ML042870422

License Renewal Application - Response to NRC Request for Additional Information Related to Aging of Mechanical Systems During the Extended Outage

ML042870422
Person / Time
Site:	Browns Ferry
Issue date:	10/08/2004
From:	Abney T Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MC1704, TAC MC1705, TAC MC1706
Download: ML042870422 (35)

Text

October 8, 2004 10 CFR 54 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop: OWFN P1-35 Washington, D.C. 20555-0001 Gentlemen:

In the Matter of

) Docket Nos. 50-259 Tennessee Valley Authority

) 50-260 50-296 BROWNS FERRY NUCLEAR PLANT (BFN) - UNITS 1, 2, AND 3 LICENSE RENEWAL APPLICATION - RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION (RAI) RELATED TO AGING OF MECHANICAL SYSTEMS DURING THE EXTENDED OUTAGE OF BROWNS FERRY NUCLEAR PLANT UNIT 1 (TAC NOS. MC1704, MC1705, AND MC1706)

By letter dated December 31, 2003, TVA submitted, for NRC review, an application pursuant to 10 CFR 54, to renew the operating licenses for the Browns Ferry Nuclear Plant, Units 1, 2, and 3. As part of its review of TVAs license renewal application, the NRC staff, by letter dated August 23, 2004, identified areas where additional information is needed to complete its review.

The specific areas are from sections 3.1, 3.2, 3.3, and 3.4, of the LRA related to aging of mechanical systems during the extended outage of BFN Unit 1.

U.S. Nuclear Regulatory Commission Page 2 September 8, 2004 to this letter contains the specific NRC requests for additional information and the corresponding TVA response.

If you have any questions regarding this information, please contact Ken Brune, Browns Ferry License Renewal Project Manager, at (423) 751-8421.

I declare under penalty of perjury that the forgoing is true and correct. Executed on this 8th day of October, 2004.

Sincerely, Original signed by:

T. E. Abney Manager of Licensing and Industry Affairs

Enclosure:

cc: See page 3

U.S. Nuclear Regulatory Commission Page 3 October 8, 2004 Enclosure cc (Enclosure):

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 Mr. Stephen J. Cahill, Branch Chief U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 NRC Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611-6970 NRC Unit 1 Restart Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611-6970 Kahtan N. Jabbour, Senior Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 Eva A. Brown, Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 Yoira K. Diaz-Sanabria, Project Manager U.S. Nuclear Regulatory Commission (MS 011F1)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739

U.S. Nuclear Regulatory Commission Page 5 October 8, 2004 JWD:BAB Enclosures cc (Enclosure):

A. S. Bhatnagar, LP 6-C K. A. Brune, LP 4F-C J. C. Fornicola, LP 6A-C D. F. Helms, LP 6A-C F. C. Mashburn, BR 4X-C R. G. Jones, NAB 1A-BFN K. L. Krueger, POB 2C-BFN R. F. Marks, Jr., PAB 1A-BFN J. R. Rupert, NAB 1F-BFN K. W. Singer, LP 6A-C M. D. Skaggs, PAB 1E-BFN E. J. Vigluicci, ET 11A-K NSRB Support, LP 5M-C EDMS, WT CA-K s://Licensing/Lic/BFN LR Lay-up of Mechanical Systems RAI Response.doc

ENCLOSURE TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 1, 2, AND 3 LICENSE RENEWAL APPLICATION (LRA),

RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION (RAI)

RELATED TO AGING OF MECHANICAL SYSTEMS DURING THE EXTENDED OUTAGE OF BROWNS FERRY NUCLEAR PLANT UNIT 1 (SEE ATTACHED)

E-2 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 1, 2, AND 3 LICENSE RENEWAL APPLICATION (LRA),

RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION (RAI)

RELATED TO AGING OF MECHANICAL SYSTEMS DURING THE EXTENDED OUTAGE OF BROWNS FERRY NUCLEAR PLANT UNIT 1 By letter dated December 31, 2003, the Tennessee Valley Authority (TVA) submitted, for NRC review, an application pursuant to 10 CFR 54, to renew the operating licenses for the Browns Ferry Nuclear Plant, Units 1, 2, and 3. As part of its review of TVAs license renewal application, the NRC staff, by letter dated August 23, 2004, identified areas where additional information is needed to complete its review. The specific NRC questions are from sections 3.1, 3.2, 3.3, and 3.4, of the LRA and are related to aging of mechanical systems during the extended outage of BFN Unit 1.

Listed below are the specific NRC requests for additional information and the corresponding TVA responses.

NRC Request The license renewal application (LRA) states that there were no additional aging effects and, consequently, there is no need for additional aging management as a result of the extended outage on Unit 1. However, the aging of the mechanical systems is highly dependent upon the environment that was maintained during the extended outage. In order to determine whether 1) there was additional or more severe aging during the extended outage,

2) any additional aging has been properly identified, evaluated, and managed, and 3) the proposed aging management can distinguish the aging during the extended outage from the aging during future operation, the staff needs the following additional information:

Questions applicable to all Mechanical System Groups (3.1., 3.2, 3.3, and 3.4)

NRC RAI 3.0-1 LP Describe the process that was used to maintain equipment in a wet lay-up condition. The Evaluation of the Browns Ferry Nuclear (BFN) Unit 1, Lay-up and Preservation Program (Reference 2) states that the systems were maintained with flowing, demineralized, air-saturated water, and indicates that the water chemistry

E-3 program was used to maintain the water quality. Describe the water parameters that were maintained for the various systems and discuss the differences from the water chemistry that exists during plant operation. What flow rates were maintained (and how) for the various systems in wet lay-up, including the low flow portions of those systems. In particular, discuss the following:

a. Discuss the differences between the chemistry program(s) implemented during the lay-up period and the chemistry aging management program (AMP) to be implemented during the period of extended operation.

Discuss the bases for concluding that the chemistry AMP is sufficient to manage the aging effects listed in the aging management review (AMR) if the chemistry program(s) implemented during the period of extended operation is not consistent with the Generic Aging Lesson Learned (GALL) report AMP XI.M2.

b. Discuss the criteria (e.g., guidelines) used to maintain the chemistry of the fluid in the lay-up systems, the chemistry parameters monitored, and the frequency of the monitoring/trending. Discuss the results of the monitoring/trending. Describe the corrective actions, including any inspections, for conditions where the water chemistry failed to meet acceptance criteria. Provide information on the following attributes for each system (in RCS, ESF, Auxiliary Systems, and SPCS) maintained wet lay-up:

1. Temperature of the water

2. Existence of any stagnant conditions

3. Water chemistry maintained (i.e., PH, conductivity, corrosion inhibitors, concentrations of aggressive chemicals, etc.)

4. Reactor Coolant System (RCS only) Any additions of hydrogen

5. (RCS only) Measurement of Electro Chemical Potential (ECP) of the reactor coolant which will provide information on the oxidizing nature of the RCS water.

The susceptibility of the corrosion is directly proportional to the oxidizing nature of the RCS water.

E-4

c.

Because of the potential differences in water temperature and chemistry, and the potential effect of stagnant flow condition in portions of the Unit 1 wet lay-up components, discuss the possibility of incurring more severe aging degradations to these wet lay-up components than could have occurred during the plant operation. Also, discuss the potential for latent effects, and provide the basis for not performing additional inspections (i.e., startup inspections) for potential aging effects.

