ML051580319
| ML051580319 | |
| Person / Time | |
|---|---|
| Site: | Millstone  (DPR-065) |
| Issue date: | 12/17/2004 |
| From: | Lund A NRC/NRR/DE/EMCB |
| To: | Samson Lee NRC/NRR/DRIP/RLEP |
| References | |
| FOIA/PA-2005-0210, TAC MC1825, TAC MC1826 | |
| Download: ML051580319 (11) | |
Text
December 17, 2004 MEMORANDUM TO:
Samson S. Lee, Chief License Renewal Section License Renewal and Environmental Impacts Branch Division of Regulatory Improvement Programs FROM:
A. Louise Lund, Chief IRA!
Steam Generator Integrity & Chemical Engineering Section Materials and Chemical Engineering Branch Division of Engineering
SUBJECT:
MILLSTONE POWER STATION UNITS 2 & 3 SAFETY EVALUATION FOR THE AGING MANAGEMENT OF STEAM GENERATORS IN SUPPORT OF LICENSE RENEWAL (TAC NOS.: MC1 825 AND MC1826)
The staff of the Steam Generator Integrity and Chemical Engineering Section of the Materials and Chemical Engineering Branch has completed its review of the steam generator aging management program in license renewal application (LRA) Appendix B, Section B2.1.22, and aging management review of steam generator items in LRA Section 3.1 for Millstone Power Station Units 2 & 3.
On the basis of the information submitted, the staff finds that the aging management of the steam generator components discussed in the above two LRA sections is acceptable. The staff's safety evaluation is attached.
Docket Nos.: 50-336 and 50-423
Attachment:
As stated CONTACT:
Yamir Diaz-Castillo, DE/EMCB 415-2228
ML050030148 G:\\EMCB\\Diaz, Yamir\\Millstone License Renewal\\Millstone LR SE PKlein KKarwoski ER.wpd OFFICE EMCB: DE EMCB: DE NAME YDiaz LLund
. DATE 12/17 /2004 12 /17/2004
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION OF MATERIALS AGING MANAGEMENT PROGRAMS FOR MILLSTONE UNITS 2 AND 3 LICENSE RENEWAL APPLICATION DOCKET NOS. 50-336 AND 50-423 3.1 Steam Generator Structural Integrity Program The applicant describes its Steam Generator Structural Integrity Program (SGSIP) for Units 2 and 3 in LRA Appendix B, Section B2.1.22. The staff reviewed LRA Appendix B, Section B2.1.22 to determine if the applicant has demonstrated that the program will adequately manage the applicable aging effects in the steam generators (SGs) during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Summary of Technical Information in the Application The applicant states that the SGSIP is consistent with the 10 attributes of the program described in NUREG-1 801,Section XI.M1 9, "Steam Generator Tube Integrity Program" with no exceptions. In addition, the program scope includes the Units 2 and 3 steam generator tubesheet and cladding. The applicant states that its program is based on Nuclear Energy Institute (NEI) 97-06 (Steam Generator Program Guidelines) and the associated Electric Power Research Institute (EPRI) guidelines, which provide performance acceptance criteria and guidance for monitoring and maintaining SG tubes. The applicant's program includes performance acceptance criteria for structural integrity, accident-induced and operational leakage, as well as SG integrity and support elements. The program also includes preventive measures to mitigate degradation through control of primary side and secondary side water chemistry; assessment of degradation mechanisms; leakage monitoring; in-service inspection of the SG; evaluation and plugging, as needed; to ensure the leakage integrity of the pressure boundary. The applicant states that the tube inspection scope and frequency, tube plugging or repair, and leakage monitoring are in accordance with the Millstone Units 2 & 3 Technical Specifications.
The applicant states that it currently participates in industry programs whose goals include the investigation of aging effects applicable to nickel-based alloys (i.e., primary water stress corrosion cracking in Alloy 600 base metal and Alloy 82/182 weld metals) and identification of appropriate aging management activities. The applicant commits to implement the appropriate recommendations that result from this investigation. This commitment is identified in Appendix A, Table A6.0-1 of License Renewal Commitments, Item 14.
