ML050270121
| ML050270121 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 01/25/2005 |
| From: | Veronica Rodriguez NRC/NRR/DRIP/RLEP |
| To: | Nuclear Management Co |
| Rodriguez V, RLEP/DRIP/NRR, 415-2232 | |
| References | |
| Download: ML050270121 (13) | |
Text
January 25, 2005 LICENSEE: Nuclear Management Company, LLC FACILITY: Point Beach Nuclear Plant, Units 1 and 2
SUBJECT:
SUMMARY
OF TELEPHONE CONFERENCE HELD ON JANUARY 05, 2005, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND NUCLEAR MANAGEMENT COMPANY, LLC, CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION The U.S. Nuclear Regulatory Commission staff (the staff) and representatives of Nuclear Management Company, LLC (NMC) held a telephone conference on January 05, 2005, to discuss and clarify the staffs requests for additional information (RAIs) concerning the Point Beach Nuclear Plant, Units 1 and 2, license renewal application. The conference call was useful in clarifying the intent of the staffs RAIs. provides a listing of the meeting participants. Enclosure 2 contains a listing of the RAIs discussed with the applicant, including a brief description on the status of the items. contains draft responses provided by the applicant.
The applicant had an opportunity to comment on this summary.
/RA/
Verónica M. Rodríguez, Project Manager License Renewal Section A License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket Nos. 50-266 and 50-301
Enclosures:
As stated cc w/encls: See next page
ML050270121 DOCUMENT NAME: E:\Filenet\ML050270121.wpd OFFICE PM:RLEP SC:RLEP NAME VRodríguez Slee DATE 1/25/05 1/25/05 Point Beach Nuclear Plant, Units 1 and 2 cc:
Jonathan Rogoff, Esq. Mr. Jeffrey Kitsembel Vice President, Counsel & Secretary Electric Division Nuclear Management Company, LLC Public Service Commission of Wisconsin 700 First Street P.O. Box 7854 Hudson, WI 54016 Madison, WI 53707-7854 Mr. Frederick D. Kuester David Weaver President and Chief Executive Officer Nuclear Asset Manager We Generation Wisconsin Electric Power Company 231 West Michigan Street 231 West Michigan Street Milwaukee, WI 53201 Milwaukee, WI 53201 James Connolly John Paul Cowan Manager, Regulatory Affairs Executive Vice President & Chief Nuclear Point Beach Nuclear Plant Officer Nuclear Management Company, LLC Nuclear Management Company, LLC 6610 Nuclear Road 700 First Street Two Rivers, WI 54241 Hudson, WI 54016 Mr. Ken Duveneck Douglas E. Cooper Town Chairman Senior Vice President - Group Operations Town of Two Creeks Palisades Nuclear Plant 13017 State Highway 42 Nuclear Management Company, LLC Mishicot, WI 54228 27780 Blue Star Memorial Highway Covert, MI 49043 Chairman Public Service Commission Fred Emerson of Wisconsin Nuclear Energy Institute P.O. Box 7854 1776 I Street, NW., Suite 400 Madison, WI 53707-7854 Washington, DC 20006-3708 Regional Administrator, Region III Roger A. Newton U.S. Nuclear Regulatory Commission 3623 Nagawicka Shores Drive 801 Warrenville Road Hartland, WI 53029 Lisle, IL 60532-4351 James E. Knorr Resident Inspector's Office License Renewal Project U.S. Nuclear Regulatory Commission Nuclear Management Company, LLC 6612 Nuclear Road 6610 Nuclear Road Two Rivers, WI 54241 Point Beach Nuclear Plant Two Rivers, WI 54241
DISTRIBUTION: Note to Licensee: NMC, LLC, Pt. Beach Nuclear Plant, Units 1 and 2,
Subject:
Summary of Telephone Conference Held on January 5, 2005 ML050270121 HARD COPY RLEP RF 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 P. Lougheed, RIII J. Strasma, RIII A. Stone, RIII H. Chernoff W. Ruland C. Marco L. Raghavan T. Mensah OPA
LIST OF PARTICIPANTS FOR TELEPHONE CONFERENCE TO DISCUSS THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION JANUARY 5, 2005 Participants Affiliations J. Knorr Nuclear Management Company, LLC M. Morgan Nuclear Regulatory Commission G. Suber Nuclear Regulatory Commission V. Rodriguez Nuclear Regulatory Commission Enclosure 1
DRAFT REQUESTS FOR ADDITIONAL INFORMATION (RAI)
POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION January 5, 2005 The U.S. Nuclear Regulatory Commission staff (the staff) and representatives of Nuclear Management Company, LLC (NMC) held a telephone conference call on January 05, 2005, to discuss and clarify the staffs requests for additional information (RAIs) concerning the Point Beach Nuclear Plant, Units 1 and 2, license renewal application (LRA). The following RAIs were discussed during the telephone conference call.