TVA Response to RAI 3.0-1 LP The process used to maintain the Systems [Reactor Vessel and Internals (RVI), part of Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69), and Control Rod Drive (85)] in a wet lay-up condition consists of the following:

One Reactor Water Cleanup System (69) filter demineralizer was in service at approximately 100 gpm to maintain reactor coolant water quality per CI-13.1 "Chemistry Program." The wet lay-up flow path was Reactor Water Cleanup System (69) suction from the 'A' Recirculation Loop through a short section of Residual Heat Removal System (74) piping with a small portion of Reactor Water Cleanup System (69) suction flow coming from the Reactor Vessel bottom head drain line, through Reactor Water Cleanup System (69) inlet piping to the Reactor Water Cleanup System (69) filter demineralizer returning via the Reactor Water Cleanup System (69) effluent piping which returns to the Reactor Pressure Vessel via the 'B' Feedwater line. A portion of the Reactor Water Cleanup System (69) effluent flow was routed to provide flow through Control Rod Drive System (85) components.

The Reactor water during power operation and cold shutdown was monitored per Chemistry Program CI-13.1. The cold shutdown impurity limits for conductivity, chloride and sulfate given in CI-13.1 (1.5 µS/cm, 15 ppb, 15 ppb) are more restrictive than those given in the EPRI BWR Water Chemistry Guidelines (TR-103515-R2, page 4-6, Table 4-2) for "Reactor Water - Cold Shutdown" (2.0 µS/cm, 100 ppb, 100 ppb) and those given in the Browns Ferry Technical Requirements Manual Section TR 3.4.1 "Coolant Chemistry" Table 3.4.1-1 Column C for "Reactor Not Pressurized" (10 µS/cm, 500 ppb, no sulfate limit given). The power operation impurity limits are given in CI-13.1 for conductivity, chloride, sulfate, pH, silica, dose equivalent, dissolved oxygen, total copper, non-filterable copper, total iron, non-filterable iron, total zinc, and boron (0.11 µS/cm, 1 ppb,

E-5 2 ppb, 5.9-8.2 (pH), 300 ppb, 0.032 µCi/gm, 250 ppb, 1 ppb, 0.5 ppb, 20 ppb, 10 ppb, 10 ppb, and boron trending).

TVA Response to RAI 3.0-1 LP (a)

The above systems contain reactor water which was monitored for conductivity, chloride, and sulfate per Chemistry Program CI-13.1.

The impurity limits for conductivity, chloride, and sulfate given in CI-13.1 are 1.5 µS/cm, 15 ppb, and 15 ppb, respectively. The power operation impurity limits are given in CI-13.1 for conductivity, chloride, sulfate, pH, silica, dose equivalent, dissolved oxygen, total copper, non-filterable copper, total iron, non-filterable iron, total zinc,and boron (0.11 µS/cm, 1 ppb, 2 ppb, 5.9-8.2 (pH), 300 ppb, 0.032 µCi/gm, 250 ppb, 1 ppb, 0.5 ppb, 20 ppb, 10 ppb, 10 ppb, and boron trending).

The chemistry control limits implemented during wet lay-up are the same as the chemistry control limits utilized by Browns Ferry Units 2 and 3 during Cold Shutdown conditions for refueling and maintenance outages. The selected BFN impurity limits are consistent with the limits for cold shutdown that are contained in BWRVIP-79, BWR Water Chemistry Guidelines - 2000 Revision (EPRI Report TR-103515-R2, February 2000) that is invoked by NUREG-1801 (GALL). The BFN Chemistry Control Program, described in LRA Appendix B.2.1.5, is consistent with NUREG-1801, Generic Aging Lesson Learned (GALL),Section XI.M2.

TVA Response to RAI 3.0-1 LP (b)

During wet lay-up, reactor water was monitored per Chemistry Program CI-13.1, Table 5. The impurity limits for conductivity, chloride and sulfate given in CI-13.1 are 1.5 µS/cm, 15 ppb, and 15 ppb, respectively. The sampling was performed once per two weeks.

The monitoring and trending results demonstrated that the reactor water was maintained within its impurity limits during wet lay-up.

A search was performed in eCAP for Unit 1 Problem Evaluation Reports (PERs) with no results that gave instances of the reactor water Systems [Reactor Vessel and Internals (RVI), part of Feedwater System (03), Reactor Vessel Vents and Drains System (10), Reactor Recirculation System (68), Reactor Water Cleanup System (69) and Control Rod Drive System (85)] exceeding the CI-13.1 limits.

E-6 TVA Response to RAI 3.01 LP (b)1 The temperature of the reactor water for these systems [(Reactor Vessel and Internals (RVI), part of Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69), and Control Rod Drive (85)] was less than 120 degrees F.

TVA Response to RAI 3.01 LP (b)2 The stagnant conditions would exist in the same portions of piping, fittings, and valves in the wet lay-up systems as they would during normal system operation.

Due to stagnant conditions in the wet lay-up systems a One-Time Inspection will be performed prior to restart to verify the material condition. The One-Time Inspection Program is described in the BFN LRA, Appendix B.2.1.29. The One-Time Inspection Program does not differentiate between the rates of aging in different environments (for example, normal power operation versus cold shutdown).

TVA Response to RAI 3.01 LP (b)3 The monitoring and trending results demonstrate that the Chemistry Program CI-13.1 maintained the reactor water within impurity limits for conductivity, chloride and sulfates respectively:

1.5 µS/cm, 15 ppb, 15 ppb, during wet lay-up.

TVA Response to RAI 3.01 LP (b)4 No hydrogen was added to any of these Systems [Reactor Vessel and Internals (RVI), part of Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69), and Control Rod Drive (85)] during wet lay-up. Hydrogen is added during normal power operation.

TVA Response to RAI 3.01 LP (b)5 No RCS ECP measurements were made during wet lay-up.

TVA Response to RAI 3.01 LP (c)

A discussion on incurring more severe degradation on wet lay-up components is not needed since a one time inspection for the non-Reactor Coolant Pressure Boundary (RCPB) portion of these systems and Section XI baseline testing will be performed for the

E-7 RCPB portions of these systems prior to restart. The One-Time Inspection Program is described in the BFN LRA, Appendix B.2.1.29.

The One-Time Inspection Program does not differentiate between the rates of aging in different environments (for example, normal power operation versus cold shutdown).

NRC RAI 3.0-2 LP For the systems covered by Table 1, the applicant stated that during lay-up, the systems were maintained in dehumidified air (60 percent relative humidity) and no additional aging effects were identified for the lay-up condition.

NRC Inspection Report 50-259/87-45 reported that in 1987 an acceptable program for monitoring the relative humidity of all pipe environments had not been finalized and the extent to which all parts of each system was being continually purged with dry air had not been established. For example, the standby liquid control system contained moisture in portions of the system and procedures did not require the system to be monitored for dryness. Although inadequacies in the program were later resolved, it appears that the moisture concerns existed for an extended period of time.

Also, industry documents such as Electric Power Research Institute (EPRI) NP-5106, Sourcebook for Plant Lay-up and Equipment Preservation," Revision 1, identify the need to monitor the effectiveness of the lay-up practices. This document states that relative humidity (RH) can not be used alone as a lay-up surveillance technique to evaluate lay-up effectiveness.