The applicant concludes that the SGSIP ensures that the effects of aging associated with the in-scope components will be adequately managed so that there is reasonable assurance that their intended functions will be maintained consistent with the current licensing basis (CLB) throughout the period of extended operation.
ATTACHMENT
Staff Evaluation The staff reviewed the information included in LRA Appendix B, Section B2.1.22 and the applicant's response to the staff's request for additional information (RAI), dated August 11, 2004, to ensure that the aging effects will be adequately managed so that the intended functions of the SG tubes will be maintained consistent with the CLB throughout the period of extended operation.
The 10 program attributes in the GALL SG Section XI.M19 provide detailed programmatic characteristics and criteria that the staff considers necessary to manage aging effects of the SG tubes and tube plugs. The GALL SG AMP recommends preventive measures to mitigate degradation phenomena; assessment of degradation mechanisms; in-service inspection of SG tubes to detect degradation; evaluation and plugging or repair, as needed of the SG tubes; and leakage monitoring to ensure the leakage integrity of the pressure boundary. Although the applicant did not describe the program attributes in LRA Section B2.1.22, the applicant has stated that the program attributes are consistent with those stipulated in GALL SG AMP,Section XI.M19, without exceptions nor enhancements.
In addition, the applicant identifies the SGSIP as the AMP to manage the aging effect loss of material in the tubesheet and cladding. Currently, the GALL SG AMP does not address the SG tubesheet and its cladding; therefore, the staff asked the applicant to explain how SGSIP manages aging in those areas. Based on operating experience, cladding has not shown significant degradation. In addition, during routine SG tube inspections, the applicant would inspect the cladding and the tube-end welds as part of the SGSIP. If degradation is identified, the applicant would take appropriate measures to correct the problem. In its response to RAI B2.1.22-2, the applicant stated that although the scope of the GALL SG AMP only addresses the SG tubes, the SGSIP for Millstone Units 2 and 3 additionally addresses the secondary side of the steam generator tubesheet. The staff asked the applicant to discuss how the SGSIP manages the aging effects through the effective incorporation of the following program elements: Preventive Actions, Parameters Monitored/Inspected; Detection of Aging Effects, Monitor and Trending, and Acceptance Criteria. The five elements to manage the aging effects associated with the tubesheet are discussed below.
Preventive Actions: The applicant did not discuss preventive actions required by the SGSIP for the tubesheet, however, consistent with NEI 97-06 and GALL Section XI.M19, the applicant's SGSIP relies upon the Chemistry Control for Secondary Systems Program to prevent or mitigate initiation of degradation mechanisms or reduce rates of degradation in the tubesheet.
The applicant identified loss of material as the aging effect for the tubesheet. The staff finds that the Chemistry Control for Secondary Systems Program acceptable because it will be effective in preventing or mitigating the secondary side tubesheet degradation.
Parameters Monitored/Inspected: The applicant stated that the SGSIP identified loss of material as the aging effect for the uncladded secondary side of the tubesheet. The applicant will perform an assessment prior to the inspection to predict the expected amount of degradation.
The applicant also stated that in addition to tubesheet secondary side inspection, it performs primary side inspections of the tubesheet. Secondary side visual inspections of the tubesheet are performed in accordance with the applicable guidance in NEI 97-06. The applicant's inspection procedures include remote and direct visual examination of the tubesheet's accessible areas for evidence of degradation. The applicant considers factors such as potential 2
degradation mechanisms, industry operating experience and SG design when determining the appropriate inspection requirements. The staff finds that the inspection parameters monitored or inspected are acceptable because the inspection requirements provide reasonable assurance that the SGSIP will monitor the parameters necessary to prevent and mitigate degradation of the secondary side of the tubesheet.
