NL-04-1296, Application for License Renewal - Requests for Additional Information
| ML042100057 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 07/16/2004 |
| From: | Stinson L Southern Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NL-04-1296 | |
| Download: ML042100057 (10) | |
Text
L. M. Stinson (Mike)
Vice President Southern Nuclear Operating Company, Inc.
40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201 Tel 205.992.5181 Fax 205.992.0341 SOUTHERN A COMPANY Energy to Serve Your World SM July 16, 2004 Docket Nos.:
50-348 50-364 NL-04-1296 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Joseph M. Farley Nuclear Plant Units 1 and 2 Application for License Renewal - Requests for Additional Information Ladies and Gentlemen:
In response to NRC Staff requests, this letter provides supplemental and/or revised information for previously submitted Request for Additional Information (RAI) responses. Also provided is a response to new RAI B.5.9-1 provided in your letter dated July 12, 2004 requesting additional information for the review of the Joseph M. Farley Nuclear Plant, Units 1 and 2, License Renewal Application. This information is provided in the enclosure.
Mr. L. M. Stinson states he is a vice president of Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and to the best of his knowledge and belief, the facts set forth in this letter are true.
If you have any questions, please contact Charles Pierce at 205-992-7872.
Respectfully submitted, SOUTHERN NUCLEAR OPERATING COMPANY L. M. Stinson
- -vo7 to and subscribed before me this l& day of JkLj
'forary Public MY Commission EXpirs Aprfl 28, 2007 My commission expires:
2004.
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U. S. Nuclear Regulatory Commission NL-04-1296 Page 2 LMS/MAM/slb
Enclosure:
Joseph M. Farley Nuclear Plant, Units 1 and 2 Application for License Renewal - Supplemental Information and Responses to Requests for Additional Information cc:
Southern Nuclear Operating Company Mr. J. B. Beasley Jr., Executive Vice President Mr. D. E. Grissette, General Manager - Plant Farley Document Services RTYPE: CFA04.054; LC# 14085 U. S. Nuclear Regulatorv Commission Ms. T. Y. Liu, License Renewal Project Manager Dr. W. D. Travers, Regional Administrator Mr. S. E. Peters, NRR Project Manager - Farley Mr. C. A. Patterson, Senior Resident Inspector - Farley Alabama Department of Public Health Dr. D. E. Williamson, State Health Officer
Enclosure NL-04-1 296 ENCLOSURE Joseph M. Farley Nuclear Plant Units I and 2 Application for License Renewal Supplemental Information and Responses to Requests for Additional Information E-1
Endosure NL-04-1 296 LRA Section 3.1: Aging Management of Reactor Vessel, Internals, and Reactor Coolant System Supplemental Information on Aging Management of SG Shell Assemblies -
LRA Tables 3.1-1 (item 2) & 3.1.2-4 and Section 3.1.2.2.2 In a teleconference on July 6, 2004, the NRC staff requested supplemental information in reference to LRA Table 3.1-1 (item 2), Table 3.1.24 ("Upper Shells, Lower Shells, and Transition Cones" component type on page 3.1-79), and LRA Section 3.1.2.2.2 regarding aging management of the steam generator (SG) shell assemblies. The following text was provided by the staff.
in Farley LRA, Table3. 1.2-4, page 3.1-79, for upper shells, lower shells, and transition cone component type, FNP has credited water chemistry control program for loss of material aging effect. The LRA also references GALL section IV.D1. 1-c, Table I item 3.1.1-2, and footnote "A". Footnote "A"is defined as "consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801AMP."
However, GALL item IV.D1. 1-c recommends water chemistry control program (WCCP) and ISI to manage this aging effect. Thus, footnote 'A"is not applicable and perhaps footnote "E" applies. Also, SRP section 3.1.2.2.2 states that WCCP and ISI may not be enough, and augmented inspections may be required. In LRA section 3.1.2.2.2, FNP states that WCCP is used for loss of material, but ISI is used for cracking. This section only addresses loss of material due to pitting and crevice corrosion. Also, in conclusion FNP states that no augmented inspections are required, since the steam generators were replaced and since then, water chemistry has been maintained per EPRI standards. But, the LRA did not state that ISI will be performed for loss of material or that the ISI that is performed for managing cracking would also be used for loss of material.
Please clarify if WCCP and ISI are intended to be used for loss of material, if not, should the note be changed to Footnote "E', and the rationale for not performing ISI for loss of material, if it is already being performed for cracking.
Based on the preceding text and discussion with the staff, SNC provides the following supplemental information.
