ML042740651
| ML042740651 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 09/30/2004 |
| From: | Gregory Suber NRC/NRR/DRIP/RLEP |
| To: | Entergy Operations |
| Suber G, NRR/DRIP/RLEP 301-415-1124 | |
| References | |
| TAC MB8402 | |
| Download: ML042740651 (18) | |
Text
September 30, 2004 LICENSEE:
Entergy Operations Inc.
FACILITY:
Arkansas Nuclear Station, Unit 2
SUBJECT:
SUMMARY
OF TELEPHONE CALLS HELD ON AUGUST 26 AND SEPTEMBER 1, 2004, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION (NRC) STAFF AND ENTERGY OPERATIONS INC.,
REPRESENTATIVES CONCERNING REQUEST FOR ADDITIONAL INFORMATION PERTAINING TO THE ARKANSAS NUCLEAR ONE, UNIT 2 LICENSE RENEWAL APPLICATION (TAC NO. MB8402)
On August 26 and September 1, 2004, the U.S. Nuclear Regulatory Commission (NRC) staff and representatives of the Entergy Operations Inc., held telephone conference calls to discuss formal responses to the request for additional information (RAI) pertaining to the technical review for the Arkansas Nuclear One, Unit 2 license renewal application.
These conference calls were used to clarify the staffs position with respect to certain responses to RAIs. On the basis of the discussion, the applicant agreed to modify and/or supplement several responses. provides a listing of the telephone conference call participants. Enclosure 2 contains a listing of the RAIs, formal responses from the applicant, and a brief description of the status of each item. A copy of this summary was provided to the applicant for comment.
/RA/
Gregory F. Suber, Project Manager License Renewal Section A License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket No.: 50-368
Enclosures:
As stated
September 30, 2004 LICENSEE:
Entergy Operations Inc.
FACILITY:
Arkansas Nuclear Station, Unit 2
SUBJECT:
SUMMARY
OF TELEPHONE CALLS HELD ON AUGUST 26 AND SEPTEMBER 1, 2004, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION (NRC) STAFF AND ENTERGY OPERATIONS INC.,
REPRESENTATIVES CONCERNING REQUEST FOR ADDITIONAL INFORMATION PERTAINING TO THE ARKANSAS NUCLEAR ONE, UNIT 2 LICENSE RENEWAL APPLICATION (TAC NO. MB8402)
On August 26 and September 1, 2004, the U.S. Nuclear Regulatory Commission (NRC) staff and representatives of the Entergy Operations Inc., held telephone conference calls to discuss formal responses to the request for additional information (RAI) pertaining to the technical review for the Arkansas Nuclear One, Unit 2 license renewal application.
These conference calls were used to clarify the staffs position with respect to certain responses to RAIs. On the basis of the discussion, the applicant agreed to modify and/or supplement several responses. provides a listing of the telephone conference call participants. Enclosure 2 contains a listing of the RAIs, formal responses from the applicant, and a brief description of the status of each item. A copy of this summary was provided to the applicant for comment.
/RA/
Gregory F. Suber, Project Manager License Renewal Section A License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket No.: 50-368
Enclosures:
As stated Adams Accession no.: ML042740651 C:\\ORPCheckout\\FileNET\\ML042740651.wpd OFFICE:
PM:RLEP LA:RLEP SC:RLEP NAME:
GSuber MJenkins SLee DATE:
09/29/04 09/23/04 09/30/04 OFFICIAL RECORD COPY
DISTRIBUTION: Licensee: Entergy Operations, Inc. Re: ANO-2, Dated: September 30, 2004 ADAMS Accession No.: ML042740651 HARD COPY RLEP RF G. Suber (PM)
E-MAIL:
RidsNrrDrip RidsNrrDe G. Bagchi K. Manoly W. Bateman J. Calvo R. Jenkins P. Shemanski J. Fair RidsNrrDssa RidsNrrDipm D. Thatcher R. Pettis G. Galletti C. Li M. Itzkowitz (RidsOgcMailCenter)
R. Weisman M. Mayfield A. Murphy S. Smith (srs3)
S. Duraiswamy Y. L. (Renee) Li RLEP Staff R. Gramm A. Howell T. Alexion L. Smith RIV R. Nease RIV LIST OF PARTICIPANTS TELEPHONE CALLS WITH ENTERGY OPERATIONS, INC.
ARKANSAS NUCLEAR ONE, UNIT 2 LICENSE RENEWAL APPLICATION August 26 and September 1, 2004 Participants Affiliation Natalie Mosher Entergy Operations, Inc. (Entergy)*
Alan Cox Entergy Michael Stroud Entergy Garry Young Entergy Kerry Gaston Entergy Ted Ivy Entergy Reza Ahrabli Entergy**
Lori Potts Entergy Gregory Suber U.S. Nuclear Regulatory Commission (NRC)
Richard McNally NRC Shiu-Wing Tam Argonne National Laboratory**
- Did not participate in September 1, 2004 call.