Table 1 does not identify any additional inspections prior to restart to assess the condition of these systems, and it is not clear if inspections were performed in the lay-up condition. In light of the above inspection findings, the recommendations in the industry documents, and the possibility that parts of this system may not have been continually purged with dry air (such that the exact dryness of the surrounding air can not be ascertained),

discuss any inspections planned before startup to address the potential aging during the extended outage, and whether these inspections target system low points where condensate and/or chemicals could accumulate. If inspections have been performed recently, discuss the results of the inspections. If no inspections to verify the aging during the extended outage are planned, provide justification for not performing such inspections. Describe the process that was used to maintain equipment in a dry lay-up condition. Discuss how humidity was controlled and maintained below 60 percent, whether the 60 percent

E-8 is relative to the coldest portion of the system, the results of any monitoring and trending of the air quality and humidity, and the corrective actions taken (including any inspections) for any conditions where the humidity criterion was exceeded (including corrective actions for the conditions identified in the above inspection report). Also, Table 1 identifies that future one-time inspections are planned. Discuss how the one-time inspections will differentiate between the rate of aging in the different environments (operation vs. shutdown), and discuss whether the one-time inspections will target locations that are susceptible to aging during normal operation or during shutdown.

TVA Response to RAI 3.0-2 LP For components within the dry lay-up systems, a One Time Inspection will be performed prior to restart to verify the material condition. The One-Time Inspection Program is described in the BFN LRA, Appendix B.2.1.29. The One-Time Inspection Program does not differentiate between the rate of aging in different environments (for example, normal power operation versus cold shutdown).

NRC RAI 3.0-3 LP Industry documents such as EPRI NP-5106 indicate that all metals are susceptible to microbiologically influenced corrosion (MIC),

especially in stagnant and low flow areas, and microbes in the system should be monitored by an adequate program at least every week and more often in outages. NRC Inspection Report 50-259/

87-45 identified damage due to MIC had already occurred in the fire protection system and water samples in the demineralized water system were planned. Table 2 does not identify MIC as a corrosion mechanism (for example, in the reactor water cleanup (RWCU) and control rod drive (CRD) systems for systems intended for wet lay-up with demineralized water. Table 3 does not identify MIC as a corrosion mechanism for systems that had no water chemistry control (wet, non-lay-up) during the extended outage. Similarly, Table 4 does not identify MIC as a corrosion mechanism for components subject to a moist air environment for extended periods of time. Provide technical justification that MIC is not an aging mechanism applicable to the stagnant, low flow, and moist air portions of the mechanical systems.

Alternatively, describe how inspections would detect loss of material caused by MIC at susceptible locations.

E-9 TVA Response to RAI 3.0-3 LP Table 2 contains Systems [Reactor Vessel and Internals (RVI),

Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69) and Control Rod Drive (85)] laid up with demineralized water maintained by the Chemistry Program CI-13.1 and moist air from possible pooling of Chemistry Program CI-13.1 controlled treated water between drain valves and double isolation valves due to closure sequence, closure timing, and possible leaking past the valves. Although portions of these systems had stagnant, low flow, and moist air environments, the Chemistry Program prevented the presence of microbes necessary to cause MIC damage. A review of BFN PERs and Work Orders (WOs) (operating experience) did not identify MIC as a concern in treated water.

Table 3 contains Systems [Condenser Circulating Water (27), Gland Seal Water (37), Containment (64), Reactor Core Isolation Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75)].

1. MIC is identified as a concern for raw water environments regardless of flow rate in the Condenser Circulating Water System (27).

2. The laid up environment for the Gland Seal Water System (37) was treated (condensate) water and moist air from possible pooling of treated water between drain or isolation valves and in the loop seals. BFN operating experience did not identify MIC as a concern in treated water environments. Although there were no chemistry controls placed on system 37 during lay-up, raw water or other MIC agents were not introduced into this system.

Therefore, the microbes necessary for the propagation of MIC were not present in this system during lay-up.

3. Treated (torus) water was maintained by the Chemistry Program CI-13.1 during wet lay-up. The portions of Systems

[Containment (64), Reactor Core Isolation Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75)] within the BFN LR scope (torus and torus attached piping) during Unit 1 lay-up had a treated water environment and moist air from possible pooling of treated water (torus water) between drain valves and double isolation valves due to closure sequence and timing and possible leaking past the valves.

Although portions of these systems had stagnant, low flow, and moist air environments, the Chemistry Program CI-13.1 prevented the presence of microbes necessary to cause MIC

E-10 damage. A review of BFN PERs and WOs (operating experience) did not identify MIC as a concern in treated water.

Table 4 Systems [Main Steam (01), Condensate (02), Heater Drains and Vents (06), Containment Inerting (76), and Containment Atmosphere Dilution (84)] contained treated water or nitrogen prior to Unit 1 lay-up. These systems were drained during lay-up.

These systems were isolated without the introduction of raw water or other MIC agents. Therefore, the microbes necessary for the propagation of MIC were not present in these systems during lay-up.

NRC RAI 3.0-4 LP For components in a lubricating oil environment, the LRA identified no aging effects requiring management. Discuss how the lubricating oil was maintained during the extended outage.

Discuss whether testing was performed to verify the oil qualities, including moisture, that would effect aging. If the lubricating oil was drained, discuss the resulting environment and any applicable aging degradation. Discuss any planned inspections to verify that there was no significant aging during the extended outage.

TVA Response to RAI 3.0-4 LP No maintenance or testing was performed for the Recirculation System (68) lubricating oil environment during plant lay-up.

However, this lubricating oil environment is being deleted by DCN 51219A which replaces the Recirculation Pump MG sets with a Variable Frequency Drive. This modification has been installed on Units 2 and 3 and will be installed on Unit 1 prior to restart.

No maintenance or testing was performed for the Reactor Core Isolation Cooling System (71) or the High Pressure Coolant Injection System (73) lubricating oil environment during plant lay-up. A sample of components with a lubrication oil environment within these systems will be inspected for the following aging effects by the One-Time Inspection Program.

• Carbon and low alloy steel - Loss of material due to general corrosion, crevice corrosion, pitting corrosion, and galvanic corrosion.

E-11

• Stainless steel - Loss of material due to crevice corrosion and pitting corrosion.

• Copper and copper alloys - Loss of material due to crevice corrosion, pitting corrosion, galvanic corrosion, and selective leaching.

• Cast iron and cast iron alloys - Loss of material due to general corrosion, crevice corrosion, pitting corrosion, galvanic corrosion, and selective leaching.

NRC RAI 3.0-5 LP Tables 2 and 3 show that some components are exposed to an air/gas internal environment during normal operation, but state that this environment is not applicable during the extended outage. These tables state that, due to drainage and system isolation, portions of several systems may have been exposed to an internal environment of moist air. These tables also state that the evaluation for treated water encompasses the aging effects for a moist air environment in these systems. However, Tables 2 and 3 identify additional aging effects for moist air than they identify for treated water (for example, cracking in low points where condensation and chemicals can accumulate). Clarify the above discrepancy in Tables 2 and 3. Also, since the rate of loss of material caused by a moist air environment during lay-up may be more severe than a flowing treated water environment, explain why the evaluation of the aging effects for the treated water environment would encompass that of the aging effects for a moist air environment in these systems. Tables 2 and 3 state that one-time inspections are planned for the components that are exposed to an air/gas internal environment. Discuss the plans for additional inspections before startup of Unit 1 to evaluate aging during the extended outage, or inspections that were performed during the extended outage. If no such inspections are planned or none have been performed, provide justification that they are not needed and discuss how the one-time inspection will distinguish between the rate of aging in the different environments.