For the FNP Steam Generator (SG) Upper Shells, Lower Shells, and Transition Cones Component Type, SNC provides the following corrections and clarifications. NUREG-1801, 'Generic Aging Lessons Learned (GALL) Report," Volume 2, item IV.D1.1-c should not have been applied to cracking, only to loss of material. Standard note "H" should have been applied to the cracking line item instead of notes "A" and "9". For the SG Upper Shells, Lower Shells, and Transition Cones, SNC conservatively considered crack growth due to cyclic loading as an aging effect requiring management, with existing ASME Section Xl inspection requirements performed by the FNP ISI Program credited to manage cracking.
For loss of material associated with the SG Upper Shells, Lower Shells, and Transition Cones, the aging management programs listed should have included both the Water Chemistry Control Program and the ISI Program. Water chemistry controls directly E-2
Enclosure NL-04-1 296 mitigate loss of material within the SG shell assemblies. ISI Program inspections are not specifically designed to detect loss of material due to corrosion. However, ASME Section Xl requirements implemented by the ISI Program are designed to identify any flaws large enough to potentially result in a loss of component intended function, whether caused by cracking, loss of material, or a combination of the two aging effects.
Based on these changes, the SNC programs applied to the SG shell assemblies in the LRA are consistent with those specified in GALL item IV.D1.1-c and standard note "A" applies. This GALL report item indicates that the detection of aging effects is to be further evaluated. Specifically, the GALL report states that, if general corrosion pitting of the SG shell exists, the GALL program recommendations may not be sufficient to detect general and pitting corrosion. The GALL report refers to NRC Information Notice (IN) 90-04 as the basis.
IN 90-04 summarizes instances of corrosion fatigue cracking of the shell-to-transition cone girth welds in SGs. The incidents occurred in SG girth welds located at gross structural discontinuities (i.e., the shell to transition cone welds) at plants with poor water chemistry controls and other contributing factors. As stated in LRA Section 3.1.2.2.2, IN 90-04 indicates that pitting corrosion on the surface served as corrosion fatigue crack initiation sites, not that pitting corrosion resulted in sufficient degradation to cause loss of component function. This degradation mode has been limited to isolated cases of weld-zone cracking in Westinghouse Model 44 and 51 SGs. SNC is unaware of any subsequent industry experience of pitting corrosion resulting in reportable indications for the SG shell.
At FNP, water chemistry control has been carefully controlled and maintained throughout plant life. There have been no instances of weld zone cracking or pitting at the transition cone to shell girth welds in FNP's original Model 51 SGs or in the Model 54F replacement SGs (installed in the 2000-2001 timeframe). General corrosion or pitting of the SG shell has been insignificant.
The Model 54F replacement SG design eliminated the geometric discontinuity at the transition cone to shell girth welds. The FNP Water Chemistry Control Program maintains secondary side chemistry in accordance with strict EPRI Guideline limitations.
The GALL report and Section 3.1.2.2.2 of the Standard Review Plan for License Renewal (NUREG-1 800) state that aging management via chemistry control and Inservice Inspection is adequate unless general corrosion or pitting of the shell is known to exist. Based on the FNP operating experience, general corrosion or pitting does not exist and therefore no additional inspection procedures are needed to manage loss of material due to general and pitting corrosion.
SNC notes that SG secondary side internals are periodically accessed as a part of the FNP Steam Generator Program. During the course of these activities, if loss of material degradation on the inside surface of the SG shell is noted, corrective action(s) would be initiated to manage the problem.
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Enclosure NL-04-1296 RAI B.5.2 Supplemental Response (Revised)
(The following request for supplemental information on the Flux Detector Thimble Tube Inspection Program was provided by the NRC staff.)
Follow-up question (revised based on telecon on 6/7/04) to the SNC response to RAI B.5.2-3 provided in SNC letter NL04-0617 dated April 16, 2004:
For the Unit 2 thimble tubes, the staff requests the following information to support that an inspection frequency of once every other refueling outage is reasonable:
- a.
worst case adjusted amount of wear used for the wear rate projection that supported an inspection frequency of once every other refueling outage, including a quantitative clarification of what NDE uncertainty value (as a percentage of the total thimble tube wall thickness) was used to adjust the amount of wear in the calculation;
- b.
clarification of what the thimble tube thickness is;
- c.
a statement that for the projection of wear, the applicant used the equation in Proprietary WCAP-12866 as the basis for projecting the wear to the next inspection outage, and that plant specific wear data applicable to the Farley thimble tubes was used to curve fit the equation and establish the curve coefficient. Specify what the amount of projected wear is for the Unit 2 thimble tubes using the Westinghouse equation (Note to SNC: only if Westinghouse agrees that it is non-proprietary, then the applicant is requested to provide the coefficient value for the wear rate equation.)
For the Unit 1 thimble tubes, since SNC has not yet performed two inspections of the new tube materials (the next one is in 2006), the staff requests that the applicant provide a commitment to submit the same information being requested for the Unit 2 tubes after the applicant performs the second inspection of the new Unit I thimble tubes in 2006.
