NL-08-091, Reply to Request for Additional Information Regarding License Renewal Application - Operating Experience
| ML081630202 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 06/05/2008 |
| From: | Dacimo F Entergy Nuclear Northeast, Entergy Nuclear Operations |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NL-08-091 | |
| Download: ML081630202 (12) | |
Text
Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 SEntergy Buchanan, NY 10511-0249 Tel 914 788 2055 Fred Dacimno Vice President License Renewal June 5, 2008 Re: Indian Point Units 2 & 3 Docket Nos. 50-247 & 50-286 NL-08-091 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
SUBJECT:
Reply to Request for Additional Information Regarding License Renewal Application -
Operating Experience
Reference:
NRC letter dated May 7, 2008; "Request for Additional Information for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application -Operating Experience"
Dear Sir or Madam:
Entergy Nuclear Operations, Inc is providing, in Attachment I, the additional information requested in the referenced letter pertaining to NRC review of the License Renewal Application for Indian Point 2 and Indian Point 3. The additional information provided in this transmittal addresses staff questions for Operating Experience.
There are no new commitments identified in this submittal. If you have any questions or require additional information, please contact Mr. R. Walpole, Manager, Licensing at (914) 734-6710.
I declare under penalty of perjury that the foregoing is true and correct. Executed on ( '- (: 4.
Sit Fred R. Dacimo Vice President License Renewal Ap_8
NL-08-091 Docket Nos. 50-247 & 50-286 Page 2 of 2
Attachment:
Reply to NRC Request for Additional Information Regarding License Renewal Application - Operating Experience cc: Mr. Bo M. Pham, NRC Environmental Project Manager Ms. Kimberly Green, NRC Safety Project Manager Mr. John P. Boska, NRC NRR Senior Project Manager Mr. Samuel J. Collins, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel IPEC NRC Senior Resident Inspectors Office Mr. Paul D. Tonko, President, NYSERDA Mr. Paul Eddy, New York State Dept. of Public Service
ATTACHMENT I TO NL-08-091 REPLY TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE RENEWAL APPLICATION Operating Experience ENTERGY NUCLEAR OPERATIONS, INC INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 and 3 DOCKETS 50-247 and 50-286
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 1 of 9 INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION (LRA)
REQUESTS FOR ADDITIONAL INFORMATION (RAI)
OPERATING EXPERIENCE The U.S. Nuclear Regulatory Commission (NRC or staff) has reviewed the information related to Operating Experience provided by the applicant in the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) LRA. The staff has identified that additional information is needed to complete the review as addressed below.
RAI RCS-1 The staff's review of the condition report (CR) summaries of operating experience related to Class 1 mechanical systems identified four areas of degraded conditions. Those areas are as follows: (1) borated water leakage/boric acid deposits associated with control, rod drive, control rod drive mechanism, resistance temperature device, reactor pressure vessel (RPV) bottom head, seal tables, penetrations, fittings and thimble tubes; (2) seal housing bolt cracks; (3) steam generator tube indications; and (4) RPV head weld indications.
Please provide the following information for each type of degraded condition identified above, in sufficient detail for the staff to make a determination about the adequacy of corrective actions for the extended period of operation:
(a) history of the degradation; (b) evaluation of the extent of degradation; (c) corrective actions already taken or planned; (d) the current status of the degraded condition; (e) special or augmented aging management requirements during the period of extended operation; (f) license renewal commitments.
Based on the staff's review of the CR list, it is not clear to the staff if this list contains all significant plant-specific reactor coolant system (RCS) component degradation experienced at Indian Point Unit 2 (IP2) and Indian Point Unit 3 (IP3). Please identify and provide the same information (items a-f) for any other significant existing conditions of aging for the RCS not specifically identified in this RAI.
In addition, please identify and provide the same information (items a-f) for other significant existing conditions of aging, if applicable, in any Class 1 mechanical components for included in LRA Section 3.2 through 3.4.
Response for RAI RCS-1 Area (1): Borated water leakage/boric acid deposits associated with control rod drive, control rod drive mechanism, resistance temperature device, reactor pressure vessel (RPV) bottom head, seal tables, penetrations, fittings and thimble tubes.
