ML20236W513
| ML20236W513 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 07/30/1998 |
| From: | Cruse C BALTIMORE GAS & ELECTRIC CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9808060027 | |
| Download: ML20236W513 (30) | |
Text
CHARLES II. CRUSE Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant Nuclear Energy 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 410 495-4455 l
l July 30,1998 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION:
Document Control Desk
SUBJECT:
Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Responses to Requests for Additional Information for the Review of the Calvert Cliffs Nuclear Power Plant, Units 1 & 2, Integrated Plant Assessment Reports for the Feedwater System and Diesel Fuel Oil System
REFERENCES:
(a)
Letter from Mr. C.11. Cruse (BGE) to NRC Document Control Desk, dated May 23,1997," Request for Review and Approval of System and Commodity Reports for License Renewal" (b)
Letter from Mr. D. L. Solorio (NRC) to Mr. C. H. Cruse (BGE), dated February 13,1998," Request for Additional Information for the Review of the Calvert Cliffs Nuclear Power Plant, Units 1 & 2, Integrated Plant Assessment Report for the Feedwater System" 1
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(c)
Letter from Mr. D. L. Solorio (NRC) to Mr. C. H. Cruse (DGE), dated February 19,1998," Request for Additional Information for the Review of the Calvert Cliffs Nuclear Power Plant, Units 1 & 2, Integrated Plant
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Assessment Report for the Diesel Fuel Oil System" go Reference (i) forwarded Baltimore Gas and Electric Company's (BGE's) first four system and commodity reports for license renewal. References (b) and (c) forwarded questions from NRC staff on two of those four reports, Feedwater System and Diesel Fuel Oil System.
References (b) and (c) requested schedules for the submittal of BGE's responses within 30 days of receipt. After discussions with NRC staff, it was agreed that developing these schedules was not practical prior to a public meeting to provide clarifications to the staffs questions. That public meeting occurred on May 6,1998. As a result, responses can now be provided. Certain questions remain under deliberation within NRC staff. Additionally, public meetings were conducted in late June for BGE to provide technical briefings in areas related to some of these questions.
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l 980O'd600dd 980730 PDR ADOCK 05000317 P
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Document Control Desk July 30,1998 Page 2 t
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Attachments (1) and (2) forward our responses to the questions contained in References (b) and (c),
l respectively. Those questions under deliberation are marked as such.
Should you have further questions regarding this matter, we will be pleased to discuss them with you.
j Very truly yours, l
l A
bY STATE OF MARYLAND
- TO WIT:
i COUNTY OF CALVERT 1
I, Charles H. Cruse, being duly sworn, 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 l
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 personal knowledge, they are based upon information provided by other BGE employees and/or consultants. Such l
mformation has been reviewed in accordance with company practice and I believe '
be reliable.
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Subscripd and sworn before me a Notary Public in and for the State of Maryland and County of
[1XJAAi)
.this IOfldayof Oy A /.1998.
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WITNESS my Hand and Notarial Seal:
Fl4AA >
2nd Ud Notary Public My Commission Expires:
$,A 200A Date CHC/DLS/ dim Attachments: (1) Response to Request for Additional Information; Integrated Plant Assessment Report for the Feedwater System (2) Response to Request for Additional Information; Integrated Plant Assessment Report for the Diesel Fuel Oil System cc:
R. S. Fleishman, Esquire C. I. Grimes, NRC J. E. Silberg, Esquire D. L. Solorio, NRC
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S. S. Bajwa, NRC Resident Inspector,NRC A. W. Dromerick, NRC R. I. McLean, DNR H. J. Miller, NRC J. H. Walter, PSC j
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ATTACHMENT (1) l l
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; i
j INTEGRATED PLANT ASSESSMENT REPORT FOR THE FEEDWATER SYSTEM l
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Baltir.1 ore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 30,1998
ATTACHMENT (1) l l
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM NRC Oues' tion No.1 l
Provide a discussion of the operating experience review relating to the Feedwater System (FWS).
l Identify the NRC generic communications and other industry experience that were identified as potentially applicable to aging in the FWS.
RGE Response Baltimore Gas and Electric Company (BGE) understands that this question remains under l
deliberation within the NRC staff.
l NRC Ouestion No.1 Provide a description of the evaluation that resulted in the exc!usion of the following aging effects as plausible for the FWS:
a) Fatigue assisted corrosion, stress assisted corrosion, (as described in NRC Bulletin 79-13
[" Cracking in Feedwater System Piping"), Information Notice llN} 84-87 (" Piping Thermal Deflection Induced by Stratyied Flow"), and IN 93-20 [ Thermal Fatigue Cracking ofFeedwater Piping to Steam Generators"]), and other phenomenon (that may not have been "/zdly understood" in 1979) that have resulted in cracking of feedwater (FW) nozzle-to-pipe welds.
b) Stress corrosion cracking, vibration and thermal fatigue, and dynamic loading concerns that have resulted in cracking of FWS piping.
BGE Response Fatigue assisted corrosion is considered under the fatigue age-related degradation mechanism (ARDM) in the aging management review (AMR). Stress assisted corrosion can be considered stress corrosion cracking (SCC) or corrosion fatigue. Corrosion fatigue is also considered under the fatigue ARDM in the AMR.
The FW piping from the Containment penetration to the steam generator (SG) feed nozzle is 1
identified as a single component at Calvert Cliffs. Fatigue is considered plausible for the horizontal portion of this piping from the SG safe end-to-reducer weld out to the first elbow. A discussion of aging management results is provided in Section S.9 of the License Renewal Application (LRA).
For piping from the motor-operated valve (MOV) to the containment, fatigue is considered not plausible. The explanation in the AMR is:
"The feedwater piping components in this group are far removed from the S/G, and are not subject to rapid thermal transient conditions associated with the S/G feedwater nozzle / piping thermal stratification conditions. The source of thermal cycling for the piping in this group is plant start-ups/ shutdowns and secondary plant transients.
These thermal cycles are conservatively enveloped by the design code requirements associated with this piping
([American National Standards InstituteJ ANSI B31.7/B31.1 rules for calculating allowable stress range for expansion stresses) which allow 7000 full temperature range cycles before applying additional stress limitations.
The code requirements conservatively envelope expected plant thermal transients through the period of extended operation; therefore, thermal fatigue is not considered plausible for this group of piping components."
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ATTACHMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR THE FEEDWATER SYSTEM keferences include:
Environmental Effects on Components Commentary for American Society of Mechanical l
Engineers (ASME)Section III, Electric Power Research Institute (EPRI) Report No. NP-5775, April 1988 Calvert Cliffs Nuclear Power Plant (CCNPP) Updated Final Safety Analysis Report (UFSAR),
e Revision 18; Chapter 4 - Reactor Coolant and Associated Systems UFSAR, Revision 18, Chapter 10 - Steam and Power Conversion Systems e
ANSI B31.1,1967; Power Piping Code e
y ANSI B31.7,1969; Nuclear Power Piping Code e.
Various Condensate and FWS Drawings and Isometrics e
For FW piping in the AMR, SCC is considered not plausible. The explanation in the AMR is:
Control of FW chemistry (particularly oxygen concentration) prevents the environment necessary for l
SCC of carbon steel material. Therefore, this ARDM is not plausible.
References include:
Environmental Effects on Components Commentary for ASME Section III EPRI Report l
No.NP-5775, April 1988; and The secondary chemistry procedure.
e It might appear that SCC should be considered plausible, however; a review of the SCC discussion in the reference makes it clear that carbon steel is not susceptible to SCC in pressurized water reactor environments. As a matter of fact, it is recommended as an alternate material to replace susceptible materials. There is a s:arcity of documentation about non-existent corrosion effects.
NRC Ouestion No. 3 In Reference (1), for Request for Additional Information (RAI) No. 8 [89), you stated that the FWS heaters were not within the scope of license renewal. Expand upon your previous response by specifically addressing two of the three issues identified in IN 96-41 to determine why the FW heaters should not be included within the scope. Information Notice 96-41 describes the following concerns:
"There are three aspects of this event which have generic implications. First, with a loss ofsecondary l
plant eficiency, " programmed" Tm can no longer reliably represent core thermalpower. Second, the venturi-based input into the computer-based calorimetric system may not be accurate with cold seedwater." The third concern is not applicable to license renewal. Provide an assessment for the two concerns presented above as they relate to the scope required by the rule.
