ML041680255

License Renewal Application - Response to Requests for Additional Information on Electrical and Auxiliary Systems

ML041680255
Person / Time
Site:	Cook
Issue date:	06/08/2004
From:	Nazar M Indiana Michigan Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP:NRC:4034-06, TAC MC1202, TAC MC1203
Download: ML041680255 (24)

Text

Indiana Michigan Power'Company 500 Circle Drive Buchanan, MI 49107 1373 INDIANA MICHIGAN POWER June 8, 2004 AEP:NRC:4034-06 10 CFR 54 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P I-17 Washington, DC 20555-0001

SUBJECT:

Donald C. Cook Nuclear Plant, Units 1 and 2 Docket Nos. 50-315 and 50-316 License Renewal Application - Response to Requests for Additional Information on Electrical and Auxiliary Systems (TAC Nos. MC 1202 and MC1203)

REFERENCES:

1. Letter from J. Rowley, U. S. Nuclear Regulatory Commission, to M. K. Nazar, Indiana Michigan Power Company, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Unit 1 and 2 License Renewal Application," dated May 6, 2004.

2. Letter from J. Rowley, U. S. Nuclear Regulatory Commission, to M. K. Nazar, Indiana Michigan Power Company, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Unit I and 2 License Renewal Application," dated May 19, 2004.

Dear Sir or Madam:

By letter dated October 31, 2003, Indiana Michigan Power Company (I&M) submitted an application to renew the operating licenses for Donald C. Cook Nuclear Plant (CNP), Units 1 and 2.

During the conduct of its review, the Nuclear Regulatory Commission (NRC)

Staff identified areas where additional information was needed to complete its review of the license renewal application (LRA). This letter responds to requests for additional information (RAIs), which were documented in the NRC letter dated May 6, 2004 (Reference 1), for the following LRA sections:

• 2.5 - Scoping and Screening Results: Electrical and Instrumentation and Control Systems

• 3.3.2 - Aging Management Review Results: Auxiliary Systems

-A I ct

U. S. Nuclear Regulatory Commission Page 2 AEP:NRC:4034-06

• 3.6 - Aging Management Review Results: Electrical and Instrumentation and Controls Reference I also included RAIs pertaining to time-limited aging analyses (TLAAs) in Section 4 of the LRA. I&M's responses to the TLAA RAIs are included in a separate letter that is currently being prepared to respond to the TLAA RAIs documented in the NRC letter dated May 19, 2004 (Reference 2).

The enclosure to this letter provides an affirmation pertaining to the statements made in this letter.

The attachment to this letter provides the additional information requested from the NRC Staff. There are no new commitments contained in this submittal.

Should you have any questions, please contact Mr. Richard J. Grumbir, Project Manager, License Renewal, at (269) 697-5141.

Sincerely, M. K. Nazar Senior Vice Pre dent and Chief Nuclear Officer NH/rdw

Attachment:

Affirmation Response to Requests for Additional Information for the Donald C. Cook Nuclear Plant License Renewal Application -

Auxiliary Systems and Electrical and Instrumentation & Controls (I&C) Systems Aging Management Review Results c:

J. L. Caldwell, NRC Region III K. D. Curry, AEP Ft. Wayne, w/o attachment J. T. King, MPSC, w/o attachment J. G. Lamb, NRC Washington DC MDEQ - WHMD/HWRPS, w/o attachment NRC Resident Inspector J. G. Rowley, NRC Washington DC

Enclosure to AEP:NRC:4034-06 AFFIRMATION I, Mano K. Nazar, being duly sworn, state that I am Senior Vice President and Chief Nuclear Officer of American Electric Power Service Corporation and Vice President of Indiana Michigan Power Company (I&M), that I am authorized to sign and file this request with the Nuclear Regulatory Commission on behalf of l&M, and that the statements made and the matters set forth herein pertaining to I&M are true and correct to the best of my knowledge, information, and belief.

American Electric Power Service Corporation M. K. Nazar Senior Vice Presid t and Chief Nuclear Officer SWORN TO AND SUBSCRIBED BEFORE ME THIS She! DAY OF

-3 C'..c-

,2004

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uNotaiwPailic My Commission Expires WZ 1 l00I

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Attachment to AEP:NRC:4034-06 Page 1 Response to Requests for Additional Information for the Donald C. Cook Nuclear Plant License Renewal Application Auxiliary Systems and Electrical and Instrumentation & Controls (I&C) Systems Aging Management Review Results This attachment provides Indiana Michigan Power Company's (I&M's) responses to the Donald C. Cook Nuclear Plant (CNP) License Renewal Application (LRA) Requests for Additional Information (RAIs) provided in a Nuclear Regulatory Commission (NRC) letter dated May 6, 2004 (Reference 1). The RAIs addressed in this letter pertain to the following LRA Sections:

• 2.5 - Scoping and Screening Results: Electrical and Instrumentation and Control Systems

• 3.3.2 - Aging Management Review Results: Auxiliary System's

• 3.6 - Aging Management Review Results: Electrical and Instrumentation and Controls Reference I also included RAIs pertaining to time-limited aging analyses (TLAAs) in Section 4 of the LRA. I&M's response to the TLAA RAIs are included in a separate letter that is currently being prepared to respond to the TLAA RAIs documented in the NRC letter dated May 19, 2004 (Reference 2).