Detection of Aging Effects: The applicant stated that the SGSIP manages the aging effects for the tubesheet prior to the loss of intended function. Visual inspections of the secondary-side of the tubesheets are performed in accordance with the guidance identified in NEI 97-06. The tubesheet Millstone Unit 2 SGs is inspected every other refueling outage while the tubesheet in the Unit 3 SGs is inspected every outage. The applicant performs a degradation assessment before inspection in which it predicts the expected amount of degradation. Inspection frequencies are based on these results of the degradation assessments and the comparison of such assessments to the as-found inspection results. The applicant performs visual inspections should the eddy current testing of the tubes indicate the presence of a foreign object. Loose parts or foreign objects are removed from the steam generators unless it can be shown that these objects would not represent any challenge to tube integrity. The staff finds that these are acceptable methods for identifying tubesheet degradation.
Monitoring and Trending: Degradation is managed within the corrective action process to ensure that timely corrective and mitigative actions are performed as necessary. The applicant monitors and trends the tubesheet degradation found through inspections to assure that the intended function is maintained. The staff finds that the applicant's monitoring and trending activities follow GALL AMP Section Xi.M19, and therefore, are acceptable.
Acceptance Criteria: The applicant stated that the acceptance criterion for tubesheet secondary side inspections is based on the corrective action process and engineering analysis. Whenever degradation is identified, it is incorporated into the corrective actions program where an evaluation is performed. Deficiencies that may present a challenge for the component to complete its intended function are promptly corrected or evaluated to be acceptable. If an evaluation is performed without repair or replacement, an engineering analysis is executed to reassure that the intended function is maintained. The staff finds the acceptance criteria acceptable because they follow the GALL AMP Section XI.M19.
Operating Experience In the fall of 1992, Millstone Unit 2 steam generators were replaced with Babcock and Wilcox steam generators. The pre-service inspection consisted of a 100% eddy current examination and it covered the full length of each tube from the hot leg plenum. The applicant did not identify any measurable flaws. During the February 2002 outage, the applicant performed a 100% full length bobbin examination of No. 1 SG. The applicant expanded the scope of examination to include locations of special interest tested with a rotating probe. The examinations were performed in the hot and cold leg areas, dings and dents. A visual inspection of the cold leg tubesheet surface of the secondary side revealed a foreign object lodged diagonally between pairs of tubes. The applicant was not successful in retrieving the object. No tubes were plugged in association with this object since no evidence of degradation was observed. The applicant will periodically examine the tubes to verify that there has not been any change to these two tubes in the conditions evaluated.
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The Millstone Unit 3 original SGs began commercial operation in the spring of 1986. During the September 2002 outage, the applicant performed a bobbin inspection on approximately 50% of the tubes in SGs A and C. The applicant expanded the scope of examination to include plus point coil inspections on special interest areas such as the hot leg expansion transitions, low row u-bends, dents and locations where the bobbin response was ambiguous.
The inspection results showed seven tubes exhibiting anti-vibration bar wear, two tubes with loose part wear, one tube with an obstruction not allowing the insertion of a probe, and one tube with a lodged loose part. All of these tubes were preventively plugged. The tube with the lodged loose part had incurred minor damage and was stabilized and plugged. In addition, the applicant performed a 20% inspection expansion at top-of-tubesheet locations in both the hot and cold legs of SG A to address the inspection results related to loose part wear. The staff reviewed the annual inspection report and found the SG inspection results acceptable.
During the August 2004 outage, the applicant performed a bobbin inspection on approximately 50% of the tubes in SGs B and D in Unit 3. The applicant expanded the scope of the examination to include plus point coil inspection on special interest areas such as the hot leg expansion transitions, low row u-bends, dents and locations where the bobbin response was ambiguous. The inspection results showed two tubes with loose part wear, one tube with anti-vibration wear, one tube with a single volumetric indication (SVI) exceeding the plugging limit and a cluster of 5 tubes identified with SVI signals. Of the cluster of five tubes, three were potentially caused by a loose part. Since the area is not accessible for visual inspection, all of the tubes were plugged and removed from service. One tube in the u-bend region was identified with an SVI. The applicant determined that this indication seems to be a manufacture defect, similar to the tubes plugged prior to startup. This indication was small and not detectable with the bobbin probe. This tube was plugged and removed from service.