BGE Response Baltimore Gas and Electric Company's Industry Experience Assessment Unit has reviewed IN 96-41,
" Effects of Decrease in Feedwater Temperature on Nuclear Instrumentation," that alerted addressees to the potential for operating above licensed power as a result of a decrease in FW temperature event
]
affecting nuclear instrumentation..The Industry Experience Assessmem Unit determined that IN 96-41 was applicable to CCNPP. Updated Final Safety Analysis Report Chapter 14.7, describes the excess FW heat removal event involving the loss of both high pressure FW heaters. This event is bounded by the excess load event and the Thermal Margin / Low Pressure, Variable High Power or 2
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ATTACHMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR THE FEEDWATER SYSTEM i
kow SG Pressure trips will prevent exceeding departure from nucleate boiling ratio and fuel
. limits. Therefore, the high pressure FW heaters do not meet livense renewal scoping criteria.
l Calvert Cliffs does not have a turbine runback or any other system that automatically attempts to l
. continue power operation following (or during) an excess FW heat removal event. Calvert Cliffs uses j
a " Programmed" Cold Leg Temperature versus T The computer-based calorimetric incorporates m.
i the effect of colder FW.
NRC Ouestion No. 4
-In Reference (1), for RAI No. 88, you stated that the FWS isolation function does not rely on the regulating valve or any other block ulve as a backup in the event that the FWS isolation MOV fails to l-close. Instead, CCNPP's design relies on tripping the main feedwater (MFW) pumps, heater drain l
pumps, and condensate pumps as a backup in the event that the isolation MOV fails to close. Provide a justification for excluding the MFW pumps, heater drain pumps, and condensate pumps from the scope l
of renewal. In addition, identify the input signals to the trip functions of the MFW pumps, heater drain pumps, and condensate pumps, and identify all the components, including in-line sensors, that contribute to the trip function for each of these pumps. Provide justification for excluding any of the components 4
that contribute to the trip functions of these pumps from within the scope of renewal.
l-BGE Response Baltimore Gas and Electric Company considers the function of SG isolation to include the backup means of stopping FW flow, i.e., the tripping of the MFW pumps, heater drain pumps, and condensate booster pumps. Steam generator isolation is required in the event of a postulated main steam line break inside containment. In accordance with our scoping process, we have determined that any l
component required to accomplish this tripping function is within the scope oflicense renewal.
L The signal to trip the pumps originates in the Engineered Safety Features Actuation System (ESFAS).
l' The pumps are tripped coincident with the generation of a containment isolation or a steam generator isolation signal. These ESFAS contact outputs are multiplied by a series of auxiliary relayt Although the components required to trip these pumps are in the scope of license renewal (includinc,-
the relays, breakers, etc.), the onlr function they support is active. As such, they do not require AMR.
I NRC Question No. 5 l
Page 5.9-1 contains the following information: the instrumentations for "SG level control information as l
well as the rotectivefunctions of the SG isolation and auxiliaryfeedwater init!ation" are identitied as l
p I
being within the scope of license renewal. The CCNPP UFSAR, Q10.2.2.2, states that the "feedwater regulating valve controller that in combination with the turbine driver speed control system, controls the level in each steam generator by modulating thefeedwaterfow." If the instrumentation for SG level
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control is within the scope of license renewal, provide an explanation for excluding the components that control SG level from the scope of FWS components requiring an AMR.
BGE Response Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
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ATTACilMENT (1) l RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR Tile FEEDWATER SYSTEM MC One tion No. 6 l
During a previous site visit to review FWS information, the staff was informed that the upstream piping from the FWS isolation MOVs to the next upstream anchor point will be included within the scope of license renewal under the component support commodity group. Did the CCNPP piping analysis under the current licensing basis (CLB) analyze the pipe segment from the downstream anchor to the upstream anchor of FWS isolation MOV in a single analysis, if so, explain how the piping between the MOV and the upstream anchor point will be appropriately addressed for renewal.
BGE. Response The subject piping has been analyzed under the current license and is addressed for license renewal in BGE LRA, Section 3.l A," Piping Segments that Provide Structural Support."
NRC Ouestion No 7 Clarify the design code of record for the FWS piping. If both ANSI B31.1 and B31.7 were used, clarify wiiat code was used for the different sections of the piping and design for the purpose of assessing the l
adequacy of aging management.
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BGE Response The design code for the piping from the containment penetration to the SGs is ANSI B31.1. The l
design code for the piping from the MOV through the containment penetration is ANSI B31.7 Class II.
NRC Ouestion No. 8 The CCNPP UFSAR, 10.2.2.1, contains a statement that: "[t]hefeedpump high discharge pressure l
trip andpump speed controls are credited as the means to limit thefeedwater system pressure to within j
the system design pressure rating." As discussed in RAI No. 6 (above), the piping upstream of the l
isolation valve to the first anchor point is within the scope of components requiring an AMR, and its l
pressure-retaining function appears to be within the scope of components that are subject to over j
pressurization upon a FWS isolation at the motor-operated isolation valve. Identify the components that contribute to the discharge pressure trip and pump speed control, and provide justification as to why these components are not included within the scope of the renewal.
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BGE Res_nonse The system pressure boundary intended function that makes this portion of pipe within the scope of license renewal does not extend beyond the isolation valve. As discussed in BGE LRA Section 3.l A, the portion of piping upstream of the isolation valve to the first anchor point is only required to perform a structural function in support of the seismic adequacy of the piping.
The design code for the portion of piping upstream of the isolation valve to the first anchor point is USAS B31.1-1967. The current design analysis performed for this pipirig utilizes a maximum sustained pressure of 1500 psig, which is higher than the pump trip setpoint plus tolerances. The MFW pump discharge pressure is typically in the order of 1100 psig during normal operations. There is an alarm at 1300 psig and pump trip at 1450 psig.
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ATTACIIMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; I
INTEGRATED PLANT ASSESSMENT REPORT FOR Tile FEEDWATER SYSTEM
'The design code allows for occasional operation for short periods at higher than the design pressure or temperature. For this piping an " occasional limit (USAS B31.1 paragraph 102.2.4)" was established based on up to a 20% increase above the s-value during 1% of the operating period. An " occasional" limit of 1800 psig was selected and is based on all pumos operating at their miniflow shutoff l
condition with the lowest possible FW temperature. The selection of this value acknowledges that the l
pump trip, alarms, and controls act as a more than reasonable limit to sustained high pressure l
operation. Furthermore, current analyses for UFSAR Chapter 14 design basis events show that secondary pressure iemai is well below 1600 psig for all accidents.
l The FW piping of concern is within the code requirements as referenced in the UFSAR. This piping is not subject to over pressur! an upon a feedwater isolation.
NRC Ouestion No. 9 The component-level intended function of fuses to provide continuity has been determined by the staff to be passive, as described in Reference (2). Explain how BGE intends to address aging management for fuses.
BGE Response Section 5.1.2 of the BGE Integrated Plant Assessment Methodology, Revision 1, specifically identifies fuses as having the active intended function of fault isolation and, therefore, not requiring further evaluation. Please refer to the Reference (1) responses to questions 6,90 and 103. Baltimore Gas and Electric Company supports the position the Nuclear Energy Institute presented to the NRC in Reference (3).
Baltimore Gas and Electric Compary believes that fuses are active and, therefore, not subject to AMR for the following reasons:
All electrical equipment / devices contribute to maintaining electrical continuity, in addition to performing their other intended function (s). Some electrical devices are recognized as excluded from AMR by the license renewal rule [10 CFR 4.21(a)(1)(i)]; i.e., breakers, etc. Since electrical continuity is a common function of both excluded and included electrical devices, the electrical continuity function is not a discriminatory factor in the decision regarding which devices require aging management and which do not. The decision must be based on other characteristics; i.e., the similarity and dissimilarity between the devices in question and the excluded and included devices.
Fuses and breakers are different devices that perform the same function; i.e., interrupt circuits when fault conditions exist. The choice of fuse or breaker in any given application is often simply an economic issue that depends on an analysis of initial equipment cost, breake maintenance costs, and fuse replacement costs. Both devices perform the intended fc.ction of circuit interruption in an active manner (motion or change of state).
In conclusion, due to functional similarity, BGE contends that fuses and breakers should be treated equally with respect to the license renewal rule.