TVA Response to RAI 3.0-5 LP Table 2 Systems [Reactor Vessel and Internals (RVI), Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69) and Control Rod Drive (85)] and Table 3 Systems [Condenser Circulating Water (27), Gland Seal Water (37), Containment (64), Reactor Core Isolation Cooling (71),

E-12 High Pressure Coolant Injection (73), and Core Spray (75)] address the portions of these systems laid up in a wet environment. Due to closure sequence, closure timing, and possible leakage past the double isolation valves or two drain valves for these systems, it is assumed that an air/gas environment with an uncertain amount of moisture was trapped between the double isolation valves. The trapped moisture between the double valves was considered the same, (i.e., treated water or raw water) as was flowing through the valves prior to closure. The N/A (not applicable) denotes that this trapped air/gas environment will be evaluated under the corresponding raw or treated water evaluations.

During lay-up the temperature of the systems addressed in Tables 2 and 3 were less than 1400F. Therefore, crack initiation and growth due to SCC is not a concern for stainless steels and nickel-based alloys in a wet lay-up environment.

The evaluation of these moist air environments for the systems addressed in Tables 2 and 3 identified no additional aging effects other than those identified for the corresponding raw or treated water environment. The BFN LRA identified these trapped air environments for One-Time Inspection because the extent of corrosion could be quantified. It was not the intent of this aging management review to determine the rate of loss of material.

The One-Time Inspection described in the license renewal application will be performed prior to restart to verify the material condition.

NRC RAI 3.0-6 LP Table 3 of Reference 2 identifies several systems that were not incorporated into the Unit 1 wet lay-up program. These systems were exposed to treated (non-controlled) or raw water during the extended outage. Table 3 concludes that there is no additional aging management for these systems. In order to justify this conclusion, discuss the results of any water samples, including pH, oxygen levels, aggressive chemical species, biological activity, and corrosion product levels. Discuss whether the systems were stagnant or periodically flowed. Discuss the plans for prestartup inspections to determine the loss of material due to general, pitting, and crevice corrosion, MIC, dealloying, and galvanic corrosion, or provide justification that such inspections are not needed. Also, discuss inspections for the degradation of other materials, such as elastomers and other non-metallic materials.

E-13 TVA Response to RAI 3.0-6 LP Condenser Circulating Water System (27) - System 27 was exposed to Tennessee River water which is the same environment it is exposed to during normal operation. Without the addition of foreign chemicals the aging effects during normal operation and during lay up are the same.

Gland Seal Water System (37) - The system was drained (ambient air present) with the Gland Seal tank in component lay-up per MPI-1-000-TNK002. However, it was assumed that the secondary containment loop seal as well as other low points in the system were not completely drained. Therefore, stagnant treated water supplied from the Condensate System (02) was evaluated for these areas.

Systems (Containment (64), Reactor Core Isolation Cooling (71),

High Pressure Coolant Injection (73), and Core Spray (75) - The torus and torus attached piping for System 64 (i.e., the torus itself) and for Systems 71, 73, and 75 (torus attached piping) saw torus water maintained by Chemistry Program CI-3.1, Appendix A, Table 20) for extended periods of time until the torus was drained in the summer of (2003). When filled, the torus is approximately 1/2 full of water with the other half ambient air. The torus water was not "flowing" in that the only significant water movement was relatively infrequent transfers into and out of the Unit 1 torus. The torus on an operating unit can not be considered "flowing" either. The operating unit's torus would also be nitrogen-inerted. Torus coating touch-up/repair is part of the restart work to be completed while the torus is drained.

The torus impurity administrative goals for conductivity, chloride, and sulfate given in CI-13.1 are 2.0 µS/cm, 75 ppb, and 75 ppb, respectively. A review of sampling data showed that the torus water was maintained within the chemistry specifications.

Sampling is performed quarterly.

The One-Time Inspection described in the license renewal application will be performed prior to restart to verify the material condition.

NRC RAI 3.0-7 LP Notes 1 and 2 of Tables 2 and 4 indicate that inspections will be performed prior to Unit 1 restart for certain components where additional aging effects were identified for the extended shutdown. Examples include additional aging effects for copper alloy, cast iron, cast iron alloy, and stainless steel components

E-14 in system locations where condensation could build up, and carbon and low alloy steel in an internal environment. No descriptions of the inspections were provided. Discuss the proposed inspections, including scope, method, procedure, parameters monitoring and trending, detection of aging effects, and acceptance criteria, in order to justify the adequacy of the inspections.

TVA Response to RAI 3.0-7 LP Note 1 of Tables 2 and 4 states:

The AMR for the operating condition did not consider general corrosion as an aging mechanism on external surfaces of carbon steel when the operating temperature is greater than 212°F. The AMR for the lay up period did consider general corrosion as an aging mechanism because the surface is less than 212°F during the extended outage of Unit 1. The piping and components will be inspected for external corrosion prior to Unit 1 restart. If necessary, unacceptable external corrosion effects will be corrected prior to Unit 1 restart. These piping and components will not require additional aging management during the period of extended operation.

This note identifies the potential for external general corrosion on carbon and low alloy steel components that are normally operated at temperatures greater than 212°F. This note is applicable to the Reactor Vessel (RV), Feedwater System (03),

and the Heater Vents and Drains System (06).

External surface monitoring is performed in accordance with the System Monitoring Program described in the BFN LRA, Appendix B, Section B.2.1.39. This is the same aging management program proposed for managing external loss of material during the period of extended operation.

Note 2 of Tables 2 and 4 states:

The internal operating environment for these systems is air/gas without a significant amount of moisture present. During lay up there were no moisture controls on the non-operating Unit 1 portions of these systems. Without moisture controls the possibility of moisture collecting at system low points exists.

The piping components will be inspected for the potential aging effects prior to Unit 1 restart. If necessary, unacceptable

E-15 internal corrosion effects will be corrected prior to Unit 1 restart. These piping and components will not require additional aging management during the period of extended operation.

This note identifies the potential for internal loss of material and cracking (aluminum only) that are normally exposed to either dry air or nitrogen. This note is applicable to the following systems and materials.

Feedwater (03)

Copper Alloy Main Steam (01)

Aluminum Alloy Containment Inerting (76)

Carbon and Low Alloy Steel Stainless Steel Nickel Alloy Copper Alloy Aluminum Alloy Cast Iron Containment Atmosphere Dilution (84)

Carbon and Low Alloy Steel Stainless Steel Copper Alloy Aluminum Alloy Cast Iron Internal surface monitoring is performed in accordance with the One-Time Inspection Program described in the BFN LRA, Appendix B, Section B.2.1.29. This is the same aging management program proposed for managing internal aging effects of components exposed to moist air during the period of extended operation.