No degradation of either the primary side or secondary side of the tubesheets has been identified for Millstone Units 2 and 3.
UFSAR Supplement The UFSAR supplement for the SGSIP is discussed in LRA Appendix A2.1.22. The staff verified that the information in the UFSAR supplement provides an adequate summary of the program activities, and is consistent with Table 3.1-2 of NUREG-1800. The staff concludes that the information provided in the UFSAR supplement for aging management of the steam generators is acceptable because it provides an adequate summary of the program activities, as required by 10 CFR 54.21 (d).
Conclusion On the basis of its review of the applicant's SGSIP, the staff concludes that the applicant has demonstrated that the effects of aging associated with the SGs will be adequately managed by the SGSIP so that the intended functions of the SGs will be maintained consistent with the current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).
The staff also reviewed the UFSAR supplement for this AMP and finds that it provides an adequate description of the program, as required by 10 CFR 54.21 (d).
3.1.2.1.4-A Steam Generator Aging Management Review Results 4
Summary of Technical Information in the Application In Section 3.1.2.1.4 of the LRA for Unit 2, the applicant identified the materials, environments, aging effects, and associated aging management programs related to the steam generator components that are within the scope of the LRA. The steam generator components that require aging management review are listed in LRA Table 3.1.2-4 and are discussed below.
The steam generator components are constructed of the following materials:
Rubber Carbon Steel Stainless Steel Low-alloy Steel Nickel-based Alloys The steam generator components are exposed to the following environments:
Air Steam Treated Water Borated Water Leakage Treated Water and Steam The steam generator components may experience the following aging effects:
Cracking Loss of Material Loss of Pre-Load Change of Material Properties The above aging effects will be managed by the following aging management programs:
Boric Acid Corrosion Work Control Process Flow-Accelerated Corrosion Steam Generator Structural Integrity Chemistry Control for Primary Systems Chemistry Control for Secondary Systems Inservice Inspection Program: Systems, Components and Supports Staff Evaluation In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information in LRA Section 3.1, Table 3.1.2-4 and the applicant's December 3, 2004 response to the staff's request for additional information dated August 11, 2004, to determine whether the applicant has demonstrated that the effects of aging of the SG components will be adequately managed so that the intended functions of SG components will be maintained consistent with the current licensing basis throughout the period of extended operation. The staff finds that the materials, 5
environments, and aging effects associated with steam generator components in LRA Table 3.1.2-4 are acceptable because they are consistent with NUREG-1 800 and NUREG-1801.
The applicant replaced the 2 steam generators (SGs) at Millstone Unit 2 in 1993 with replacement SGs fabricated by Babcock and Wilcox International. Each replacement SG nominally contains 8,523 thermally treated Alloy 690 tubes. Thermally treated Alloy 690 tubes have been shown in laboratory tests and operating nuclear power plants to be resistant to primary water stress corrosion cracking (PWSCC) and outside diameter stress corrosion cracking (ODSCC). Each tube has a nominal outside diameter of 0.750-inch and a nominal wall thickness of 0.0445-inch. The tubes were hydraulically expanded at both ends for the full length of the tubesheet and are supported by a number of Type 410 stainless steel tube support plates with a lattice arrangement. The U-bends of the tubes installed in rows 1 through 8 were thermally stress relieved after bending.
3.1.2.1.4-B Steam Generator Aging Management Review Results Summary of Technical Information in the Application In Section 3.1.2.1.4 of the LRA for Unit 3, the applicant identified the materials, environments, aging effects, and associated aging management programs related to the steam generator components that are within the scope of the LRA. The steam generator components that require aging management review are listed in LRA Table 3.1.2-4 and are discussed below.