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I ATTACHMENT (I)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM NNC Oue' tion No.10 s
Page 5.9-4 contains a list of device types that is used throughout the AMR to identify the structures and components within the scope of the license renewal. The use of device types appears to be a mix between commodity groupings and a more general grouping based on component type. The grouping of components in device types does not appear to be consistent with the requirement of 10 CFR 54.21(a)(1),
or the guidance in the BGE template under QI.B, fourth item. Provide a list of structures and components requiring an aging review at the level of detail illustrated by Reference (4), 3.II.A, second paragraph.
EE Response Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
NRC Ouestion No.11 Page 5.9-5, describe the specific components included in the group of components referred to as
" current / current devices."
EE Response Current / current devices refer to signal loop isolation devices that protect a portion of a signal loop from a fault in another portion of the signal loop. They are used, for example, to allow a signal from a safety-related transmitter to be sent to a non-safety-related indicator or other device while protecting the safety-related signal loop from a fault in the non-safety-related portion of the circuit. This is not a device type for power isolation devices such as breakers or fuses.
NRC Ouestion No.12 Reference (5) contains a list of seven system-level functions. In a previous FWS report submittal, a list of 11 system-level functions were identified. Provide a discussion as to why four system-level intended functions were removed.
Reference (5) also contains a list of 20 device types that have been identified as being within the scope of license renewal. A number ofinstrumentation device types (e.g., pressure or level instrumentation) were identified, but the sensors (other than temperature elements) were not included on that list. Provide a discussion as to why pressure and level sensors are excluded from the list of components within the scope oflicense renewal.
l It is also not clear as to why temperature elements are excluded from the scope of components requiring an AMR. Provide your analysis for excluding temperature elements from the scope of components requiring an AMR.
f EE Response There are eleven functional requirements identified for the FWS listed on page 5.9-3 (note that the ninth bullet contains two functions). " Prev.re and hvel sensors-' are included in the list of 20 device types on page 5.9-4 as pressure transmitters ad level transmitters. Temperature elements are included as device types requiring AMR as identified in Table 5.91 and discussed in Groups 1 and 3.
Only the pressure retaining portion, i.e., the thermowell is evaluated. Please refer to the response to RAI No. 92 of Reference (1).
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ATTACIIMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM NRC Ouestion No.13 Table 5.9-2 of Reference (5) indicates that the FWS is potentially susceptible to general corrosion and erosion / corrosion. With respect to the above identified degradation mechanisms, provide the following information.
a.
General Corrosion
- 1) Identify the corrosion allowance that has been used in the design of the FWS.
- 2) Identify BGE plans to ensure that general corrosion of the FWS will be appropriately monitored during the period of extended operation.
- 3) is there any data to support the assumptions that the general corrosion of the FWS will remain negligible and that the piping minimum wall thickness will not reach unacceptable values during the period of extended operation? Describe how the data has bea generated.
- 4) If there is no data available to substantiate the general corrosion assumpticas, are there any plans to generate such data?
b.
Erosion / Corrosion
- 1) How many locations in the FWS are monitored for erosion-corrosion?
- 2) What are the bases for the selection of these locations?
- 3) Describe the results of these examinations including any failures to meet your erosion corrosion program criteria.
- 4) Describe the corrective action activities for the erosion corrosion program.
BGE Response a.
Carbon steel FW piping requiring AMR is American Society for Testing and Materials (ASTM) A-106, Grade C and the design code is ANSI B31.1 or ANSI B31.7 Class 11. See response to Question Nos. 7 (above) and 14 (below) for additional information. There was no specific corrosion allowance included in the original design of piping. Other requested information was furnished as part of the public presentation to the NRC on the Age-Related Degradation Inspection (ARDI) Program as described in the response to Question No.20 (below).
b.
The total number of erosion / corrosion inspection locations for all FW piping between the FW Isolation MOVs and the SGs in both units is 51. Please see response for Question No.31 (below) and References 34,37, and 38 of Reference (5) for additional requested information.
l Detailed information concerning the FWS is readily available onsite for review. The formula l
used to calculate minimum wall thickness of pipe in the FWS for the Erosion Corrosion l
Program is as follows:
Tmin =
P Do
{
2(SE + PY)
I Tmin = Minimum Wall Thickness,in inches Nominal outside diameter of pipe, in inches Do
=
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Y d
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ATTACHMENT (I) l RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; l
INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM Design Pressure (psig) from the Piping Class Summary P
=
SE Maximum allowable stress due to internal pressure and joint efficiency in psi
=
Y 0.4 (for FW piping between the FW Isolation MOVs and the SGs)
=
J NRC Ouestion No.14 1
Page 5.9-7 contains the following statement: "Some segments have been replaced with chromium-molybdenum (Cr-Mo) alloy steel, which provides increased resistance to erosion-corrosion over carbon steel." Identify the segments of the piping that have been changed to Cr-Mo alloy steel. Provide a discussion of any changes to the aging management program for those segments that have been changed to Cr-Mo alloy steel, and provide thejustification for these changes.
BGE Response Page 5.9-7 states: "Since only some segments have been replaced, no distinction is made between Cr-Mo and carbon steel piping for aging management demonstration. This assumption results in the same conclusions for Cr-Mo pipe as for carbor, steel pipe, which is a more conservative approach."
Documentation s available at CCNPP for identifying those pipe segments constructed of Cr-Mo low alloy steel.
NRC Ouestion No.15 I
Page 5.9-8 contains a description of the internal environment of the FWS as being chemically treated.
l Provide a description of the chemistry control program at the level of detail illustrated by Reference (4),
Q3.III.C. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAI.
1 BGE Respoms Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
NRC Ouestion No.16 Provide a description of the FWS external environment (s) and include a discussion of any potential aging effects applicable to the external surfaces of the components requiring an AMR.
BGE Response j
l The FWS external environment is climate-controlled air (inside the Auxiliary Building and the l
Containment Building). General corrosion of the external surfaces of the FW piping is potential.
i However, this piping is maintained ler.k-tight and dry and operates at steady state high temperatures; therefore, dry conditions on the surfar.e of the piping make general corrosion noplausible.
NRC Ouestion No.17 Because carbon steel and Cr-Mo steel are dissimilar metals, provide a technical basis, including any appropriate references, and existing electrochemical potentials and thresholds to support your basis for determining galvanic corrosion as a nonplausible aging effect. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAI.
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ATTACIIMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION;
[NTEGRATED PLANr ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM A ' review of your reference material identified a single reference to galvanic corrosion. (Reference 36, page 219 of) Reference (S) contains the following statement: "[TJhe diference in solubility and electrochemical coupling effects we believe are extremely remote due to the relatively high purity low conductivity fluid involved. " is the chemistry control program used to maintain "high purity low conductivity" of the FWS. If so, the chemistry control program is serving as an aging management program, and "highpurity low conductivity" cannot be used as a justification for determining this aging effect as nonplausible. Provide a discussion, based on this information, as to the nonplausability of galvanic corrosion.
BGE Respame Various low alloy grades of ASTM A335 can be used for replacement of carbon steel FW piping.
Low alloy steel and carbon steel are not dissimilar materials with respect to galvanic corrosion. There is little or no documentation about non-existent corrosion issues. On page 420 of[American Society for Metals] ASM Handbook, Volume 13, March 1996, carbon steel and low alloy steel are shown with similar potentials in seawater. The FW environment is chemically-treated, demineralized water, which is less aggressive than seawater.
NRC Ouestion No.18 If wet and/or dry layup is used to control corrosion, provide a description of the layup programs at the level of detail illustrated by Reference (4), Q3.Ill.C, and provide the technical bases as well as any specific references (the document and page or pages) for how the layup programs contribute to managing the effects of corrosion.
]lGE Responn Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
NRC Ouestion No.19 In Reference (1), for RAI No. 94, you outlined why the loss of bolting preload due to thermal load fluctuations, or mechanical vibrations was not determined to be an ARDM requiring an AMR.
