ML15112A449
| ML15112A449 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/08/1999 |
| From: | Joseph Sebrosky NRC (Affiliation Not Assigned) |
| To: | Mccollum W DUKE POWER CO. |
| References | |
| NUDOCS 9904160008 | |
| Download: ML15112A449 (21) | |
Text
April 8, 1999 Mr. William R. McCollum, Jr.
Vice President, Oconee Nuclear Site Duke Ehergy Corporation P. 0. Box 1439 Seneca, SC 29679
SUBJECT:
POTENTIAL SAFETY EVALUATION REPORT (SER) OPEN ITEMS REGARDING THE REVIEW OF THE OCONEE NUCLEAR STATION, UNITS 1, 2, AND 3, LICENSE RENEWAL APPLICATION
Dear Mr. McCollum:
As you are aware, the Nuclear Regulatory Commission (NRC) staff is in the process of writing the SER for the Oconee license renewal application. The staff expects to issue this SER on June 17, 1999. At this time the staff has identified potential open items for the SER. In an effort to minimize the amount of SER open items it has been decided that the potential open items list will be made available to you (See Enclosure). The staff will support phone calls and meetings in an attempt to resolve as many of the open items as possible prior to issuing the SER. The aim of this process is to minimize the amount of SER open items without impacting the schedule for issuing the SER. It should be noted that the enclosed list represents the staff's potential open items as of this date. During the preparation of the SER, additional open items may be identified. To the extent it is practical, the staff will notify Duke of these additional open items and attempt to close the items prior to issuing the SER.
The potential SER open items in the Enclosure have the original request for additional information (RAI) number for reference. There are cases where an open item has been identified that is not associated with a previous RAI. For tracking purposes, new numbers have been assigned to these open items. In addition, the word "new" appears in parentheses after the number. Unlike the first round of RAls, Duke is not expected to provide answers to all the open items in the Enclosure. Rather, to the extent that the staff and Duke resolve issues, the issue resolution will be documented in a phone call summary, meeting summary, or in a letter from Duke. If an issue is not resolved it will be carried forward in the SER as an open item.
Sincerely, Joseph M. Oeraln Manager License Renewal Standardization Branch Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket Nos. 50-269, 50-270, and 50-287
Enclosure:
Potential SER Open Items cc w/encl: See next page DISTRIBUTION:
See next page
- See previous concurrence DOCUMENTNAME:G:\\SEBROSKY\\SEROL.WPD OFFICE LA RLSB/DRIP:PM RLSB/DRIP:BC NAME EHylton JSebrosky ClGrime DATE 04/7/99*
04/,99 04/0/99 OFFICIAL RECORD COPY
- 9046008 994006 PDR ADOCK 05000269 P
- PDR
Oconee Nuclear Statio*cense Renewal) cc:
Ms. Lisa F. Vaughn Duke Energy Corporation Mr. J. E. Burchfield 422 South Church Street Compliance Manager Mail Stop PB-05E Duke Energy Corporation Charlotte, North Carolina 28201-1006 Oconee Nuclear Site P. 0. Box 1439 Anne W. Cottingham, Esquire Seneca, South Carolina 29679 Winston and Strawn 1400 L Street, NW.
Ms. Karen E. Long Washington, DC 20005 Assistant Attorney General North Carolina Department of Justice Mr. Rick N. Edwards P. O. Box 629 Framatome Technologies Raleigh, North Carolina 27602 Suite 525 1700 Rockville Pike L. A. Keller Rockville, Maryland 20852-1631 Manager - Nuclear Regulatory Licensing Duke Energy Corporation Manager, LIS 526 South Church Street NUS Corporation Charlotte, North Carolina 28201-1006 2650 McCormick Drive, 3rd Floor Clearwater, Florida 34619-1035 Mr. Richard M. Fry, Director Division of Radiation Protection Senior Resident Inspector North Carolina Department of U. S. Nuclear Regulatory Commission Environment, Health, and 7812B Rochester Highway Natural Resources Seneca, South Carolina 29672 3825 Barrett Drive Raleigh, North Carolina 27609-7721 Regional Administrator, Region 11 U. S. Nuclear Regulatory Commission Gregory D. Robison Atlanta Federal Center Duke Energy Corporation 61 Forsyth Street, SW, Suite 23T85 Mail Stop EC-12R Atlanta, Georgia 30303 P. O. Box 1006 Charlotte, North Carolina 28201-1006 Virgil R. Autry, Director Division of Radioactive Waste Management Robert L. Gill, Jr.
Bureau of Land and Waste Management Duke Energy Corporation Department of Health and Mail Stop EC-12R Environmental Control P. O. Box 1006 2600 Bull Street Charlotte, North Carolina 28201-1006 Columbia, South Carolina 29201-1708 RLGILL@DUKE-ENERGY.COM County Supervisor of Oconee County Douglas J. Walters Walhalla, South Carolina 29621 Nuclear Energy Institute 1776 I Street, NW W. R. McCollum, Jr., Vice President Suite 400 Oconee Site Washington, DC 20006-3708 Duke Energy Corporation DJW@NEI.ORG P. 0. Box 1439 Seneca, SC 29679 Chattooga River Watershed Coalition P. O. Box 2006 Clayton, GA 30525
Distribution:
Hard copy PUBLIC (Docket File RLSB RF N. Dudley, ACRS - T2E26 EHylton.