The steam generator components are constructed of the following materials:
Carbon Steel Stainless Steel Low-alloy Steel Nickel-based alloys The steam generator components are exposed to the following environments:
Air Steam Treated Water Borated Water Leakage Treated Water and Steam The steam generator components may experience the following aging effects:
Cracking Loss of Material Loss of Pre-Load The aging effects above will be managed by the following aging management programs:
Boric Acid Corrosion Flow-Accelerated Corrosion Steam Generator Structural Integrity 6
Chemistry Control for Primary Systems Chemistry Control for Secondary Systems Inservice Inspection Program: Systems, Components and Supports Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section 3.1, Table 3.1.2-4 and the applicant's December 3, 2004 response to the staff's request for additional information dated August 11, 2004, to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions of steam generator components will be maintained consistent with the current licensing basis throughout the period of extended operation. The staff finds that the materials, environments, and aging effects associated with steam generator components in LRA Table 3.1.2-4 are acceptable because they are consistent with NUREG-1800 and NUREG-1801.
Millstone Unit 3 has four Westinghouse Model F steam generators. Each SG contains 5626 thermally treated Alloy Inconel 600 tubes. Each tube has a nominal outside diameter of 0.688-inch and a nominal wall thickness of 0.040-inch. The tubes were hydraulically expanded at both ends for the full length of the tubesheet and are supported by a number of stainless steel Type 405 tube support plates with quatrefoil-broached holes and upper support anti-vibration bars.
Steam Generator Components in LRA Table 3.1.1for Units 2 and 3 The staff reviewed SG related items in LRA Table 3.1.1 to determine their acceptability in the aging management review and the consistency with GALL. The staff concludes that the applicant has the appropriate aging management programs to manage the aging effect of the steam generator components. In addition, the staff concludes that Table 3.1.1 of the LRA is consistent with Table 3.1-1 of NUREG-1 800 (Standard Review Plan for License Renewal).
Steam Generator Components in LRA Table 3.1.2-4 for Units 2 and 3 LRA Table 3.1.2-4 provides a summary of the aging management review of steam generator components. Each steam generator component covered under LRA is identified with associated intended function, material, environment, aging effect, and aging management program. The staff reviewed LRA Table 3.1.2-4 to determine whether the applicant has demonstrated that the effects of aging of the steam generator components will be adequately managed during the period of extended operation, as required by 10 CFR 54.21 (a)(3).
In LRA Table 3.1.2-4, the applicant identified the Inservice Inspection Program as the AMP to manage the aging effect of cracking in the SG base support and flange, support brackets and lugs for Unit 2. In RAI 3.1.2-4-1, the staff asked the applicant to provide details for some of the AMP attributes (e.g., Preventive Actions, Parameters Monitored/inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria) for these components since they are not addressed in the GALL Inservice inspection AMP.
By letter dated December 3, 2004, the applicant responded that in NUREG-1 801,Section XI.M1, the program scope of the Inservice Inspection AMP includes "all pressure retaining components and their integrally welded attachments." The integral weld attachment of the base support to the steam generators is included under ASME Section Xl, Subsection IWB. The 7
flange, support brackets and lugs are included under ASME Section Xl, Subsection IWF. In LRA Appendix B Table B2.0, the applicant lists all the GALL AMPs and the designated Millstone AMP that meets the GALL requirements. In Table B2.0, the applicant stated that the Inservice Inspection AMP will address GALL Section XI.M1, ASME Section Xl Inservice Inspections, Subsection IWB, IWC and IWD and Section XI.S3, ASME Section Xl, Subsection IWF (for supports). Since the program elements in NUREG-1801, XI.M1 and XL.S3 are both addressed by the Millstone Inservice Inspection AMP, the applicant stated that they do not need to describe separately the attributes mentioned above. The staff finds the applicant's response acceptable because the applicant has clarified that the GALL Inservice Inspection AMP attributes for the base support flange, support brackets and lugs are addressed in the applicant's Inservice Inspection AMP.
