LR-N10-0317, Response to NRC Request for Additional Information Dated August 3, 2010, Related to Bolting and Flow Element, and Update to PSEG July 6, 2010, Response to NRC RAI Associated with RPV Leak Detection Line - License Renewal Application
| ML102440678 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 08/26/2010 |
| From: | Davison P Public Service Enterprise Group |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| LR-N10-0317, TAC ME1832 | |
| Download: ML102440678 (16) | |
Text
PSEG Nuclear LLC RO. Box 236, Hancocks Bridge, NJ 08038 0 PSEG NuclearLLC AUG 26 2010 10 CFR 50 10 CFR 51 10 CFR 54 LR-N10-0317 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Hope Creek Generating Station Facility Operating License No. NPF-57 NRC Docket No. 50-354
Subject:
Response to NRC Request for Additional Information, dated August 3, 2010, Related to Bolting and Flow Element, and Update to PSEG July 6, 2010 Response to NRC RAI associated with RPV Leak Detection Line - Hope Creek Generating Station License Renewal Application
References:
- 1. Letter from Ms. Bennett Brady (USNRC) to Mr. Thomas Joyce (PSEG Nuclear, LLC) "REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE HOPE CREEK GENERATING STATION LICENSE RENEWAL APPLICATION FOR BOLTING AND FLOW ELEMENT (TAC NO. ME1832),"
dated August 3, 2010
- 2. Letter from Mr. Paul J. Davison to USNRC, "Response to NRC Request for Additional Information, Related to Sections 3.1.2 and 3.3.2 of the Hope Creek License Renewal Application," dated June 9, 2010 In Reference 1, the NRC requested additional information related to submerged bolting and the Main Steam flow element associated with the Hope Creek Generating Station License Renewal Application (LRA). Enclosed are the responses to that request for additional information.
Reference 2 provided a response to NRC RAI 3.1.2.2.4.1, related to the RPV leak detection line. As a follow-up to subsequent discussions with the NRC staff, PSEG Nuclear hereby provides an update to the original RAI response in the Enclosure associated with this letter.
This update replaces the original response in its entirety.
There are no new or revised regulatory commitments contained in this letter.
If you have any questions, please contact Mr. Ali Fakhar, PSEG Manager - License Renewal, at 856-339-1646.
74-/44?-
Document Control Desk LR-N10-0317 Page 2 of 2 AUG 26 2010 I declare under penalty of perjury that the foregoing is true and correct.
Executed on ' ('
Sincerely, Paul J. Davison Vice President, Operations Support PSEG Nuclear LLC
Enclosure:
Response and Update to Requests for Additional Information cc: Regional Administrator - USNRC Region I B. Brady, Project Manager, License Renewal - USNRC R. Ennis, Project Manager - USNRC NRC Senior Resident Inspector - Hope Creek P. Mulligan, Manager IV, NJBNE L. Marabella, Corporate Commitment Tracking Coordinator T. Devik, Hope Creek Commitment Tracking Coordinator
Enclosure LR-N10-0317 Page 1 of 14 Enclosure Response to Request for Additional Information related to Sections B.2.1.12 and 3.4.2.4; and Updated response to Request for Additional Information related to Section 3.1.2.2.4 of the Hope Creek Generating Station License Renewal Application RAI B.2.1.12-02 RAI 3.4.2.4-01 RAI 3.1.2.2.4.1 (Updated response)
Note: For clarity, portions of the original LRA text are repeated in this Enclosure.
Added text is shown in Bold Italics, and deletions are shown with strikethrough text.
Enclosure LR-N10-0317 Page 2 of 14 RAI B.2.1.12-02
Background:
The Generic Aging Lessons Learned (GALL) Report, aging management program (AMP)
XI.M18, "detection of aging effects" states that for both American Society of Mechanical Engineers code class bolting and for other pressure retaining bolting visual detection of leakage before the leakage become excessive is one acceptable way to inspect for loss of preload in bolting.
License renewal application (LRA) Section B.2.1.12 (Bolting Integrity) states that the program provides for managing cracking, loss of material and loss of preload by performing visual inspections for pressure retaining bolted joint leakage in the following environments: air indoor and outdoor, raw water, soil and treated water.