(a) Routine inspections of control rod drives, control rod drive mechanisms, resistance temperature devices, reactor pressure vessel (RPV) bottom head, seal tables, penetrations, fittings and thimble tubes at IP2 and IP3 during 2001-2005 revealed indications of boric acid
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 2 of 9 leakage that could lead to loss of material due to boric acid corrosion. These conditions were identified as part of existing inspection programs that are designed to identify and correct these conditions prior to loss of system intended function.
(b, c & d) Each of these conditions were evaluated and corrected, and none resulted in a loss of intended function. Corrective actions included cleaning of the affected areas, replacement of leaking gaskets, repair of leaking seal welds, and revisions to procedures for foreign material control and for visual inspection of the reactor vessel. As-left conditions were acceptable for operation.
(e & f) No special or augmented aging management activities or license renewal commitments other than the boric acid corrosion prevention and reactor vessel head inspection programs are required for the period of extended operation since these programs are consistent with the NUREG-1801 program recommended to manage this aging effect.
Area (2): seal housing bolt cracks (a) During an inspection of #24 RCP at IP2 in 2002, crack-like indications were reported in six bolts in the #1 seal housing for this pump.
(b) No similar indications were identified on other seal housing bolting. Further evaluation determined the indications were machine marks made when the bolts were fabricated and not cracks. This condition was not age-related, and did not result in a loss of system intended function.
(c & d) The corrective action was to replace the bolts for this seal housing unit. The current status is no known degradation of the bolting.
(e & f) The identified condition was unrelated to the effects of aging and therefore involves no implications for aging management programs or license renewal commitments.
Area (3): Steam generator tube indications (a) During steam generator integrity program inspections of #31, #32, #33 and # 34 steam generators at IP3 in 2003, indications of potential degradation were detected on eleven steam generator tubes. Three of these were attributed to a historical anomaly of unknown origin that was first detected in 1999. Eight others were found to have new degradation attributed to wear from sludge lance equipment used in 2001. One other tube was found to have magnetic permeability variations that could interfere with the detection of degradation.
(b) Engineering review determined that sample expansion was not required. This condition did not result in a loss of intended function.
(c & d) Twelve tubes were plugged. The condition of the tubes continues to be monitored under steam generator integrity program activities. The degradation noted in this 2003 inspection has been recorded for comparison to future inspection results.
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 3 of 9 (e & f) No special or augmented aging management activities or license renewal commitments other than the steam generator integrity program are required for the period of extended operation since the program is consistent with the NUREG-1801 program recommended to manage degradation of steam generator tubes.
Area (4): RPV head weld indications (a & b) During inservice inspection (ISI) of the IP3 reactor pressure vessel (RPV) head in 2005, a recordable indication was identified in #2 meridional weld. Similar indications were not detected on any of the other five such welds on the RPV head during this 2005 inspection. This condition did not result in a loss of intended function.
(c & d) The indication was similar to original fabrication indications, with no cracking characteristics, and was evaluated as acceptable. The indication was recorded for comparison in future inspections under the ISI program.
(e & f) No special or augmented aging management activities or license renewal commitments are required for the period of extended operation.
These conditions were identified and corrective actions performed as part of the corrective action program in accordance with the requirements of the Entergy quality assurance program and 10CFR50 Appendix B. This site-specific operating experience is consistent with the operating experience described in NUREG-1801 and confirms the effects of aging identified in the LRA.
The operating experience review for Class 1 mechanical components identified no significant conditions of aging that are not described in the LRA.
RAI RCS-2 Based on the review of the plant basis documents associated with operating experience discussions for aging management programs (AMPs) B.1.16, B.1.18, B.1.30, and B.1.31, the staff found that additional information is needed to complete its operating experience review.
Therefore, please provide the following additional information to assist the staff in its review:
(i) For AMPs B.1.16, B.1.18, B.1.30, and B.1.31, please describe in sufficient detail the plant-specific CR review that forms the basis to conclude that each of these existing programs will be effective in managing applicable aging effects, as identified in the LRA.
(ii) For new AMPs B.1.37 and B.1.38, which are currently being developed, the AMP description of each program identifies that RCS components will be managed for thermal and/or irradiation embrittlement. Please describe in sufficient detail any operating experience for these AMPs, 'and the review of plant-specific and industry-wide operating experience for those RCS components that have been identified as potentially susceptible to thermal and/or irradiation embrittlement at IP2 and IP3.