E-mail R. Zimmerman J. Fair W. Kane P. Shemanski D. Matthews H. Ashar S. Newberry J. Davis C. Grimes B. Elliot C. Carpenter A. Hiser B. Zalcman F. Grubelich J. Strosnider J. Rajan R. Wessman K. Parczewski E. Imbro T. Cheng W. Bateman D. Jeng J. Calvo S. Coffin H. Brammer M. Hartzman T. Hiltz J. Guo G. Holahan T. Collins C. Gratton B. Boger R. Correia R. Latta J. Moore J, Rutberg R. Weisman M. Zobler M. Mayfield S. Bahadur A. Murphy D. Martin W. McDowell S. Droggitis RLSB Staff R. Emch D. LaBarge L. Plisco C. Ogle R. Trojanowski M. Scott C. Julian J. Peralta J. Wilson C. Sochor
Potential Safety Evaluation Report Open Items Regarding the License Renewal Application for Oconee Units 1, 2, and 3 Potential Open Item related to RAI G-1 and 4.13-1 RAI G-1 requested clarification regarding Duke's commitment to extend 10 CFR Part 50, Appendix B requirements for corrective actions, confirmation process, and administrative controls to cover non-safety related structures and components subject to an aging management review (AMR) program. Similarly, RAI 4.13-1 requested a description of the methodology and processes that will be used by Duke to address corrective actions, confirmation process, and administrative controls for non-safety related SSCs subject to an AMR program at Oconee in a manner consistent with the guidance in the SRP.
As described in Duke's RAI response letter to the NRC dated February 17, 1999, in accordance with the provisions of the SRP they have elected to include the non-safety related structures and components in a separate renewal program that is summarized in the FSAR Supplement.
Specifically, Duke stated that the program elements for corrective action, including confirmation, and administrative controls will be clarified for each program that addresses the aging effects on non-safety related structures and components within the scope of license renewal to assure these elements are properly addressed. These updated program elements will be summarized for the applicable programs in the Oconee FSAR.
Therefore, pending the development and implementation of this separate renewal program to address corrective action, confirmation processes, and administrative controls for non-safety related structures and components that are subject to an AMR program, this item is identified as an open item.
RAI 1.5.5-1 This RAI involves the resolution of GSI-190. Duke has referenced the industry studies performed by EPRI to resolve this issue. We have provided NRC staff comments concerning the EPRI reports in a November 2, 1998, letter, to NEI. We had additional discussions with EPRI and NEI regarding the industry response to the staff comments on March 23, 1999. NEI plans to provide a response to the staff comments the week of April 14. This item remains open until either GSI-190 is resolved and the resolution implemented at Oconee, or Duke provides a basis which demonstrates the current licensing basis will be adequately managed through the extended period of operation.
Status: Waiting for NEI submittal Potential Open Item 2-2 (New)
A 10 CFR Part 54 scoping issue was raised during a March 11, 1999, meeting with the staff. In that meeting Duke reiterated its belief that the set of design basis events contained in Chapter 15 of the Oconee updated final safety analysis report (UFSAR) complies with the requirements of 10 CFR 54.4(a)(1) and meets the definition of 10 CFR 50.49(b)(1). The staff does not agree with Enclosure
-2 this position and intends to raise this issue to the license renewal steering committee for resolution. Pending satisfactory resolution of this issue this item will remain an open item.
RAI 2.2-7 In response to RAI Question 2.2-7 on control room radiation monitors, Duke stated that the radiation monitors shown on the OLRP series of drawings (OLRFD-116C-1.1, OLRFD-124B-1.5, OLRFD-133A-1.5) do not support any system intended functions as defined in §54.4(a)(1), (2),
(3), or (b). Therefore, the radiation monitors are excluded from the scope of license renewal.
The staff does not agree with Duke's assessment based on the reasons stated below.
Additionally, Duke needs to address other OLRP series drawings (OLRFD-116J-1.2 for Units 1 and 2 control room and OLRFD-116J-3.2 for Unit 3 control room) showing radiation monitors (1,2RIA-39 and 3RIA-39).
The design basis function of radiation monitors (1,2RIA-39 and 3RIA-39) is stated in FSAR Section 9.4.1.1, Design Bases, which states that "The radiation monitor, RIA-39, has a continuous sample of control room air pumped through the detector. High radiation level and loss of sample flow are annunciated at which time the operator energizes the outside air filter trains. The outside air filter trains act to filter particulate matter from the outside air to minimize uncontrolled infiltration into the Control Room." The continuous radiation monitoring is a safety related function which cautions the control. room operators to manually activate the filtration train of the Control Room Pressurization and Filtration System for Units 1, 2, and 3 control rooms in a given accident conditions to filter outside air for control room intake in order to pressurize them and thus meeting TMI Action Plan Item III.D.3.4, Control Room Habitability, requirements through dose analysis. The continuous radiation monitoring is supported by UFSAR Section 9.4.1.3 which states that "Return air from the Control Room is continuously monitored by a radiation monitor before recirculating back to the Control Room. A high radiation level will alert the operators to energize the outside air filter trains". TMI Action Plan Item Ill.D.3.4 retrofits the requirements of General Design Criterion (GDC) 19, Control Room, during bounding accident conditions and may be required during the severe accidents, transients, or station blackout conditions.
RAI 2.5.8-1 a)
With respect to the component level scoping of the HVAC systems, Duke stated that (1) no heating coils, cooling coils, compressors, valves and air dryers are found within the license renewal portions of the Auxiliary Building Ventilation System and (2) chilled water system components including compressor, valves, and air dryer are not a part of the Control Room Pressurization and Filtration System on Figure 9-24 that is within the scope of license renewal. Duke needs to provide the bases corresponding to 10 CFR 54 requirements that justify the exclusions of these components from the scope of the license renewal.
b)
With respect to the control room pressurization and filtration system cooling function, Duke stated that the chilled water system is not required to support the control room pressurization and filtration system function. Duke needs to provide justification of why the cooling function is not safety-related, and thus, within the scope of license renewal.
-3 Typically, these components are required to conform with TMI Action Plan Item Ill.D.3.4, Control Room Habitability which retrofits the General Design Criterion (GDC) 19, Control Room, requirements during bounding accident conditions and maybe required during severe accidents, transients, or station blackout conditions.
c)
With respect to the component level scoping of the HVAC systems concerning the heating coils and valves, Duke stated that (1) the heating coils are subject to an aging management review and are identified in Table 2.5-13 for the control room pressurization system and (2) valves for the Penetration Room Ventilation System are subject to an aging management review and are listed in Table 2.5-13. Provide clarification of why the above items are not listed in Table 2.5-13 of OLRP -1001 and provide justifications of why the valves are excluded from AMR for the Auxiliary Building Ventilation System and Pressurization and Filtration System.