Additionally, page 5.9-8 of Reference (S) states that: " corrosion is not plausiblefor any of the bolts, because they are not exposed to water. " However, in the safety evaluation for the Babcock and Wilcox Owners Group technical report entitled, " Demonstration of the Management of Aging Effects for the Pressurizer," dated August 18, 1997, 3.2.3, the staff concluded that aging effects were plausible for bolting based on exposure to the internal environment (water). In addition, the industry guidance relative to loss of bolting preload provided in the EPRI report, " Good Bolting Practices," page 118, contains the following statement: "[a] significant change in temperature (100*F or more) ofpreviously tightened joints can create several different types ofproblems... " This EPRI report also discusses the effects of vibration on loss of preload but does not make a distinction with respect to high or low frequencies of vibration. Provide additional justification to address the concerns relating to the loss of preload and corrosion of bolting as noted above, l
l BGE Responu Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
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ATTACHMENT (1)
RESPONSE TO REQtJEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM NRC Ouestion No. 20 l
Page 5.9-9, " Methods to Manage Aging," contains the following statement: "The effects ofcorrosion on system components can be discovered and monitored through nondestructive examination techniques such as visual inspections.. The inspection must be performed on afrequency that is sufficient to ensure that the minimum wall thickness requirements will be met. " Provide a description of the aging management programs at the level of detail illustrated by Reference (y, {3.III.C. Provide additional details of your visual inspections that will describe how you will trend ongoing wall thinning, and include the criteria and/or alert values to be used during visual inspections to ensure that minimum wall thickness limits do not reach unacceptable values. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAI.
BGE Response The program credited for discovery of the effects of crevice corrosion, general corrosion, and pitting of Group I components is the ARDI Program as discussed on page 5.9-9. A detailed presentation to the NRC on the ARDI Program was given during a public meeting in June 1998.
NRC Ouestion No. 21 The Chemistry Program is described beginning on page 5.9-9. Ilowever, the description provided is not sufficient for the staff to adequately assess the Chemistry Control program for aging management. For example, the information in the BGE template (top of page 4): (1) "...the technology applied to carry out the program, which should include thefrequency and the criteriafor establishing thefrequency of performance, sample si:e or location, parameters measured, etc....;" (2) a discussion of the
"... acceptance criteria, including alert values, to ensure timely corrective actions; and (3) a discussion of "... how theprogram will beperiodically verified..., " were not provided. Provide a description of your primary and secondary chemistry control programs at the level of detail illustrated by Reference (4), 3.l!I.C. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAI.
Page 5.9-9 also contains a statement that the Chemistry Program "is based on References (12) through (18). " Provide a summary description of how each of the references contributed to the features of the Chemistry Control Program.
BGE Respanic Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
NRC Ouestion No. 22 Page 5.9-10 contains a description for the ARDI Program. However, the description provided does not contain the information requested by the BGE template and is not sufficient for the staff to adequately assess the program for aging management. Provide a description of the ARDI Program at the level of detail illustrated by Reference (4), Q3.Ill.C. Also, cddress the presence of magnetite in your description of the ARDI Program. Magnetite was identified in Reference (5) as general corrosion that occurs throughout the FWS. Therefore, general corrosion will be visible whenever a visual inspection is performed. Provide a discussion of how the ARDI will address magnetite with respect to. general l
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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR Tile FEEDWATER SYSTEM corrosion. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAl.
BGE Response Refer to response to Question No. 20.
NRC Ouestion No. 23 Page 5.9-18, describe the effects of magnetite and the continuous erosion of magnetite on the rate of crevice corrosion, general corrosion, and pitting of the FWS components.
BGE Respanae The effects of erosion corrosion as an ARDM are considered in Group 3. On page 5.9-18 the negative effects of erosion of the protective passive corrosion film (magnetite) is discussed. Crevice corrosion, general corrosion, and pitting are discussed separately in Group 1. On page 5.9-9, the protective effects of magnetite are discussed. Note that effects of crevice corrosion, pitting, and general corrosion are not significant relative to the effects of erosion corrosion, in components where erosion corrosion occurs.
NRC Ouestion No. 24 Page 5.9-10 contains the following statement: "[o]perating experience relative to the Chemistry Program at CCNPP has been such that no major site-specific event related to these aging mechanisms are known to have occurred that required changes or adjustments to the program. " Provide a description of the process used to review site-specific and industry (as applicable) operating experience related to the Chemistry Program, the criteria used to determine a major site-specific event (e.g.,a component failure, reaching minimum wall thickness, or exceeding an alert value), and the criteria used to determine when a change to the program will be needed.
In addition, provide a description of site-specific and industry (as applicable) operating experience that provides supporting information and/or objective evidence that adequately demonstrates that the aging management programs for crevice corrosion, general corrosion, and pitting in the FWS (and other identical piping systems and internal environment) will manage these aging effects during the period of extended operation. Provide this supporting information and/or objective evidence at the level of detail illustrated by Reference (4), {3.II.C.10.
BGE Response Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
NRC Ouestion No. 25 Page 5.9-10 contains the following statement: "[i]t has been demonstrated that, as long as SG chemistry is carefully monitored and controlled, the rest of the secondary cycle is maintained within acceptable chemical control." Provide the technical basis for this statement. Specifically address stagnant areas around drain lines as well as the FWS in general.
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,a ATTACIIMENT (1) j RESPONSE TO REQUEhi FOR ADDITIONAL INFORMATION; j
INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM BGE Response l
This statement is a qualitative assessment of BGE's operating experience relative to the Secondary Chemistry Program at CCNPP. Although dead legs such as drain lines are not in the flow stream, an effective high pli, low oxygen, reducing chemical environment is established during full power operation. Aging Menagement for Group I components is described under Methods to Manage Aging, Aging Management Programs, and Demonstration of Aging Management.
l NRC Ouestion No. 26 1
Page 5.9-10 contains the following statement with respect to crevice corrosion, general corrosion, and pitting of the FWS components: "[t]hese types ofcorrosion occur over a longperiod oftime and will be evident prier to minimum wall thickness reaching an unacceptable value " Howmr, page 193 of i
Reference (7) stu the following: " CORROSION BEHA VIOR is a combinedpropery of the metal and the environment to which it it exposed" indicating that the rate of conosion is condition dependent.
Provide additional information that will describe the "longperiod ofrime" for these types of corrosion to occur, and how these types of corrosion "will be evident prior to minimum wall thickness reaching an unacceptable value. "
BGE Respone See response tc, Question No. 20.
NRC Ouestion No. 27 Page 5.9-11, provide a description of the corrective actions that will be taken when the acceptance criteria for an aging management program are not met at the level of detail illustrated by Reference (4),
f3.III.C.7.
BGE Resonnat Detailed, specific corrective actions are not provided, for the following reasons:
Section 6.3.3 of the Methodology states, "... for the purposes of the IPA [ Integrated Plant Assessment], it is only necessary to establish how the degradation will be discovered on a system-by-system basis."
Section 3.6.2.2 of the Methodology Final Safety Evaluation states, "... The staff concurs with
+
BGE Gat once degradation is discovered, the CLB process would ensure that l
assessment / analysis, corrective action, and confirmation / documentation would oc appropriately performed to maintain the intendec functions under CLB design conditions...."
Section III, second paragraph, of the template, requires the following statement: "The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL-t ' Corrective Actions Program.' QL-2, " Corrective Actions Program," is pursuant ;o Appendix B and covers all structures and components subject to aging management review."
NRC Ouestion No. 28 Page 5.913 of Reference (5) contains the following statement: "[c]orrosionfatigue is not considered plausible, due to the water quality control and the lack ofcrevices or lowflow areas in the piping subject 12
ATTACIIMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; l
INTEGRATED PLANT ASSESSMENT REPORT FOR THE FEEDWATER SYSTEM I
to therma'l strafi/ication." Page 928 of Reference (7) contains the following statement: "[c]orrosion fatigue is defined in terms of both environmental and mechanicalproperties... However, the mode of fracture and the preventive measures differ to a degree such that it is considered advisable to examine it separately." As disciassed above in Question No.17, water quality is a result of the chemistry control mogram and should not be used to conclude an aging effect as nonplausible. In addition, page 5.9-8 of Reference (5) identiiles the areas around drain lines and in crevices as stagnant areas. Based on this j
information, provide a technicaljustification for determining corrosion fatigue as a nonplausible aging effect. Provide the technical bases as well as any specific references (the document and page or pages) i for the information being requested in this RAI.
BGE_Resnonse i
Corrosion fatigue is not plausible based on the lack of crevices and lack oflow flow areas, includ.:ng drain lines, in the piping subject to thermal stratification. The excellent water chemistry makes it even less likely.
NRC Ouestion No. 29 Numerous generic communications have been written on thermal stratification. Page 5.9-12 of Reference (5) identifies thermal stratification as being limited to cracking in the horizontal length of FW pipe and does "not extend beyond the first elbow to the vertical pipe run."