Issue:
It is not clear to the staff how visual inspection of bolting in a raw water or treated water environment would be capable of detecting loss or reduction of bolting preload since the environment would preclude capability to detect seepage or minor indications of leakage at bolted joints.
Reauests:
a) Clarify what pressure joint bolting within the scope of the Bolting Integrity Program is exposed to the raw water and treated water environments; and b) Explain how and on what frequency visual inspections are performed for submerged bolted joints and how those inspections would detect loss, of preload in the bolting.
PSEG Response:
a) The population of pressure retaining bolted joints exposed to raw water within the scope of license renewal at Hope Creek is limited to the service water pump bolting. The submerged portion of the service water pumps includes bolted connections attached with aluminum bronze bolting.
The population of pressure retaining bolted joints exposed to treated water within the scope of license renewal at Hope Creek is limited to bolting for the emergency core cooling systems suction strainers and connecting piping located in the suppression chamber. The Core Spray System, High Pressure Coolant Injection System, Reactor Core Isolation Cooling System, and Residual Heat Removal System suction strainers and connecting piping are assembled with stainless steel bolting and are submerged in the suppression chamber.
b) The service water pump bolting is inspected during periodic service water pump maintenance. Each service water pump is removed and replaced with a refurbished spare pump on a 10-year frequency. The removed pump is then disassembled, inspected, repaired and reassembled, and serves as the refurbished spare service water
Enclosure LR-NlO-0317 Page 3 of 14 pump for future installation. During disassembly, the pumps are inspected for loose or missing bolting. The aluminum bronze service water pump bolting normally exposed to a raw water external environment is removed and inspected for loss of material during disassembly of the service water pumps. During reassembly, the bolting is torqued as designed to prevent loss of preload. Performance of the service water pump overhaul procedure is sufficient to ensure loss of preload associated with service water pump bolting in a Raw Water environment will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.
A walkdown and visual inspection of the suppression chamber is performed on an 18-month frequency. The inspection of the suppression chamber includes examination of accessible component surfaces. The suppression chamber is inspected for loose components and loss of integrity at bolted connections. The submerged emergency core cooling systems (ECCS) suction strainers, including bolted connections, are observed from the catwalk inside the suppression chamber. The suppression pool floor and the suction strainers are inspected for loose objects and debris, including any bolting that may have become unattached.
The submerged torus shell is subject to periodic inspection in accordance with ASME Section XI ISI requirements. The torus shell inspections are performed underwater by divers certified to perform VT-1NT-3 inspections. Although not included in the torus shell ISI inspection scope, the divers inspect the ECCS suction strainers for general condition, debris accumulation and mechanical damage. The last inspection identified the strainers to be in good condition, free of fibrous debris or other foreign matter, with no mechanical damage or other physical deficiencies noted.
The periodic inspections described above ensure loss of preload associated with the emergency core cooling systems suction strainer bolting in a Treated Water environment will be detected so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.
Enclosure LR-N1O-0317 Page 4 of 14 For clarity the LRA Appendix A, Section A.2.1.12, on page A-13 is revised as follows:
A.2.1.12 Bolting Integrity The Bolting Integrity aging management program is an existing program that provides for aging management of pressure retaining bolted joints, component support bolting, and structural bolting within the scope of license renewal. The Bolting Integrity program incorporates NRC and industry recommendations delineated in NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," EPRI TR-104213, "Bolted Joint Maintenance & Applications Guide," and EPRI NP 5769, "Degradation and Failure of Bolting in Nuclear Power Plants," as part of the comprehensive corporate component bolting program. The program provides for managing loss of material and loss of preload of p~essuwe Fetaing bolted joints by P.... Ring .. visual SPc;tiOnS for beltod joint loa,.ag Ointhe following .nvf"i..nmnt: air, ra-aw wat-r, scol, and tcatcd watcr. Included in the aging management activities directed by this program are visual inspections for pressureretainingbolted joint leakage and preventive measures for bolted joint maintenance and installation.
