ML20217M999
| ML20217M999 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 10/22/1999 |
| From: | Cruse C BALTIMORE GAS & ELECTRIC CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9910280102 | |
| Download: ML20217M999 (15) | |
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!- #' g4 Charte) H. Cruse Calvert Cliffs Nuclear Power Plant Vice President 1650 Calvert Cliffs Parkway Nuclear Energy Lusby, Maryland 20657 410 495 4455 q A Memberof the Constellation Energy Group October 22,1999 1 l
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. U. S. Nuclear Regulatory Commission Washington,DC 20555 ,
1 ATTENTION: Document Control Desk
SUBJECT:
Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Additional Information Regarding the License Renewal Application for Calvert Cliffs Nuclear Power Plant. Units 1 and 2
REFERENCES:
(a) Letter from Mr. D. B. Matthews (NRC) to Mr. C. H. Cruse (BGE), dated )
March 21,1999, "Calvert Cliffs Nuclear Power Plcnt, Units 1 and 2, j License Renewal Safety Evaluation Report" l
(b) Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, l dated July 2,1999, " Response to License Renewal Safety Evaluation Report" (c) Letter from Mr. D. L. Solorio (NRC) to Mr. C. H. Cruse (BGE), dated l August 12,1999, " Status of Open and Confirmatory Items from March 21, 1999, Safety Evaluation Report for Baltimore Gas and Electric Company's License Renewal Application for Calvert Cliffs Unit Nos. I and 2" (d) Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated September 28,1999, " Additional Information Regarding the j License Renewal Application for Calvert Cliffs Nuclear Power Plant, Units 1 and 2" (e) . Letter from Mr. D. L. Solorio (NRC) to Mr. C. H. Cruse (BGE), dated ;
September 30,1999," Request for Information Regarding the Potential Aging Effect of Void Swelling" ,
R:ference (a) forwarded the Safety Evaluation Report (SER) for Baltimore Gas and Electric Company's (BGE's) application for the renewal of the operating licenses for Calvert Cliffs Nuclear Power Plant Units 1 and 2, and included certain open and confirmatory items. Reference (b) was BGE's response to the open and confirmatory items. Reference (c) provided a short list of items for which the NRC requested interaction with BGE to seek additional information, clarifications, and to propose an
, acceptable way to resolve these items. Reference (d) provided information based on some of those interactions. Reference (c) requested information icgarding the void swelling degradation mechanism.
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9k1OE80102 991022 NRC Distribution Code A036D PDR ADOCK 05000317 P PDR '
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Document Control Desk
' October 22,1999 Page 2 l
This letter provides , formation, as Attachment (1), associated with the remaining interactions related to
. Reference (c) and other interactions related to the SER, for NRC staff use in finalizing the SER.
l Should you have questions regarding this matter, we will be pleased to discuss them with you.
1 Very tialy yours, l
,. WW STATE OF MARYLAND - :
- TO WIT:
COUNTY OF CALVERT :
1, Charles H. Cruse, being duly worn, state that I am Vice President, Nuclear Energy Division, Baltimore Gas and Electric Company (BGE), and that I am duly authorized to execute and file this response on behalf of BGE. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my persona! knowledge, they are based upon information provided by other BGE employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it to be reliable, w &na---
Subsc ibed and sworn before me, a Notary Public ir and for the State of Maryland and County of l
C ffAf) , this M day of ffC '(A)1999.
WITNESS my Hand and Notarial Seal: 1/ M . 7 Notary Public My Commission Expires: N Date hNk l
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' CHC/RCG/ dim i
. Attachment (1): Additional Information Regarding the License Renewal Application for Calvert Cliffs Nuclear Power Plant, Units 1 and 2 cc: R. S. Fleishman, Esquire C. I. Grimes, NRC J. E. Silberg, Esquire D. L. Solorio, NRC S. S. Bajwa, NRC Resident inspector, NRC A. W. Dromerick, NRC R.1. McLean, DNR H. J. Miller, NRC J. H. Walter, PSC
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,- .,. ATTACHMENT (1) l l
l ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL I APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 & 2 Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant October 22,1999
n j ATTACHMENT (1) 1 ADDITIONAL INFORMATION REGA.RDING Tile LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS (
NUCLEAR POWER PLANT, UNITS 1 AND 2
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stem #1 - Regarding Safety Evaluation Report (SER) Open Item 3.2.3.3.1.1-2 TGSCC ofinsulated RCS piping Baltimore Gas and Electric Company (BGE) performed an aging management review (AMR) evaluation l for external surfaces of piping systems. The evaluation considered all combinations of materials and j environments. The evaluation considered Calvert Cliffs practices that contain necessary guidance to '
retard or prevent corrosion on external surfaces of piping components. Those practices include painting
, and protet .ive coatings application standards and thermal insulation standards.