- Did not participate in August 26, 2004 call.
REQUEST OF ADDITIONAL INFORMATION FOR ANO-2 LICENSE RENEWAL APPLICATION RAI 3.3-1 LRA Tables 3.3.2 5 and 3.3.2-11 identify cracking fatigue as an aging effect requiring aging management, but LRA Section 4.3.2 states that, Engineering evaluations identified no non-Class 1 pressure vessels, heat exchangers, storage tanks or pumps requiring evaluation for thermal fatigue. The applicant credits the Periodic Surveillance and Preventive Maintenance Program for managing this aging effect in the chemical volume control system (CVCS) pump casing and the system walkdown aging management program for various components in miscellaneous systems in scope for Title 10 of the Code of Federal Regulations Part 54.4(a)(2) (10CFR) 10 CFR54.4(a)(2). Clarify the type of fatigue managed by these inspections, the basis for these inspections in lieu of a time-limited aging analysis (TLAA) and explain how the inspections are effective in detecting internal cracks prior to loss of the intended function, including operating experience.
Applicants Response
- 1. Type of fatigue: For the CVCS pump casing (charging pumps), as identified in LRA Table 3.3.2-5, cracking due to high-cycle fatigue (as a result of deflection of the plunger cap during a pump cycle) is the aging effect identified. For the components in miscellaneous systems in scope for 10CFR54.4(a)(2), as identified in LRA Table 3.3.2-11, the aging effect managed is cracking due to thermal fatigue.
- 2. Basis for inspections in lieu of a TLAA: In reference to Table 3.3.2-5, cracking of the charging pump plunger cap (pump casing) was discovered during plant operation and documented in the Corrective Action Program. Neither an analysis involving time-limited assumptions defined by the current operating term nor a requirement for such an analysis was found for this condition during the identification of TLAAs for license renewal. Components in LRA Table 3.3.2-11 are generally nonsafety related components designed in accordance with the American Society of Mechanical Engineers B.31.1 with an implicit analysis limit of 7000 thermal cycles. Cracking due to thermal fatigue was conservatively identified as an aging effect requiring management although it is not expected to occur. If cracking due to thermal fatigue were to occur, the System Walkdown Program would manage this aging effect as described in Part 3 of this response.
- 3. Effectiveness of inspections: For the charging pump plunger cap, a preventive maintenance task exists to disassemble and inspect the charging pumps and plungers.
Operating experience has shown this inspection to be effective in identifying the effects of aging prior to loss of system function. For components in LRA Table 3.3.2-11, system walkdowns detect leakage and spray from liquid-filled systems. Industry operating experience has shown that age-related failures of nonsafety-related structures, systems, and components, (SSCs) containing steam or liquid that could prevent safety-related components from accomplishing their safety function have only occurred as a result of loss of material due to flow accelerated corrosion (FAC), which is managed by the FAC Program. Leakage from causes other than FAC has been limited in extent such that it has been identified and corrected through normal operational activities or system walkdowns prior to loss of system functions. For further information on how the System Walkdown Program is effective in managing this aging effect see response to RAI 3.3.2.4.11-1.
Staffs Comment This item concerns the use of a condition monitoring program to manage fatigue cracking in the chemical volume control system (CVCS) charging pumps rather than a TLAA used for other CVCS components. The applicants response to RAI 3.3-1 clarifies that the type of fatigue is high-cycle fatigue (rather than thermal) and a requirement for a TLAA does not exist. The applicant states that the preventative maintenance has been effective in identifying aging effects prior to loss of system function. The 1989 ASME Section III Code NC-3454.4 states that, for reciprocating pumps, the liquid cylinder and bolting are exposed to significant fatigue loadings, but a specific fatigue analysis is not required. Since a requirement for a TLAA does not exist, the use of the PSPM Program appears to be appropriate to detect and correct cracking. However, the PSPM aging management program B.1.18 and aging management review Table 3.3.2-5 do not address fatigue-cracking in the charging pump bolting and the PSPM does not address fatigue-cracking in the casing. The applicant is requested to clarify how the PSPM or other aging management programs manage fatigue cracking in the charging pump casing and bolting.
Applicants Clarification Fatigue-cracking of the charging pump block (casing) occurred in the early 1990s at ANO-2.
As a result of this cracking, the pump block design was modified to incorporate features that increase resistance to fatigue cracking such as enlarged radii at the bore intersection and shotpeening. Since the design change was implemented, there have been no instances of charging pump block cracking which provides evidence that the condition has been corrected.
