Requirements The licensee used QA Condition 1 welding materials and met the requirements of the ASME Code,Section II, Part C and SFA 5.18. The licensee installed the new welds using the gas tungsten arc welding process and ER-70S-2 filler material. The new piping and plate material used was SA-105 (Grade WPS), A-106 (Grade 8), and A-36. The existing piping material was A-106 (Grade 8) and A-105 (Grade WP8), which are all category P1 materials per the applicable edition of Section IX of the ASME Code.
The licensee stated that the minimum pre-heat requirement was defined as 50°F for all P1 material. The licensee noted that the material thickness does not exceed 1 inch in thickness; therefore, pre-heat as defined in the ASME Code, 831.1, 2004, 131.4.2 does not apply. The licensee further stated that post-weld heat treatment is not required because the thickness of any member does not exceed 3/4 inch thick per the ASME Code, 831.1, 2004, Table 132.
The requirements of the ASME Code, 831.1, 2004, for this weld are (1) 3/16 inches maximum reinforcement per Table 127.4.2 of ASME 831.1, 2004, and (2) visual inspection per Table 136.4 of ASME 831.1, 2004. The proposed alternative also used applicable Duke Energy inspection procedures NDE- 600 and QAL-16.
Examination Requirements The proposed alternative requires that after welding, a visual examination be performed on welds for the replacement pressure retaining parts in accordance with ASME 831.1-2004, Table 136.4.
The licensee stated that the encapsulation boundary is subject to inservice inspection in accordance with the ASME Code, Table IWD-2500-1, Category D-8, which requires a system leakage test and accompanying VT-2 examination each inspection period. The piping internal to the encapsulation boundary is inaccessible and will not be examined in the future because credit will no longer be taken for its pressure retaining function, thus, it will be outside the inservice examination requirements of Section XI of the ASME Code.
Pressure Testing The proposed alternative requires a hydrostatic pressure test be performed in accordance with articles IWA-4540, IWA-5000, and IWD-5230 of Section XI of the 2007 edition with 2008 addenda of the ASME Code, using an external pressurization source upon completion of the repair to confirm the leak-tight integrity of the modification and its connecting welds to the component pressure boundary.
The licensee stated that it has performed the hydrostatic test as part of the design change modification. The cavity between the inner pipe and the outer pipe was filled with demineralized water using the threaded vent holes in the outer pipe. The water was pressurized to a hydrostatic test pressure of 105 psig, a fluid temperature of 64. 7°F, and a hold time of 12 minutes while LPSWS was in service. The average LPSWS pressure is 82 psig which results in a differential pressure across the 3-inch pipe of approximately 23 psid.
To demonstrate that the hydrostatic test will not affect the structural integrity of the degraded 3-inch pipe, the licensee used the criteria in ASME Code,Section VIII, Division 1, Section UG-28 (Thickness of Shells and Tubes under External Pressure). The licensee assumed the thinnest point identified in ultrasonic test (UT) scanning as the wall thickness (0.038 inch) for the entire 3-inch pipe. The results demonstrated that, with the assumed wall thinning, the 3-inch piping could withstand an external differential pressure of greater than 47 psi which is greater than a differential pressure of 23 psid as a result of the hydrostatic test as discussed above.
3.1.6 Duration of Proposed Alternative The licensee requested approval of the proposed alternative for the remaining life of the plant, or until such time that further repair/replacement activities are required for the affected portions of the LPSWS piping, whichever occurs first.
3.2 NRC Staff Evaluation The NRC staff evaluated the general requirements, design, pre-installation evaluation, installation, welding, examination and pressure testing of the proposed alternative. The NRC staff also evaluated the licensee's defense-in-depth measures and 10 CFR 50.55a(b)(2)(xxv)
Condition associated with the proposed alternative. The goal of NRC's evaluation is to determine whether the proposed alternative will provide reasonable assurance of the structural integrity and leak tightness of the subject piping after encapsulation.
General Requirements The NRC staff determined that limiting the encapsulation of the subject 3-inch pipe to only one application is appropriate because if the encapsulation does not provide the structural integrity or leak tightness after deployment, it indicates that the encapsulation design has inherent deficiencies and cannot be applied again to the subject pipe. Therefore, NRC staff concludes that limiting the use of the proposed encapsulation to one time application is desirable and acceptable.
Design The NRC staff determined that the licensee has performed the necessary stress analysis to demonstrate that the 6-inch outer pipe will support the loads of the 3-inch inner pipe and that the stresses on the 6-inch outer pipe satisfies the ASME Code, 8 31.1 allowable stresses. The NRC staff further determined that the proposed encapsulation is designed in accordance with the Construction Code (ASME 831.1-2007) and Owner's requirements. Therefore, the NRC staff concludes the design requirements of the proposed alternative are acceptable.