The staff has indicated that transgranular stress corrosion cracking (TGSCC) of the Reactor Coolant System (RCS) piping would be the result of the presence of chlorides from insulation, concrete, or i contaminated surfaces. However, water, residual stresses, and a specific temperature range are also !
required for the onset of chloride ' induced TG..JC, To address the non-plausibilby of TGSCC of RCS piping in more detail, two of the four contributing factors will be addressed - a sor.rce of chlorides and a source of water.
1 The following Calvert Cliffs Nuclear Power Plant (CCNPP) documentation contains information relative to the insulation installed on RCS piping: Engineering Specification 6750-M-336, Specification for Reactor Coolant System and Steam Generators Insulation; Engineering Standard ES-015 (formerly DS-015), Thermr.1 Insulation; and BGE Drawing 83240, Thermal Insulation for Piping and Equipment. 1 The first of these documents, Specification 6750-M-336, is the specifict. tion that was used for the original innallation of the insulation on the RCS piping. The insulation originally installed on the system was other: (1) reflective insulation composed of all Type 304 stainless steel components; or (2) mineral wool sandwiched between an external stainless steel shell and an inner layer of stainlen sti el foil to cover all surfaces and edges. The specification required that the mineral wool material be taated with sodium
! silicate to act as an inhibitor against stress corrosion cracking (SCC) and that the leachable chloride content be no more than 100 ppm.
Engineering Standard ES-015 identifies that after years of RCS insulation installation and plant operation
- resulting in gradually increased containment heat load, a replacement program for the original insulation
, was initiated. At that time, an engineering evaluation was performed and the decision was made to use l fiberglass insulation in p! ace of the originally specified types. Drawing 83240 was created at the onset of l
this program to provide a controlled document that maintained an as-built status of all insulation installed l in both CCNPP units. This drawing indicates, for RCS piping, where the original insulation is still mstalled as well as where the replacement fiberglass insulation has been installed.
Engineering Standard ES-015 identifies three critical design character stics for insulation on safi:ty-related piping. They are the insulation thermal conductivity, the insulation density (for weight considerations), and the insulation corrosivity. It further identifies that insulation materials used at CCNPP, per design specifications, are to have less than 200 ppm leachable chlorides to control the possibility ofinsulation-initiated SCC.
Drawing 83240 contains all of the insulated s'ainless steel piping classes that are identified as being within the scope oflicense renewal in the RCS AMR Report. All of these piping classes are insulated and, with the exception of a small number of ychhally exempted cases, are covered with stainless steel jackets. The exempted lines have undergone u. engmes. ring evaluation.
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l ATTACHMENT (1) !
ADDITIONAL INFORMATION REGARDING Tile LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS ;
NUCLEAR POWER PLANT, UNITS 1 AND 2 '
Transgranular stress corrosion cracking f the external surfaces of RCS piping is not plausible because the stainless steel jacket and limited chloride content of the insulation prevents exposure of the piping surfaces to the wetted chloride environment needed for TGSCC to occur. For the few instances where fiberglass insulation is installed without a stainless steel jacket, engineering justification for the equivalency has been formally documented.
Additionally, the hypothesis that a leak could cause the wettir.g of piping externals with chloride contaminated water resulting in TGSCC is an event-driven scenario, not an aging or aging management scenario. Any kind of leak that could cause such wetting in containment would be detected and corrective actions would be taken accordingly. It would be a short term anomaly.
Further, after obtaining and performirg detailed reviews of complete copies of the licensee event reports j from the list sent to CCNPP as examples of the occurrence of SCC within the industry, it was found that l these events do not involve aging or aging management. They were event-driven scenarios of one form j or another. '
It is, therefore, BGE's conclusion, because of the CCNPP insulation design considerations and because l only an event-driven scenario could result in the remote possibility of the wetting of RCS piping with .
chloride contaminated water, that TGSCC of the RCS piping is not a plausible aging effect.
l TGSCC of Un-insulated RCS Piping Calvert Cliffs engineering standards and drawings generally require that all piping with a maximum l normal operating (process) temperature above 160 F be insulated and jacketed with stainless steel. All l
RCS piping within the scope of license renewal is required to be insulated by this criteria. The only portions of the RCS that would not be insulated are instrument lines that are normally 160 F or colder.