Cracking of charging pump bolting was not identified in the operating experience review and as such was not identified as an aging effect requiring management.
Based on operating experience, cracking due to fatigue was not identified in the LRA as an aging effect requiring management for the charging pump block or bolting.
Additional Staff Comment The applicants draft response submitted by e-mail dated August 10, 2004, clarified that fatigue cracking in the charging pump block (casing) occurred in the early 1990's at ANO-2. The applicant states that the pump block design was modified and since the design change was implemented, there have been no instances of charging block cracking which provides evidence that the condition has been corrected. With regards to bolting, the applicant states that cracking of charging pump bolting was not identified in the operating experience review and as such was not identified as an aging effect requiring management. The applicant concludes that, based on operating experience, cracking due to fatigue was not identified in the LRA as an aging effect requiring management for the charging pump block or bolting.
The response requires additional clarification. The LRA identifies fatigue-cracking in the CVCS pump casing is managed by the periodic surveillance and preventive maintenance program, however, LRA Appendix B.1.18 does not identify fatigue-cracking for the CVCS pumps. The applicant clarification states that, based on operating experience, fatigue was not identified as an aging effect for the charging pump block bolting. The staff recognizes that various industry experience with reciprocating type pumps shows that fatigue is plausible for CVCS charging pumps. The ASME Section III Code identifies that, for reciprocating type pumps, the liquid cylinder and pressure retaining bolting are exposed to significant fatigue loadings. GALL Item VII E1.5.1 and E1.5.2 identify crack initiation and growth/cracking in the high pressure pump casing and closure bolting in the CVCS. The Calvert Cliffs LRA Section 5.2 identifies operating experience with fatigue failures in the CVCS piping and considers fatigue to be plausible for the charging pump block and bolts in that these components are subject to significant transients, including high or low cycle vibration, thermal cycles and pressure cycles. The ANO-1 LRA Appendix C Section 9.3.3 also identifies cracking of bolting materials caused by fatigue as an aging effect. The applicant is requested to clarify if pump casing and bolting in the CVCS are susceptible to fatigue-cracking and, if they are, to update the periodic surveillance and preventive maintenance program to include inspection criteria for fatigue-cracking. If CVCS pumps are not subject to fatigue-cracking, the applicant is requested to provide the technical justification considering the ASME Code/industry experience and clarify why LRA Table 3.3.2-5 identifies fatigue-cracking as an applicable aging effect for the CVCS pump casing managed by the periodic surveillance and preventive maintenance program. Also, if after further review, cracking-fatigue will be considered an appropriate aging effect in CVCS pump bolting, the applicant is requested to clarify which program will manage this aging effect.
Applicants Response Charging pump casing Cracking of the charging pump casing was identified as an aging effect requiring management in LRA Table 3.3.2-5 for the charging pump plunger cap since operating experience indicated that cracking due to fatigue of the plunger cap is a credible failure mechanism. Although cracking due to fatigue of the charging pump block was not identified as a likely failure mechanism, the pump block will be periodically inspected for indications of cracking.
Consistent with our clarification response on Page 8 of 2CAN070409, the periodic surveillance and preventive maintenance program will manage cracking of the charging pump plunger cap and block.
Parameters monitored During maintenance inspections, plunger caps and block are visually inspected for indications of cracking.
Detection of aging effects Inspections for wear or damage, including cracking, are performed on any parts removed and the pump cylinder bore during maintenance.
Acceptance criteria Indications of cracking will result in additional NDE (such as dye penetrant tests) and replacement of the affected component if cracking is confirmed.
Charging Pump Bolting Industry guidance, EPRI 1003056 (The Mechanical Tools), which was the source for Appendix C of the ANO-1 License Renewal Application, states that cracking of bolting may be attributed to stress corrosion cracking and/or fatigue. It further states that fatigue cracking of bolting due to high cycle fatigue is not a concern for license renewal since it would be discovered during the current license period in most cases where systems are frequently operated. Since the CVCS charging pumps have been operated for over 25 years with no operating experience indicating fatigue cracking of charging pump bolting, cracking due to fatigue of the charging pump bolting is not an aging effect requiring management.
Status The applicant agreed to revise its response to include the information on the CVCS pump casing and to modify the discussion on CVCS pump bolting to address fatigue cracking.