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 4 of 9 Response for RAI RCS-2 (i) For inspection programs, such as B.1.16 (Flux Thimble Tube Inspection Program), B.1.18 (Inservice Inspection (ISI) Program), B.1.30 (Reactor Head Closure Studs Program), and B.1.31 (Reactor Vessel Head Penetration Inspection Program), a two-fold approach was used to obtain operating experience that forms the basis to conclude each of these existing programs will continue to be effective in managing applicable aging effects.
First, interviews with site program owners were conducted. Program owners are responsible for assuring implementation of each program in accordance with applicable regulations and site commitments. Interviews with program owners consisted of discussions related to program effectiveness. Interviewers prompted the program owners to discuss program changes and reasons for the changes. Program owners were asked to provide evidence of successful implementation and performance of their program. Program owners related evidence of program success or weakness and identified self-assessments, QA audits, peer evaluations, and NRC reviews applicable to their program.
Second, reports of recent inspections, examinations, or tests were located and reviewed to determine if aging effects have been identified on applicable components. Supplemental keyword searches of the paperless condition reporting system (PCRS) were used to locate CRs related to components within the program. Keywords were selected that would reveal CRs related to the applicable components. For example, for the Flux Thimble Tube Inspection Program, keywords "flux thimble", "instrument guide tube," and "instrument nozzle" were selected. The CRs resulting from this search were evaluated. A CR was retained for further evaluation if it provided an indication of the ability of a program to identify degradation prior to loss of intended function. Inspection results related to these programs were found in inspection reports, QA surveillance reports, and assessment findings.
Results of these program owner interviews and program-specific document reviews were documented in the IPEC "Operating Experience Review Report." This information confirmed the ability of the programs to identify degradation prior to loss of intended function so that corrective action could be taken. This provides a basis for concluding that the programs will remain effective for managing the applicable effects of aging during the period of extended operation as discussed in LRA Appendix B.
(ii) Operating experience for new AMPs B. 1.37 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) and B.1.38 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) is provided in NUREG 1801 Volume 2, Revision 1, Sections XI.M12 and XI.M13. These AMPs were developed using research data (NUREG/CR-4513, Revision 1) obtained on both laboratory-aged and service-aged materials. Based on this information, the effects of thermal aging and neutron irradiation embrittlement on the intended function of CASS components will be effectively managed. These aging effects have not been detected at IPEC.
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 5 of 9 RAI AUX-1 In reviewing IP2 and IP3 CR summaries related to operating experience applicable to non-Class 1 mechanical systems, and operating experience summaries for the Diesel Fuel Monitoring, Oil Analysis, Service Water Integrity, Water Chemistry Control -- Auxiliary Systems, and Water Chemistry Control -- Closed Cooling Water Systems AMPs, the staff identified conditions of aging degradation that are not described in detail in the LRA or plant basis documents. The following areas of aging degradation were identified by the staff: (1) degraded IP2 traveling screens; (2) eroded fuel line in IP2 utility tunnel caused by in-leakage; (3) erosion/corrosion of IP2 components and thru-wall leaks; (4) IP3 feedwater outer-diameter thinning; and (5) IP3 service water degradation.
The applicant is requested to provide the following information for each type of degraded condition identified above, in sufficient detail for the staff to make a determination about the adequacy of corrective actions for the extended period of operation:
(a) history of the degradation; (b) evaluation of the extent of degradation; (c) corrective actions already taken or planned; (d) the current status of the degraded condition; (e) special or augmented aging management requirements during the period of extended operation; and (f) license renewal commitments.
In addition, the applicant is requested to identify and provide the same information (items a-f) for other significant existing conditions of aging in non-Class 1 mechanical components included in LRA Sections 3.2 and 3.4, which are not specifically addressed in this RAI.
Response for RAI AUX-1 Area (1): Degraded IP2 traveling screens (a) During a visual inspection of the 1P2 traveling screens in 2001, conditions such as flange leakage, flushout stop valve leakage, and accumulation of debris were noted.
(b, c & d) Engineering review determined that these conditions did not affect the integrity of the traveling screens. Actions taken include cleaning of accumulated debris, tightening of bolts, and cycling of stop valves.