For SCC to occur, all the contributing factors must be present. If any one of these factors is not present, SCC will not occur. The instrument lines in question would not be susceptible to SCC because at least two of the factors are not present: !
l e There is not a plausible source of chloride contamination; and j
=- Since the lines are un-insulated, there is no enveloping material to support an aqueous l environment. !
i In addition, a third factor is not expected to be present:
- The temperature on the outside diameter of the instrument lines should be below the threshold for SCC (150 F). The instrument lines are dead-headed and the temperature of the outside diameter will approach containment ambient temperature.
Concerning Whether Air Pockets Promoting SCC Could Exist in the RCS i Complete venting of the RCS precludes the existence of air pockets that could promote SCC. The following venting operations are currently performed:
- The pressurizer is vented in accordance with CCNPP Operating Procedure OP-7, Shutdown Operations; e The reactor vessel is vented in accordance with CCNPP Operating Procedure OP-7, 1
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J ATTACHMENT (1)
' ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS !
NUCLEAR POWER PLANT, UNITS I AND 2 l
e Steam generator tube sweeps are performed in accordance with CCNPP Operating Procedure OP-7; e
Reactor coolant pump seals are vented in accordance with CCNPP Operating Instruction OI-lE, ;
Reactor Coolant Pump Seal Venting Procedure; The regenerative heat exchanger is vented in accordance with CCNPP Operating Procedure OP-7; The hot leg sample line is vented in accordance with CCNPP Operating Procedure OP-7; and !
- The CEDM/RVLMS housings are vented in accordance with CCNPP Technical Procedure RV-25, CEDM Housing Venting. !
1 Item #2 - Regarding SER Open Item 3.2.3.2.12 Reference (1) indicates that a preventive measure is necessary regarding the cracking in the reactor pressure vessel head seal leakage detection lines that cecurred in Unit 2 in 1994. Baltimore Gas and Electric Company believes the practice initiated at that time of blowing these lines dry following each I refueling outage provides this preventive measure, and commits to continuing this practice. Details l associated whh this particular aging scenario are provided below.
Baltimore Gas and Electric Company discussed operating experience with the reactor pressure vessel head closure seal leakage detection lines on pages 4.1-8 and 4.1-46 of the BGE License Renewal Application (I.RA). The Unit 2 line had cracked, due to an ever increasing concentration of contaminants in the vicinity of tne cracking because of repeated boil-ofYof the ligid iett in the line at the end of each refaeling, eventually reaching levels high enough to cause 'IGSCC. The lines in both units were subsequently replaced. Measures were taken to prevent recurrence in that the lines were to be drained l and blown dry every refueling outage. The practice of blowing the lines dry changed this aging scenario.
l These reactor vessel flange leak detection lines were downgraded from B31.7 Class I (RCS pressure boundary) to B31.7 Class II based on the existence of an orifice in the reactor vessel flange that limits flow rate from a break in the line to less than normal RCS makeup capacity.
These lines are not readily accessible in the areas (now dry) where leakage previously occurred. These areas are completely within the reactor vessel annulus region, which is a confined space below the l permanent pool seal / shield. Visual examinations in these areas would require an extended entry into a contaminated, confined space. Scaffolding weuld have to be erected. Respirators would be required to prevent internal conte.mination of personne; due to the presence of loose surface contamination.
Insulation would need to be removed to inspect the line. In summary, the job woald involve a significant time period and multiple personnel working in a contaminated and confined space with dose rates from 0.lR/hr to 0.3R/hr gamma, and contact readings as high as 0.6R/hr gamma.
Item #3 - Regr rding SER Open item 3.2.3.2.1-4 Baltimore Gas and Electric Company will include RCS small bore fittings and branch connections in the Age-Related Degradation Inspection (ARDI) Program, for detecting cracking mechanisms. This program will examine representative components to determine if they will be capable of performing their intended function under all current licensing basis design loading conditions during the period of extended operation.
The ARDI Program is defined in the CCNPP Integrnied Plant Assessment Methodology presented in Section 2.0 of the application.
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ATTACIIMENT (1)
ADDITIONAL INFORMATION REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 The elements of the ARDI Program will include:
Determination of the examination sample . size based on plausible aging effects; Identification of inspection locations in the system / component based on plausibb aging effects and consequences ofloss of component intended function; Determination of examination techniques (including acceptance criteria) that would be effective, considering the aging effects for which the component is examined; e Methods for interpretation of examination results; e
Methods for resolution of adverse examination' findings, including consideration of all design l loadings required by the current licensing basis and specification of required corrective actions; and Evaluation of the need for follow-up examinations to monitor the progression of any age-related I degradation.
Any corrective actions that are required will be taken in accordance with the CCNPP Correctiv Actions Program, and will ensure that the components will remain capable of performing their intended function under all current licensing basis conditions.