RAI 3.3-2 The LRA aging management evaluation credits the Water Chemistry Control Program for managing aging effects for various components in the auxiliary systems, but it is not clear which specific subprogram is used to manage each component. Clarify which subprogram manages each auxiliary system component. Also, identify any additional inspection programs such as one-time inspections that will be used to verify the effectiveness of the Chemistry Control Program. Provide a description of the elements of the inspection program as defined in Appendix A.1 of the Standard Review Plan - License Renewal including details such as inspection methods, how susceptible locations are determined, basis for inspection population and sample size, timing, acceptance criteria including codes and standards, and operating experience. LRA Table B-1 identifies that one time inspections are not applicable. If periodic inspections are planned rather than one time inspections, identify the frequency. If opportunistic inspections are planned rather than one time inspections, how does the program assure that the inspections will be completed prior to the end of the existing operating license?
Identify any specific operating experience (i.e., inspection results) relevant to inspections to verify effective chemistry control in auxiliary systems that demonstrate the effectiveness of the inspection program.
Applicants Response a) The water chemistry control programs manage aging effects for various components in the auxiliary systems.
Components in Table 3.3.2-1, Spent Fuel Pool System, and Table 3.3.2-5, Chemical and Volume Control System, that list water chemistry control as the program are included in the Primary and Secondary Water Chemistry Control Program.
Components in Table 3.3.2-3, Emergency Diesel Generator (EDG) System, and Table 3.3.2-4, Alternate AC (AAC) Diesel Generator System, that list water chemistry control as the program are included in the Auxiliary Systems Cooling Water Chemistry Control Program.
Components in Table 3.3.2-11, Miscellaneous Systems in Scope for 10 CFR54.4(a)(2), that list water chemistry control as the program are included in the program that applies to the system in which the component resides. Since all of the water chemistry control subprograms provide reasonable assurance that the aging effect loss of material will be managed such that the applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation, the particular subprogram for a specific component is beyond the level of detail necessary in the table.
b) The effectiveness of the water chemistry programs at ANO-2 has been confirmed through routine component inspections that are performed by chemistry, maintenance and engineering personnel. This includes the Primary and Secondary, Closed Cooling, and Auxiliary Systems Water Chemistry Programs. These inspections were performed when primary and secondary systems were opened for maintenance, when an adverse chemistry trend existed, or when requested by the chemistry or engineering departments. The areas inspected have included areas that are susceptible to the aging effects identified in the license renewal application. In addition, for many reactor coolant system components included in the Primary and Secondary Water Chemistry Control Program, inspection activities within other aging management programs provide additional confirmation of chemistry program effectiveness. These other programs include the Inservice Inspection, Alloy 600 Aging Management, Cast Austenitic Stainless Steel Evaluation, Pressurizer Examinations, Reactor Vessel Internals Inspection, and Steam Generator Integrity Programs. Some components, such as heat exchangers, have been inspected periodically providing repetitive evidence that the water chemistry programs are adequately managing aging effects. If, during these inspections significant abnormal conditions were noted, including those that were the result of aging effects such as loss of material and cracking, these conditions would have been documented under the Corrective Action Program. Actions to determine the cause of the condition and corrective actions to prevent recurrence would have then been taken.
The Generic Aging Lessons Learned (GALL) One Time Inspection Program XI.M32 focuses on the most susceptible material and environment combinations in the most susceptible locations. Items such as heat exchangers, piping and valves normally in standby, and system low points or stagnant areas are representative of these susceptible locations. At ANO-2, inspections have been performed in systems such as emergency feedwater (EFW) and EDGs which are normally in standby, steam generators, condensate storage tanks, feedwater heaters, moisture separator reheaters, chillers, main steam safety valves, and blowdown heat exchangers. All of these components are made of susceptible materials (stainless and carbon steel) and are exposed to environments (treated water and steam) that would be conducive to aging effects managed by the water chemistry programs.
Many components in the steam generators are inspected under other aging management programs that provide additional assurance that significant degradation is not occurring and that the Primary and Secondary Water Chemistry Control Program is effective. These inspection activities include those contained in the Inservice Inspection and Steam Generator Integrity Programs. The inspection results of steam generator components are also applicable to the main steam, main feedwater and EFW components with the same material and environment combinations.
As additional confirmation of the effectiveness of water chemistry programs, the ANO-2 review of operating experience included a review of condition reports (CRs), CR trending data, and interviews with site personnel regarding water chemistry program operating experience. The operating experience review did not identify component failures or significant adverse conditions that were the result of an ineffective water chemistry program. Also, the CR trending data did not identify recurrent component degradation occurring in the systems covered under this aging management program. The review of CRs, CR trending data, and personnel interviews provided additional confirmation of chemistry program effectiveness.
The combination of inspections under the Inservice Inspection Program, the Steam Generator Integrity Program, and maintenance and routine chemistry inspections as a whole, constitute a more thorough confirmation of water chemistry aging management program effectiveness than could be obtained from one-time inspections of a sample of items.
Staffs Comment This item relates to the application of water chemistry control subprograms to specific systems.