Provido a technical justification as to why the applicant's program does not address the following thermal str0tification concerns: (1) pipe movement and the potential for permanent pipe deformation as a result J this movenient as is described in NRC Bulletin 88-11 [" Pressurizer Surge Line Thermal Stratylcation") snd IN 88-80; (2) " Global" thermal st ratification that rest.lts in low-cycle fatigue versus cyclic thermel stratification thr.t results in high-cycle fatigue as is discussed in IN 91-38; and (3) thermal stratification a:
elbowjoints as is discussed in Bulletin 88-08.
BGE Response Page 5.9-12 of Reference (5) states: "The effects oflocal cyclical thermal stratification do not extend beyond the first elbow to the vemcal pipe." The effects of the. mal stratification that were considered included thermal shock resulting from level changes, pipe moments, and deformations (both local and global effects).
(1) IN 88-80 " Unexpected Piping Movement Attributed to Thermal Statifica'. ion" addresses unexpected pipe movement found in the Trojan pressurizer surge line. Subsequently, NRC issued Bulletin 88-11. The actions requested by this bulletin are only applicable to the pressurizer surge lines.
(2) IN 91-38, " Thermal Stratification in the 1 ecdwater System Piping" discusses "... global thermal stratification over a long stretch of horizontal FWS piping inside containment..."
CCNPP has addressed this issue. Pages 5.9-14 and 15 of Reference (5) describe the Fatigue Monitoring Program and how CCNPP addressed the effects of thermt! stratification in the horizontal FW piping.
(3)Bulletin 88-08," Thermal stresses in Piping Connected to Reactor Coolant Systems" discusses t
the effects of thermal stratification in reactor coolant systems specifically " connected, I
unisolable piping that could be subjected to temperature distributions..." The actions requested by this bulletin are only applicable to unisolable piping connected to the RCS.
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INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM
'These items were not cited in Reference (5) because the specific scopes were not applicable to the FWS.
NRC Ouestion No. 30 l
Are any portions of the FWS piping inaccessible? If so, how will the efTects of aging be managed in these areas?
i BGEResponse Baltimore Gas and Electric Company can access all FWS piping if required.
NRC Ouestion No. 31 l
Beginning on page 5S-14, Reference (5) contains a discussion on how FatiguePro and CHECWORKS software are being used to select inspection points and collect data relating to thermal fatigue and erosion-corrosion of FW piping. What are the quality assurance requirements for these programs?
l Provide a discussion regarding the applicability of quality control requirements described in l
NUREG'CR-4640, "liandbook of Software Quality Assurance Techniques," for FatiguePro and l
CHECWORKS. Include in your discussion the need for acceptance testing or verification and validation.
[
Page 5.9-16 of Reference (5) mentions an " indust 2y-developed methodology to identifyfatigue..."
Provide a description of the industry-developed methodology for identifying fatigue at the level of detail illustrated by Reference (4),63.Ill.C. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAI.
BGE Response FatiguePro was procured under a Safety-Related Purchase Order and certified compliant with the vendors' Quality Assurance Program. This program is consistent with the requirements of l
10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Phnts, and ASME NQA-2a-1990 Part 2.7, Quality Assurance Requirements of Computer Softwac. for Nuclear Facility Application. Baltimore Gas and Electric Company has an l
internal " engineering standard" to provide the requirements for specifying, prxuring, and j
maintaining the configuration control of analytical software. The " engineering standard" ensures software is verified and validated before being considered qualified for its intended use. Various NRC Combined Inspection Reports and NUREGs, including NUREG/CR-4640, were used as developmental references for the " engineering standard."
Page 5.9-16 of the FW LRA discusses the EPRI-sponsored effort to demonstrate the industry fatigue position. Baltimore Gas and Electric Company participated in this effort. The EPRI Report TR-107.515, " Evaluation of Thermal Fatigue Etiects on Systems Requiring Aging Management Review for License Renewal for Calvert Cliffs Nuclear Power Plant," December 1997, documents the results of this work. The " industry-developed methodology to identify fatigue..." discussed in the LRA refers to EPRI Report TR-104534,"EPRI Fatigue Management Ilandbook." One of the tasks of the EPRI fatigue demonstration effort was to demonstrate that the Fatigue Management flandbook would provide an acceptable method for identifying components that may be susceptible to thermal fatigue aging.
Erosion corrosion inspection points are primarily determined through evaluations of site-specific data j
and failures at other plant sites. The CliECWORKS software is used for the collection and storage of 14
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ATTACIIMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM test data obtained as part of the Erosion Corrosion Program, to maintain current status of inspection locations, and as a report generator. After the data from the current outage is entered into l
CilECWORKS, it is printed out onto separate data sheets and reviewed for accuracy. When I
compatible data from a prior examination exists, CIIECWORKS is used to perform a point-to-point comparison of previot.3 data to current data. CHECWORKS acts as a backup to the data contained in the hard copy data sheets that are kept for each inspection location. CHECWORKS is not currently relied on to rank inspection locations for frequency of examination or for automatic data evaluation.
As such, there are no formal quality assurance requirements for the use or maintenance of this software.
NRC Ouestion No. 32 Page 5.9-16 contains a description of the Environmental Fatigue Program for the FWS. Ilowever, the description provided does not contain the informatica requested in the BGE template and is not sufficient for the staff to adequately assess the program for aging management. Provide a description of the Environmental Fatigue Program at the level of detail illustrated by Reference (4), Q3.Ill.C. Provide the technical bases as well as any specific references (the document and page or pages) for the information being requested in this RAI.
BGE Resnonic Baltimore Gas and Electric Compary's fatigue program is titled the Fatigue Monitoring Program.
Baltimore Gas and Electric Company provided a detailed briefing to the NRC staffin June 1998 that followed BGE's Integrated Plant Assessment process from beginning to end, for the area of the FWS l
that relates to these questions and involves the Fatigue Monitoring Program. The briefit.g explained I
how this program was reflected in the technical report.
Additionally, the evaluction described on pages 5.9-16 and 17 is now complete and is documented in EPRI TR-107515. Therefore Reference 33 of Section 5.9., "CCNPP Specification No. 6422284D
..., is essentially superseded by EPRI TR-107515. The following additional references in the BGE LRA are also that same CCNPP Specification and are also essentially superseded:
Section 4.1 Reference 50 Section 4.2 Re.~erence 34 Section 5.2 Reference 20 l
Section 5.13 Reference 53 I
Section 5.15 Reference 79 I
NRC Ouestion No. 31 Page 5.9-17, the description of the aging management programs for fatigue is repeated and given crulited for the demonstration required unJer 10 CFR 54.21(a)(3). Provide a description of site-specific and industry (as applicable) operating experience that provides supporting information and/or objective evidence that adequately demonstrates that the aging management programs for f.nigue will manage this aging effect during the period of extended operation. ; vide this supporting information and/or objective evidence at the level of detail illustrated by Reference (4), Q3.II.C.10.
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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM
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- BGE Response Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
HRC Ouestian No. 34 Page 5.9-17 contains a discussion on low oxygen content, but does [not] identify the low oxygen criteria and limits for the erosion / corrosion program. Identify the low oxygen limits and the technical bases for these values.
BGE Response Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC r*.aff.
NRC Ouestion No. 35 During a previous staff visit to CCNPP to review the FWS, including the aging management of erosion-cerrosion, we found cases where the minimum wall thicknesses fell below acceptable values. Clarify what is meant by the statement on page 5.9-20, "nofurther majorfailures"(e.g., a component failure, reaching minimam wall hickness, or exceeding an alert vaiae).
BGE Response On page 5.9-20 " major failures" means component failures.
NRC Ouestion No. 36 Provide a justification for excluding the FWS check valves, isolation MOV, and temperature elements from the Erosion Corrosion Program.
BGEJtesponse Aging effects of FWS check valves, isolation MOV, and temperature elements are managed by other programs. The Erosion Corrosion Program manages aging effects for piping only.
NRC Ouestion No. 37 Page 5.9-21 contains a discussion on the replacement of the FWS check valves as occurring " prior to any breach ofpressure boundary" under the preventive maintenance program. Describe the criteria and the technical basis for replacing of the FWS check valve. Discuss any instances since 1988 where the check valves minimum wall thickness limit were reached or exceeded. Describe any instances since 1988 where the replacement criteria was reached or exceeded.
BGE Response The SG FW header check valves 2CHKFW130 and 133 were replaced with like valves based on engineeringjudgment due to the discovery of seat-to-body weld deterioration e.nd wash out. There was not a minimum wall thickness concern at that time, nor has there been since. Valve minimum wall requirements are included on the valve drawing.