These inspections will be performed prior to, and near, the end of the current license period (e.g.,no sooner than five years prior to the expiration of the current license) for each unit.
Item #4 - Regarding SER Confirmatory Item 2.2.3.23.2.1-1 Reference (2) addressed 24 requests for additional information on the Calvert Cliffs Reactor Vessel Internals (RVI) System, a few of which involved RVI device type CEASB (control element assembly
{CEA] shroud and bolts). Reference (3) forwarded NRC's SER on BGE's LRA and contained Confirmatory item 3.2.3.2.1-4, which also involved the CEASB. Reference (4) previded BGE's response to SER open and confirmatory items, including the response to Confirmatory item 3.2.3.2.1-4.
l Reference (1) requested further BGE interactions with NRC Staff on certali open and confirmatory items, including Confirmatory item 3.2.3.2.1-4. Those interactions have caused BGE to continue to assess our integrated plant assessment results for the CEASB. The results of that continued assessment l are provided below and represent replacement of the response to Confirmatory Item 3.2.3.2.1-4 contained i
in Reference (4).
- CEA Shroud and FAP Functions The CEA shrouds and Fuel Alignment Plate (FAP) are part of the RVI and contribute to the RVI functions as discussed in the following excerpts from CCNPP Updated Final Safety Analysis Report (UFSAR), Revision 15, Section 3.2.3.4.:
"Ihe reactor internals are designed to perform theirfunctions safely during steady state conditions and DBEs: The internals can safely withstand the forces due to deadweight, handling, system pressure, flow-induced pressure drop, flow impingement, temperature differential, shock, and vibration. The structural components satisfy stress values given in the ASME B&PV Code,Section III.
Thefollowing limitation on stresses or deformations are employed to ensure capability of a safe and orderly shutdown in the combined event of earthquake and major loss-of-coolant accident 4
i ATTACIIMENT (1) 1 ADDITIONAL INFORMATION REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 (l.OCA). For reactor vessel internal structures, the stress criteria are given in Table 3.2-1 of the UFSAR. The intent ofthe limits in this table is asfollows:
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- a. Under design loading plus design earthquake forces the critical reactor vessel internal i structures are designed within the stress criteria established in ASME B&PY Code,Section III, Article 4;
- b. Under normal operating loadings plus maximum hypothetical earthquakeforces, the design l criteriapermits a small amount oflocalyielding;
- c. Under normal opera:ing loading plus reactor coolant pipe rupture loadings plus maximum hypothetical earthquakeforces, permanent deformation is permitted by the design criteria.
To properlyperform theirfunctions, the critical reactor internal structures are designed to satisfy 1
the additionaldeflection limits described below, in addition to the stress limits given in Table 3.21 i ofthe UFSAR. i Under normal design loadings plus design earthquakeforces or normal operating loadings phis maximum hypothetical earthquakeforces, deflections are limitedso that the CEAs canfunction and adequate core cooling is maintained. Under normal operating loadings plus maximum hypothetical earthquakeforces plus pipe rupture loadings, the deflection design criteria depend on the si:e of the piping break. If the equivalent diameter of the pipe break is no larger than the largest line connected to the main reactor coolant lines, deflections are limited so that the core is held in place, the CEAs fsmetion normally, and adequate core cooling is maintained. Those
- deflections which would "ence CEA movement are limited to less than two-thirds of the deflection required to prevent CEA fimetion. For pipe breaks larger than the above, the criteria l are that thefuel is held in place in a manner permitting core
- onling and that adequate coolant flowpassages are maintained. For these majorpipe break si:es, CEA insertability is not required to achieve shutdown because the rapid voiding during the ensuing blowdown and the subsequent refill with the borated safety injection water ensures adequate shutdown margin for the reactor.
i For the larger break si:es, critical components are restrainedfrom buckling byfurther limiting the stress levels to two-thirds ofthe stress level calculated to produce buckling. "
The upper guide structure (UGS) assembly consists of the UGS support plate assembly, CEA shroud assemblies, and the FAP. The UGS assembly aligns and laterally supports the upper end of the fuel asamblies, maintains CEA spacing, supports the fuel assemblies during operation, prevents the fuel assemblies from being lifted out of position during severe accidents, protects the CEAs from the effect of reactor coolant cross-flow in the upper plenum, and supports the top-entry incore instrumentation. There are 20 dual and 45 single CEA shrouds. The CEA shrouds extend from the FAP to an elevation above the UGS support plate. The FAP is designed to support and align both the upper ends of the fuel assemblies and the lower end of the CEA shrouds. The FAP also has four equally-spaced slots in the outer edge that engage with Stellite hardfaced lugs protruding from the core shroud to limit lateral motion of the UGS assembly.