RAI 2.6-4 Section 2.6.6.1.2 of the application identified insulated cables and connections used for fire detectors as part of the fire detection system and excluded them from an aging management review because they are replaced based on a performance or condition program. In response to RAI 2.6-4, Duke referenced SOC Section Ill.f.(i)(b) and 10 CFR 54.21(a)(1)(ii) as the basis for excluding fire detector cables from an aging management review. However, Duke also stated that fire detector cables are not physically different than other insulated cables. 10 CFR 54.21(a)(1) requires that cables and connections are subject to an aging management review.
Since fire detector insulated cables are not physically different than other insulated cables and performance or condition programs have not been proven to adequately predict cable insulation degradation due to aging, the staff does not agree that these cables can be excluded from an AMR.
RAls 2.6-6 & 2.6-7 Sections 2.6.6.5 and 2.6.6.6 of the application conclude that resistance temperature detectors (RTDs) and thermocouples do not perform their function without moving parts or without a change in configuration or properties and thus are not subject to an aging management review.
However, the industry guidance for license renewal in NEI 95-10, Revision 0, Appendix A, recommends that RTDs and thermocouples should be subject to an aging management review.
During a clarification conference call with Duke on January 7, 1999, the staff stated that the pressure boundary intended function for RTDs and thermocouples is subject to an aging management review. Therefore, Duke should supplement the February 17, 1999, response (RAls 2.6-6 and 2.6-7) by including RTDs and thermocouples (pressure boundary) as being subject to an aging management review and reference the sections of the LRA that address the mechanical review (pressure boundary) for these components. This is a confirmatory item.
Potential Open Item 2.7-11 (New)
Section 2.7.1 of report OLRP-1001 indicates that the conceptual boundary of auxiliary buildings includes the hot machine shop and spent fuel pools for Units 1, 2, and 3. Section 2.7.3 of report OLRP-1001 describes the auxiliary buildings and the hot machine shop.but not the spent fuel
-4 pool. Explain why the spent fuel pool is not described and where in report OLRP-1001 you address the spent fuel pool?
Potential Open Item 2.7-12 (New)
The earthen embankments, Keowee structures, and yard structures are not described clearly in report OLRP-1001 and very little information on these structures can be found in the UFSAR.
Provide information on (1) configuration, (2) location, and (3) structural classification on each of these structural components. A drawing of Oconee and Keowee sites is helpful to locate these structures.
Potential Open Item 2.7-13 (New)
Section 2.7.3 of report OLRP-1001 states that the hot machine shop extension is a QA 4 structure. Give the definition of QA 4 structure and why this QA 4 structure is within the scope of license renewal.
Potential Open Item 2.7-14 (New)
Section 2.7.9.1 states that the Units 1 & 2 transformer and switchgear enclosures and Unit 3 switchgear enclosure are Class 1 structures. Clarify if these enclosures are for transformer CT4 and 4kV switchgear.
RAI 3.2-3 As the high flux neutron fluence is known to have adverse effects on structures, Table 3.2-2 should contain the 40-year and 60-year estimates of high flux neutron fluence to ensure that they are within the threshold limits stated in the response to this RAI for all structures in the Table.
RAI 3.3-19 In accordance with 10 CFR 54.21(a)(1)(ii), components not subjected to a qualified life or a specified time period are subjected to aging management review. Based on operating experience, if the applicant has a specified replacement schedule for moisture barriers, etc.,
these components would not be subjected to AMR under the license renewal rule. However, an ad-hoc replacement based on the component's condition would'not justify this exclusion. The licensee is requested to justify the replacement interval for these passive components in order to meet the exclusion criteria specified in the license renewal rule.
Potential Open Item 3.3.3-1 (New) - Applicable Aging Effects for Steel Components Under the Coating Program in Section 4.7 of the LRA, there is no mention of training and qualification of applicators. Please-provide this information.
-5 Potential Open Item 3.4.3-2 (New) - Reactor Coolant System Cast austenitic stainless steel (CASS) materials were reviewed in the Staff's SER on Topical Report BAW-2243. It does not contain our newest position on thermal embrittlement of CASS.
Our position on thermal embrittlement of CASS has been modified as a result of our review of Topical Report EPRI TR-106092. To be consistent with our position on thermal embrittlement of CASS, the aging management program for CASS piping and valve bodies must meet the criteria discussed for RCP pump casings.
Potential Open Item 3.4.5-9 (New) - Reactor Vessel The staff intends to issue the final safety evaluation shortly on the Babcock and Wilcox Topical Report BAW-2251 "Demonstration of the Management of Aging Effects for the Reactor Vessel."
The final safety evaluation will contain plant-specific items that an applicant who references the report needs to address in its license renewal application. After Duke receives the final safety evaluation, it must demonstrate to the staff that these plant-specific items are already contained in its license renewal application, or it must provide the plant-specific information to the staff.
Potential Open Item 3.4.6-3 (New) - Reactor Vessel Internals Below are plant-specific items from the staff Draft SER on Topical Report BAW-2248 (the Draft SER for Topical Report BAW-2248 is under preparation).
(A) According to B&WOG, one of its objectives in BAW-2248 states, "It is intended that NRC review and approval of this report will allow that no further review of the matters described herein will be needed when the report is incorporated by reference in a plant specific renewal license application." The license renewal applicant must address matters not described in the report, such as the issues addressed in Section 3.3.1 of the SE pertaining to the following letters: (1) Letter from Raj F. Anand, (NRC), to David J.
Firth, December 2, 1998, Request for Additional Information Regarding the Babcock &
Wilcox Owners Group Generic License Renewal Program Topical Report, "Demonstration of the Management of Aging Effects for the Reactor Vessel Internals, BAW-2248, July 1997," and (2) Letter from William R. Gray to David B. Mathews, (NRC),
dated February 18, 1999, B&WOG Generic License Renewal Program Topical Report BAW-2248, "Demonstration of the Management of Aging Effects for the Reactor Vessel Internals" (RAls 1 through 14 from December 4, 1998).