References, I. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Unit 1 and 2 License Renewal Application," dated May 6, 2004.

2. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Informnation for the Review of the Donald C. Cook Nuclear Plant, Unit 1 and 2 License Renewal Application," dated May 19, 2004.

Auxiliary Systems RAI 3.3.2-1:

In Tables 3.3.2-1 through Table 3.3.2-11 for the auxiliary systems, the applicant lists several components having environments and applicable aging effects' with associated aging management programs.

In the same columns, for the same component, material, and environment, the applicant list no aging effects and no aging management programs (i.e.,

Table 3.3.2-11, page 3.3-130, stainless steel bolting with a function of pressure boundary exposed to an external environment of air is credited with experiencing loss of material managed by Bolting and Torquing Activities. The same item in the table on page 3.3-130 for the same component exposed to the same environment has no aging effects and therefore no aging

Attachment to AEP:NRC:4034-06 Page 2 management program required; Table 3.3.2-6, page 3.3-77, copper alloy valves exposed to an external condensation environment experiences loss of material. The same item in the table on page 3.3-77 for the same component exposed to the same environment has no aging effects and therefore no aging management program required; etc.). Justify these discrepancies or revise the tables to correct the errors.

I&M Response to RAI 3.3.2-1:

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, there are six instances in which a component type lists both an aging effect and "none" for the same material/environment combination.

While this appears contradictory where occurring, it is not because each component type in the table actually represents more than one component in the system. While the components are exposed to the same overall environment, specific conditions for individual components differ.

The following paragraphs provide additional information for the six instances.

1. LRA Table 3.3.2-6. Heating. Ventilation. And Air Conditioning Systems (Page 3.3-77) -

copper alloy valves exposed to external condensation Copper alloy valves associated with the auxiliary feed pump room ventilation may be wetted by condensation that could contain sulfates, chlorides, or fluorides.

Therefore, loss of material was identified as an aging effect requiring management for these copper alloy valves exposed to condensation.

Copper alloy valves within the control room liquid chiller packages may be wetted by condensation. However, since these components are in a clean, air-conditioned environment, the condensation should not contain sulfates, chlorides, or fluorides. Therefore, no aging effects requiring management were identified for these copper alloy valves exposed to condensation.

2. LRA Table 3.3.2-7. Fire Protection System (Page 3.3-80) - stainless steel bolting exposed to air externally Stainless steel bolting on the fire pump diesel engines is exposed to air and to significant vibration and/or elevated temperatures from the diesel engines.

Therefore, loss of mechanical integrity (loss of pre-load) was identified as an aging effect requiring management for this stainless steel bolting exposed to air.

The stainless steel bolting in other parts of the fire protection system is exposed to air, but is not exposed to significant vibration, nor is it exposed to elevated temperatures. Therefore, no aging effects requiring management were identified for this stainless steel bolting exposed to air.

Attachment to AEP:NRC:4034-06 Page 3

3. LRA Table 3.3.2-8. Emergency Diesel Generator (Page 3.3-95) - stainless steel bolting exposed to air externally Stainless steel bolting in this system is exposed to air and to significant vibration and/or elevated temperatures from the diesel engines. Therefore, loss of mechanical integrity (loss of pre-load) was identified as an aging effect requiring management for this stainless steel bolting exposed to air.

Stainless steel bolting in parts of the emergency diesel generator system that are isolated from diesel engine vibration (e.g., air start subsystem) is exposed to air, but is not exposed to significant vibration or elevated temperatures from a diesel engine. Therefore, no aging effects requiring management were identified for this stainless steel bolting exposed to air.

4. LRA Table 3.3.2-10.

Post-Accident Containment Hydrogen Monitoring System (Page 3.3-127) - stainless steel heat exchangers exposed to air internally (heat transfer and pressure boundary intended functions)

Stainless steel heat exchangers exposed to air internally within the hydrogen analyzer sample panel "hot box" are exposed to a temperature slightly above the threshold for fatigue because they are heated by heat tracing.

Therefore, cracking due to fatigue was conservatively identified as an aging effect requiring management for these stainless steel heat exchangers exposed to air internally.