At the lower end of each CEA shroud, flow channels protrude approximately 2.25 inches into a precision-machined 6.810-inch diameter hole in the 3-inch-thick FAP. This serves as an alignment feature between the CEA shroud and the FAP. Radial clearances are 0.016 inches and 0.021 inches for single and dual shrouds respectively. In order that the FAP may be removed with the UGS for refueling and to prevent relative movement between the FAP and the CEA shroud, the CEA shrouds are attached to the FAP by 5
ATTACHMENT (1)
ADDITIONAL INFORMATION REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS !
NUCLEAR POWER PLANT, UNITS 1 AND 2 threaned structural fasteners (bolts). The bolts are installed through the under side of the FAP and thread into the CEA shrouds.
The cross-sectional area of the flow channel protrusion into the FAP is slightly less than the cross-sectional area of the bolts that connect the FAP to the CEA shroud. The bolts are preloaded, thus imparting a vertical compressive force at the interface between the bottom surface of the CEA shroud and the upper surface of the FAP. There are 8 bolts for each single CEA shroud and 16 for each dual CEA shroud. The bolts are captured in place by means of a counter-bore in the FAP and a lock bar that engages with precision-machined castellated slots in the bead of the bolts. The lock bar is welded to the FAP; no welding is permitted on the 7/8-inch diameter bolts.
Normal Operation During normal operation the fuel assembly hold-down springs and the hydraulic loads provide vertical upward forces on the FAP that are directly transmitted to the CEA shrouds and serve to force the FAP against the CEA shrouds. The CEA shrouds have horizontal hydraulic forces imposed on them from the reactor coolant cross-flow that is exiting from the UGS plenum to the reactor vessel outlet nozzles. Lateral displacement of the lower end of the CEA shroud is prevented by the tight l radial clearances discussed above, by the frictic.nal forces resulting from the upward flow, and fuel l assembly spring forces pressing the FAP against the CEA shrouds. I Upset and Faulted Conditions: When considering both seismic and loss-of-coolant accident, the vertical load application to the FAP is consistent with normal operation in the respect that the FAP is contained between the bottom surface of the CEA shrouds and the top of the fuel assemblies. The FAP upward forces are transmitted directly to the CEA shrouds with no additional load on the bolts. The vertical downward forces on the FAP are resisted by the bolts and the fuel assembly hold-down springs.
The horizontal forces imposed on the FAP are reacted by the CEA shrouds through the preloaded connection and the flow channel protrusions. In the absence of any bolts, the protrusion of the CEA shroud flow channels into the FAP react the horizontal forces. The UGS, CEA shrouds, and FAP would retain their design functions under all design basis loads.
Based on the above qualitative review of the current design W, the CEA shroud bolts are not required for the CEA shroud and FAP functions to be performed during normal and design basis event conditions.
However, the boundary conditions for the CEA shrouds will change when all of the bolts are considered failed. This extreme assumption may result in changes in thu natural frequency of CEA shrouds and could have an effect on the CEA sh 'd response.
Potential for Wear between the FAP and CEA Shroud Flow Channels The radial clearance between the FAP and CEA shroud flow channel protrusions would need to increase significantly (e.g., greater than 0.5-inch from the original 0.016-inch) for CEA shroud alignment and CEA insertion functions to be affected during normal operating or accident conditions. This could only occur as a result of excessive wear and could only occur if the clamping force holding the FAP against the CEA shrouds were insufficient to prevent !ateral relative movement. Such movement would need to be oscillatory in nature for wear to occur.
Normal Operation: In the unlikely absence of any htact CEA shroud bolts, the lateral flow force on a CEA shroud during normal operation is not sufficient to overcome the friction forces between tne FAP and the CEA shroud or result in excessive oscillatory movement. Therefore, wear cannot occur during normal operation.
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ATTACHMENT (1)
ADDITIONAL INFORMA*alON REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 Upset and Faulted Conditions: Wear during design basis events is not a concern since these are one-time events.
Conclusions An aging effect is considered plausible for a specinc component if, whea allowed to continue without any prevention or mitigation measures or enhanced monitoring techniques, it could not be shown that the component would maintain its capability te perform its intended, passive function throughout the period of extended operation. The underlying function of concern in this instance is maintaining the alignment between the FAP and CEA shrouds so that CEAs function as required and core cooling is maintained.