NRC RAI 3.0-8 LP The LRA and Reference 2 are not clear regarding the management of galvanic corrosion. There is the potential for galvanic corrosion during the extended outage for those systems that were maintained in wet lay-up, wet non-lay-up, or moist air such that condensation and pooling could occur. The LRA and Reference 2 state that galvanic corrosion is managed through use of the Chemistry AMP and the One-Time Inspection AMP; however, there were differences in water chemistry during the extended outage and the One-Time Inspection AMP does not cover galvanic corrosion. Describe how galvanic corrosion during the extended outage is managed. Also, discuss any inspections that are planned to determine the extent of galvanic corrosion during the extended outage.

E-16 TVA Response to RAI 3.0-8 LP The chemistry program implemented during the extended outage is the same program that BFN uses on the two operating units during Cold Shutdown conditions for refueling and maintenance outages.

This extended outage program would consist of CI-13.1 "Chemistry Program" controls which would continue to be based on the EPRI BWR Water Chemistry Guidelines (TR-103515). The One-Time Inspection Program utilized to verify the effectiveness of the Chemistry Control Program for preventing loss of material will select the susceptible locations (where materials with different electrochemical potentials are in contact in the presence of contaminants). Galvanic corrosion is included in the One-Time Inspection Program.

Questions related to Reactor Vessel, Internals, and Reactor Coolant System (3.1)

NRC RAI 3.1-1 LP Reference 2 indicated that the internal environment of System 068 (RRS) is flowing, air saturated, demineralized water conforming to the Chemistry Program (CL-13.1). Define flowing." Identify all components in the RV, RI and RRS that may not have contained flowing, air saturated, demineralized water conforming to the Chemistry Program (CL-13.1) which will not be replaced prior to restart. For each component that may have had stagnant conditions, provide a list of materials, degradation mechanisms, and aging management programs (AMPs) and describe why the AMPs will manage any aging effects resulting from stagnant conditions during wet lay-up.

TVA Response to RAI 3.1-1 LP One Reactor Water Cleanup System (69) filter demineralizer was in service at approximately 100 gpm to maintain reactor coolant water quality per CI-13.1 "Chemistry Program". The wet lay-up flow path was Reactor Water Cleanup System (69) suction from the 'A' Recirculation Loop through a short section of Residual Heat Removal System (74) piping with a small portion of Reactor Water Cleanup System (69) suction flow coming from the Reactor Vessel bottom head drain line, through Reactor Water Cleanup System (69) inlet piping to the Reactor Water Cleanup System (69) filter demineralizer returning via the Reactor Water Cleanup System (69) effluent piping which returns to the Reactor Pressure Vessel via the 'B' Feedwater line. A portion of the Reactor Water Cleanup

E-17 System (69) effluent flow was routed to provide flow through Control Rod Drive System (85) components.

Portions of both A and B loops of Recirculation piping are being replaced as part of the BFN Unit 1 restart effort.

The components within the scope of BFN LR for the RV, RI, and RRS are exposed to flowing water per the flow path described above. Within the established flow path, stagnant areas may have persisted in branch lines used to isolate the RRS.

The aging effects identified for the flowing portions of these systems are the same as those for the stagnant portions. However, due to the stagnant nature in these lines the material may have corroded at a higher rate. The One-Time Inspection described in the license renewal application will be performed prior to restart to verify the material condition.

The Unit 1 wet lay-up program is essentially the same program that BFN uses for the operating units during Cold Shutdown conditions for refueling and maintenance outages (EPRI BWR Water Chemistry Guidelines (TR-103515-R2, page 4-6, Table 4-2) for "Reactor Water

- Cold Shutdown").

NRC RAI 3.1-2 LP For all heat exchangers that will not be replaced:

a) Identify whether the reactor coolant side was subject to flowing or stagnant conditions during wet lay-up.

b) For each location that may have had stagnant conditions, provide a list of materials, degradation mechanisms, and AMPs and describe why the AMPs will manage any aging effects resulting from stagnant conditions during wet lay-up.

c) Identify the environment on the shell side during wet lay-up; the materials, degradation mechanisms, and AMPs; and describe why the AMPs will manage any aging effects resulting from lay-up.

TVA Response to RAI 3.1-2 LP (a)(b)(c)

The scope of BFN License Renewal Application does not include any heat exchanger within the reactor coolant pressure boundary for any system.

E-18 NRC RAI 3.1-3 LP Describe any inspections, including results, of components in the RV, RI, and RRS that were performed during the lay-up period.

Also list prestartup inspection plans for all RV, RI, and RRS components and describe why the wet lay-up inspections and prestart inspections are sufficient to ensure that any aging effects resulting from lay-up are being adequately managed.

The RI inspection program discussed should include the following locations:

(1) CRD Nozzle welds (2) In Core Monitor (ICM) nozzle welds (3) Standby Liquid Control (SLC) nozzle welds (4) Core Shroud (5) Access Hole Covers (6) Top Guide (7) Core Spray Piping and Spargers (8) Jet Pump Assembly In Section F.6 of the LRA, the licensee makes a commitment to perform preservice inspection of the RI using the referenced BWRVIP guidelines. Provide information of the extent of preservice inspection that each RI component will receive in accordance with the BWRVIP guidelines.

TVA Response to RAI 3.1-3 LP (1) CRD Nozzle welds The examination of the components located in the lower plenum is performed in accordance with the augmented examination recommendations of BWRVIP-47. The following components are located in the lower plenum and addressed by BWRVIP-47: CRD housing; control rod guide tube; orifice fuel support; in-core housing; and guide tube and dry tube assemblies.

All examination requirements of BWRVIP-47 will be completed prior to Unit 1 restart.

(2) In Core Monitor (ICM) nozzle welds The examination of the components located in the lower plenum is performed in accordance with the augmented examination recommendations of BWRVIP-47. The following components are located in the lower plenum and addressed by BWRVIP-47: CRD

E-19 housing; control rod guide tube; orifice fuel support; in-core housing; and guide tube and dry tube assemblies.

(3) Standby Liquid Control (SLC) nozzle welds The inspection of the standby liquid control (SLC) nozzle-to-safe end weld shall be performed in accordance with current industry guidance (ASME Section XI). Insulation covering this weld will be removed if accessible, in order to meet the intent of BWRVIP-27-A, which requires an enhanced VT-2 leak test while the system is pressurized in conjunction with a volumetric inspection that is to be repeated once each 10-year ISI interval.

All examination requirements of BWRVIP-27 will be completed prior to Unit 1 restart.

(4) Core Shroud The examination of the core shroud is performed in accordance with the augmented examination requirements of the NRC and BWRVIP-76.

The BFN core shroud is considered to be Category C, as defined in Appendix B of BWRVIP-76, which reflects the highest susceptibility to cracking. The core shroud provides a floodable volume in the event of a postulated recirculation line break and is formed of cylindrical shell sections. The circumferential welds are ultrasonically examined at the frequency specified in BWRVIP-76. The percent of the examined circumferential weld length and percent of the circumferential weld length examined.

All examination requirements of BWRVIP-76 will be completed prior to Unit 1 restart.