In LRA Table 3.1.2-4, the applicant identifies cracking as the aging effect for the primary instrument nozzles and tube plugs under treated water. In RAI 3.1.2-4-2, the staff asked the applicant to identify the mechanism for cracking in the primary instrument nozzles and tube plugs (e.g., PWSCC or ODSCC).
By letter dated December 3, 2004, the applicant responded that consistent with GALL, the cracking mechanism for the primary instrument nozzles and tube plugs subcomponents is PWSCC. The staff finds the applicant's response acceptable because the applicant clarified that the aging mechanism for the primary instrument nozzles and tube plugs is PWSCC, consistent with what is stated in GALL.
In LRA Table 3.1.2-4, the applicant identified cracking as an aging effect and the Inservice Inspection as the AMP for the primary manway bolting in the air environment. In RAI 3.1.2-4-3, the staff asked the applicant to clarify the aging mechanism for cracking and to explain how the Inservice Inspection AMP is used to manage this aging effect similar to the recommended Bolting Integrity AMP in the GALL.
By letter dated December 3, 2004, the applicant responded that consistent with GALL, the aging mechanism for the primary manway bolting is stress corrosion cracking, which can result from flaw initiation and growth. The applicant stated that they will implement a Bolting Integrity Program to manage the aging effect of stress corrosion cracking as stated in GALL IV.D1.1-I.
The staff finds the applicant's response acceptable because it is consistent with GALL.
In LRA Table 3.1.2-4, the applicant identified the only aging effect as cracking and the Inservice Inspection Program as the AMP for the secondary manway and handhole bolting in the air environment. In RAI 3.1.2-4-4, the staff asked the applicant to justify why loss of preload and stress relaxation are not applicable aging effects as stated in GALL IV.D1.1-f.
By letter dated December 3, 2004, the applicant responded that loss of preload due to stress relaxation is not an applicable aging effect for the ASME Class 2 secondary manway and handhole bolting. The applicant uses SA-1 93, Grade B7 bolting for these applications. The applicant stated that, according to ASME Section II, Part D, Table 4, stress relaxation may occur at temperatures of 7001F or higher for Grade B7 bolting materials. The applicant's normal operating reactor coolant system hot leg temperature, which bounds the maximum temperature for the SG secondary side components, is 600.51F for Unit 2 and 61 8'F for Unit 3.
The applicant stated that since these temperatures are below the 7000F, loss of preload due to stress relaxation is not an aging effect requiring aging management. The staff reviewed the 8
operating thresholds and footnotes for stress relaxation in Section II of the ASME Boiler and Pressure Vessel Code for these bolting materials and confirmed that the applicant's determination is valid. The staff finds the applicant response acceptable because the bolts will not be exposed to temperatures in excess of the threshold for stress relaxation in the bolting materials.
In LRA Table 3.1.2-4, the applicant identified loss of material as the aging effect for the tube supports lattice rings. In RAI 3.1.2-4-5, the staff stated that cracking is also a potential aging effect and therefore asked the applicant to justify why cracking is not considered as an aging effect for the tube support lattice rings under treated water and steam.
By letter dated December 3, 2004, the applicant responded that only high-strength carbon steels are susceptible to this stress corrosion cracking in this environment. Since the tube support lattice rings are made of carbon steel and not high strength carbon steel, they are not susceptible to stress corrosion cracking under the steam generator secondary-side environment. The staff finds the applicant's response acceptable because based on operating experience, carbon steel is not likely to be susceptible to stress corrosion cracking under the steam generator secondary-side environment.
Conclusion On the basis of its review, the staff concludes that the applicant has demonstrated that the aging effects associated with steam generator components will be adequately manages so that the intended functions of the steam generators will be maintained consistent with the current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).
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