Because of the tight radial clearances between the CEA shroud now channels and the precision machined holes in the FAP, BGE has determined that the conditions needed for unacceptable wear to occur at the interface between the FAP and CEA shrouds are not credible. The CEA shrouds and FAP will resist vertical and lateral operating and accident loads to the extent necessary for the CEAs to function as required and for adequate core cooling to be maintained.
However, because of the potential to affect the CEA shroud frequency response with the extreme assumption.that all of the CEA shroud bolts are failed, BGE will perform an analysis to confirm the above conclusions. This confirmation will be completed not later than the end of 2002.
Item #5 - Regarding SER Open Item 3.2.3.2.1-3 i
Baltimore Gas and Electric Company's response to SER Open item 3.2.3.2.1-3 in Reference (4) included l a commitment for a one-time visual inspection of a portion of the cladding of one pressurizer. Based on '
subsequent interactions with the NRC staff, involving the information that follows, BGE will not perform this one-time visual inspection.
l The highest fatigue locations in the pressurizer are at the surge nozzle at the inside radius and at the safe- !
end transition. The design cumulative usage factor is approximately 0.75. The next highest location internal to the pressurizer is the spray nozzle, with an approximate cumulative usage factor of.07.
American Society of Mechanical Engineers (ASME)Section XI inspection Category B-D requires a volumetric examination of all full penetration nozzles once every 10 years. The inspection vol:ime would !
include the highest fatigue locations in the surge nozzle. The volumetric exam is capable of detecting a l Daw that has penetrated the cladding and propagated into the base metal. l l
Item #6 - Regarding SER Confirmatory Item 3.2.3.2.1-1 l Reference (4) provided a response to SER Confirmatory item 3.2.3.2.1-1. Subsequent interactions with NRC staff requested responses to four questions, which follow, i 1
Question 1: Provide the basisfor the cut offof the 15 KSI Tensile Stressforpiausibility of thermal aging l in reactor vessel components. This s'wuld be identified as a cut ofin th: >lgmjicance of the impact of 1 thermalaging, notplausibility ofthe ARDM(age-reltted degradation mechanistrJ. l
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ATTACHMENT (1)
ADDITIONAL INFORMATION REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS i ,
NUCLEAR POWER PLANT, UNITS 1 AND 2 1
BGE Response l The selection of 15 ksi as a reasonably low tensile stress was somewhat arbitrary, but represents approximately one-half the yield strength of the material. Baltimore Gas and Electric Company has
' revised this value as discussed below.
l The components that are manufactured from cast aastenitic stainless steel (CASS) and are subjected to both thermal and neutron embrittlement are CEA shrouds and the core support columns in the RVI. It is not currently possible to develop screeninh criteria for determining actual material property degradation of these components. Instead, these components will be screened to determine whether they are subjected to significam tensile stress during normal and upset operation.
For the CASS components subject to both thermal and neutron embrittlement, the loads applied to the components during normal and upset operation will be determined. If the maximum applied load anywhere on the component is less than approximately 5 ksi, then the no further analyses will be performed, and the effects of the embrittlement will be determined to be inconsequential. .
I For the subject CASS components that do experience tensile stresses exceeding 5 ksi under any design j basis condition, the operating history of the components will be reviewed to determine whether any l such conditions have ever happened. As long as the component never experiences an event or condition that imposes a tensile stress that exceeds approximately 5 ksi, the effects of the embrittlement will be determined to be inconsequential.
For the subject CASS components that actually experience tensile stresses that exceed 5 ksi, an enhanced VT-1 inspection (a visual examination capable of % mil resolution) will be performed.
Baltimore Gas and Electric Company will demonstrate that the enhanced VT-1 technique is capable of resolving relevant indications on cast surfaces. If BGE is unable to demonstrate the enhanced VT-1 technique is applicabic to cast surfaces, then an alternative qualified technique will be used.
l Baltimore Gas and Electric Company will continue to participate in industry programs that are currently underway to develop ultrasonic inspection methods for CASS, and could use ultrasonic l techniques in lieu of surface techniques. l l
Baltimore Gas and Electric Company will also follow industry programs that evaluate the combined dE.a of neutron and thermal embri+tlement and modify this program accordingly.
Question #2: Provide a description of the olansfor susceptible piping, base metal- inspect, replace, or 1
what? Regarding the surge line, are there any activities related to NRC Bulletin 88-11 that effectively serve as aging managementfor the surge line?
l BGE Response Components that do not meet the screening criteria described in Reference (4) will be:
- 1. Subject to an augmented inspection combined with a flaw tolerance evaluation; or
- 2. A full leak-before-break evaluation w ill be performed to prove that current inspection requirements are adequate to prevent catastrophic failure; or
- 3. Replaced.