(B) License renewal applicants must identify whether the intended function of the RVI is to provide shielding for the RPV. If not an intended function, the license renewal applicant should provide justification for that conclusion. Should a license renewal applicant determine that the RVI's intended function is to provide shielding for the RPV, then the items that support this intended function, such as, the thermal shield and the thermal shield upper restraint assemblies, must be identified and reviewed in accordance with 10 CFR 54.21(a)(3).
(C) Plant-specific analysis is required to demonstrate that under loss-of-coolant-accident (LOCA) and seismic loading the RVI's have adequate ductility to absorb strains at the
-6 regions of maximum stress intensity and that irradiation accumulated at the expiration of the renewal license will not adversely affect deformation limits. The Reactor Vessel Internals Aging Management Program (RVIAMP) must develop data to demonstrate the RVI's will meet the deformation limits at the expiration of the renewal license.
Potential Open Item 3.4.6-4 (New)
Below are Open Items from staff Draft SER on Topical Report BAW-2248. These open items need to be addressed by the B&WOG. If these issues are not resolved prior to the issuance of the Oconee SER they will be carried as open items in the Oconee SER.
(A) The B&WOG must modify their aging management program to include the program proposed by the staff in Section 3.3 of the Draft SER for BAW-2248 for managing the effects of SCC, IASCC, thermal embrittlement and neutron embrittlement.
(B) To determine whether CASS components are above or below the threshold value of 1 x 1017n/cm2 discussed in Section 3.3.3 of the Draft SER for BAW-2248, the B&WOG must provide estimates of the neutron fluence of each CASS component at the expiration of the license renewal term, identify the method of determining the neutron fluence and provide justification for why the method is applicable for components above or below the core.
Potential Open Item 3.4.6-5 (New) (The item below refers to RAls 12 & 13 on BAW-2248)
The staff's review of BAW-2248, "Demonstration of the Management of Aging Effects for the Reactor Internals" resulted in RAls 12 and 13 which were transmitted to the B&W Owners Group (B&WOG) in a letter from Anand to Firth dated December 2, 1998. In RAI 12, the staff requested the B&WOG to describe the baffle bolt inspections that will be conducted prior to the start of the extended license renewal period and indicate how these actions provide the basis for assuring that the monitoring and inspection techniques that are planned for implementation during the period of extended operation are appropriate. In RAI 13, the staff requested that the B&WOG describe the program that will be implemented as outlined in Section 4.6 of BAW-2248 with regard to the aging management of the RVI baffle bolts and include a description of the overall inspection program, the inspection techniques, intervals and monitoring.
The B&WOG responded to these RAls, by stating that an Issues Task Group (ITG) on reactor vessel internals is currently addressing the issues related to baffle bolts, and the data and information acquired from these various program activities will be used to determine the necessary steps in managing the issues of baffle bolt age-related degradation, including future inspection plans. The B&WOG will provide support to the ITG by providing plant-and design specific data. The licensees will be responsible for using the tools provided by both the ITG and the Owners Group to determine the necessary steps to manage the applicable aging effects.
These plans are expected to be outlined on a plant specific basis, therefore, the information requested in RAI 12 and 13 remain as an open item pending the licensee's submittal of plant specific information and plans.
-7 RAI 3.4.7-1 It is the staffs understanding that the tubes in the Oconee Unit 3 steam generators (SG) were subjected to stresses slightly beyond the allowable values during an event in August 1994 involving the injection of cold feedwater into a hot, dry SG. In RAI 3.4.7-1, the staff requested the applicant to discuss whether or not this event contributed to the aging of the SG tubes. In addition, the applicant was requested to describe the procedures that are used to evaluate the impact of such events on the adequacy of the aging management programs (AMPs).
In its response, the applicant stated that the Unit 3 event that occurred on August 10,1994, was a reactor trip from full power that resulted in the dry-out of the B SG. The overcooling that occurred as a result of the inadvertent opening of a turbine bypass valve resulted in tube-to-shell differentials in excess of established tube-to-shell limits. According to the applicant, reactor trip is an upset event (i.e., level B) and is not an emergency or faulted event (level C or D). A subsequent evaluation by B&W using actual transient data indicated that the axial tube loads (both compressive and tensile) were within the limits of the allowable tube loads. Since the allowable tube loads were not exceeded, the event of August 10,1994, did not impact the integrity of the SG tubes.
It is the staff's understanding that there was uncertainty associated with the actual transient data, and therefore potential for damage to tubes cannot be ruled out. The B&WOG recognize the significance of this event and agreed to incorporate changes in procedures to manage such events more effectively in the future. The applicant's response did not address this aspect of the staff's concern. Therefore, this issue remains an open item.
Potential Open Item 3.4.8-6 (New) - Reactor Coolant Pumps RCP Casings which are fabricated from Cast Austenitic Stainless Steel (CASS) should have the following aging management program:
The CASS components should be evaluated to the criteria in EPRI TR-106092 with the following additional criteria:
(a)
Statically cast components with a molybdenum content meeting the requirements of SA-351 Grades CF3 and CF8 and with a delta ferrite content less than 10 percent will not need supplemental examination.
(b)
Ferrite levels will be calculated using Hull's equivalent factors or a method producing an equivalent level of accuracy (+/-6 percent deviation between measured and calculated values).
(c)
Cast stainless components with Niobium are subject to supplemental examination.
(d)
Flaws in CASS with ferrite levels less than 25 percent and no niobium may be evaluated using ASME Code IWB-3640 procedures.
-8 (e)
Flaws in CASS with ferrite levels exceeding 25 percent or niobium will be evaluated using ASME Code IWB-3640 procedures. If this occurs, fracture toughness data will be provided on a case-by-case basis.