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ATTACIIMENT (1)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; a4TEGRATED PLANT ASSESSMENT REPORT FOR TIIE FEEDWATER SYSTEM NBC Oues' tion No. 38 Page 5.9 21, provide a description of the ARDI Program and the other necessary information (i.e., frequency, criteria, basis, etc.) used to monitor the erosion corrosion of the MOVs and temperature elements at the level of detail illustrated by Reference (4), Q3.IIIC. Describe how erosion corrosion is monitored, tracked, and documented for the MOVs and temperature elements.
1 BGE Response See response to Question No. 20.
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NRC Ouestion No. 39 I
Page 5.9-22, the description of the aging management program for erosion corrosion is repeated and l
given credit for the demonstration required under 10 CFR 54.21(a)(3). Provide a description of site-specific and industry (as applicable) operating experience that provides supporting information and/or j
objective evidence that adequately demonstrates that the aging management programs for erosion / corrosion will manage this aging effect during the period of extended operation. Provide this supporting informt. tion and/or objective evidence at a level of detail illustrated by Reference (4),
Q3.II.C.10.
BGE Response Baltimore Gas and Electric Company understands that this question remains under deliberation within the NRC staff.
References 1.
Letter from Mr. C.11. Cruse (BC, to NRC document Control Desk, dated February 14,1997,
" Response to Request for Additional Information; Baltimore Gas and Electric Company's t
l Integrated Plant Assessment Systems and Commodity Reports" 2.
Letter from Mr. C. I. Grimes (NRC) to Mr. D. J. Walters (NEI), dated September 19,1997,
" Determination of Aging Management Review for Electrical Components" 3.
Letter from Mr. D. J. Waters (NEI) to Mr. C. I. Grimes (NRC), dated April 10,1998, " Aging Management Review for Selected Electrical Components" l
4 Standard Review Plan for the Review of La ise Renewal Applications for Nuclear Power l
Plants, Working Draft, U. S. Nuclear Regulatory Commission, September 1997 5.
Attachment (3) to Letter from Mr. C.11. Cruse (BGE) to NRC Document Control Desk, dated May 23,1997, " Request for Review and Approval of System and Comniodity Reports for License Renewal" l
6.
Attachment (3) to Letter from Mr. C.11. Cruse (BGE) to NRC Document Control Desk, dated May 22,1996, " Request for Review and Approval of License Renewal IPA System and Commodity Reports" 7.
ASM International Metals llandbook@, Ninth Edition, Volume 13 17
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l RESPONSE To REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE s
DIESEL FUEL OIL SYSTEM 1
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l Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 30,1998
ATTACitMFNT (2)
RESPONSE TO REQUEST FOR AsDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FUEL OIL SYSTEM N' C Ouention No.1 R
Page 5.7-1 of Reference (1) describes the Diesel Fuel Oil (DFO) System. Please provide a discussion of the pipe sizes within the system and whether corrosion allowances were provided in the piping design.
BGE Response Diesel fuel oil piping is fabricated from American Society for Testing and Materials (ASTM) A-106, Grade B carbon steel and designed in accordance with the requirements of American National Standards Institute (ANSI) B31.1. There were no specific corrosion allowances included in the original design of the piping. Detailed information concerning the DFO System is readily available onsite for review.
Baltimore Gas and Electric Company (BGE) understands that the specific system information needed remains under deliberation within the NRC waff.
NRC Ouestion No. 2 Page 5.7-1 of Reference (1) indicates that the DFO S; stem is a Seismic Category I system. Figure 5.7-1 of Reference (1) indicates that certain portions of piping up to the isolation valves are within the scope of license renewal, but the piping downstream of the isoleion valves up to the next anchor are not within i
scope. Under the current licensing basis (CLB) the entire pipe run, which includes the associated pipe and the next anchor downstream from the isolation valves, should have been analyzed by the BGE to determine that the piping could withstand design basis event loads, such as a seismic event. If there is a failure in the remainder of the pipe run or the associated piping anchors, the identified portions of the piping may not be able to perform their intended function under CLB design conditions. Did the BGE piping analysis under the CLB analyze the pipe segments from the downstream anchors to the upstream anchors of the isolation valves in a single analysis? If so, explain how the piping between the isolation valves and the downstream anchor points will be appropriately addressed for renewal.
BGE Respansc The subject piping has been analyzed under the current license. Piping between the isolation valve and the next downstream anchor is addressed in BGE License Renewal Application (LRA)
Section 3.l A," Piping Segments That Provide Structural Support."
NRC Ouestion No. 3 Page 5.7-2 of Reference (1) describes the DFO System. However, Reference (1) does not identify a non-l safety related line from the No. 21 Fuel Oil Storage Tank (FOST) identified the in Updated Final Safety Analysis Report (UFSAR) Section 8.4.1.2. Specifically, page 8.4-7 of the UFSAR contains a statement that indicates that the enclosure for the No. 21 FOST "also acts as a dike for No. 21 FOST with fuel being supplied by way of a non-safety-rt.ted line." Baltimore Gas and Electric Company, in Reference (2) (Question No.17), stated that the non-safety-related building drain line for the No. 21 FOST is not within the scope of license renewal because it is not on the "Q-List." Pleau explain whether this line is relied upon to remain functional during and following any design basis events to ensure any of the intended functions delineated by the license renewal rule [10 CFR 54.4(a)(2)]. Since this line is designated to be used to supply the diesel generators in the event of No. 21 FOST rupture, explain whether the rupture of the FOST is posmlated to occur as a result of any design basis event that would also require diesel generator operation (via No. 21 FOST).
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ATTACIIMENT (3)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR Tilt FUEL OIL SYSTEM In addition, page 5.7-3 of Reference (1) indicates that the non-safety-related line from No. 21 FOST to diesel generating room waste oil collection tank No. I1 is not within the scope oflicense renewal.
Discuss whether there is a potential for draining No. 21 FOST if the non-safety-related line should rupture, and if there are any isolation valves in the line. If then are isolation valves in the non-safety-related line, discuss whether the valves and associated upstream piping are within the scope of license renewal.
i BGEEemame The line, discussed in the first paragraph of the question, is not relied upon to remain functional during and following any design basis events to ensure any of the intended functions delineated by the j
license renewal rule. The rupture of the FOST is not postulated to occur as a result of any design i
basis event.
The non-safety-related line, discussed in the second paragraph of the question, is the tank overfill line. There is no potential for draining the No. 21 FOST if the line should rupture. The simplified drawing, Figure 5.7-1 of Reference (1), shows this line coming out of the tank bottom; it actually i
comes out near the top.
NRC Ouestion No. 4 Page 5.7-2 of Reference (1) discusses operating experience with the DFO System regarding aging effects. Reference (1) indicates that the DFO System has "in general, performed well." flowever, later i
on in Reference (1), on page 5.7-19, an outstanding site " Issue Report" on the degradation of caulking and scalants that could affect the FOST was mentioned. Provide additional plant-specific operating experience related to the aging effects applicable to the DFO System. Also, discuss any NRC generic communications and other industry experience related to aging that are applicable to the DF0 System.
I Further, Reference (1) indicates that the No. 21 FOST was inspected during the 1997 refueling outage.
Please provide information on the results of that inspection.
l BGE Response Issue reports are the site means for getting all discrepant conditions; however minor, into the site Corrective Actions Program. Thousands are written and resolved each year. The mention of an Issue Repon is not necessarily an indication of a significant problem.
Operating experience is discussed in Reference (3) on pages 5.7 2 and 5.7-3. The plant-specific operating experience, NRC generic communications, and other industry experience is provided to the level of detail identified in the BGE LRA template. Note that throughout this response, "BGE LRA Template"is deGned as Attachment 3 of Reference (1). It is not clear what additional information is being requested. Baltimore Gas and Electric Company understands that the specific operating experience needed remains undu deliberation within the NRC Staff.
I On April 13,1997, an inspection of No. 21 FOST was completed. The inspection included visual and non-destructive examinations. The scope of the visual inspections consisted of an examination of the inside surfaces of the shell, roof and bottom, and an examination of the exterior of the tank. The visual inspection indicated that the tank is in good overall condition.