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l A'ITACIIMENT (1)
ADDITIONAL INFORMATION REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 If an augmented inspection / flaw tolerance approach is chosen, the acceptable flaw size for the inspection will be determined as follows:
For non-niobium containing components having less than 25% delta ferrite, a component-specine J-R curve will be estimated using the method of Reference (2) or equivalent. If a component contains niobium or 25% or greater delta ferrite, the actual fracture toughness properties will be determined on a case-by-case basis.
An clastic-plastic fracture mechanics analysis will be performed for the component to determine the critical flaw size that is stable under all anticipated normal and ascident loadings.
This analysis may be component specific, or an analysis that bounds a group of components l may be referenced.
- The critical flaw size will be used to determine the inspection acceptance criteria. The critical j flaw size minus an allowance for flaw growth during operation until the next inspection will equal the allowable flaw size.
The inspection will be conducted as follows:
- If available inspection technology permits, a volumetric examination appropriate to a pressure retaining weld in an ASME Section XI category B L-1, B-M-1, or BJ component will be performed.
. If ava!!able inspection technology does not permit a volumetric examination, an alternative approach similar to that described in Code Case N-481 will be usec' Regarding NRC Bulletin 88-11, BGE has re-analyzed the surge line to address thermal stratification.
All locations were found to meet fatigue limits and are being managed under the Fatigue Monitoring Program.
Question 3: Confirm the presence / absence ofCASS valves (that includes - bodies & bonnets) in the RCS, since the LRA is ambiguous on this item.
BGE Response The RCS includes valves with CASS bodies and bonnets. With few exceptions, these valves aie vent, drain, and instrument isolation valves that are not subject to RCS How and are configured (distance and geometry) so that they are not regularly subjected to temperatures exceeding 500 F. Although not c!carly stated in the LRA, CASS valves (bodies and bonnets) in the RCS are subject to the CASS evaluations.
Question 4: Provide the basisfor not requiring inspection ofniobium containing CASSparts exceptfor reactor vesselinternals.
BGE Response Baltimore Gas and Electric Company did not intend to exclude niobium containing RCS CASS parts from inspection. It should be noted that BGE review of material specifications and certifications has not identified any components for which niobium was intentionally added.
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ATTACHMENT (1) ;
i ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS ;
, NUCLEAR POWER PLANT, UNITS 1 AND 2 l
1 Item #7 - Regarding Confirmatory Item 3.2.3.2.1-3 Baltimore Gas and Electric Company provided a response to Confirmatory Item 3.2.3.2.1-3 in :
Reference (4). NRC staff requested clarification for a certain portion of that response. The two !
following paragraphs are provided as direct replacements for the second and third paragraphs under "Results of Susceptibility Evaluation"in Reference (4). (The references within the quoted paragraphs are !
references in Reference (4) and are not spelled out at the end of this attachment.): '
"Using the current methodology (the EPRI Model) outlined in Enclosure (6) to Reference (11), a 34%
chance of a 75% through-wall crack is reached in the year 2034 for Calvert Cliffs Unit 1. Therefore, ir. the year 2029, Calvert Cliffs Unit I will reach the <5 EFPY category as defined by the histogram.
Baltimore Gas and Electric Company will conduct a volumetric inspection of vessel head penetrations j at a date no later than 5 years prior to the date at which the probability of a 75% through-wall crack in
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at least one CEDM becomes 34%. This date will be determined using the aforementioned EPRI model or an improved model that may be developed in the future. The current model prediction of a 34% probability of a 75% through-wall crack in the Unit I CEDM nozzles. would require BGE to schedule this inspection for no later than 2029.
j "For Calvert Cliffs Unit 2, the probability of one RV head penetration developing a 75% through-wall crack is only 10% at the end of the extended license period. A 34% probability of a 75% through-wall crack in not reached until e,7 , EFPY from January 1,1997, which falls in the year 2044 or later (the actual date depends on the cai.,acity factor of Unit 2). Therefore, BGE does not intend to schedule any ;
volumetric inspections of the Unit 2 CEDM penetrations between now and the end of extended life in !
2036. However, if a revised model were applied which indicated a 34% probability of a 75% through-wall crack in a CEDM was reached prior to the end of the extended license period for Unit 2, a vobimetric inspection wold be scheduled accordingly."
Item #8 - Regarding void Swelling i
Reference (1) requested interaction regarding void swelling and BGE briefly discussed this issue as 1 l
Item #8 in Reference (6). Reference (7) further discussed void swelling and indicated that void swelling needs to be to be included in BGE's LRA. In response, while we maintain that void swelling is not ,
plausible:
l BGE agrees to participate in industry programs to address the significance of void swelling.
l l e Prior to year 40, if BGE determines that void s, welling is a significant issue in the renewal term, l BGE agrees to develop a sufficient inspection program (including the basis, methods, locations to be examined, timing frequency and acceptance criteria) for management of the issue based upon
) the results of the inuustry programs, and performed in conjunction with the 10-year inservice i inspection program.