The Bolting Integrity aging management program will be enhanced to include:
- 1. In the following cases, bolting material should not be reused:
- a. Galvanized bolts and nuts,
- b. ASTM A490 bolts; and
- c. Any bolt and nut tightened by the turn of nut method.
This enhancement will be implemented prior to the period of extended operation.
Enclosure LR-N10-0317 Page 5 of 14 For clarity the LRA Appendix B, Section B.2.1.12 Program Description, starting on page B-65, is revised as follows:
B.2.1.12 Bolting Integrity Program Description The Bolting Integrity aging management program is an existing program that provides for aging management of pressure retaining bolted joints, component support bolting, and structural bolting within the scope of license renewal. The Bolting Integrity program incorporates NRC and industry recommendations delineated in NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants", EPRI TR-104213, "Bolted Joint Maintenance & Applications Guide," and EPRI NP 5769, "Degradation and Failure of Bolting in Nuclear Power Plants," as part of the comprehensive corporate component bolting program. The program provides for managing loss of material and loss of preload of p-essure "etain4"" bolted joints by peForming visual inSPections for bolted joint leakage in the folloWing onVironments: air indoor and outdoorF, raw water, seil and treated water.
Included in the aging management activities performed by this program are visual inspections for pressureretainingboltedjoint leakage and preventive measures for bolted joint maintenanceand installation.
The Hope Creek ISI program plan tables provide the examination category and description as identified in ASME Section Xl, Table IWB-2500-1 for Class 1 components, Table IWC-2500-1 for Class 2 components, and Table IWD-2500-1 for Class 3 components.
Examinations at Hope Creek are currently performed in accordance with the ASME Section XI, 2001 Edition through the 2003 addenda, per the Hope Creek ISI program plans. Examinations for the period of extended operation will be in accordance with the appropriate code edition and addenda for the Hope Creek ISI Program Plan. In accordance with 10 CFR 50.55a(g)(4)(ii), the program is updated each successive 120-month inspection interval to comply with the requirements of the latest edition of the ASME Code specified twelve months before the start of the inspection interval.
The extent and schedule of the inspections is in accordance with IWB-2500-1, IWC-2500-1 and IWD-2500-1 and assures that detection of leakage or fastener degradation will occur prior to loss of system or component intended functions. Bolting associated with Class 1 vessel, valve and pump flanged joints receive VT-1 inspection. For other accessiblepressure retaining bolting, routine observations will document any leakage before the leakage becomes excessive. Normally inaccessible bolted connections will be inspected for degradationwhen made accessible during maintenance activities.
The integrity of accessible non-ASME Class 1, 2, and 3 system and component pressure retaining bolted joints are evaluated by detection of visible leakage during maintenance or routine observation such as system walkdowns. Normally inaccessiblenon-ASME Class 1, 2, and 3 system and component boltedjoints will be inspected when made accessible during maintenanceactivities. MC
Enclosure LR-N10-0317 Page 6 of 14 component pressure retaining bolting is monitored in accordance with ASME Section Xl, Subsection IWE, B.2.1.28, aging management program.
High strength bolts (actual yield strength >150 ksi) are not used on structural connections. The structural bolting and fasteners (actual yield strength <150 ksi) both inside and outside containment are inspected by visual inspection by the Structures Monitoring Program, B.2.1.32.
ASTM A490 bolts are used for NSSS Class 1 reactor pressure vessel supports. The bolts are installed with a preload that yields approximately 105 ksi tensile stress, which is less than the minimum yield strength of the bolt. Stress corrosion cracking (SCC) is not an applicable aging effect for these bolts since they are not subject to high sustained tensile stress. These bolts are inspected by the ASME Section Xl, Subsection IWF, B.2.1.29, aging management program.
Procurement controls and installation practices, defined in plant procedures, ensure that only approved lubricants, sealants, and proper torque are applied. The activities are implemented through station procedures.
Other aging management programs also manage inspection of bolting and supplement this bolting integrity program. The ASME Section XI Inservice Inspection (ISI)
Subsections IWB, IWC, and IWD, B.2.1.1, aging management program manages the inspection of safety-related bolting and supplements this bolting integrity program. The ASME Section XI, Subsection IWF, B.2.1.29, aging management program addresses aging management of ASME Section Class 1, 2, 3 and MC piping and component support bolting. The ASME Section XI, Subsection IWE, B.2.1.28, aging management program addresses aging management of containment pressure retaining bolting.