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ATTACHMENT (2) i RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FUEL OIL SYSTEM 1
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The scope of the non-destructive examinations consisted of:
Ultrasonic Thickness scan of the bottom plates; e
l Lgnetic Flux examination of the tank bottom; Magnetic Particle test of the interior of the shell-to-bottom corner weld and the interior bottom e
12 inches of each first shell course vertical seam; and Vacuum Box Test of the bottom plate welds and the interior of the shell-to-bottom corner e
The non-destructive examination inspection found the bottom plates to be in good condition. The interior bottom coating was disbonded and worn away in various locations and widely scattered pitting less than 0.050 inch iu depth was brved. No leaks were found. The original nominal bottom plate thickness on the design drawing is 0.25 inch. Per ASTM A-6, the minimum permissible thickness specification for steel plates is 0.24 inch. The minimum measured bottom plate thickness was 0.247 inch. An evaluation of the inspection results concluded no immediate actions were required prior to returning the tank to service, and rec mmended an inspection of the internals be performed in approximately 10 year::.
l Based on the inspectN results, BGE concludes that in approximately 20 years of service no significant age-related degradation of the carbon steel tank bottom has occurred. The FOST internal surfaces will be inspected under a new "FOST Inspection Program" described under the response to I
Question No.14.
NRC Ouestion No. 5 Page 5.7-2 of Reference (1) describes the DFO System. Discuss whether the DFO System is partially supported by the Diesel Generator Building and foundation, and identify where these structures will be l
evaluated for license renewal.
l BGE Responic l
l The DFO System contains components that are supported by the Emergency Diesel Generator (EDG) l Rooms (adjacent to the Auxiliary Duilding) and in the No. 21 FOST Enclosure. The EDG Rooms are i
addressed in BGE LRA Section 3.3E, " Auxiliary Building and Safety-Related Diesel Generator Building Structures." The No. 21 FOST Enclosure is addressed in BGE LRA Section 3.3D, 1
" Miscellaneous Tank and Valve Lclosures."
NRC Ouestion No. 6 Page 5.7-6 of Reference (1) indicates that BGE may elect to replace comptnents for which the AMR l
identifies further analysis or examination is needed. Baltimore Gas and Electric Company also indicates that the replacements would not be subject to an AMR for license renewal. Tha license renewal rule excludes AMR for replacements that are based on a qualified life or specified time period. Ilowever, replacing components based on their condition or performance is not a basis for excluding components from an AMR. The condition or performance monitoring program, including replacements, is considered an aging management program for license renewal. Please identify the structures and components that will be replaced and, therefore, excluded from an AMR for license renewal.
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ATTACIIMENT (3)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FUEL OIL SYSTEM m
BGE Response The statements addressed in the question were meant to be generic and account for a future hypothetical scenario where BGE may elect to replace a component based on time er qualified life, hence removing it from the population of components requiring AMR. No components were excluded from AMR based on the hypothetical scenario described above. Any components specifically excluded from AMR based on a time or qualified life replacement schedule are clearly identified in the LRA.
NBC Ouestion No. 7 Page 5.7-6 of Reference (1) indicates that an electrical fuse has only active functions and is not subject to an AMR for license renewal. The component-level intended function of fuses to provide continuity has been determined by the staff to be passive, as described in Reference (4). Explain how BGE intends to j
address aging management for fuses.
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BGE Response Section 5.1.2 of the BGE Integrated Plant Assessment Methodology, Revision 1, specifically identifies fuses as having the active intended function of fault isolation and therefore not requiring further evaluation. Please refer to the responses to questions 6,90 and 103 provided in the attachment to Reference (2). Baltimore Gas and Electric Company supports Nuclear Energy Institute's position in Reference (5).
I Baltimore Gas and Electric Company believes that fuses are active sad, therefore, not subject to AMR for the following reasons:
All electrical equipment / devices contribute to maintaining electrical continuity, in addition to l
performing their other intended function (s). Some electrical devices are recognized as excluded from AMR by the license renewal rule [10 CFR 54.21(a)(1)(i)]; i.e., breakers, etc. Since electrical continuity is a common function of both excluded and included electrical devices, the electrical continuity function is not a discriminatory factor in the decision regarding which devices require aging management and which do not. The decision must be based on other characteristics; i.e., the similarity and dissimilarity between the devices in question and the excluded and included devices.
Fuses and breakers are different devices which perform the same function; i.e., interrupt circuits when fault conditions exist. The choice of fuse or breake-in any given application is often simply l
an economic issue which depends on an analysis of initial equipment cost, breaker maintenance j
costs, and fuse replacement costs. Both devices pmorm the intended function of circuit interruption in an active manner (motion or change of strite).
In conclusion, due to functional similarity BGE contends that fuses and breakers should be treated equally with respect to the license renewal rule.
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ATTACIIMENT (2)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FUEL OIL SYSTEM l
N'RC Ouestion No. 8 Table 5.7-1 (Page 5.7-7) in Reference (1) indicates that the FOST for the new EDO is not included in this technical report. Please identify in which report the FOST and supporting components for the new EDG l
will be addressed for license renewal. If BGE has determined that this FOST and supporting components j
l are not within the scope of license renewal, provide th justification for that determination and describe the extent to which the new EDG is relied upon to satisfy the station blackout rule.
l HGE Response j
The new EDGs and supporting components (including the FOST for No. l A EDG) are addressed in l
BGE LRA Section 5.8.1.2.2, Emergency Diesel Generator System. Number I A EDG is not relied upon to satisfy the station blackout rule. The CCNPP site has a dedicated non-safety-related diesel generator built to the quality standards of Regulatory Guide 1.155, Station Blackout, to support j
station blackout, or Engineered Safety Features loads, if necessary.
1 NRC Ouestion No. 9 t
Pages 5.7-10 and 5.7-19 of Reference (1) describe plant procedures MN-3-100, " Paint and Other j
l Protective Coatings," PEG-7, " System Walkdown," and QL-2-100, " Issue Reporting and Assessment
)
l Procedure," for managing aging of the Group 1 and 4 components, respectively, for license renewal.
l l
Picase expand on the summary description for PEG-7 and provide summary descriptions for MN-3-100 and QL-2-100. The summary descriptions should provide information addressing the specific elements l
described in Subsection II.C of Section 3.0 of Reference (6). For example, the summary description l
should include briefinformation on the operating experience of there programs regarding aging detected l
in th-Group 1 and 4 components, extent of degradation when %
'1 frequency of occurrence, and
{
l resulting corrective actions. Additional examples of what the e nu d.scription should include are:
inspection frequency, outline of inspection procedures, techniqu wd, acceptance criteria, assessment and reporting requirements, and guidelines for corrective actions.
IlGE Response l
Calvert Cliffs procedure PEG-7 (now called MN-1-319) is the only program of the three that is being directly credited for aging management. It is the only program of the three that directs periodic activity that will discover degradation. Once aiscovery occurs, the PEG-7 process would invoke MN-3-100 and QL-2-100 as supporting programs. This should have been made more clear in Reference (1).
The description provided for PEG-7 is in accordance with the BGE LRA template. Detailed information concerning credited aging management programs is readily available onsite for review.
j NRC Ouest'on No.10 Page 5.7-12 of Reference (1) indicates that BGE will develop a new program for buried pipe insper: tion for license renewal. Please provide a summary description of this program addressing the specific elements described in Subsection II.C of Section 3.0 of Reference (6). For example, the summary description should include frequency of inspection, consideration for variations in environmental conditions, guidelines for selecting representative samples, inspection techniques, acceptance criteria, assessment and reporting requirements, and guidelines for potential corrective actions.
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ATTACHMENT (3)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; i
INTEGRATED PLANT ASSESSMENT REPORT FOR Tile FUEL OIL SYSTEM
' 11GERegaggag Buried pipe inspection program development will consist of three phases:
l
- 1) Initial assessment to provide basis fe: program scope (Estimated Completion Date [ ECD)
October 31,1998):
Review of existing cathodic protection PM results; Review and catalog previous pipe inspection reports; e
Cc:: duct and document inspections on select sections of buried pipe; and e
Conduct detailed cathodic protection surveys.
e
Draft Buried Piping Condition Monitoring Program; and Review and refine draft program with help of concerned parties.
e
- 3) CCNPP program implementation (ECD October 31. W991 Integrate program requirements into n aintenance planning and procedures as appropriate; and Provide training to personnel involved in conducting activities regt: ired under the e
program.