(5) Access Hole Covers The existing access hole cover (AHC) design serves to maintain a leak-tight barrier between the annulus and lower plenum. The core shroud access hole covers are examined in accordance with GE SIL No. 462, Revision 1.

The access hole covers for Unit 1 are cracked essentially 360 degrees and are scheduled for replacement prior to unit restart.

(6) Top Guide The examination of the top guide and associated components is performed in accordance with the augmented examination recommendations of BWRVIP-26. The top guide provides lateral

E-20 support for the fuel assemblies and is considered a safety related component. The components which comprise the top guide are itemized along with the BWRVIP-26 "location" designation.

All examination requirements of BWRVIP-26 will be completed prior to Unit 1 restart.

(7) Core Spray Piping and Spargers The examination of the core spray piping and spargers is performed in accordance with the recommendations of BWRVIP-18. The core spray piping and spargers located inside the RPV provide a flow path for emergency core cooling water from the Core Spray System RPV nozzle through the shroud to the core spray spargers above the reactor core.

All examination requirements of BWRVIP-47 will be completed prior to Unit 1 restart.

(8) Jet Pump Assembly The examination of the jet pumps, their welds, and other associated components is performed in accordance with the augmented examination recommendations of BWRVIP-41. Each jet pump assembly, 10 assemblies in each RPV, consists of a riser pipe, riser pipe brace, and two jets. The safety function of the jet pump assembly is to provide a floodable volume to 2/3 of the core height in a post-accident core re-flood scenario. The BWRVIP-41 report prioritizes the different jet pump assembly weld locations as high, medium, or low depending on the potential safety consequences from the failed location (NOTE: There are no low priority inspection welds at BFN). The priority rankings are used to determine the sequence at which the baseline inspections are to be performed. Inspection recommendations for these weld locations are made with respect to a period of time called inspection cycle. This time period is defined as 6 years. For the high priority welds, 100 percent inspection in one inspection cycle (6 years) is required. For the medium priority welds, 100 percent inspection in two inspection cycles is justified provided 50 percent of the welds are examined during the first inspection cycle.

[NOTE: All baseline inspections (both high and medium priority welds) for Unit 1 will be performed prior to unit restart, designated as the U1C6 Refueling Outage. Re-inspection cycles will be clarified once the actual restart date of Unit 1 is determined.]

E-21 All examination requirements of BWRVIP-41 will be completed prior to Unit 1 restart.

Questions related to Engineered Safety Features Group (3.2)

NRC RAI 3.2-1 LP In Table 1 of Reference 2, for high pressure coolant injection system (73) and core spray system (75), the Unit 1 lay-up components made of carbon and low alloy steel as well as cast iron and cast iron alloy were exposed to air/gas (internal) or inside air (external) environments, and are identified as being susceptible to loss of material due to general corrosion during the lay-up period. The same aging effect is also identified for the same components, in the supposedly same environments, during plant operation. Because of the possible uncertainty of the dryness of air environments, the applicant is requested to provide technical justification that the lay-up air environments (such as, air/gas, inside air, outside air, etc.) for these components are not any more aggressive than their counterparts in the plant operating environments. Consideration should be given, but not limited to, the oxygen level and moisture content of the air which is the source of electrolytic reaction that initiates the corrosion.

TVA Response to RAI 3.2-1 LP The High Pressure Coolant Injection System (73) was drained and laid up dry per 1-GOI-100-13.A and 0-TI-373. The Core Spray System (75) was drained and laid up dry per 1-GOI-100-13.17 and 0-TI-373.

The air/gas environments for these systems were maintained to less than 60 percent humidity with dehumidifiers. Both the normal and lay up environments were relatively dry (no pooling) air/gas environments. Therefore, the aging effects for these components are the same.

The heating and ventilation in the reactor building was maintained during lay-up. Therefore, the inside air environment for systems 73 and 75 did not significantly change systems 73 and 75.

Furthermore, the aging effects during normal operation and lay up are the same.

There is no outside air environment identified within the LR boundary for systems 73 and 75.

E-22 NRC RAI 3.2-2 LP In Table 1, for high pressure coolant injection system (73) and core spray system (75), the applicant identified One-Time Inspection Program as the AMP for carbon and low alloy steel components and cast iron and cast iron alloy components exposed to air/gas (internal) environments. One-time inspections are appropriate where degradation is at a negligibly slow rate in environments such as dehumidified air, but may not be appropriate for a moist air environment. Provide justification that the one-time inspections are appropriate for possible unintended moisture conditions in both systems during the lay-up period.

Also discuss whether the one-time inspections will include areas susceptible to aging effects caused by the moist air lay-up condition as well as those areas susceptible during normal operation.

TVA Response to RAI 3.2-2 LP Pooled water is not anticipated for the portions of Systems 73 and 75 addressed in Table 1 per the lay-up program 0-TI-373.

However, the One-Time Inspection described in the license renewal application will be performed prior to restart to verify the lay-up program was adequate in protecting the material from significant degradation.

Questions related to Auxiliary Systems Group (3.3)

NRC RAI 3.3-1 LP Section 3.0.1 of the LRA describes the criteria for evaluating systems for aging during the extended outage. Systems that remain in operation for Unit 1 or in support of operation for Units 2 and 3 are not evaluated. However, based on the system descriptions, it appears that at least a portion of the following systems should have been evaluated (i.e., it appears that the system was idle or that only the main headers were needed to support operation of Units 2 and 3). Discuss the operation of the following systems during the extended shutdown, and explain why these systems were not evaluated for aging during the extended shutdown.

Residual Heat Removal Service Water System (023)

Control Air System (032)

Sampling and Water Quality System (043)

Emergency Equipment Cooling Water System (067)

Reactor Water Cleanup System (069)

E-23 Reactor Building Closed Cooling Water System (070)

Radioactive Waste Treatment System (077)

Neutron Monitoring System (092)

If it is determined that these systems, or portions thereof, met the criteria for evaluation, provide an evaluation of aging during the extended outage. Include a description of the environment, identification of AERMs, and proposed aging management. Also, discuss any inspections that are planned to determine the extent of aging during the extended outage.

TVA Response to RAI 3.3-1 LP Residual Heat Removal Service Water System (23) and Emergency Equipment Cooling Water System (67).

The Unit 1 portions of piping and components for these systems not required for Unit 2/3 operation are not in the Lay-up Program.

The piping and components in these systems are in shared systems and contained either raw water or moist air during the extended outage period. These systems have been evaluated for a raw water and/or moist air environment for the in-service portions of these systems. The aging effects identified for the operating conditions encompass the aging effects for the lay-up conditions.

The One-Time Inspection described in the license renewal application will be performed prior to Unit 1 restart to verify the material condition.

Control Air System (32)

The Unit 1 piping components of this system not required for Unit 2/3 operation but in scope for license renewal is not in the Lay-up Program. For this system, the additional aging effects are due to the possibility of moisture collecting in the system components. For the operating condition the internal environment is air/gas without a significant amount of moisture present.

During lay-up there were no moisture controls on the non-operating Unit 1 portions of this system. Without moisture controls the possibility of moisture collecting at system low points exists.

The aging effects associated with moist air are contained in the detailed lay-up evaluation of the Containment Inerting System (76) and the Containment Atmosphere Dilution System (84). The potential aging effects for the Control Air will be similar to those identified for the Containment Inerting and Containment Atmosphere Dilution systems. The One-Time Inspection described in the license renewal application will be performed prior to Unit 1 restart to verify the material condition.