Pre-Installation Evaluation The NRC staff notes that before installing the encapsulation, the proposed alternative required measurements of the degraded 3-inch pipe to determine the extent of corrosion and measurements of the 36-inch header to demonstrate its structural integrity for the attachment of the encapsulation. The NRC staff also notes that the licensee has ultrasonically examined the 3-inch inner pipe and replaced a segment of the 3-inch inner pipe in 2014.
The NRC staff determined that the licensee has adequately demonstrated that the 36-inch header has satisfied the allowable stresses. The NRC staff performed an independent calculation of the required minimum wall thickness for the 36-inch header and verified that the measured wall thickness satisfies the ASME Code 831.1. Therefore, the NRC staff concludes that the licensee has performed an adequate pre-installation evaluation.
Installation The NRC staff has determined that the locations where the encapsulation is to be welded to the system pressure boundary are located sufficiently far from locations of identified wall thinning to preclude the growth of identified corrosion from challenging the integrity of the encapsulation.
The NRC staff has determined that the proposed alternative considers the corrosion rate of the 3-inch pipe in the encapsulation design and the wall thickness of the 36-inch header where the reinforcement pad are welded is sufficient to meet the ASME Code requirement.
At the other end of the encapsulation, the 6-inch outer pipe is welded to a 6-inch by 3.5-inch reducer which is, in turn, welded to a flange. The NRC staff determined that this is acceptable because the flange has sufficient thickness to support the welding and attachment of the reducer.
As stated in the October 16, 2015, letter, the licensee decided that it will not inject sealant into the 6-inch outer pipe as was proposed in the June 12, 2015 submittal. The NRC staff determined that this decision is acceptable because if a large crack is developed on the 3-inch pipe inside the encapsulation, the sealant inside of the encapsulation may enter into the LPSWS flow stream via the break and cause damage to the components downstream of the 3-inch piping. Therefore, it is preferable the sealant is not injected into the encapsulation.
The NRC staff determined that the licensees continued monitoring of the 36-inch header pipe as part of the service water piping corrosion program which will indirectly monitor the condition of the encapsulation, is acceptable.
Welding Requirements The NRC staff has determined that the welding requirements of the proposed alternative are acceptable because the welding follows ASME Code,Section II, Part C; the ASME Code,Section IX; and ASME 831.1, 2004 Edition. Also, as part of welding procedures, the proposed alternative requires a visual inspection be performed per Table 136.4 of ASME 831.1, 2004 and the use of applicable Duke inspection procedures NOE- 600 and QAL-16.
Examination Requirements The NRC staff has determined that the examination requirements of the proposed alternative are acceptable because the licensee will perform inservice inspections of the encapsulation in accordance with the ASME Code, Table IWD-2500-1, Category D-8, which requires a system leakage test and accompanying VT-2 examination each inspection period.
Pressure Testing Requirement The NRC staff has determined that pressure testing of the proposed alternative is acceptable because a hydrostatic pressure test of the encapsulation is required to be performed in accordance with the requirements of articles IWA-4540, IWA-5000 and IWD-5230 of Section XI of the 2007 edition with 2008 addenda of the ASME Code.
Safety Consequences The NRC staff questioned the adequacy of the LPSWS coolant flow inside the encapsulation to achieve the LPSWS safety function if the 3-inch inner pipe had a catastrophic failure and blocked the coolant flow in either the 3-inch pipe or 6-inch pipe. The NRC staff also questioned how the control room operator will be notified and take corrective actions in this scenario.
In its letter dated October 16, 2015, the licensee stated that two independent flow paths provide coolant from the 36-inch header to the MDEFW motor coolers as seen in Attachments 1 and 2 to letter dated June 12, 2015. These two flow paths combine downstream of valve LPSW-30 (beyond the area affected by Relief Request 15-0N-001) and either flow path can supply adequate flow to the motor coolers.
The licensee stated that inadequate cooling flow to the MDEFWP motor coolers could potentially affect operability of the MDEFWPs. However, sufficient flow to the coolers can be supplied by either the valve LPSW-27 branch line or the valve LPSW-30 branch line. The LPSWS operating procedure requires both flow paths from the LPSWS header to the MDEFW motor cooler supply line to be aligned by locking open valves LPSW-27 and LPSW-30. The startup procedure also has operators verify the position of LPSWS valves. The licensee stated that if a flow reduction in the LPSW-30 branch line was to occur due to degradation of the 3-inch pipe, it is unlikely that flow through the LPSW-30 branch line would be reduced to a no-flow condition. If the LPSW-30 branch line were to be totally blocked, the LPSW-27 branch line would still provide adequate flow to the MDEFWP motor coolers. Thus, any potential effect on safety function caused by flow degradation upstream of valve LPSW-30 (i.e., inside the encapsulation) can be compensated by the valve LPSW-27 flow path.