Stainless steel heat exchangers exposed to air internally, but outside the "hot box" are not exposed to temperatures above the threshold for fatigue.

Therefore, no aging effects requiring management were identified for these stainless steel heat exchangers exposed to air internally.

5. LRA Table 3.3.2-10, Post-Accident Containment Hydrogen Monitoring System (Page 3.3-129) - stainless steel valves exposed to air internally Stainless steel valves exposed to air internally in the sample flow path are exposed to a temperature slightly above the threshold for fatigue because they are heated by heat tracing.

Therefore, cracking due to fatigue was conservatively identified as an aging effect requiring management for these stainless steel valves exposed to air internally.

Stainless steel valves exposed to air internally in the reagent gas flow path are not exposed to temperatures above the threshold for fatigue.

Therefore, no aging effects requiring management were identified for these stainless steel valves exposed to air internally.

Attachment to AEP:NRC:4034-06 Page 4

6. LRA Table 3.3.2-1 1, Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2) (Page 3.3-130

- stainless steel bolting exposed to air externally Stainless steel bolting exposed to air in high temperatures systems may experience loss of pre-load from thermal effects. Therefore, loss of mechanical closure integrity was identified as an aging effect requiring management for this stainless steel bolting exposed to air in high temperature systems.

Stainless steel bolting in lowv temperature systems will not experience loss of pre-load from thermal effects. Also, components in these systems are not exposed to significant vibration, such as from a diesel engine.

Therefore, no aging effects requiring management were identified for this stainless steel bolting exposed to air in low temperature systems.

RAI 3.3.2-2:

Page B-96 of the LRA states that the Service Water System Reliability program, B. 1.29, will be enhanced to check for evidence of selective leaching during visual inspections. Howvever, NUREG-1801, XI.M33, "Selective Leaching of Material, "recommends a visual inspection and a hardness measurement of selected components to determine i'hether loss of material due to selective leaching is occurring. Provide justification for excluding a hardness measurement from the Service Water System Reliability program to detect selective leaching.

I&M Response to RAI 3.3.2-2:

Since the detection of selective leaching is an enhancement to the Service Water System Reliability Program, specific details on the methods for detection of selective leaching are not available at this time. Implicit in the current commitment to enhance the Service Water System Reliability Program is implementation using industry best practices at the time of implementation.

Current industry practices include visual inspections and either hardness testing, as stated in NUREG-1801, SectionXI.M33, or other inspection methods. Additionally, in the future, more effective techniques for the detection of selective leaching may become available.

RAI 3.3.2.1.1-1:

The applicant's Auxiliary Systems Water Chemistry Control program, B. 1.40.3, Water Chemistry Control - Auxiliary Systems Water Chemistry Control, page B-128 of the LRA, states the programns purpose as managing loss ofmaterial and fozuling. The program description firther states that it does not provide for detection of aging effects, such as loss of material and cracking. LRA Table 3.3.2-1, page 3.3-32 identifies cracking as a spent fiel pool poison aging effect and Water Chemistry Control as the applicable AMP [aging management program].

Attachment to AEP:NRC:4034-06 Page 5 Identify the AMP utilized to manage cracking of SFP [spent fiuel pool] poison and provide justification that the program vill ensure the components intendedjfunction is maintained within accident design limits.

I&M Response to RAI 3.3.2.1.1-1:

The water in the spent fuel pool is included in the Primary and Secondary Water Chemistry Control Program (not the Auxiliary Systems Water Chemistry Control Program). As identified in LRA Section B.1.40.1, the Primary and Secondary Water Chemistry Control Program is identified as managing cracking of components.

LRA Table 3.3.2-1, Page 3.3-32, conservatively identified cracking as an aging effect requiring management since aluminum alloys are susceptible to cracking from stress corrosion and intergranular attack in corrosive environments with high chloride concentrations. This aging effect is prevented by the Primary and Secondary Water Chemistry Program, which controls spent fuel pool water quality by maintaining chemistry levels (i.e., chlorides, fluorides, and sulfates) within acceptable limits.

Therefore, the Primary and Secondary Water Chemistry Control Program is adequate to manage this aging effect for aluminum, such that the Boral will continue to maintain its component intended function through the period of extended operation.

RAI 3.3.2.1.4-1:

Table 3.3.2-4, page 3.3-49, identifies change in material properties and cracking as AERMs

[aging effects requiring management] for elastomer flex hose components in an internal treated air environment. The Preventive Maintenance AMP, B.1.25, page B-82 of the LRA, is credited in managing these aging effects by periodic visual inspections and replacement as necessary. It is not apparent from the program description if the flex hoses vill be inspected both internally and externally. It is also not apparent how effective a visual inspection vill be in detecting internal changes in material properties and cracking. Provide justifi cation that the Preventive Maintenance AMP, B.1.25, will adequately identify and manage the identified internal aging effects.