RAI-2.1 .1 Short Term Exposure Duration Definition - 10 CFR 54(a)(2)
The PBNP LRA and page 13 of LR-TR-514 did not adequately define short term exposure duration for low and moderate energy piping failures covered under10 CFR 54.4(a)(2) that could affect safety related electrical equipment under the scope of 10 CFR 54.4(a)(1).
Specifically, the staff found that some safety-related electrical equipment may exist in the turbine building or other parts of the plant and may be subject to harsh environments from low or moderate energy pipe breaks but are not environmentally qualified (EQ). Since this equipment may not be EQ, they could fail due to 10 CFR 54.4(a)(2) piping failures.
The staff requests additional information to adequately define short term exposure duration for low and moderate energy piping failures and how it relates to scoping and screening of 10 CFR 54.4(a)(2) piping that could cause these types of failures.
Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.
RAI- 2.1.2 First Equivalent Anchor Definition - 10 CFR 54(a)(2)
The PBNP LRA Section 2.1.2.1.2, page 2-19, states, under, NSR SSCs Directly Connected to SR SSCs, ?For NSR SSCs directly connected to SR SSCs (typically piping systems), the NSR piping and supports, up to and including the first equivalent anchor beyond the safety/non safety interface, are within the scope of license renewal per 10 CFR 54.4(a)(2). Although these piping segments are not uniquely identified on the LR boundary drawing, applicable aging effects on these piping segments are managed along with the adjoining SR piping.
The staff requests additional information to adequately describe and define what is meant by the first equivalent anchor and how it relates to the scoping and screening of 10 CFR 54.4(a)(2)
NSR piping and supports.
Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.
Enclosure 2
RAI -2.1.3 Flow Accelerated Corrision affect on Piping Section Scoping - 10 CFR 54(a)(2)
The PBNP LRA Section 2.1.2.1.2, pages 2-20&21, states, under Piping Supports, ?All NSR supports for non-seismic or Seismic II/I piping systems with a potential for spatial interaction with safety related SSC, will be included within the scope of license renewal per 10 CFR 54.4(a)(2). These supports will be addressed in a commodity fashion, within the civil/structural area review. As long as the effects of aging on the supports for these piping systems are managed, falling of piping sections, except for flow accelated corrosion (FAC) failures, is not considered credible, and the piping section itself would not be in-scope for 10 CFR 54.4(a)(2) due to physical impact hazard (although the leakage or spray may still apply).
The staff requests additional information to adequately describe why the falling of piping sections is not considered credible, and why the piping section itself would not be in-scope for 10 CFR 54.4(a)(2) due to physical impact hazard. Please describe how the management of FAC relates to the scoping and screening of 10 CFR 54.4(a)(2) Seismic II/I piping systems that could cause these types of failures.
Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION (LRA)
The following information is provided in response to the Nuclear Regulatory Commission (NRC) staff's request for additional information (RAI) regarding the Point Beach Nuclear Plant (PBNP)
The NRC staff's questions are restated below, with the Nuclear Management Company (NMC) response following.
NRC Question RAI-2.1 .1 Short Term Exposure Duration Definition - 10 CFR 54(a)(2)
The PBNP LRA and page 13 of LR-TR-514 did not adequately define short term exposure duration for low and moderate energy piping failures covered under10 CFR 54.4(a)(2) that could affect safety related electrical equipment under the scope of 10 CFR 54.4(a)(1).
Specifically, the staff found that some safety-related electrical equipment may exist in the turbine building or other parts of the plant and may be subject to harsh environments from low or moderate energy pipe breaks but are not environmentally qualified (EQ). Since this equipment may not be EQ, they could fail due to 10 CFR 54.4(a)(2) piping failures.