(e & f) The intended function of IP2 traveling screens for license renewal is to support safe shutdown in the event of a fire in the auxiliary feedwater pump room. As discussed in LRA Section 2.3.4.5, integrity of the traveling screens is continuously confirmed by normal plant operation. During the short duration of the fire event, further aging degradation that would not have been apparent prior to the event is negligible. Therefore, no aging effects requiring management are identified for the IP2 traveling screens. As discussed in section 2.2 of the LRA, the IP3 traveling screen system is not in the scope of license renewal. Therefore, a review of conditions related to traveling screens is not relevant to the aging management programs described in Appendix B of the LRA. However, aging effects for the prevalent material and environment combination in the traveling screens (stainless steel in raw water) are described in several LRA tables. No special or augmented aging management activities are required for the period of extended operation. The Bolting Integrity, External Surfaces Monitoring, One-Time
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 6 of 9 Inspection, and Service Water Integrity Programs are consistent with the NUREG-1801 programs recommended to manage the effects of aging for this material and environment combination.
Area (2): Eroded fuel line in IP2 utility tunnel caused by in-leakage (a) During a tour of the utility tunnel in 2001, loss of material due to corrosion was noted on the external surface of a fuel oil line.
(b, c & d) This condition did not result in a loss of system intended function. Corrective actions included cleaning the line, performing ultrasonic (UT) wall thickness measurements at various locations along the length of the pipe, and wrapping the pipe with herculite. Reduction of water intrusion to the utility tunnel has been accomplished through replacement of manhole seals and other improvements. Engineering review of pipe UT data determined the remaining wall thickness was acceptable. Inspections of the fuel oil piping continue under the external surfaces monitoring program.
(e & f) No special or augmented aging management activities or license renewal commitments are required for the period of extended operation. The External Surfaces Monitoring Program is consistent with the NUREG-1801 program recommended to manage the effects of aging on external surfaces of fuel oil piping.
Area (3): Erosion/corrosion of IP2 components and thru-wall leaks (a) During activities performed under the External Surfaces Monitoring, Water Chemistry -
Closed Cooling Water, and Flow-Accelerated Corrosion (FAC) programs at IP2 during 2001-2006, cracking and loss of material were detected on various components, leading to through-wall leakage in some cases.
(b, c & d) These conditions did not result in a loss of system intended function. The reports of loss of material due to flow-accelerated corrosion were evaluated under an ongoing project to replace components degraded by the flow of wet steam. Corrective actions included replacement of piping, fittings, and valve bodies, increased monitoring of water chemistry and additional wall thinning examinations. Inspections of these components continue under activities of the External Surfaces Monitoring Program, Flow-Accelerated Corrosion Program, and Water Chemistry Control - Closed Cooling Water Program.
(e & f) No special or augmented aging management activities or license renewal commitments are required for the period of extended operation. The External Surfaces Monitoring, Flow-Accelerated Corrosion, and Water Chemistry Control - Closed Cooling Water programs are consistent with the NUREG-1801 programs recommended to manage cracking and loss of material.
NIL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 7 of 9 Area (4): IP3 feedwater outer-diameter thinning (a) Tube leakage was detected in the #31 feedwater heaters at IP3 in 1997.
(b, c & d) This condition did not result in a loss of system intended function. Damage to tubes was in the form of outer diameter thinning at the bottom of the inlet passes, attributed to steam erosion caused by flashing on the shell side due to improper water levels. Actions taken included plugging of leaking tubes and follow-up eddy current examinations of a sample of the tubes in feedwater heaters #31A, #31 B, and #31C.
(e & f) IP3 feedwater heater tubes have no license renewal intended function. The intended function of IP2 feedwater heater tubes is to support safe shutdown by supplying feedwater to the steam generators in the event of a fire in the AFW pump room. As discussed in LRA Section 2.3.4.5, integrity of the feedwater heater tubes is continuously confirmed by normal plant operation. During the short duration of the fire event, further aging degradation that would not have been apparent prior to the event is negligible. Therefore, no aging effects requiring management are identified for IP2 feedwater heater tubes.
Thus for IP2 and IP3 license renewal, no aging management programs are necessary for feedwater heater tubes, and review of conditions related to feedwater heater tubes is not relevant to the aging management programs described in Appendix B of the LRA. However, aging effects for this material-environment combination (stainless steel heat exchanger tubes and treated water) are described in several LRA tables. No special or augmented aging management activities or license renewal commitments are required for the period of extended operation. The Water Chemistry Control - Closed Cooling Water and Water Chemistry Control
- Primary and Secondary programs are consistent with the NUREG-1801 programs recommended to manage the effects of aging for the applicable material and environment combination.