The staff requests that the applicant's Unit 1 submittal discuss the technical basis for establishing the inspection frequency that will be implemented after performing the second examination of the new tube materials.
Response
(This revised supplemental response is in reference to a request from the NRC staff to include the worst case projected flux thimble tube wear for Unit 2 at U2R18 and supersedes the previous SNC response in letter NL-04-1096 dated June 25, 2004.)
The acceptance criteria provided in paragraph B.5.2.8 of the Application needs clarification. The WCAP-1 2866 methodology is typically used to project flux thimble tube wear to the next planned inspection, as opposed to projecting the date at which the through-wall wear limit would be exceeded. Paragraph B.5.2.8 of the Application should therefore read: "Results of the flux thimble inspections will be evaluated using a wear rate formula to determine whether any flux thimble tube will exceed the through-wall wear limit before the next planned inspection." The clarified acceptance criteria are consistent with the response provided in both RAI B.5.2-4 and in the response which follows.
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Enclosure NL-04-1296 For the Unit 2 flux detector thimble tubes:
- a.
The worst case cumulative wear (for thimble tubes which have not been repositioned or capped) from the most recent Unit 2 inspection (U2R1 5) data (adjusted for uncertainty) was 58.8% for thimble tube J03 at 985.94" from the seal table. A 5% allowance for instrument error was applied to the measured wear data.
- b.
Nominal wall thickness of the Unit 2 thimble tubes is 0.049 +/- 0.002 inches.
- c.
For FNP, the methodology provided in Proprietary Class 2 WCAP-12866 is used to project thimble tube wear at the end of future operating cycles. Unit-specific measured wear data is adjusted for uncertainty and is input to the WCAP-1 2866 methodology to establish the curve coefficient (i.e., exponent 'n") and determine the curve-fit representing thimble tube wear over time. The next inspection is scheduled for an outage before any thimble tubes are projected to exceed the acceptance criteria for wall loss, with consideration of plant and industry experience with thimble tube wear. This process is repeated after each inspection; therefore the inspection interval is re-evaluated after each inspection.
The curve coefficient (i.e., exponent "n") used in the latest projection of flux thimble tube wear was 0.302. Applying an exponent of 0.302 to the WCAP-12866 formula leads to a multiplier of approximately 1.022 to project wear at the end of cycle 16, and 1.043 to project wear at the end of cycle 17. For the worst case cumulative wear (for thimble tubes which have not been repositioned or capped) from the U2R15 inspection, this equates to wear projections of 60.10%
at the end of cycle 16, and 61.33% at the end of cycle 17.
LRA Appendix B, Section B.5.2.12, indicated that no Unit 2 flux thimble tubes would require repositioning or capping based on the latest data, and the initial response to RAI B.5.2-3 noted that the next Unit 2 eddy current inspection was scheduled for U2R17 (Fall '05). During U2R16 (Spring '04), five thimble tubes were re-positioned and one was capped. SNC is currently considering the option of eliminating the eddy current inspection scheduled for U2R17 based on the additional margin provided by the repositioning and capping. This would allow Unit 2 to operate until U2R18 without further eddy current inspection. The Unit 2 thimble tubes will be inspected or replaced at U2R1 8. The decision to eliminate the U2R1 7 eddy current inspection will include evaluation of thimble tube wear projections performed in accordance with the WCAP-1 2866 methodology. SNC calculated the projected worst case flux thimble tube cumulative wear to be 63.3% at the end of cycle 18 in accordance with the WCAP-12866 methodology.
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Enclosure NL-04-1296 For the Unit 1 flux thimble tubes:
SNC commits to submit to the NRC the same information on the new Unit 1 flux thimble tubes requested for the Unit 2 tubes, after the second inspection (during UI R20 in 2006) and wear projection analysis is completed.
Specifically, SNC will submit the following information on the Unit 1 flux thimble tubes:
The worst case cumulative wear from the UIR20 flux thimble tube eddy current inspection.
The uncertainty applied to the actual measured wear data.
The thimble tube wall thickness.
The schedule for the next Unit 1 flux thimble tube inspection (inspection interval).
The projected wear value for the worst case wear location at the end of the next inspection interval.
A discussion of the technical basis for establishing the inspection interval that will be implemented after performing the UIR20 flux thimble tube eddy current inspection of the new tube materials. The discussion will address the use of the equation in Proprietary WCAP-1 2866 and the unit-specific wear data in projecting the wear to the next inspection outage. The curve coefficient (i.e., exponent "n") used in the projection of flux thimble tube wear will be provided.
The FNP License Renewal Future Action Commitments List will be updated accordingly.
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Enclosure NL-04-1 296 RAI B.5.9-1 The staff requests the applicant to provide the following information related to PSPMA fPeriodic Surveillance and Preventive Maintenance Activities) program:
- a.