The staff requests additional information to adequately define short term exposure duration for low and moderate energy piping failures and how it relates to scoping and screening of 10 CFR 54.4(a)(2) piping that could cause these types of failures.
NMC Response:
Based on additional information from the NRC staff, NMC will remove the Exposure Duration discussion from Section 2.1.2.1.2 of the PBNP LRA, and will add the following to the Components Qualified/Designed for Environment discussion. This response provides the technical justification as to why the Safety-Related SSCs are capable of withstanding the effects of spray/leakage (i.e., designed or qualified for that environment).
NMC asserts that non-vulnerable SR components are designed for a potential leakage environment. SR SSCs are constructed of stainless steel, copper alloys, cast iron or carbon/low-alloy steel. Liquids contained in NSR SSCs in and around safety-related areas are treated water, treated/borated water, raw water, or raw water - drainage (which is either ground water, or a potential combination of leakage from any or all these sources). Safety-related non-vulnerable components are considered to be designed for the potential leakage environment based on the following:
- 1. External surfaces of stainless steel and copper alloys are considered to be inherently resistant to corrosion. Leakage or spray from NSR SSCs would have to include aggressive chemical species (chlorides, fluorides, etc.) to have potential to cause accelerated aging effects. These aggressive chemical species are not present in liquids in SR areas at PBNP. Therefore, leakage or spray from NSR SSCs onto SR SS or
copper alloy components, will not cause aging effects that will affect the intended function of these SR SSC. The only known industry operating experience has been leakage of salt water onto SR stainless steel piping that caused thru-wall cracking in the stainless steel. PBNP is not in a salt water environment, and therefore this would not apply at PBNP. Therefore, there is reasonable assurance that SR stainless steel or copper alloy components are designed to withstand the potential leakage/spray environment, without loss of intended function.
- 2. External surfaces of carbon/low alloy steel are susceptible to corrosion. SR carbon/low alloy steel SSCs however, do have aging management programs already in-place, to manage any potential aging effects on their external surfaces. This is performed primarily by System Monitoring Program, which provides for a minimum inspection frequency of one fuel cycle. Leakage or spray from fluid sources other than borated water, would not cause loss of intended function of the SR carbon/low alloy steel SSC.
(Minor leakage or spray would create a corrosion rate on bare metal, of only a few mils per year, and the external surface aging management program would identify this and take corrective action prior to any loss of intended function. Major leakage or spray (more than a gallon per minute) would be readily identified by plant personnel, either by sump trends, system parameters, or area walkdowns. Once identified, the leakage would be isolated and corrective actions taken. Loss of material during the short time of major leakage/spray will not be substantial enough to affect the intended function of these SR components. Plant specific operating experience shows that when leakage has occurred, it has been readily identified (within a couple of weeks or less) and that leak rates of less than one gallon per minute can be identified, and corrective actions are taken before there is any effect on surrounding equipment. The only age-related failures have been pin-hole leaks in Service Water piping, which does not lead to substantial leakage or spray (note that Service Water supply piping is already managed by the Open Cycle Cooling Water Program). Therefore, there is reasonable assurance that SR carbon/low alloy steel components are designed to withstand the potential leakage/spray environment from non-borated systems, without loss of intended function.
- 3. A major concern, however, may be the potential for leakage of boric acid solution onto carbon/low alloy steel components, where if undetected, significant loss of material could occur over a short period of time. Based on the following, reasonable assurance is provided that boric acid wastage will not occur to the level of loss of intended function of the SR component.
- All SR carbon/low alloy steel (including cast iron) components are already included in the Boric Acid Corrosion Program. Recent industry experience (Davis Besse) has heightened awareness of this issue, and resulted in enhancements to this program. This is a very aggressive program that identifies leakage of boric acid solution from any source, and evaluates any potential impact on surrounding materials/components that may get leaked on.
Information on boric acid leakage comes from a number of workgroups including from deconning personnel, system engineer walkdowns, quarterly containment walkdowns, and work order documentation. This information is evaluated and trended within the Boric Acid Corrosion Program. Plant specific operating experience has shown that while minor boric acid leakage has been identified (mostly at packing glands), the program is effective at readily identifying and
controlling this leakage so that it does not affect other components, and well before any loss of intended function of nearby passive components.