The applicants response should address the following:
The response identifies that effectiveness of the water chemistry programs has been confirmed through routine component inspections, including the auxiliary systems water chemistry programs. The response also states that a combination of the ISI Program, Steam Generator Integrity Program, and maintenance and routine chemistry inspections, as a whole, constitute a more thorough confirmation of the chemistry aging management program effectiveness than could be obtained from the one-time inspections of a sample of items. The Staff questions the applicability of the Steam Generator Integrity Program to auxiliary systems and the ISI Program inspections for auxiliary systems may be limited to external surface inspections. It is not clear if the internal chemistry inspections include auxiliary system components or if these inspections are representative of auxiliary system chemistry. Where only opportunistic inspections are used to manage internal surfaces of auxiliary systems containing treated water, it is not clear how these inspections represent an adequate sample size or will be completed prior to the period of extended operation. The applicant is requested to clarify whether auxiliary system inspections are limited to opportunistic inspections and explain how the ANO-2 chemistry program verification inspections provide an appropriate sample size required by the Generic Aging Lessons Learned (GALL) one-time inspection program. The applicant is also requested to clarify how the chemistry verification inspections will be completed prior to the period of extended operation. Alternatively, the applicant may consider the application of planned maintenance inspections for auxiliary systems such as the PSPM Program or the use of future one-time inspections consistent with GALL.
Applicants Clarification While many auxiliary system inspections are opportunistic inspections during maintenance, some are performed periodically, as discussed below.
The following auxiliary system material and environment groups credit water chemistry control programs.
- 1. Carbon steel exposed to treated water:
This group includes emergency diesel generator (EDG) turbochargers, standby coolant heater housings, coolant orifices, piping, coolant pump casings, coolant expansion tanks, tubing, and coolant valve bodies. It includes the radiator, jacket water heater housing, piping, coolant pumps, coolant expansion tank, tubing and valve bodies associated with the alternate alternating current (AC) diesel generator. As described in the 10 CFR 54.4(a)(2) report, the group also includes the letdown heat exchanger shell and nonsafety-related carbon steel components exposed to treated water in the auxiliary building heating and ventilation, chilled water, component cooling water, domestic water, main feedwater, plant heating, sampling, auxiliary steam, blowdown, emergency feedwater (EFW), main steam, primary sampling and steam generator secondary systems. The Closed Cooling Water Chemistry Control Program manages loss of material for components in the diesel generator, alternate AC diesel and component cooling water systems. The Primary and Secondary Water Chemistry Control Program manages loss of material for components in the main feedwater, blowdown, EFW, main steam, primary sampling and steam generator secondary systems. The Auxiliary Systems Water Chemistry Control Program manages loss of material for components in the auxiliary building heating and ventilation, chilled water, domestic water, plant heating, sampling, and auxiliary steam systems.
Several components in the group were visually inspected during maintenance. The four EDG turbochargers were disassembled and inspected in 1999, an EDG standby coolant circulation pump was inspected in 2004, both EDG jacket water pumps were inspected in 2004, and the air cooler coolant pumps were inspected in 1994 and 2002. All of these components are exposed to stagnant conditions when the EDGs are in standby. Also, the letdown heat exchanger shell was examined in 1997 and 2000. During these inspections, evidence of loss of material was not observed. Since components in the group are exposed to the same environment, the condition of the inspected components is representative of the condition of the other components.
Additional components with this same material and environment are described in LRA Section 3.1, Reactor Vessel, Internals and Reactor Coolant System; Section 3.2, Engineered Safety Features (ESF); and Section 3.4, Steam and Power Conversion Systems. Inspections of components with this material and environment under the ISI, Steam Generator Integrity, and PSPM Programs and during maintenance and chemistry inspections provide further evidence that the water chemistry control programs manage loss of material for carbon steel components exposed to treated water.
Therefore, the effectiveness of the water chemistry control programs to manage loss of material for carbon steel components exposed to treated water has been confirmed.
- 2. Cast iron exposed to treated water:
This group includes emergency diesel generator temperature regulating valve bodies, alternate AC diesel generator temperature regulating valve bodies, and the alternate AC diesel generator jacket water heater pump casing. The Closed Cooling Water Chemistry Control Program manages loss of material for these components.
LRA Tables 3.3.2-3 and 3.3.2-4 indicate that loss of material for the temperature regulating valve bodies is also managed by the PSPM Program. This program confirms that the Closed Cooling Water Chemistry Control Programs is effectively managing loss of material for these components. The PSPM Program has not identified evidence of loss of material on the valve bodies.
Since they are exposed to the same environment and the pump is newer (replaced in 2002 due to design problems), the condition of the temperature regulating valve bodies is representative of the condition of the alternate AC diesel generator jacket water heater pump casing.