- If BGE has made its determination far enough in advance of the end of the current license period BGE will implement the inspection program prior to the end of that period. Otherwise, the program will be implemented as soon a practicaHe thereafter.
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ATTACHMENT (1)
ADDITIONAL INFORMATION REGARDING Tile LICENSE RENEWAL APPLICATION FOlt CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 Item #9 - Regarding Safety Evaluation Report (SER) Open Item No. 2.2.3.8-1 Baltimore Gas and Electric Company stated in Reference (6), Item #3, that it agreed to cc' sider certain components of the Station Blackout (SBO) Diesel Generator (DG) Building No. 2 within the scope of license renewal and subject to an AMR, and that results would be provided later. Those results are included here.
The SBO DG Building No. 2 is analyzed in the CCNPP UFSAR (Section 8.4.5.1.e) for tornado loads, and seismic loading, to preclude failure and subsequent impact of the structure on the adjacent IA DG Building No.1. There is also a general statement about anchoring equipment on the roof to resist tornado loads. However, the equipment on the roof will not exceed tornado missile guidelines. Therefore, the SBO DG Building No. 2 is considered within scope of license renewal in accordance with 10 CFR 54.4(a)(2).
The only intended license renewal function for the SBO DG Building No. 2 is to prevent impset on the 1 A Building. This is similar to providing structural / functional support to non-safety-related equipment whose failure could directly prevent accomplishment of a safety-related function. Only structural component types that provide this intended function are within scope for license renewal. Because they are all passive, they are also subject to AMR. The SBO DG Building No. 2 structural components have the same potential ARDMs as the 1 A DG Building No.1, which are shown in Reference (8) Table 3.3E-3 on page 3.3E-11. The only plausible aging mechanism for the SBO DG Building No. 2 structural component types is Corrosion of Steel.
The following structural component types provide the function described above. Those for which Corrosion of Steel is plausible are marked with r.n asterisk (*):
- Foundations; e Steel Beams *;
e Concrete Columns; e Baseplates*; !
- Concrete Walls; e Floor Framing *; !
- Concrete Basemat; e Roof Framing *; and
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Cast-in-Place Anchors";
e e Steel Bracing *.
- Post-Installed Anchors *;
I Corrosion of Steel for components in the SBO DG Building No. 2 will be managed by existing program (CCNPP Administratise Procedure) MN-l-319," Structure and Systems Walkdowns." A full description of this program is provided on Reference (8), pages 3.3E-18 and 19. The structure and system walkdowns will ensure that these components perform their intended function during the period of extended operation.
REFERENCES
- 1. Letter from Mr. D. L. Solorio (NRC) to Mr. C. H. Cruse (BGE), dated August 12,1999, " Status of Open and Confirmatory Items from March 21,1999, Safety Evaluation Report for Baltimore Gas and Electric Company's License Renewal Application for Calvert Cliffs Units Nos. I and 2"
- 2. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated November 19,1998,
" Response to Request for Additional Information for the Review of the Calvert Cliffs Nuclear i
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ATTACHMENT (1)
ADDITIONAL INFORMATION REGARDING TIIE LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT, UNITS 1 AND 2 Power Plant, Units 1 & 2, Integrated Plant Assessment Report for the Reactor Vessel Internals System"
- 3. Letter from Mr. D. B. Matthews (NRC) to Mr. C. H. Cruse (BGE), dated March 21,1999, "Calvert Cliffs Nuclear Power Plant, Units 1 and 2, License Renewal Safety Evaluation Report"
- 4. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated July 2,1999,
" Response to License Renewal Safety Evaluation Report"
- 5. Chopra, O. K., Shack, W. J., " Assessment of Thermal Aging Embrittlement of Cast Stainless Steels,"NUREG/CR-6177, ANL-94/2
- 6. Letter from Mr. C. H. Cruse (BGE) to NRC Document Contrel Desk, dated September 28,1999,
" Additional Information Regarding the License Renewal Application for Calvert Cliffs Nuclear Power Plant, Units 1 and 2"
- 7. Letter from Mr. D. L. Solorio (NRC) to Mr. C. H. Cruse (BGE), dated Septernber 30,1999,
" Request for Information Regarding the Potential Aging Effect of Void Swelling"
- 8. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated April 8,1998,
" Application for License Renewal" i
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