NRC Ouestion No.11 Page 5.712 of Reference (1) indicates that the existing cathodic protection prcgram is not necessary for license renewal for buried piping. In addition, page 5.7-18 of Reference (1) indicates that the FOST j
bottoms are not subject to any applicable aging efTects. Baltimore Gas and Electric Company's basis for i
this conclusion is that the tank bottoms are coated, set on oil soaked soil, sealed with grout, and protected by cathodic protection. Baltimore Gas and Electric Company provided the same basis in Reference (2)
(Question No. 5). However, the staff concludes that the aging effects are applica', for license renewal even if there are preventive or mitigation programs to manage tl cse aging effects and the cathodic protection program constitutes an aging management pror, ram.
l Accordingly, please identify the applicable aging effects for the FOST bottoms. Describe the aging management programs for the buried piping and FOST bottoms, including the cathodic protection program, that will ensure effective control of the applicable aging effects during the period of extended operation. In particular, please provide a summary description of these programs addressing the specific elements described in Subsection ll.C of Section 3.0 of Reference (6).
j BGE Response l
As stated in the response to Question No. 5 provided in the attachment to Reference (2), BGE considers the coating, weld seam strips, perimeter sealing, and impressed current cathodic protection of the FOST bottoms to be design features and not aging management programs. Bahimore Gas and Electric Company has determined, based on an evaluation of the FOSTs' material of construction, service environment, and design featmes, there are no plausible age-related degradation mechanisms for the tank bottom exterior surfaces.
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ATTACIIMENT (2)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR Tile FUEL OIL SYSTEM Data from FOST inspections support the conclusion that the tank bottoms have experienced no significant aging effects after approximately 20 years of service due to the design features delineated I
above. The inspection results for No. il FOST are discussed on page 5.7-2 of Reference (1). See the I
response to Question No. 4 (above) for inspection results for No. 21 FOST.
NRC Ouestion No.12 Page 5.715 of Reference (1) describes plant procedures PEO-0-023 2-0-M," Drain Water From iI & 21 FOST," CP-226, " Oil Receipt inspection and Fuel Oil Storage Tank Surveillance," and CP-973,
" Determination of Particulate Contamination in Diesel Fuel Oil," for managing aging of FOST internal surfaces for license renewal. Please expand on the summary descriptions for these programs addressing the specific elements described in Subsection ll.C of Section 3.0 of Reference (6). For example, the summary description should include brief information on the operating ex'perience of these programs regarding water collected and out-of-specification fuel oil found in FOST, extent of deviation from specification when detected, frequency of occurrence, and resulting corrective actions. Additional examples of what the summary description should include are: inspection frequency and its basis, acceptance criteria, assessment and reporting requirements, and guidelines for corrective actions.
Further, please identify the corrosion inhibitor added to the fuel oil, corrosion effects being controlled by the inhibitor, and provide the basis for the effectiveness of the inhibitor in controlling corrosion.
BGE RespoJtat The description provided on page 5.7-15 for the referenced procedures is generally in accordance with the BGE LRA template developed by NRC and BGE for format and content of the technical reports. The specific periodicity for PEO-0-023-2-0-M is monthly.
Baltimore Gas and Electric Company currently uses a fuel oil additive that acts as an anti-oxidant, dispersant, rust inhibitor, and copper corrosion inhibitor.
NRC Ouestion No.13 Pages 5.7-15 and 5.7-16 of Reference (1) indicate that aging management programs are based on specific national codes and standards and industry guMelines. Please expand on how these referenced documents are relied on for aging management and identify the specific portions of these documents. Include the document titles and dates or editions for those referenced documents.
BGE Response The information provided on the national codes and standards and industry guidelines is in accordance with the level of detail identified in the BGE LRA Template. Further details are available for review during a site visit.
The specific document titles and dates or editions are as follows:
ASTM Specification No. D 975-81," Standard Specification for Diesel Fuel Oils," 1981 ASTM Specification No. D 2276-89," Standard Test Method for Particulate Contaminant in a
Aviation Fuel," 1989 Electric Power Research Institute Report No. NP-6314, " Storage and llandling of Fuel Oil for o
Standby Diesel Generator Systems," Revision 1, December 1992 l
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ATTACIIMENT (2)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; INTEGRATED PLANT ASSESSMENT REPORT FOR TIIE FUEL OIL SYSTEM
' ASTM Specification No. D270-65," Standard Method of Sampling Petroleum and Petroleum Products," 1965 American Petroleum Institute API-653, " Tank Inspection, Repair, Alteration and Reconstruction," 1992
- ASTM Specification No. Dil86-93, " Standard Tr:st Methods for Nondestructive Measurement of Dry Film Thickness of Nonmagnetic Coatings Applied to a Ferrous Base,"
1993
- National Association of Corrosion Engineers RP0188, " Discontinuity (Iloliday) Testing of Protective Coatings," 1990
- Baltimore Gas and Electric Company reserves the right to utilize whatever edition of the standard is deemed appropriate at the time of future tank inspections.
NRC Ouestion No.14 Page 5.7-16 of Reference (1) indicates that BGE ; vill develop a new program for the FOST internal inspection for licenw renewal. Please e'xpand on the sammary description of this program addressing the specific elements described in Subsection II.C of Section 3.0 of Reference (6). For example, the summary description should include frequency of inspet. tion, acceptance criteria, ard guidelines for corrective actions if degradation is found.
BGE Response The FOST Inspection Program will consist of the following:
Approximately every 5 years - Perform an external inspection per API-653 by a qualified inspector.
Approximately every 10 years - Perform an internal inspection rer API-653 by a qualified inspector.
A Preventive Maintenance Repetitive Task to perform FOST inspections will be developed (ECD November 18,1999) to initiate and track the inspection requirements.
NOTE: The inspection frequency is based upon previous tank inspection results. The frequency of inspections may be adjusted based upon conclusions formulated from lmpution results.
NRC Ouestion No.15 Page 5.7-19 of Reference (1) indicates that BGE will develop a new program for caulking and sealant inspection for the FOST for license renewal. Please expand on the summary description of this program addressing the specific elements described in Subsection II.C of Section 3.0 of Reference (6) and explain the extent to which this program is relied upon for other structures and components. For example, the summary description should include guidance for baseline inspections, inspection techniques, acceptance crit ria, and guidelines for potential corrective actions.
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I ATTACIIMENT (2)
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION;
(
INTEGRATED PLANT ASSESSMENT REPORT FOR Tile FUEL OIL SYSTEM BGE Response The DFO System report ind! cates BGE intends to develop a new " Caulking and Sealant Inspection Program" to manage the aging of the FOST perimeter seals. Ilowever, in lieu of developing a new program, BGE has chosen to modify ar. existing program, MN-1-319, " Structure and System l
Walkdowns," to incorporate inspection requirements for the FOST perimeter seals. The modified l
progam includes a periodic visual inspection of the FOST for the absence or degradation of perimeter sealing material.
NRC Ouestion No.16 l
Table 5.7-3 (page 5.7-21) of Reference (1) lists aging management programs for the DFO System for license renewal. liowever, the list does not include procedure MN-3-100, which is credited for managing the Group i and 4 componats as described in the text of Reference (1). Please correct Table 5.7-3 to include MN-3-100 for consistency with the text or explain the differences.
BGE Response The response to Question No. 9 is related to this item. As it explains, MN-3-100 is not being directly credited for aging management. This should have been made more clear in Reference (1).
References
- 1. of Letter from Mr. C. II. Cruse (DGE) to NRC Document Control Desk, dated l
May 23,1997, " Request for Review and Approval of System and Commodity Reports for License Renewal" 2.
Letter from Mr. C.11. Cruse (BGE) to NRC document Control Desk, dated February 14,1997,
" Response to Request for Additional Information; Baltimore Gas and Electric Company's Integrated Plant Assessment Systems and Commodity Reports" l
3.
NRC Memorandum by Mr. S. C. Flanders, dated September 23,1996, " Summary of Meeting
[
with Baltimore Gas and Electric Company (BGE) on BGE License Renewal Activities" 4.
Letter from Mr. C. I. Grimes (NRC) to Mr. D. J. Walters (NEI), dated September 19, 1997,
" Determination of Aging Management Review for Electrical Components" 5.
Letter from Mr. D. J. Waters (NEI) to Mr. C. I. Grimes (NRC), dated April 10,1998, " Aging Management Review for Seiected Electrical Components" 6.
Standard Review Plan for the Review of License Renewal Applications for Nuclear Power Plants, Working Draft U. S. Nuclear Regulatory Commission, September 1997 i
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