Area (5): IP3 service water degradation.
(a) During inspections at IP2 and IP3 in 2001-2004 in accordance with the Service Water Integrity Program, loss of material was detected on service water system (SWS) components.
(b, c & d) These conditions did not result in a loss of system intended function. Engineering review of external corrosion and a pinhole leak resulted in no operability concerns. The observed conditions were documented for trending under these programs. The extent of pipe coating delamination indicated the need for repair of the external epoxy coating downstream of the service water pumps. Corrective actions included repair of external coatings, replacement of expansion joints, and expansion of the scope of future inspections.
(e & f) No special or augmented aging management activities or license renewal commitments are required for the period of extended operation. The Service Water Integrity Program is consistent with the NUREG-1801 program recommended to manage the effects of aging on SWS components.
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 8 of 9 These conditions were identified and corrective actions performed as part of the corrective action program in accordance with the requirements of the Entergy quality assurance program and 10CFR50 Appendix B. This site-specific operating experience is consistent with the operating experience described in NUREG-1801 and confirms the effects of aging identified in the LRA.
The operating experience review for non-Class 1 mechanical components identified no significant conditions of aging that are not described in the LRA.
RAI AUX-2 Appendix B of the LRA concluded that the Service Water Integrity Program has been effective in managing those aging effects for which it is credited based on the results of one peer assessment, one self assessment and five NRC inspections of the Generic Letter (GL) 89-13 program. NRC GL 89-13 guidelines are directed to ensure the performance of safety-related systems and components exposed to service water. It is not clear to the staff how the results of these inspections are used to confirm the effectiveness of managing aging effects in nonsafety-related components of the service water system (SWS) that are within scope for license renewal.
The staff requests the applicant to clarify whether the Service Water Integrity Program is credited for aging management of the nonsafety-related components of the SWS that are within scope for license renewal. If so, please provide evidence for the conclusion presented in the LRA, that this AMP is effective in managing age-related degradation of the SWS. If not, identify the AMP(s) that are credited for aging management of the nonsafety-related components of the SWS that are within scope for license renewal. Provide the basis for concluding that these programs will be effective for managing aging during the period of extended operation.
Responses for RAI AUX-2 The Service Water Integrity Program is credited for managing the effects of aging on components as listed in LRA Section 3 tables regardless of safety classification.
The materials of construction and operating environment for components and piping in nonsafety-related and safety-related portions of the SWS are identical. Therefore, the aging effects managed by the Service Water Integrity Program are identical.
As stated in LRA Section B.1.34, the Service Water Integrity Program is consistent with NUREG-1801,Section XI.M20, Open Cycle Cooling Water System and includes activities that apply to both safety-related and nonsafety-related components described below.
- 1. Component inspections for erosion, corrosion, and biofouling. Results of these inspections have been used to determine the corrective actions required to preclude recurrence of unacceptable conditions, as described in LRA Section B.0.3. All components in the SWS flowpath are within the scope of such corrective actions regardless of safety classification.
- 2. Safety-related heat exchangers in the program are tested to verify heat transfer capabilities. Nonsafety-related heat exchangers cooled by service water are periodically inspected. These inspections are sufficient to manage aging effects since there is no license renewal component intended function of heat transfer.
NL-08-091 Attachment I Docket Nos. 50-247 & 50-286 Page 9 of 9
- 3. Chemical treatment using biocides and sodium hypochlorite and periodic cleaning and flushing of infrequently used loops are applied to all components in the SWS flowpath regardless of safety classification. In this manner, the program remains effective for managing aging effects for all components in the SWS.
- 4. GL 89-13 inspections are performed on nonsafety-related piping. For example, during 2R18 in March and April 2008, approximately 10% of the scheduled GL 89-13 program volumetric weld examinations were conducted on nonsafety-related SWS piping welds, and approximately 25% of the scheduled GL 89-13 program visual inspections were conducted on nonsafety-related SWS piping. Scope expansion for indications found by GL 89-13 inspections of nonsafety-related piping is based on consideration of location, severity, materials, previous inspection history, and other relevant factors.
- 5. System walkdowns apply to both SWS safety-related and nonsafety-related components.
Considering that activities under the Service Water Integrity Program apply to both safety-related and nonsafety-related components, the program effectiveness conclusions of recent peer and self assessments as well as NRC inspections described in the operating experience section are applicable to all components crediting the program for aging management.