Explain how inspections for the presence of corrosion products or fluid leakage, wall thickness, pressure, temperature, and flow will be used to detect the presence and extent of aging effects for the internal elastomer tank diaphragms.
- b.
State the diaphragm inspection frequency for boric acid tanks, reactor makeup water storage tanks, and condensate storage tanks and the basis for determining this frequency.
- c.
Explain how the data collected are evaluated against the acceptance criteria to provide a prediction of the rate of degradation in order to confirm that the timing of the next scheduled inspection will occur before a loss of intended function.
- d.
Provide plant-specific and industry operating experience for degradation of internal elastomer tank diaphragms to support the conclusion that the diaphragms will be adequately managed by the PSPMA or commit to providing operating experience in the future to confirm the effectiveness of the new PSPMA.
Response
- a.
The parameters listed in paragraph B.5.9.5 the Supplemental Response to RAI 2.3.3.23-1 contained in SNC letter NL-04-1038, dated June 18, 2004, are common parameters which can provide information on the condition of various types of components. As stated in paragraph B.5.9.5, the parameters inspected or monitored are dependent on the component(s) and the aging effect(s) being managed. This paragraph does not indicate which parameters will be monitored for the tank diaphragms. For each component included in the Periodic Surveillance and Preventive Maintenance Activities program, an implementing activity will be created which inspects or monitors the parameters which provide the most reliable indication of aging-related degradation. In the case of the tank diaphragms, visual inspections will be performed. These inspections will include inspection of the diaphragm flotation devices, checking for water on top of the diaphragm (fluid leakage), and visual inspection of diaphragm material for degradation (cracking, chalking, tears, etc.) where appropriate.
- b.
The inspection frequency for the tank diaphragms has not yet been determined; however FNP and industry operating history demonstrates age-related degradation of elastomer tank diaphragms progresses slowly. Both industry-wide and FNP-specific operating experience will be considered when the inspection frequencies are established. Vendor recommendations inherently include a much broader base of operating experience than can be obtained from the small number of tank diaphragms installed at FNP and therefore will be considered during development of the inspection frequency. In addition, the Periodic Surveillance and Preventive Maintenance Activities program includes provisions for adjusting inspection intervals using feedback from the inspection activities.
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Enclosure NL-04-1 296
- c.
As stated in the supplemental response to RAI 2.3.3.23-1 (provided in SNC letter NL-04-1038 dated June 18, 2004), the intended function of the tank diaphragms is: "Pressure Boundary (maintain integrity for 10 CFR 54.4(a)(2) concerns)" Gross failure (loss of integrity) of a tank diaphragm must occur to potentially prevent a safety-related function. Therefore, the acceptance criteria for the tank diaphragm inspection activities are focused on maintaining required integrity.
The inspection data and acceptance criteria are not used to 'provide a prediction of the rate of degradation" but rather to identify observable degradation in regards to maintaining required Integrity. The inspection parameters and criteria (see part a. of this discussion) are focused on detecting degradation that may challenge the integrity of the tank diaphragms and initiating appropriate corrective action. Inspection of the flotation devices is intended to confirm the devices are operating properly and are fully attached with no evidence of degradation that could impair the function of the flotation devices. Water on top of the diaphragm is a potential indicator of cracking, perforation, or tearing of the diaphragm. Visible cracking, chalking, tears, etc.
are recognized indicators of progressive aging in elastomer materials.
Conditions that do not meet the acceptance criteria will be investigated and corrective action initiated under the existing condition reporting system.
Potential corrective actions include increasing the frequency of inspection, repair, and replacement. Corrective actions are developed considering available operating experience and with input from the vendor as appropriate.
This is a routine function of the existing corrective actions process and provides reasonable assurance that inspection will occur before a loss of intended function.
- d.
At FNP, the Boric Acid Tank (BAT) diaphragms are made from a PVC material.
The Condensate Storage Tank (CST) and Reactor Makeup Water Storage Tank (RMWST) diaphragms were originally made from rubber and were replaced in the 1990s with thermoplastic elastomer materials. There have been no indications of degradation or failure of the currently installed diaphragms at FNP.
The vendor has indicated that inspections of diaphragms similar to those installed at FNP after ten years of operation show no significant aging of the diaphragm material. FNP and industry operating history demonstrates age-related degradation of elastomer tank diaphragms progresses slowly in the non-aggressive environments internal to the tanks. Periodic visual inspections have proven effective at detecting age-related degradations of elastomers prior to loss of function and have been previously found acceptable to the NRC staff. Based on the slow progression of age-related degradation and the effectiveness of periodic visual inspections, SNC concludes that the Periodic Surveillance and Preventive Maintenance Activities program will adequately manage aging of the tank diaphragms.
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