Other structural bolting is managed as part of the Structures Monitoring Program, B.2.1.32. The aging management of crane and hoist bolting is addressed by the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, B.2.1.15, aging management program. Aging Management of heating and ventilation bolted joints is addressed by the External Surfaces Monitoring, B.2.1.25, aging management program. These monitoring methods are effective in detecting the applicable aging effects and the frequency of monitoring has been adequate to prevent significant degradation. Inspection activities for bolting in a buried environment are performed in conjunction with buried piping and component inspections as part of the Buried Piping Inspection, B.2.1.24, aging mangement program or the plant specific Buried Non-Steel Piping Inspection, B.2.2.4, aging management program. Inspection activitiesfor submerged bolting are performed in conjunction with associated component maintenance activities.
Class 1, 2 and 3 bolted joint repair falls within the scope of the ASME Section Xl Repair and Replacement Program. Flanged joint welding repairs are implemented in accordance with IWA-4000. Pressure bolting replacements are implemented in accordance with IWA-7000. Other pressure retaining bolting maintenance evaluations and repairs follow the EPRI bolting guidelines for the evaluation and repair of the flanges and replacement bolts. The ASME Section Xl, Subsection IWF, B.2.1.29, aging management program addresses replacement of NSSS component support bolting. Corrective actions are addressed in accordance with 10 CFR Part 50, Appendix B.
Enclosure LR-N10-0317 Page 7 of 14 The program will be enhanced, as noted below, to provide reasonable assurance that the Bolting Integrity program aging effects will be managed during the period of extended operation.
Enclosure LR-N10-0317 Page 8 of 14 RAI 3.4.2.4-01
Background
The GALL Report recommends GALL AMP XI.M7 "BWR Stress Corrosion Cracking" and XI.M2
'Water Chemistry" to manage aging of components susceptible to cracking and stress corrosion cracking. In LRA Table 3.4.2-4 (page 3.4-50), the applicant states that it plans to manage the cracking/stress corrosion cracking of a class 1 flow element made of cast austenitic stainless steel (CASS) exposed to treated water (internal) > 482 OF using the 'Water Chemistry" AMP.
The AMR line item cites notes E and 4. Note E indicates the LRA AMR is consistent with GALL Report item for material, environment and aging effects, but a different AMP is credited. Note 4 states, in part, that 'This CASS nozzle is not susceptible to thermal embrittlement because the nozzles were cast by a centrifugal casting method using low molybdenum stainless steel material (SA 351 CF 8)." (page 3.4-60)
Issue Endnote 4 addresses thermal embrittlement, not cracking/stress corrosion cracking. The GALL Report recommends both GALL AMP XI.M7 "BWR Stress Corrosion Cracking" and XI.M2
'Water Chemistry" to manage stress corrosion cracking. The applicant credits only AMP (Water Chemistry) to manage the aging of this item.
Request Please provide a justification as to why only Water Chemistry AMP is credited to manage the cracking and stress corrosion cracking of the CASS portion of the flow element. Please provide material composition information (e.g., a CMTR) of this flow element.
PSEG Response:
Justification for crediting only the Water Chemistry aging management program, as opposed to the GALL recommendation of both XI.M7 "BWR Stress Corrosion Cracking" and XI.M2 'Water Chemistry", to manage the cracking due to stress corrosion cracking of the CASS portion of the Main Steam flow element is provided below.
The Hope Creek Main Steam flow element consists of an outer carbon steel pipe section, which performs the Class 1 reactor coolant pressure boundary intended function, and an internal nozzle insert that provides the throttle intended function. The nozzle insert is made up of two sections. The first or upstream nozzle section is the CASS portion; this section is welded to the second or downstream section of the nozzle, which is made of carbon steel. The upstream CASS portion of the nozzle is a close tolerance cold fit and is not welded to the outer carbon steel pipe section, as opposed to the downstream carbon steel nozzle end that is welded to the inside diameter of the carbon steel pipe section.