Therefore, the effectiveness of the Closed Cooling Water Chemistry Control Program to manage loss of material for cast iron components exposed to treated water has been confirmed.
- 3. Copper alloy exposed to treated water:
This group includes the EDG air coolers, jacket water heat exchangers, air coolant heat exchangers, associated tubing and valves. It includes the alternate AC diesel generator after-cooler heat exchanger and components in the engine cooling water sub-system. As described in the 10 CFR54.4(a)(2) report, the group also includes the nonsafety-related copper alloy components exposed to treated water in the auxiliary building heating and ventilation, chilled water, component cooling water, condensate storage and transfer, domestic water, and plant heating systems. The Closed Cooling Water Chemistry Control Program manages loss of material for components in the diesel generator, alternate AC diesel and component cooling water systems. The Auxiliary Systems Water Chemistry Control Program manages loss of material for components in the auxiliary building heating and ventilation, chilled water, condensate storage and transfer, domestic water, and plant heating systems.
The water chemistry control programs manage fouling for the EDG jacket water cooler and air coolant heat exchanger tubes. LRA Table 3.3.2-3 indicates that fouling of these heat exchangers is also managed by the Service Water Integrity Program. This aging management program confirms the effectiveness of the water chemistry control programs in managing fouling.
The water chemistry control programs manage fouling for the EDG air cooler tubes. LRA Table 3.3.2-3 indicates that fouling of these heat exchangers is also managed by the PSPM Program.
This aging management program confirms the effectiveness of the water chemistry control programs in managing fouling.
Several components in the group were visually inspected during maintenance. For example, the jacket water and air coolant heat exchangers on the A EDG were disassembled and inspected in 1991. Also, the EDG air coolers have been disassembled and inspected - the most recent one in 2000. These components are exposed to stagnant conditions when the EDGs are in standby. During these inspections, evidence of loss of material was not observed.
Since components in the group are exposed to the same environment, the condition of the inspected components is representative of the condition of the other components.
Therefore, the effectiveness of the Closed Cooling and Auxiliary Systems Water Chemistry Control Program to manage loss of material for copper alloy components exposed to treated water has been confirmed.
- 4. Stainless steel exposed to treated borated water:
This group includes the spent fuel racks, the fuel transfer tube, piping and valves in the spent fuel system. It also includes charging and boric acid makeup pumps casings, boric acid makeup tanks, pulsation dampeners, piping, thermowells, tubing and valves in the CVCS. As described in the 10 CFR54.4(a)(2) report, the group also includes the nonsafety-related stainless steel components exposed to treated borated water in the boron management, containment spray, chemical and volume control, low pressure safety injection, post accident sampling, primary sampling, reactor coolant pump, reactor coolant, and shutdown cooling systems. The Primary and Secondary Water Chemistry Control Program manages the aging effects of cracking and loss of material for these components.
The charging pumps and their suction and discharge pulsation dampeners are inspected under the PSPM Program. Other components in the group were visually inspected during maintenance. For example, the boric acid makeup pumps were inspected, one in 1999, the other in 2000. The fuel transfer tube isolation valve was inspected in 1996 and 2002. During these inspections no evidence of cracking or loss of material attributable to poor water quality was observed. Since all components in the group are exposed to the same environment, the condition of the inspected components is representative of the condition of the other components.
Additional components with this same material and environment are described in LRA Section 3.1, Reactor Vessel, Internals and Reactor Coolant System, and Section 3.2, Engineered Safety Features (ESF). Inspections of components with this material and environment under the ISI, Steam Generator Integrity, and PSPM Programs and during maintenance and chemistry inspections provide further evidence that the Primary and Secondary Water Chemistry Control Program manages cracking and loss of material for stainless steel components exposed to treated borated water.
Therefore, the effectiveness of the Primary and Secondary Water Chemistry Control Program to manage cracking and loss of material for stainless steel components exposed to treated borated water has been confirmed.
- 5. Stainless steel exposed to treated water:
This group includes EDG cooling water piping, thermowells, tubing and valves; alternate AC diesel generator cooling water expansion joints, orifices, thermowells, tubing and valves; and piping, tubing and valves in the containment demineralized and makeup water supply lines. As described in the 10CFR54.4(a)(2) report, the group also includes nonsafety-related stainless steel components exposed to treated water in the chilled water, auxiliary steam, blowdown, component cooling water, condensate storage and transfer, EFW, fuel pool cooling, main steam, plant heating, primary sampling, reactor coolant, and sampling systems. The Closed Cooling Water Chemistry Control Program manages loss of material for components in the diesel generator, alternate AC diesel and component cooling water systems. The Primary and Secondary Water Chemistry Control Program manages loss of material for components in the blowdown, emergency feedwater, fuel pool cooling, main steam, primary sampling, and reactor coolant systems. The Auxiliary Systems Water Chemistry Control Program manages loss of material for components in the chilled water, auxiliary steam, condensate storage and transfer, plant heating, and sampling systems.