Components that have delta ferrite levels below the screening criteria have adequate fracture toughness and do not require supplemental inspection. Components that have delta ferrite levels exceeding the screening criteria may not have adequate fracture toughness, as a result of thermal embrittlement, and do require supplemental volumetric inspection with techniques qualified to Appendix VIII of Section XI of the ASME Code, provided inspection techniques can be developed. The licensee must acknowledge that they will implement the above criteria.
RAI 3.4.10 Letdown Coolers Oconee operating experience was reviewed to validate the identified applicable aging effects.
The review of Oconee operating experience identified that the letdown cooler heat exchanger tubes did experience cracking in the past as a result of improper operation of the coolers. Two of the six letdown coolers have been replaced; the other four have been repaired and operating procedures have been changed to eliminate improper operation.
In RAI 3.4.10-1, the staff requested the applicant to describe the repairs which were performed on the damaged letdown coolers and the specific analyses which were performed to assure that thermal and vibrational stresses during normal and off-normal operation will not cause fatigue failure during the period of extended operation.
In its response, the applicant stated that the letdown coolers are of the shell and spiral tube design. A review of operational history identified some events where the tubes cracked due to thermal and vibrational stresses caused by improper operation of the coolers.
The applicant is requested to provide its evaluation of the damage to the various components of the letdown coolers or the specific analyses performed to assure that all the components of the damaged letdown coolers have experienced no degradation as a result of improper operation.
Further, the applicant is requested to provide an analytical assessment to assure that these letdown coolers are operating in a condition that precludes potential failure due to thermal fatigue during the extended period of operation.
Potential Open Item 3.5.7-3 (New)
The LR application does not specify what components in the Chemical Addition System (CAS) will be included in the Treated Water Systems Stainless Steel Inspection program. Also, the applicant does not specify what corrective actions will be taken if this one-time inspection finds that corrosive action of caustic solution is sufficiently significant to cause future problems.
RAI 3.5.8-3 (11/20/98B) - Air Conditioning, Heating, Cooling and Ventilation Systems In order to minimize vibration and subsequent dynamic loads, isolators are commonly installed to the attached devices (such as fans) in nuclear power plants. As described in the RAI, the operating experience of other nuclear power plants indicates that cracking of ductwork due to
-9 vibration-induced fatigue and loosening of fasteners due to dynamic loading cannot be avoided by the installation of isolators. The response to this RAI did not address this concern beyond stating that isolators are expected to completely eliminate the operational vibration and dynamic loads. The applicant should either address these types of aging effects in the application or provide justification for not including them in the AMR program.
Potential Open Item 3.5.10-1 (New)
The LR application does not include evaluation of the aging effects which may exist in the hydrogen recombiner. Although this piece of equipment is constructed from stainless steel which, as demonstrated by the applicant, resists the environment to which the hydrogen recombiner is exposed, there are some ancillary components such as gaskets and cable insulation which may be prone to aging effects.
RAI 3.5.14 Standby Shutdown Facility It is stated in Section 3.4.14.8 of the LRA, that no applicable aging effects have been identified for the components of the starting air system. The emergency diesel generator (EDG) starting air system at several other facilities has experienced degradation due to excessive vibration in the piping and starting air valves which in some cases rendered the air receivers incapable of delivering starting air to the diesel engines at the design pressures. In RAI 3.5.14-4, the staff requested the applicant to discuss the upgrades, if any, and/or surveillance requirements for the starting air system at Oconee to assure operability of this system during the period of extended operation beyond 40 years.
In its response, the applicant stated that cracking due to vibrational (mechanical or hydrodynamic) loads was a potential aging effect that was determined not to be applicable to the starting air system components subject to an AMR. The applicant further stated that cracking due to vibration can be attributed to design deficiencies. Vibration characteristically leads to cracking in a short period of time, on the order of hours to days of operation. For example, a component with a 1 Hz vibratory load will be subjected to 107 cycles in four months of service.
Therefore, the applicant contends that failure due to vibratory stresses above the endurance limit is likely to occur early in life. Because this time period is short when compared to the overall plant operational life, the applicant argues that any cracking will be identified and corrected long before the period of extended operation. Therefore, according to the applicant, cracking due to vibrational loads, both mechanical and hydrodynamic, is not an applicable aging effect for the starting air system components subject to an AMR.
The staff does not agree with this assessment because the starting air system is used very infrequently and there is no assurance that vibratory stress cycles necessary for causing fatigue failures will occur early in plant life. In view of the operational failures of this system at other facilities, adequate assurance of the operability of this system during the period of extended operation is needed. Therefore, this remains an open item.
-10 RAI 3.5.14 Standby Shutdown Facility*
The applicant's response to this RAI is that the Preventative Maintenance Activities aging management program will be used to control corrosion of underground carbon steel components.
The applicant does not discuss cathodic protection of underground or on-ground carbon steel components. NACE provides considerable guidance (RP-0169, RP-0193-93) on programs for protection of underground or on-ground carbon steel components. The applicant has not indicated that it is aware of this guidance.
RAI 3.5.14 Standby Shutdown Facility The applicant's response states that portion of the auxiliary service water system exposed to raw water and subject to fouling is the limited portion of the system that includes the pump, the pump discharging piping up to the pump discharge isolation valve, and the minimum recirculation piping. The remainder of the piping in the system is drained and is not subject to fouling. The System Performance Testing Activities will be used to control fouling.
Industry experience has shown that after fouling has taken place, flushing may not be an efficient way to remove fouling. Also, the licensee has not stated how it responded to Generic Letter 89-13, which states that licensees should have a program in place to control fouling.
Potential Open Item 3.5.14.7.1-1 (New)
This section pertains to the Standby Shutdown Facility Auxiliary Service Water System, and references Section 3.5.2.4 which discusses aging effects for cast iron in a raw water environment. Section 3.5.14.7.1 notes that there are no applicable aging effects for cast iron submersible pump casings. Please resolve this discrepancy and discuss applicable aging management programs.