The GALL AMP XI.M7 "BWR Stress Corrosion Cracking" in the Program Description and Scope of Program sections, discusses the program as follows:
"The program is to manage intergranularstress corrosioncracking (IGSCC) in boiling water reactor(BWR) coolant pressureboundary piping made of stainless steel (SS) and
Enclosure LR-N10-0317 Page 9 of 14 nickel based alloy components is delineatedin NUREG-0313, Rev. 2, and Nuclear Regulatory Commission (NRC) Generic Letter (GL) 88-01 and its Supplement 1."
"The programis applicable to all BWR piping andpiping welds made of austenitic SS and nickel alloy that is 4 in. or largerin nominal diameterand contains reactorcoolant at a temperatureabove 930 C (2000 F) during power operation, regardlessof code classification.
The program also applies to pump casings, valve bodies and reactorvessel attachments and appurtenances,such as head spray and vent components".
The CASS portion of the nozzle insert of the Main Steam flow element does not meet the applicability criteria specified in the GALL AMP XI.M7 BWR Stress Corrosion Cracking program as discussed above, since the CASS portion of the nozzle inserts are not considered piping or piping welds and do not support a pressure boundary function.
The possibility of cracking due to stress corrosion cracking of the CASS portion of the nozzle occurring is considered to be very low. Susquehanna Steam Electric Station, Units 1 and 2 in a RAI response discussed in License Renewal Safety Evaluation Report, NUREG-1931, Section 3.0.3.1.14 Main Steam Flow Restrictor Inspection, provided a position that cracking due to stress corrosion cracking is not an aging effect requiring management, as there is no tensile stress in the CASS portion of the nozzle to promote stress corrosion cracking. Hope Creek's flow element is constructed to identical specifications and manufactured by the same vendor as the flow elements used at Susquehanna Steam Electric Station, Units 1 and 2. Hope Creek made a conservative decision to include cracking due to stress corrosion cracking as an aging effect/mechanism for the CASS portion of the Main Steam flow elements.
Since the CASS portion of the flow element does not perform a reactor coolant pressure boundary intended function and only provides a throttle intended function for license renewal, extensive and severe cracking damage would have to occur before the throttle intended function could be impacted. Such severe damage is highly unlikely and there would be immediate indications available (steam line flow anomalies) should cracking occur, long before the throttle intended function could be impacted.
The GALL AMP XI.M2 'Water Chemistry" in the Program Description section states:
"The water chemistry programsare generally effective in removing impurities from intermediate and high flow areas. The GenericAging Lessons Learned (GALL) report identifies those circumstances in which the water chemistry programis to be augmented to manage the effects of aging for license renewal. For example, the water chemistry program may not be effective in low flow or stagnant flow areas."
Since the flow elements in the Main Steam system are in a high flow area, the water chemistry program will be effective in maintaining detrimental contaminants below those levels that would promote cracking due to stress corrosion cracking, therefore an augmented program is not needed or required.
In addition to the justification provided above, any type of augmented program that included inspection would be very limited in effectiveness, due to restricted accessibility to the CASS portion of the nozzle section.
Enclosure LR-N10-0317 Page 10 of 14 The CASS portion of the flow element is constructed of ASME SA351 CF8 (low molybdenum
<0.5wt. %) material. The material composition ranges from the Certified Material Test Report (CMTR) for carbon are between 0.04 and 0.06 wt. % and for ferrite are between 14 and 32 wt.
Others materials and composition ranges include:
Manganese between 0.47 and 1.19 wt. %
Silicon between 0.83 and 1.83 wt. %
Chromium between 18.26 and 21.0 wt. %
Nickel between 8.0 and 9.31 wt. %
Sulfur between 0.010 and 0.019 wt. %
Phosphorus between 0.029 and 0.040 wt. %
Columbium or Niobium + Tantalum + Titanium between 0.004 and 0.1 wt. %
Based on the above, the Water Chemistry aging management program will provide reasonable assurance that the aging effects of cracking due to stress corrosion cracking of the CASS portion of the Main Steam flow element will be adequately managed during the period of extended operation.