E-24 Sampling and Water Quality System (43)

The Unit 1 piping and components of this system not required for Unit 2/3 operation are not in the Lay-up Program. The piping and components in this system has contained treated water, raw water, and/or moist air during the extended outage period. This system has been evaluated for these environments for the operating condition. The aging effects identified for the operating conditions encompass the aging effects for the lay-up conditions.

The One-Time Inspection described in the license renewal application will be performed prior to Unit 1 restart to verify the material condition.

Reactor Water Cleanup System (69)

Evaluated per Browns Ferry Nuclear (BFN) Unit 1, Lay-up and Preservation Program, Table 2.

Reactor Building Closed Cooling Water System (70)

Portions of the Unit 1 piping and components of this system not required for Unit 2/3 operation are not in the Lay-up Program.

The piping and components in this system contained treated water maintained to CI-13.1 and/or moist air during the extended outage period. The aging effects associated with treated water maintained to CI-13.1 are contained in the detailed lay-up evaluation of the Reactor Core Isolation Cooling System (71), the High Pressure Coolant Injection System (73), and the Core Spray System (75). The potential aging effects for the Closed Cooling Water System (70) will be similar to those identified for the Reactor Core Isolation Cooling System (71), the High Pressure Coolant Injection System (73), and the Core Spray System (75).

The One-Time Inspection described in the license renewal application will be performed prior to Unit 1 restart to verify the material condition.

Radioactive Waste Treatment System (77)

The Unit 1 piping and components for this system are not in the Lay-up Program. The piping and components in this system within the BFN LRA scope remained in-service. An aging effects evaluation was performed for this system and documented in the BFN LRA Table 3.3.2.25.

E-25 Neutron Monitoring System (92)

The Unit 1 portions of piping and components for this system are not in the Lay-up Program. The portion of this system which is in scope for BFN license renewal is part of the reactor vessel pressure boundary. An aging effects evaluation was performed for the Unit 1 lay-up portions of the Reactor Vessel and Internals System (RVI). The aging effects evaluation for the Reactor Vessel and Internals System (RVI) encompasses the Neutron Monitoring System (92). The One-Time Inspection described in the license renewal application will be performed prior to Unit 1 restart to verify the material condition.

RAI 3.3-2 LP LRA Table 3.3.2.29 and Table 2 of Reference 2 state that many carbon and low alloy steel components in the Control Rod Drive System have an internal environment of raw water during normal operation. However, Table 2 states that this environment is not applicable during the extended outage. Clarify the environment during the extended outage, and discuss the implications of the environment on the aging of these components. Specify any applicable aging effects and the corresponding AMPs. Also, discuss whether any inspections are planned to determine the extent of aging during the extended outage.

TVA Response to RAI 3.3-2 LP The Raw Cooling Water System provides cooling water to the CRD pump oil cooler and thrust bearing. The following materials see the raw water environment during lay-up: Carbon steel piping and fittings, copper valves, copper heat exchanger (cooler) tubing, cast iron heat exchanger (cooler) head.

A sample of components with a raw water environment within the Control Rod Drive System (85) will be inspected for the following aging effects by the One-Time Inspection Program.

• Carbon and low alloy steel - Loss of material due to general corrosion, crevice corrosion, pitting corrosion, galvanic corrosion, microbiologically influenced corrosion, and biofouling,

• Copper and copper alloys - Loss of material due to crevice corrosion, pitting corrosion, microbiologically influenced corrosion, biofouling, and selective leaching.

E-26

• Cast iron and cast iron alloys - Loss of material due to general corrosion, crevice corrosion, pitting corrosion, galvanic corrosion, microbiologically influenced corrosion, biofouling, and selective leaching.

Questions related to Steam and Power Conversion Systems Group (3.4)

NRC RAI 3.4-1 LP In Table 3, the applicant identified portions of several systems that were not incorporated into the Unit 1 wet lay-up program.

For gland seal water system (37), containment (64), high pressure coolant injection system (73), and core spray system (75), the applicant identified various aging effects for carbon and low alloy steel, copper alloy, cast iron and cast iron alloy, stainless steel, nickel alloy, and aluminum alloy components in treated water (internal) and/or treated water (external) environments. To ensure that these components have not been subjected to aging degradation more severe than their Units 2 and 3 counterparts during plant operation, the applicant is requested to (1) describe the general environments associated with the above system components, which were not incorporated into the Unit 1 wet lay-up program; (2) provide a detailed description of the water chemistry of the treated water existing in the extended lay-up period, and discuss its differences from the water chemistry existing in the plant operation; (3) discuss any water chemistry monitoring that has been performed for the treated water during the lay-up period, and discuss how the aging effects/aging mechanisms were determined for each of the above components; (4) because of the potential differences in water temperature and chemistry, and the potential effect of stagnant flow condition in conspicuous portions of the Unit 1 lay-up components, discuss the possibility of incurring more severe aging degradations to these lay-up components than could have occurred during the plant operation; (5) discuss how the latent effect of the potentially more severe aging degradation occurring in the Unit 1 lay-up can be accounted for in their license renewal aging management review; and (6) justify the basis for not performing inspections for potential aging effects for these components prior to restart.

TVA Response to RAI 3.4-1 LP (1) System 37 (Gland Seal Water) - The system was drained (ambient air present) with the Gland Seal tank in component lay-up per MPI-1-000-TNK002. However, it was assumed that the secondary containment loop seal as well as other low points in the system

E-27 were not completely drained (The lay-up environment for System 37 is treated (condensate) water and moist air from possible pooling of treated water between drain or isolation valves and in the loop seals). Therefore, stagnant treated water supplied from the Condensate System (02) is evaluated for these areas. The impurity administrative goals for conductivity, chloride and sulfate given in CI-13.1 are 2.0 µS/cm, 75 ppb, and 75 ppb, respectively.

Sampling is performed weekly.

Systems: Containment (64), Reactor Core Isolation Cooling (71),

High Pressure Coolant Injection (73), and Core Spray (75) - The torus and torus piping for System 64 (torus itself), and for 71, 73, and 75 (torus attached piping) saw torus water maintained by Chemistry Control Program (CI-13.1, Appendix A, Table 20) for extended periods of time until the torus was drained in the summer of 2003. (When filled, the torus is approximately 1/2 full of water with the other half ambient air.). This torus water was not "flowing" in that the only significant water movement was relatively infrequent transfers into and out of the Unit 1 torus.

(The torus on an operating unit can not be considered "flowing" either. An operating unit's torus would also be nitrogen-inerted.) Torus coating touch-up/repair is a part of the restart work to be completed while the torus is drained. The torus impurity administrative goals for conductivity, chloride, and sulfate given in CI-13.1 are 2.0 µS/cm, 75 ppb, and 75 ppb, respectively. Sampling is performed quarterly.

(2) The description of water chemistry is discussed in item 1 above. The chemistry program implemented during the wet lay-up period is essentially the same program that BFN uses on the two operating units during Cold Shutdown conditions for refueling and maintenance outages. This extended operation program would consist of CI-13.1 "Chemistry Program" controls which would continue to be based on the EPRI BWR Water Chemistry Guidelines (TR-103515).