RAI 3.7.3-2 (11-30-98A)
The applicant stated that the ingress of ground water is not possible through an internal concrete slab which was found with cracks determined to be the result of slab shrinkage during initial concrete placement. The Oconee response to the RAI also stated that cracks of foundation slabs have not been validated by Oconee operating experience. Oconee further stated that the cover provided in the Oconee structures meets or exceeds the applicable requirements of ACI 318-63, which has over the years proved to be effective for preventing chemical corrosion of the concrete reinforcement that exists in an environment not subject to special chemical exposures.
For the above stated reasons, Oconee determined that cracks of foundation slabs need not be identified as applicable aging effects. Shrinkage cracks or cracks in concrete that are smaller than a few mills, may not lead to moisture ingress to rebars in concrete. Under purely shrinkage cracks, degradation of rebars is not likely; however, that is not the case with larger cracks that can be found in most nuclear power plant structures. For cracks in concrete surfaces above ground or in those surfaces that are embedded underground where ground water is contaminated with corrosive agents, it is necessary to establish an aging management program (AMP). The AMP can be as simple as a periodic observation of evidence of rebar degradation and taking appropriate corrective action when significant rebar degradation is detected. Oconee
is requested to provide its most recent chemical analysis data of the ground water surrounding Oconee safety-related structures and to address the effects of ground water on rebar. In addition, the broader aspect of managing rebar degradation needs to be addressed by the licensee. Therefore, this issue remains open.
RAI 3.7.7-1 (11-18-98A)
In order to make a realistic evaluation of the tendon system performance in the secondary shield wall (SSW), the staff needs information regarding (1) the minimum required prestress in each group of tendons, (2) results of the tendon forces as found during the periodic lift-off testing, and (3) information regarding retensioning of tendons, if performed. This information is needed for each Unit at Oconee to assess the time-dependent behavior of the SSW tendon system and their impact on license renewal related AMP and TLAA.
RAI 3.7.7-2 (11-30-98A)
The staff does not agree with the applicant's hypothetical logic in demonstrating that the concrete cracking has not occurred and will not occur in the internal concrete structures of the reactor building. The threshold temperature limits established in ACI 349 and in NUREG-1557 only assure that the concrete properties (compressive strength, modulus of elasticity, etc.) do not significantly change if a concrete structure experiences temperatures within those temperatures limits. They do not guard the structures against cracking. If the applicant wants to exclude the concrete cracking and potential corrosion of the embedded rebars in slabs and walls of the internal structures from Table 3.7-5 (Applicable Aging Effects), it should demonstrate that there are no existing cracks in those components (based on focused inspections), and justify why there will not be any future cracking.
RAI 3.7.7-3 (11-30-98A)
The applicant cites Section Ill.f.(i)(b) of the Statement of Consideration (SOC) to 10 CFR Part 54 to justify exclusion of certain structural components (i.e., caulking, sealant) from an AMR. As a matter of record, in response to a relevant question in the cited Section, the Commission states, "Absent the specific nature of the performance or condition replacement criteria (e.g., routine testing program) it is not appropriate for the Commission to generically exclude all such replacement programs for passive structures and components." The applicant should identify the specified replacement schedule for these components in order to justify their exclusion from the AMR program. See also staff position - RAI 3.3-19.
RAI 3.7.7-6 (11/30/98A)
The Duke Power response to this RAI stated that the Inspection Program for Civil Engineering Structures and Components is relied upon by the licensee as the aging management program for unique structural items, such as sump screen and the Unit Vent Stacks. The program will be enhanced to include items that are currently not covered specifically in the program (e.g., sump screens). The program consists of visual inspection of structures and components for aging effects. The sump screens and the Unit Vent Stacks are inspected for loss of material. The licensee stated that the acceptance criteria are provided in Section 4.19 of the Oconee LRA and
-12 the acceptance criteria are defined as "No unacceptable visual indication of loss of material, cracking or change of material properties for concrete, and loss of material for steel," as identified by the accountable engineer. The licensee in Section 4.19 of the LRA also stated that inspected structures and components classified as acceptable are those structures and components that are capable of performing their intended function. The staff finds that the above definition of the acceptance criteria for the broadly used inspection program rather vague and non-specific. The staff is also concerned that the application of the acceptance criteria relies heavily on the judgment of a so-called "accountable engineer" whose minimum qualification, if any required, is not clearly defined. The licensee should provide additional information as well as guidance including some examples of past inspection to better define the acceptance criteria.
The licensee also need to discuss what qualifications or conditions an engineer must meet in order to be qualified as an "accountable engineer." The licensee is also asked to list key examples of past inspection findings which led to classification of some inspected structures as "not acceptable." Pending satisfactory resolution of the above items by the licensee, this RAI remains open.
Potential Open Item 4.3.2-2 (New)
In the LR application the acceptance criterion for evaluating degradation of the component due to selective leaching corrosion is based on the acceptability of wall thickness which will be judged in accordance with the Oconee component design code on record. However, loss of the ferrite phase from cast iron by selective leaching will affect not only its dimensions but also its mechanical properties, ductility being the major affected property. Basing acceptability of a component only on its measured thickness may not give a true picture and may significantly underestimate the degree of degradation which has occurred. The applicant should address this issue.
Potential Open Item 4.3.8-7 (New)
For the Component Cooler Tubing Examination, the Condensate Cooler Tubing Examination, the Decay Heat Cooler Tubing Examination, and the Main Condenser Tubing Examination, the applicant applies an acceptance criteria of 60% throughwall. The staff requests the applicant provide the basis for this value.
Potential Open Item 4.3.8-8 (New)
The applicant should provide operating experience that demonstrates the effectiveness of the PM activities. The applicant plans to perform a formal documentation of this as part of the Preventive Maintenance Activity Assessment. The applicant plans to complete this assessment by February 2013. The staff requests the applicant provide this assessment to the staff upon completion. This is a Confirmatory Item.
Potential Open Item 4.3.8-9 (New)
The applicant committed to performing these PM activities consistent with the descriptions provided in the December 14, 1998, submittal. The applicant will revise the UFSAR Supplement
-13 (Exhibit B of the application) by November 30, 1999, to reflect this commitment. This is a Confirmatory Item.