Enclosure LR-N10-0317 Page 11 of 14 RAI 3.1.2.2.4.1
Background:
Hope Creek Generating Station (HCGS) License Renewal Application (LRA) Subsection 3.1.2.2.4, Paragraph 1 Standard Review Plan-License (SRP-LR) Subsection 3.1.2.2.4, Paragraph 1 SRP-LR Appendix A, Subsection A.1.2.3.4, Paragraph 1 LRA Subsection 3.1.2.2.4, Paragraph 1, addresses cracking due to stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) that could occur in the stainless steel or nickel alloy BWR top head enclosure vessel flange leak detection lines. The LRA states that Hope Creek Generating Station (HCGS) will use aging management program (AMP) B.2.1.1, ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD (ISI) program, and AMP B.2.1.2, Water Chemistry, to manage the aging effects of cracking due to SCC or IGSCC in the stainless steel vessel flange leak detection line exposed to treated water. It also states that the HCGS ISI program uses a VT-2 visual examination of the line prior to reactor cavity drain down, as approved by a current relief request, prior to drain down during each refueling outage.
SRP-LR Subsection 3.1.2.2.4, Paragraph 1, and GALL Report item IV.A1 -10 (R-61) state that a plant-specific AMP is to be evaluated because existing programs may not be capable of mitigating or detecting crack initiation and growth due to SCC in the vessel flange leak detection line.
SRP-LRA Appendix A, Subsection A.1.2.3.4, Paragraph 1, provides generic recommendations for the "detection of aging effects" program element of a plant-specific AMP. This paragraph states that "detection of aging effects should occur before there is a loss of the structure and component intended function(s)."
Issue:
The staff does not understand how a VT-2 visual examination of the vessel flange leak detection line, as described in the LRA, would be capable of detecting cracking in the line prior to a through-wall crack having occurred. Also, the relief request described in the LRA is approved only for the current ten-year ISI inspection interval, which does not extend into the period of extended operation; and there is no assurance that the relief request would either be made by HCGS or be approved by the staff during the period of extended operation.
Request:
a) Explain how VT-2 examination will detect cracking in the vessel flange leak detection line prior to failure of the line's intended function of providing a reactor coolant pressure boundary.
b) Explain how aging of the vessel flange leak detection line will be managed during the period of extended operation without referring to implementation of a relief request which has neither been requested nor approved for the period of extended operation.
Enclosure LR-N10-0317 Page 12 of 14 PSEG Response:
a) The reactor vessel head flange seal leak detection line is an ASME Class 2 piping line separated from the reactor pressure boundary by one passive membrane, a silver-plated O-ring located on the vessel flange. A second O-ring is located on the opposite side of the leak detection line tap in the vessel flange. This line is required during plant operation and will indicate failure of the inner flange seal O-ring should a failure occur.
Failure of the O-ring would result in a high pressure alarm in the Main Control Room. A VT-2 visual examination on the Class 2 portion of the reactor vessel head flange leak detection line is currently performed during each refueling outage when the reactor vessel head is off and the head cavity is flooded above the vessel flange. The static head developed with the leak detection line filled with water allows for the detection of any gross indications in the line. The configuration of this system precludes testing of this line at a higher pressure with the other Class 2 components. The VT-2 examination is performed while the plant is shutdown with the line pressurized, therefore any gross indications (through-wall cracking or degradation) of the line will be revealed before the Class 2 pressure boundary intended function is required during plant operations. The VT-2 examination of the line is not capable of detecting initiation or growth of cracking but would be limited to revealing gross degradation of the line due to cracking.
b) Aging of the reactor vessel head flange seal leak detection line will be managed by Water Chemistry, ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD, and One-Time Inspection Aging Management Programs, as reflected in LRA Table 3.4.2-4 on pages 3.4-53 and 3.4-54. The inspection activities associated with ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD will be performed in accordance with the Hope Creek Generating Station ISI Program Plans that will be in place during the period of extended operation. The ISI Program Plans will be developed, reviewed and approved by the NRC in accordance with 10 CFR 50.55a(g)(4)(ii).