Components in this group were visually inspected during maintenance. A containment demineralized water supply valve and an EDG expansion tank fill valve were disassembled and inspected in 1999. Also, two EDG expansion tank drain valves were disassembled and inspected in 2004. These components are exposed to stagnant conditions when the EDGs are in standby. During these inspections, evidence of loss of material was not observed. Since components in the group are exposed to the same environment, the condition of the inspected components is representative of the condition of the other components.
Additional components with this same material and environment are described in LRA Section 3.4, Steam and Power Conversion Systems. Inspections of steam and power conversion system components with this material and environment under the Flow-Accelerated Corrosion and PSPM Programs and during maintenance and chemistry inspections provide further evidence that the water chemistry control programs manage cracking and loss of material for stainless steel components exposed to treated water.
Therefore, the effectiveness of the water chemistry control programs to manage loss of material for stainless steel components exposed to treated water has been confirmed.
- 6. Aluminum exposed to treated water:
As described in the 10 CFR 54.4(a)(2) report, this group includes one nonsafety related valve body in the component cooling water system which was installed in 1998. The Closed Cooling Water Chemistry Control Program manages loss of material for this component.
The component has not been inspected to verify effectiveness of the Closed Cooling Water Chemistry Control Program to manage loss of material for the aluminum component exposed to treated water. However, as indicated in Item 1, the effectiveness of the Closed Cooling Water Chemistry Control Program to manage loss of material for carbon steel components exposed to treated water has been confirmed. Since aluminum has better corrosion resistance than carbon steel, it is reasonable to assume that the Closed Cooling Water Chemistry Control Program would also be effective in managing loss of material for the aluminum component exposed to treated water.
Inspections that verify the effectiveness of the water chemistry control programs have already been completed. These inspections have confirmed the effectiveness of water chemistry control programs in managing the effects of aging on auxiliary system components.
Additional Staff Comment The applicants draft response submitted by e-mail dated August 10, 2004, clarified that, although many auxiliary systems are opportunistic inspections during maintenance, some are performed periodically. The applicant identified various periodic verification inspections of auxiliary system components including the PSPM Program, the chemistry inspections and the service water integrity program. The applicant also identified specific recent inspections, including components exposed to stagnant conditions, that have been performed for each auxiliary system material/environment group and additional inspections from other systems that are considered representative of the material/environment group. Therefore, the applicant concludes that the effectiveness of the water chemistry control programs has been confirmed.
The LRA shows the majority of AMR components in a treated water environment do not have a chemistry verification inspection and the response does not answer the question regarding an appropriate sample size addressed in industry documents such as the GALL one-time inspection program and NEI 95-10 Section 4.3. The staff questions that the limited sample of auxiliary system components inspected may have not been sufficient to conclude that the effectiveness of the water chemistry programs has been confirmed and additional inspections may be required. The applicant is requested to provide technical justification that an adequate sample size has been or will be selected prior to period of extended operation on the basis of industry criteria/operating experience.
Applicants Response The sample of components inspected is sufficient to conclude that the effectiveness of the water chemistry programs has been confirmed and additional inspections are not required. The inspections identified are an adequate sample on the basis of industry criteria and operating experience.
Industry criteria are as follows.
NUREG-1801 One-Time Inspection Program states,
The inspection includes a representative sample of the system population, and, where practical, focus [sic] on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin.
NEI 95-10 states,
A sample consists of one or more structures or components drawn from the scope. The applicant must determine a sample size that is adequate to provide reasonable assurance that the effects of aging on the structure or component population will not prevent the performance of intended functions during the period of extended operation. The size of the sample should include consideration of the specific aging effect, location, existing technical information, materials of construction, service environment, previous failure history, etc. The sample should be biased toward locations most susceptible to the specific aging effect of concern.
ANO-2 auxiliary systems contain five groups of components that credit water chemistry control programs.
- 2. cast iron exposed to treated water
- 3. copper alloy exposed to treated water
- 4. stainless steel exposed to treated borated water
- 5. stainless steel exposed to treated water
- Group 1 contains one aluminum component which was installed recently (1998). Because aluminum has better corrosion resistance than carbon steel, conditions identified in inspections of carbon steel components bound the condition of the aluminum component.
The sample for each of the five groups includes components that are subject to loss of material; components made of the same material; and components exposed to the same, or a harsher, service environment. The samples include bounding components in stagnant or low flow areas, where loss of material is more likely and are representative of components in most susceptible locations.