Potential Open Item 4.3.9-6 (New)
For the Reactor Building Spray System Inspection, the applicant stated it will inspect the most bounding of six susceptible locations. Confirm that these six locations consist of the entire susceptible population for this system. If not, provide the basis for selecting these six locations.
Provide the parameters you will evaluate to select the most bounding or representative inspection location.
Potential Open Item 4.3.9-7 (New)
For the Reactor Building Spray System Inspection, the applicant stated it will include at least one stainless steel weld and heat affected zone, if available, since this is a more likely location for stress corrosion cracking to occur. The staff requests the applicant commit to inspecting at least one weld and heat affected zone. As an alternative, provide the staff the basis for concluding such an inspection location is not needed to confirm the absence of stress corrosion cracking.
Potential Open Item 4.3.9-8 (New)
For the Reactor Building Spray System Inspection, the applicant stated it plans to use a volumetric nondestructive examination method to assess the condition of the piping. Please confirm that the method selected will be qualified for this material type (stainless steel) and for the degradation modes (pitting and SCC). If known, provide the specific inspection method.
RAI 4.8-1 (11-19-98)
Please clarify the last sentence of the first paragraph of the response to this RAI: "The first period of the first inservice inspection interval for Subsection IWE examinations will end September 9, 2008." Should it be 2001?
RAI 4.16-10 (12/3/98E)
The response states that no supports are provided for the buried portions of the High Pressure Service Water System piping and the Keowee Service Water System piping since the piping is supported by compacted earth. Therefore, the applicant concludes that no aging management program is needed for managing aging of supports for buried piping. Based on the staff's review experience, some settlement is expected to occur for the buried piping, even it is supported on compacted soil. The applicant should provide a discussion to assure that no additional settlement would be expected during the period of extended operation. In addition, the applicant did not respond to the staff's concern regarding the buried pipe corrosion.
Potential Open Item 4.17-4 (New) - "Heat Exchanger Performance Testing Activities" How do you simulate or extrapolate to normal operating and accident conditions when performing the heat exchanger performance tests?
-14 RAI 4.17-1 On page 4.17-1 of the LRA, the applicant states the frequencies of the performance testing of the reactor building cooling units is on a refueling outage basis. In the February 8, 1999 response to RAI 4.17-1, the applicant states the reactor building cooling units receive a heat transfer test quarterly (Attachment 2, page 18). Please clarify this discrepancy.
In the response to RAI 4.17-1, the applicant provided information related to operating experience related to Heat Exchanger Performance Testing Activities. Confirm that no heat exchangers in this program have been found to not meet minimum required cooling capacity.. If heat exchangers have been found to not meet minimum acceptance criteria, describe the ensuing corrective actions.
Potential Open Item 4.17-5 (New)
In Section 3.5.2, page 3.5-3 of the LRA, the applicant lists systems with raw water that may be susceptible to fouling. The staff noted this list appears to be incorrect in that neither 3.5:11 nor 3.5.12 mention raw water. Also, there appears to the staff that there are more systems with raw water and potential fouling issues than those listed (for example, 3.5.3, 3.5.5 and 3.5.14 have raw water and fouling issues but are not included on the list on page 3.5-3). Please explain or correct these apparent discrepancies.
Potential Open Item 4.17-6 (New)
In Section 3.5.14.4, the applicant stated that flow rate of the cooling water through the SSF HVAC cooling units is measured, but not the delta-temperature across this heat exchanger.
Without additional information, the staff considers this inadequate because it appears that not all aging effects are managed. For example, one of the aging affects identified by the applicant is loss of material for the aluminum fins of the cooling coils. If one assumed some or all of these fins were broken such that cooling capacity is degraded, this condition will not be identified by the applicant because the flow rate through the condenser tubes, which is the only parameter the applicant is measuring, will remain the same. Thus, the staff concludes measuring just flow rate is not enough to verify the cooling units are maintaining their heat transfer capacity.
Potential Open Item 4.17-7 (New)
For the decay heat removal coolers and the reactor building cooling units, the applicant determines heat removal capacity and compares the test results to the acceptance criteria as well as to previous test results. For the SSF heat exchangers, the applicant verifies acceptable cooling water flow rates through these heat exchangers. Please specify what are the acceptance criteria and what they are based on.
Potential Open Item 4.17-8 (New) - Heat Exchanger Performance Testing Activities The heat exchanger performance testing activities described in Section 4.17 of the LRA discuss, in general terms, the testing and maintenance activities related to the standby shutdown facility heat exchangers, but there is not specific reference to NRC Information Notice (IN) 97-41
-15 "Potentially Undersized Emergency Diesel Generator Oil Coolers." It is not clear that the applicant has reviewed the applicability of this IN to the Oconee heat exchangers. Since fouling of heat exchanger tubing has been identified as an applicable aging effect, appropriate actions to avoid problems similar to those discussed in the IN may be necessary for Oconee heat exchangers.
Potential Open Item 4.23-2 (New)
Discuss why the RCS Operational Leakage Monitoring program is not credited for managing aging effects associated with the reactor coolant piping casing.
Potential Open Item 4.23-3 (New)
Confirm Table 3.5-3 contains appropriate references to the RCS Operational Leakage Monitoring for the HPIS. It appears from this table that this program is credited with managing aging effects only for the RCP coolers and seal return coolers and not the Class 1 pressure boundary portion of the HPIS as stated in the applicant's response to RAI 4.23-1, dated February 8, 1999.
Potential Open Item 4.23-4 (New)
To provide for early warning of leakage, the applicant relies on its containment air monitoring of radioactivity and the containment sump level monitoring. To monitor its primary-to-secondary leakage through steam generator tubes, the applicant relies on effluent monitoring in the secondary systems or by comparison of primary and secondary radioisotope concentrations.
How often are these parameters monitored? If not continuously, provide monitoring frequency.
Potential Open Item 4.25-3 (New)
The staff identified the following discrepancies within the applicant's LRA. The staff considers these minor, however, Duke should address these discrepancies.