(3) As discussed in response to item 1 above, the treated water is sampled and monitored per the Chemistry Control Program CI-13.1.

The aging effects/aging mechanisms for the components within the systems in lay-up are similar to those determined for the operational units.

(4) As discussed in item 1 above, the possibility of low flow or stagnant conditions exists in these systems. Due to low flow conditions in these systems, the One-Time Inspection described in the license renewal application will be performed prior to restart to verify the material condition.

E-28 (5) There have been no latent effects identified for the chemistry program implemented during the Unit 1 wet lay-up period. This program is essentially the same program that BFN uses for operating units during Cold Shutdown conditions for refueling and maintenance outages (EPRI BWR Water Chemistry Guidelines TR-103515-R2).

(6) One-Time Inspection will be performed prior to restart.

NRC RAI 3.4-2 LP In Table 3, the applicant indicated that, for condenser circulating water system (27), carbon and low alloy steel components and cast iron and cast iron alloy components were susceptible to loss of material due to general corrosion, crevice corrosion, pitting corrosion, biofouling, and MIC in raw water (internal) environments. Since the components were exposed to raw stagnant water for an extended period of time, portions of the components, especially those at low points, may have already been subject to aging degradation far more severe than their Units 2 and 3 counterparts in plant operation. The applicant is requested to justify the basis for not performing inspections for potential aging effects for the components prior to restart.

TVA Response to RAI 3.4-2 LP During normal operation and lay-up, Condenser Circulating Water System (27) components saw raw stagnant water. The One-Time Inspection described in the license renewal application will be performed prior to restart to verify the material condition.

NRC RAI 3.4-3 LP In Table 3, the applicant indicated that, for condenser circulating water system (27), the cast iron and cast iron alloy components (valves, fittings, etc.) were exposed to raw water (internal) environments, and identified no aging effects due to selective leaching. It should be noted that in raw water environments, leaching in the form of graphitic corrosion could occur with loss of iron matrix from gray cast iron. In addition, gray cast iron can also display the effects of selective leaching in relatively mild environments. The applicant is requested to discuss why selective leaching is not identified as a potential aging mechanism for the components.

E-29 TVA Response to RAI 3.4-3 LP The aging effects write-up (Mechanical System/Program Evaluation) identified selective leaching as an aging mechanism for gray cast iron for the Condenser Circulating Water System (27), and the line item in Table 3 should have included selective leaching for gray cast iron in System (27).

NRC RAI 3.4-4 LP In Table 3, the applicant indicated that, for gland seal water system (37), copper alloy components and cast iron and cast iron alloy components saw treated (condensate) water for an extended period of time. Similarly, cast iron and cast iron alloy components in HPCI system (73), and aluminum alloy components and cast iron and cast iron alloy components in core spray system (75) saw treated (torus) water for an extended period of time. The applicant identified loss of material due to general corrosion, selective leaching, crevice corrosion, and pitting corrosion as the aging effect requiring management. The applicant is requested to explain why galvanic corrosion is not identified as a potential aging mechanism for the above listed components, if they are galvanically coupled to a more cathodic material.

TVA Response to RAI 3.4-4 LP The cast iron components within the Gland Seal Water System (037) are in contact with carbon steel piping. Cast iron and carbon steel are grouped together in the galvanic series as similar metals. Since cast iron components within the Gland Seal Water System (037) are not in contact with more cathodic materials, galvanic corrosion is not a concern. Similarly, copper alloy components are not in contact with a more cathodic material such as stainless steel within the Gland Seal Water (037) System.

Therefore galvanic corrosion is not a concern.

For the High Pressure Coolant Injection System (73) and the Core Spray System (75), cast iron is used only for the pump casings which are connected to carbon and low alloy steels piping. Cast iron and carbon steel are grouped together in the galvanic series as similar metals. Since cast iron materials are not in contact with more cathodic materials, galvanic corrosion is not a concern for cast iron and cast iron alloys in treated (torus) water for the High Pressure Coolant Injection System (73) and the Core Spray System (75).

E-30 For the Core Spray System (75), aluminum alloy is used for flanges off the 24-inch condensate supply header within the scope of BFN license renewal. A rubber electrically insulating gasket is used to separate the aluminum flanges from more cathodic materials.

Since aluminum alloys are not in contact with more cathodic materials, galvanic corrosion is not a concern for aluminum components in a treated water environment for the Core Spray System (75).

NRC RAI 3.4-5 LP In Table 3, for main steam system (01), condensate system (02),

and heater drains & vents system (06), Unit 1 lay-up components of carbon and low alloy steel, stainless steel, copper alloy, aluminum alloy, and cast iron and cast iron alloy, were identified as being susceptible to various forms of aging degradation in air/gas (internal) moist air environments that lacked moisture controls. These same Unit 1 lay-up components will be exposed to treated water (internal) environments after restart. The applicant identified the aging effects of loss of material due to various selective leaching, general corrosion, crevice corrosion, pitting corrosion, and galvanic corrosion, and of crack initiation/growth due to stress-corrosion cracking (SCC), for the extended period of operation. Since the rate of loss of material caused by a moist air environment during lay-up may be more severe than a flowing treated water environment, explain why the evaluation of the aging effects for the treated water environment would encompass that of the aging effects for a moist air environment in these systems, and justify the basis for not performing inspections of these affected system components prior to restart. Also, explain, specifically, why galvanic corrosion" was identified for cast iron and cast iron alloys in the condensate system (02) during the Unit 1 lay-up, but not for the plant operation condition.

TVA Response to RAI 3.4-5 LP It is our understanding that RAI 3.4-5 LP should have referred to Table 4 instead of Table 3. It was not stated that an evaluation of the aging effects for a treated water environment would encompass the aging effects for a moist air environment in the systems addressed in Table 4. The evaluation of the aging effects for a moist air environment for the systems addressed in Table 4 is captured in the Mechanical System/Program Evaluation Detail for (Unit 1 - Dry Lay-up - Not in Lay-up Program Revision 1).

E-31 The One-Time Inspection described in the license renewal application will be performed prior to restart to verify the material condition.

The cast iron valves and fittings within the scope of BFN license renewal for both normal operation and Unit 1 lay-up are coupled with either carbon steel or aluminum. Due to cast iron being either equal or greater in the galvanic series than carbon steel or aluminum, galvanic corrosion is not a concern for the cast iron components within the scope of BFN license renewal for Condensate System (02).

NRC RAI 3.4-6 LP In Table 4, for condensate system (02), copper alloy components were identified as being susceptible to loss of material due to selective leaching, crevice corrosion, and pitting corrosion.

Copper alloys will preferentially corrode when coupled with more cathodic metals such as stainless steel, nickel-based alloys, titanium or graphite in an electrolytically conducive environment.

The applicant is requested to explain why galvanic corrosion was not included as a potential aging mechanism in air/gas (internal) moist air and treated water (internal) environments.

TVA Response to RAI 3.4-6 LP The copper alloys fittings and valves within the scope of BFN license renewal for the Condensate System (02) are not in contact with a more cathodic material such as stainless steel or nickel based alloys. Therefore, galvanic corrosion is not a concern for copper alloys for the period of extended operation for the Condensate System (02).