During review of information in support of the response to this RAI, it was identified that a line item crediting the One-Time Inspection Program would be an appropriate addition to manage the aging effect of cracking due to stress corrosion cracking for the reactor vessel head seal leak detection line. The One-Time Inspection program performs volumetric examinations for cracking to confirm the effectiveness of the Water Chemistry program. The combination of Water Chemistry, One-Time Inspection and ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD aging management programs will provide reasonable assurance that age-related failure due to cracking will not occur the period of extended operation.
Hope Creek LRA Table 3.1.1, Subsection 3.1.2.2.4.1 and Table 3.4.2.4 are revised to reflect the addition of the One-Time Inspection program as a credited aging management program for the reactor vessel head seal leak detection line for cracking due to stress corrosion cracking as shown below. Added text is shown in bold italics, and deletions are shown with strikethrough text.
Enclosure LR-N10-0317 Page 13 of 14 The Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant Systems Table 3.3.1 on page 3.1-21 is revised as follows:
Table 3.1.1 Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Aging Aging Further Item Effect/Mechanism Management Evaluation Discussion Number Component Programs Recommended 3.1.1-19 Stainless steel and Cracking due to A plant-specific Yes, plant The ASME Section XI Inservice nickel alloy top head stress corrosion aging specific Inspection, Subsections IWB, enclosure vessel cracking and management IWC, and IWD program, B.2.11.1, flange leak detection intergranular stress program is to be aPA Water Chemistry, B.2.1.2, line corrosion cracking evaluated, and One-Time Inspection program, B.2.1.22, will be used to manage the effects of stress corrosion cracking of the stainless steel for the vessel flange leak detection line exposed to treated water.
See subsection 3.1.2.2.4.1.
Subsection 3.1.2.2.4.1 on pages 3.1-9 and 3.1-10 is revised as follows:
3.1.2.2.4 Cracking due to Stress Corrosion Crackinq (SCC) and Interaranular Stress Corrosion Crackinq (IGSCC)
- 1. Cracking due to SCC and IGSCC could occur in the stainlesssteel and nickel alloy BWR top head enclosure vessel flange leak detection lines. The GALL Report recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigatingor detecting cracking due to SCC and IGSCC. Acceptance criteriaare described in Branch Technical Position RLSB-1.
Hope Creek will use ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program, B.2.1.1, aP:d Water Chemistry, B.2.1.2, and One-Time Inspection program, B.2.1.22 to manage the effects of stress corrosion cracking in the stainless steel vessel flange leak detection line exposed to treated water. The head seal leak detection line is evaluated in the Main Steam System under the Steam and Power Conversion Systems grouping. The Hope Creek ISI Program, as discussed in an approved relief request, utilizes a VT-2 visual examination on the line prior to reactor cavity drain down during each refueling outage. The Water Chemistry program activities provide for monitoring and controlling of water chemistry in accordance with EPRI BWR Vessel and Internals Project BWR Water Chemistry Guidelines. The Water Chemistry program activities prevent or mitigate loss of material, reduction of heat transfer and cracking aging effects to ensure there is no loss of component intended function. The One-Time Inspection program performs volumetric examinations for cracking to confirm the effectiveness of the Water Chemistry program. The ISI examinations together with the Water Chemistry and One-Time Inspection programs will adequately
Enclosure LR-N10-0317 Page 14 of 14 identify, evaluate, and manage the effects of stress corrosion cracking in the stainless steel vessel flange leak detection line to ensure there is no loss of intended function during the period of extended operation. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and Water Chemistry and One-Time Inspection programs are described in Appendix B.
Table 3.4.2-4 on pages 3.4-54 and 3.4-60 is revised as follows:
Table 3.4.2-4 Main Steam System Component Intended Material Environment Aging Effect Aging NUREG- Table 1 Notes Type Function Requiring Management 1801 Vol. 2 Item Management Programs Item Pipingand Pressure Stainless Treated Water Cracking/Stress One-Time IV.A 1-10 3.1.1-19 E, 6 Fittings(Head Boundary Steel (Internal)> 140 F Corrosion Inspection Seal Leak Cracking Detection)
Plant Specific Notes:
- 6. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program includes inspection of this component; therefore the ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD, and-Water Chemistry and One-Time Inspection programs are credited here for managing the effects of cracking for this component.