- a.
Section 4.25 includes within its scope the Low Pressure Injection System. This system is not listed in Section 3.5.2.4.
- b.
Section 3.5.2.4 includes the SSF Sanitary Lift System. This is not consistent with Section 3.5.14.6 and Table 3.5-12 because no raw water environment appears to be in this system.
- c.
The description of component materials in 2.5.6.3 does not match the description in 3.5.6.3.
- d.
The description of component materials in 2.5.6.4 does not match the description in 3.5.6.4.
e The description of component materials in 2.5.6.5 does not match the description in 3.5.6.5.
-16 f
The description of component materials in 2.5.13.6 does not match the description in 3.5.13.6.
Potential Open Item 4.25-4 (New)
The staff identified the following discrepancies within the applicant's LRA. The staff requests the applicant clarify these discrepancies so that the staff can ensure all aging effects, systems and components are completely and correctly identified for aging management:
- a.
On page 3.5-118 and 3.5-121 in Table 3.5-4, page 3.5-140 in Table 3.5-11, and page 3.5 149 in Table 3.5-12, the applicant stated that several components in the Condenser Circulating Water System, High Pressure Service Water System, Keowee Service Water System, and the SSF Auxiliary Service Water System are not subject to aging effects.
Without additional clarification from the applicant, the staff believes this finding contradicts the applicant's position on aging effects stated in Section 3.5.2.4. Explain why no aging management programs are identified for the various materials exposed to a raw water environment.
Potential Open Item 4.25-5 (New)
As stated on page 4.25-1, under Section 4.25.1, the scope of the Service Water Piping Corrosion program includes all bronze, carbon steel, cast iron and stainless steel components exposed to raw water and included within the scope of license renewal. (The staff notes that this statement is not consistent with the introductory paragraph on the same page.) How is loss of material managed for the other material types exposed to raw water; e.g., copper, brass, and ductile iron?
Potential Open Item 4.25-6 (New)
The applicant stated that the focus of the Service Water Piping Corrosion Program to date is on the carbon steel piping components exposed to raw water because they are the most susceptible to general corrosion and can serve as a leading indicator of the general material condition of the system components (page 4.25-1). Thus, the staff assumes that the applicant has not performed and has no plans to perform, at this time, inspections of components fabricated from materials other than carbon steel. The staff is unaware of any relationship between the course of general corrosion of carbon steel components and pitting or MIC attack of stainless steel components. Provide the technical basis for relying on inspections of carbon steel component for general corrosion to "serve as a leading indicator" of the condition of other components fabricated from other materials and susceptible to other corrosive mechanisms such as pitting or MIC. Without additional information, the staff finds the program, as described in the LRA, insufficient to manage aging effects for components fabricated from materials other than carbon steel.
Potential Open Item 4.25-7 (New)
The applicant stated that the program does not currently include inspections of the Keowee systems because the components in that system remain bounded by the overall program results.
State specifically how the Keowee system is bounded.
-17 Potential Open Item 4.25-8 (New)
The applicant inspects the bounding locations in the various system within the scope of the Service Water Piping Corrosion Program using ultrasonic test techniques, supplemented by visual inspections if access to the interior surfaces is allowed such as during plant modifications.
The staff finds this technique acceptable for general corrosion, but questions the validity of this technique for detecting localized degradation such as pitting or MIC. Describe more fully your inspection technique to justify the use of UT for localized degradation.
RAI 5.3.1-1 (11-19-98)
The response to RAI 5.3.1-1, dated February 8, 1999, refers to Table 5.2 of the Oconee UFSAR.
Table 5.2 of the Oconee UFSAR shows 360 design cycles for heat up from 70 F to 8% power and cooldown back to 70 F. However, the table also shows other normal operating design transients, such as 1440 cycles of power change from 0% to 15% and back to 0%, 18000 cycles of power loading from 8% to 100% and unloading back to 8%, and 8000 cycles of 10% load increase and decrease. Provide a justification as to why the thermal expansion of the RCS under these additional cycling conditions, and its effect on the steam and feedwater lines, should not be included in the fatigue assessment of the containment liner penetrations for the period of extended operation of these components that are shown in Figure 3.20 of the UFSAR.
RAI 5.3.2-2 (11-19-98)
In responses to RAls 4.8-1, 4.8-2, and 4.8-3, the applicant provided information regarding the aging management programs related to the post-tensioning tendon system of the containments of the three Units at Oconee. To establish a reasonable assurance regarding the quantitative aspect of the tendon force TLAA, the applicant should provide information regarding the trending of the measured prestressing forces in the Oconee containments. If an adequate sampling is not available to perform a reliable regression analysis to construct trend lines, this information should be collected in the future and provided by the applicant to confirm the accuracy of the tendon monitoring activity. This remains an open item.
RAls 5.4.1-2, 5.4.1-3 and 5.4.1-4 The RAls involve TLAAs that are not completed. Duke indicates that these items will be completed prior to the extended period of operation. Duke further indicated that after the evaluations are completed, these items would be managed by the Thermal Fatigue Management Program. Duke indicated that this complies with 54.21(c)(1)(iii). Completion of the additional evaluations prior to the extended period of operation are confirmatory items.
Status: Duke provided supplemental response on 3/29/99.
Potential Open Item 5.7.1-2 (New) - TLAA for fatigue of Polar Cranes The fatigue due to lift cycles of the polar cranes (PCs) at/or near-rated loads is considered by the applicant to be a time-limited aging analysis for Oconee because the analyses meet all of the criteria contained in §54.3. The analyses addressing heavy load lifts for the polar and spent fuel
-18 cranes are summarized in Section 5.7.1 of the LRA. According to the applicant, these analyses demonstrate that the fatigue requirements are satisfied for the period of extended operation.
Typically, some of the components of the PC system, such as PC rails, are constructed of carbon steel, which has a lower allowable stress range. The applicant's analyses do not distinguish between components which have different allowable stress ranges. The applicant should provide a justification that the lower limit of the stress range will not be exceeded during service life.