- Carbon/low alloy steel components are either painted or insulated (sometimes both), and as such, any boric acid leakage or spray would not be in direct contact with the carbon/low alloy steel surface. Painted surfaces have proven to hold up well, even in boric acid leakage environments, which in turn protects the underlying carbon/low alloy steel from the boric acid attack. Insulation will also prevent the boric acid leakage from directly contacting the carbon/low alloy steel components. Evidence of leakage (boric acid residue) on insulation would lead to removal of the insulation to evaluate the underlying metal surface.
- Non-safety related systems containing boric acid solutions are all fabricated from stainless steel. The non-safety portions of borated systems are typically below the temperature threshold for cracking, and have had excellent operating experience with respect to loss of material. Leakage that has been identified is normally at packing glands or bolted connections. Leakage at these locations is seldom more than a few drops per minute. Through-wall leakage due to age-related degradation on these systems has not been identified at PBNP. The chemistry controls that are applied to the in-scope borated systems are the same chemistry controls that are used for the out-of-scope borated systems.
Therefore, there is reasonable assurance that significant leakage or spray from non-safety borated systems will not occur.
The above discussion provides reasonable assurance that SR carbon/low alloy steel components are also designed to withstand the potential leakage/spray environment from borated systems, without loss of intended function.
NRC Question RAI- 2.1.2 First Equivalent Anchor Definition - 10 CFR 54(a)(2)
The PBNP LRA Section 2.1.2.1.2, page 2-19, states, under, NSR SSCs Directly Connected to SR SSCs, For NSR SSCs directly connected to SR SSCs (typically piping systems), the NSR piping and supports, up to and including the first equivalent anchor beyond the safety/non safety interface, are within the scope of license renewal per 10 CFR 54.4(a)(2). Although these piping segments are not uniquely identified on the LR boundary drawing, applicable aging effects on these piping segments are managed along with the adjoining SR piping.
The staff requests additional information to adequately describe and define what is meant by the first equivalent anchor and how it relates to the scoping and screening of 10 CFR 54.4(a)(2)
NSR piping and supports.
NMC Response:
The concept of first equivalent anchor is associated with the Non-Safety Related Attached to Safety-Related concern identified in Interim Staff Guidance ISG-09 regarding implementation of 10CFR54.4(a)(2), and the staff has requested additional detail/clarification of PBNPs definition of first equivalent anchor.
PBNP LRA Section 2.1.2.1.2, p. 2-19 states, For NSR SSCs directly connected to SR SSCs (typically piping systems), the NSR piping and supports, up to and including the first equivalent anchor beyond the safety/non-safety interface, are within the scope of license renewal per 10 CFR 54.4(a)(2). Although these piping segments are not uniquely identified on the LR boundary drawings, applicable aging effects on these piping segments are managed along with the adjoining SR piping.
The NSR pipe supports are addressed in a commodity spaces approach wherein all supports in the areas of concern are included in scope. The directly connected non-safety related piping will be age managed using the same programs that manage the safety-related piping. This process conforms to the requirements for the NSR SSCs directly connected to SR SSCs per 10CFR54.4(a)(2) and draft Interim Staff Guidance ISG-09.
As background, first equivalent anchor refers to a piping stress analysis modeling practice wherein a piping systems analysis boundary cannot be properly defined by physical anchors, or when a large piping system needs to be broken down into smaller and more manageable piping subsystems. In these cases, an overlapping analysis technique is used whereby the main portion of the piping analysis that is being evaluated is extended beyond the boundaries of interest sufficiently far to ensure the effects of the overlapped portions of piping are adequately transmitted to the main piping of interest and piping beyond the overlap region is effectively isolated from the main piping.