The licensee stated that water flow is initiated to the motor cooler of a MDEFWP when it is started. Operations records the LPSWS flow rate to each MDEFWP motor cooler during a quarterly performance test. During those tests/checks, flow to the motor cooler is typically greater than 100 gallons per minute (gpm). If flow to the motor cooler reduces below 30 gpm (minimum design flow), the Operator Aid Computer (OAC) will alarm. The OAC also alarms on HI (high) and HI-HI stator temperature for a MDEFWP. The alarm response procedure guide directs the operator to closely monitor pump parameters and check LPSWS valve lineup.
The licensee noted that procedural valve alignment, performance testing of MDEFWPs, and OAC alarms all provide a means for the control room operators to be aware of reduced flow conditions to the motor coolers. However, reduced flow through the LPSW-30 branch line will have little effect on available flow to the motor coolers because of the dual supply lines from the LPSW header, via valve LPSW-27 and valve LPSW-30 paths.
The NRC staff determined that operators have sufficient means (e.g., alarms, temperature indicators and valve position indicators) in the control room and procedures to monitor the potential flow reduction in the proposed encapsulation. Therefore, the redundant flow paths, quarterly tests, and control room monitoring have resolved the NRC staffs concern on the potential of flow reduction in the proposed encapsulation.
10 CFR 50.55a(b)(2)(xxv) Condition 10 CFR 50.55a(b)(2)(xxv) prohibits the use of ASME Code,Section XI, IWA-4340 because of the NRC's concern that corrosion in a degraded pipe may grow outside the modification and defeats the usefulness of the modification. The NRC staff considers that the licensee's proposed encapsulation is a mitigation of defects by modification. However, the NRC staff has determined that on a plant-specific basis, the proposed alternative is acceptable with respect to the condition imposed in 10 CFR 50.55a(b)(2)(xxv) because of the following reasons: (a) The NRC staff determined that the subject 3-inch LPSW pipe is operated in a relatively low pressure
and low temperature environment. The subject modification is properly supported. This means that the stresses on the 6-inch outer pipe would not be significant. (b) The licensee replaced half of the 3-inch pipe in 2014. The other half of the 3-inch pipe (the degraded segment) is connected to the 36-inch header. (c) The observed corrosion rate of the 3-inch inner pipe is 0.004 inches per year. The licensee stated that it would take 50 years to affect the wall thickness of the 36-inch header. (d) The subject encapsulation will be visually inspected and pressure tested every inspection period per ASME Code,Section XI, IWD-2500-1 to monitor the condition of the encapsulation. The 36-inch header is monitored through the licensee's service water piping corrosion program. (e) Should the encapsulation fails its function, the operator has sufficient alarms and indicators in the control room to take corrective actions. Therefore, the 10 CFR 50.55a(b)(2)(xxv) Condition does not need to apply to the proposed alternative.
Hardship Justification The NRC staff determines that the licensee has considered various options of performing the repair in accordance with Section XI of the ASME Code, without success. The NRC staff concludes that the compliance with the repair of the ASME Code,Section XI, would result in hardship without a compensating increase in the level of quality and safety.
4.0 CONCLUSION
As set forth above, the NRC staff has concluded, that the use of the proposed alternative described in request 15-0N-001, will provide reasonable assurance that the structural integrity and leakage tightness of the subject LPSWS piping will be maintained. The NRC staff has also concluded that compliance with the repair/replacement activities required by article IWA-4421 of Section XI of the ASME Code, would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all the regulatory requirements set forth in 10 CFR 50.55a(z)(2). Therefore, the NRC staff authorizes the use of Relief Request 15-0N-001 at ONS Units 1 and 2, for the remaining life of the plant, or until such time that further repair/replacement activities are required for the affected portions of the LPSWS piping, whichever occurs first.
All other ASME Code requirements for which relief was not specifically requested and approved in this relief request remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector.
Principal Contributor: John Tsao D~e: December 29, 2015
S. Batson If you have any questions, please contact the ONS Senior Project Manager, Mr. James R. Hall, at randy.hall@nrc.gov or 301-415-4032.
Sincerely,
/RA/ Shawn Williams for Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-269 and 50-270
Enclosure:
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DATE 12/28/15 12/21115 11/19/15 12/29/15 OFFICIAL RECORD COPY