Operating experience has shown that loss of material is more likely in softer materials such as carbon steel, cast iron, and copper alloys. Three of the five sample groups include these materials.
Operating experience has also shown that loss of material is more likely in stagnant or low flow areas. The samples for each of the five auxiliary system groups include items such as heat exchangers, piping and valves normally in standby, and system low points or stagnant areas which are the most susceptible locations.
The ANO-2 review of operating experience included a review of condition reports (CRs), CR trending data, and interviews with site personnel regarding water chemistry program operating experience. The operating experience review did not identify component failures or significant adverse conditions that were the result of an ineffective water chemistry program. Also, the CR trending data did not identify recurrent component degradation occurring in the systems covered under this aging management program.
Since the identified inspections address all industry criteria and operating experience, they are an adequate sample on the basis of industry criteria/operating experience. Therefore, the sample of components inspected is sufficient to conclude that the effectiveness of the water chemistry programs has been confirmed and additional inspections are not required.
Status The staff requested additional information on the number of samples and the number of inspections conducted in lieu of the of the one-time inspection recommended by GALL. The applicant agreed to revise its response to provide this information and submit it formally.
RAI 2.3.3.4-1 SAR Section 8.3.3, Alternate AC Power Source, states that the engine generator set has Class F insulation. The insulated piping is shown on license renewal drawing LRA-M-2241, sheet 2 as not being subject to aging management review. Briefly state the basis for excluding this insulation (e.g., system efficiency, heat load calculations, environmental qualification (EQ) purposes, etc.) The insulation is passive and long-lived and should be subject to an aging management review in accordance with the requirements of 10 CFR 54.21(a)(1) if it is relied upon for EQ purposes. Verify whether the Class F insulation is subject to an aging management review.
Applicants Response SAR Section 8.3.3 states that the generator has Class F insulation. This refers to the insulation on the generator windings not to piping insulation. As part of the alternate AC generator system, the generator and the piping are in the scope of license renewal. However, the generator with its associated insulation is an active component that is not subject to aging management review. The insulation shown on exhaust piping on the referenced drawing though not specifically highlighted is subject to aging management review. This insulation is indoors and hence, is protected from the weather. A review of ANO-2 operating experience verified that the plant has not experienced aging-related degradation of piping insulation in indoor environments. Therefore, based on operating experience, there are no aging effects requiring management for indoor insulation at ANO 2. This is consistent with NUREG-1705, which states: The staff concludes that, even if the chemical volume control system relied on the insulation to perform any accident mitigation functions, there are no plausible aging effects for the insulation that would warrant an aging management program.
Staffs Comment The staff finds the applicants response to RAI 2.3.3.4-1, for the insulation on the exhaust piping, which is in scope and subject to an AMR, to be pending the review of the AMR and the revision of LRA Tables 2.3.3.4-2 and 3.3.2-4 with component type insulation.
Applicants Clarification The applicant stated that the insulation on the emergency diesel generator exhaust piping is made of fiberglass and covered with netting. The insulation is indoor and exposed to ambient temperature and humidity. Ventilation in the building is facilitated by a damper system.
Moisture condensation on the surface of the insulation is not likely since the insulation temperature would be in equilibrium with the air temperature during idle periods and greater than the air temperature during operation. Consequently, there are no aging effects identified for the exhaust piping insulation in a dry, indoor environment.
Status No addition information is required at this time.
Arkansas Nuclear One, Unit 2 cc:
Executive Vice President
& Chief Operating Officer Entergy Operations, Inc.
P. O. Box 31995 Jackson, MS 39286-1995 Director, Division of Radiation Control and Emergency Management Arkansas Department of Health 4815 West Markham Street, Slot 30 Little Rock, AR 72205-3867 Winston & Strawn 1400 L Street, N.W.
Washington, DC 20005-3502 Mr. Mike Schoppman Framatome ANP, Richland, Inc.
Suite 705 1911 North Fort Myer Drive Rosslyn, VA 22209 Senior Resident Inspector U.S. Nuclear Regulatory Commission P. O. Box 310 London, AR 72847 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-8064 County Judge of Pope County Pope County Courthouse Russellville, AR 72801 Vice President, Operations Support Entergy Operations, Inc.
P. O. Box 31995 Jackson, MS 39286-1995 Wise, Carter, Child & Caraway P. O. Box 651 Jackson, MS 39205 Garry Young 1448 SR 333 Russellville, AR 72802 Mr. Fred Emerson Nuclear Energy Institute 1776 I St., N.W., Suite 400 Washington, DC 20006-3708 Mr. Jeffrey S. Forbes Site Vice President Arkansas Nuclear One Entergy Operations, Inc.
1448 S. R. 333 Russellville, AR 72801