Current piping stress analysis practice at PBNP with respect to the use of the overlapping technique and equivalent anchors is described in design installation guideline DG-M09 Design Requirements for Piping Stress Analysis. Section 5.2.9 of DG-M09 states, the use of overlapping techniques is not encouraged for PBNP analyses and should only be used where justified. An informal evaluation of the desirability of adding a structural anchor is recommended prior to initiating an overlap analysis. When the overlap technique is used, current guidance states, the boundaries of the overlapped portions shall include at least two supports acting in each orthogonal restraint direction. (With properly documented justification, the overlapped portion may be restrained with less than two separate restraints in each orthogonal direction). The guideline goes on to state the treatment of the Seismic Category I/non-seismic interface in a piping system is handled in a similar manner. The piping in the overlapped portion shall be restrained in such a way that it contains at least two supports acting in each orthogonal restraint direction. This is done to include the effects of non-seismic piping on Seismic Category I piping in cases where a physical anchor does not exist to separate the lines. In cases where a physical anchor does exist, the Category III piping up to the anchor shall be included in the Seismic Category I model. This guidance ensures that truncated piping beyond the overlap region (or anchor) is effectively isolated from the main piping while ensuring the integrity of the safety-related main piping stress and support analyses.
A majority of the PBNP pipe stress analyses of record were reanalyzed in the early 1990s in response to IE Bulletin 79-14 using the criteria discussed above. The remaining analyses were
validated as part of this effort, and therefore were not revised. These reanalyzed and validated analyses are part of PBNPs existing design basis and are the qualifying stress analyses of record.
In summary, PBNP has included all the attached non-safety related piping and supports up to and including the first equivalent anchor beyond the safety/non-safety interface into the scope of License Renewal. The NSR pipe supports will be managed in a commodity spaces approach and the attached non-safety related piping will be managed using the same programs that manage the safety-related piping. This meets the requirements for the NSR attached to safety-related requirements of 10 CFR 54.4(a)(2) and draft interim staff guidance ISG-09.
NRC Question RAI-2.1.3 Flow Accelerated Corrosion affect on Piping Section Scoping -
The PBNP LRA Section 2.1.2.1.2, pages 2-20 & 21, under Piping Supports states, All NSR supports for non-seismic or Seismic II/I piping systems with a potential for spatial interaction with safety related SSC, will be included within the scope of license renewal per 10 CFR 54.4(a)(2). These supports will be addressed in a commodity fashion, within the civil/structural area review. As long as the effects of aging on the supports for these piping systems are managed, falling of piping sections, except for flow accelerated corrosion (FAC) failures, is not considered credible, and the piping section itself would not be in-scope for 10 CFR 54.4(a)(2) due to physical impact hazard (although the leakage or spray may still apply).
The staff requests additional information to adequately describe why the falling of piping sections is not considered credible, and why the piping section itself would not be in-scope for 10 CFR 54.4(a)(2) due to physical impact hazard. Please describe how the management of FAC relates to the scoping and screening of 10 CFR 54.4(a)(2) Seismic II/I piping systems that could cause these types of failures.
NMC Response:
NSR pipe segments for the purposes of Criterion 2 scoping, have essentially three potential failure modes.
- 1) NSR Low or Moderate Energy piping, regardless of seismic classification, could also fall on or otherwise physically impact SR SSCs. However, earthquake experience data has shown that pipe (even aged pipe) does not fall during earthquakes as long as its supports stay intact.
If aged pipe does not fall during earthquakes as long as its supports stay intact (bounding condition), it is assumed that aged pipe will stay intact and not fall when the pipe is subject only to the aging process. Therefore, all NSR supports for piping systems with any potential spatial interaction with SR SSCs, will be included in-scope, and age managed. The managing of the NSR supports will ensure that these supports remain intact, and thereby also ensuring that the NSR pipe will not fall or otherwise impact SR SSCs. This then eliminates the need to include the low or moderate energy NSR piping section in-scope for potential physical impacts.
- 2) A NSR High Energy piping segment could fail due to Flow Accelerated Corrosion (FAC), and such a failure could result in pipe whip or other physical impact on SR pipe or components in proximity to the failure. A failure is assumed to occur at any point along the high energy piping run. NSR High Energy piping in proximity to SR components would be considered in-scope, as long as a FAC failure in that line and impact on SR components is considered credible. (Note
that effect of spray, leakage or harsh environment, will still be considered for NSR high energy lines, see #3 below.)
- 3) NSR piping, either High, Moderate, or Low Energy, could fail and result in leakage or spray on nearby SR components. High energy piping has an additional potential of creating a harsh environment (high humidity and high temperatures) that some SR components may not be designed for. Sections of NSR piping that could have spray, leakage, or harsh environment effects on vulnerable SR equipment, are considered in-scope.