I&M Response to RAI 3.3.2.1.4-1:

The elastomer flex hoses listed in LRA Table 3.3.2-4 are control air system rubber hoses located in containment. These hoses are exposed to treated air internally and ambient air externally.

Degradation of rubber from cracking and change in material properties can be due to ultraviolet radiation, ionizing radiation or thermal exposure. The external and internal hose surfaces are exposed to the same environmental conditions, with the exceptions that the air environments differ and the internal hose surfaces are not exposed to ultraviolet radiation, since they are not exposed to light.

Attachment to AEP:NRC:4034-06 Page 6 Since the external surface is exposed to an environment that is more severe than the internal environment, the condition of the external surface would conservatively reflect the condition of the internal surface.

Therefore, inspection of the external surfaces is adequate to ensure detection of aging effects prior to loss of the pressure boundary intended function.

RAI 3.3.2.1.5-1:

Table 3.3.2-5, page 3.3.62, identifies the Boric Acid Corrosion Prevention AMP, B.1.4, for managing the loss of material on the internal surface of a carbon steel tank in an air environment. The program description states that periodic visual inspections are performed of components on which borated reactor water may leak. Explain how the visual inspection referred to in the Boric Acid Corrosion Prevention program will adequately identify and manage the internal aging effects for the tank I&M Response to RAI 3.3.2.1.5-1:

The tanks with carbon steel surfaces that are included in the component type "Tank" listed in the LRA Table 3.3.2-5 are the volume control and boric acid tanks.

These tanks are primarily stainless steel, but the manway external cover and some external welded sub-components, such as the tank support legs, are carbon steel. The carbon steel manway cover has a stainless steel liner that protects the carbon steel from contact with borated water.

As identified in LRA Table 3.3.2-5, the inside surface of the stainless steel liner is subject to an air (internal) and treated borated water (internal) environment, and will be included in the scope of the Water Chemistry Control Program. LRA Table 3.3.2-5 also correctly indicates that the external carbon steel tank sub-components (i.e., the manway cover and other welded sub-components, such as the tank support legs) are subject to an air (external) environment, and are included in the scope of the Boric Acid Corrosion Prevention and System Walkdown Programs. The air (internal) environment on carbon steel is conservatively considered to be applicable to inside surface of the manway cover, which is protected from the treated borated water environment by the stainless steel liner. The Boric Acid Corrosion Prevention Program is applicable because the carbon steel subcomponents are in an air environment with the potential for exposure to borated water leakage.

RAI 3.3.2.1.8-1:

Several stainless steel components listed in Table 3.3.2-8, page 3.3-95 to 3.3-112, identify cracking as an AERM for stainless steel with an internal treated ivater environment. The Preventive Maintenance Program, B-1.25, page B-82 of the LRA, is accredited Wvith managing the cracking aging effect by general inspections rather than specific component-by-component listings. The program description states that the AMP

'vi'l ensure that loss of material, cracking, fouling, and change in material properties are managedfor EDG [/emergency diesel generator]

Attachment to AEP:NRC:4034-06 Page 7 subsystem components. NUREG-1801 recommends management of these aging effects utilizing chemistry control programs supplemented by one-time inspections in lowv-floiv areas. Justify the effectiveness of the Preventive Maintenance Program, B.1.25, to manage the aging effect of crackingfor each stainless steel component so identified in Table 3.3.2-8 or revise Table 3.3.2-8 to include an applicable chemistry control program and one-time inspection.

I&M Response to RAI 3.3.2.1.8-1:

Both the Preventive Maintenance Program, B.1.25, and the Chemistry One-Time Inspection Program, B.1.41, would be effective in managing the aging effect of cracking for stainless steel components subject to an internal treated water environment.

The Preventive Maintenance Program is credited for managing cracking of stainless steel components containing treated water, because a representative sample of these components is inspected on a routine basis.

These inspections would reveal evidence of cracking such that corrective actions can be taken to manage applicable aging effects.

Degraded conditions or adverse trends identified during inspections are addressed through the corrective action process. In addition, the treated water environment of the EDG subsystems is included in the Auxiliary Systems Water Chemistry Control Program. Verification of the effectiveness of the chemistry control programs, by the Chemistry One-Time Inspection Program, will provide additional assurance that aging effects, such as cracking, are effectively managed.

RAI 3.3.2.1.8-2:

Table 3.3.2-8, pages 3.3-95 to 3.3-112, identifies several carbon steel components in a treated water environment utilizing a Water Chemistry Control AMP to manage a loss of material aging effect. NUREG-1801 also supports rising a tvater chemistry program for managing loss of material to carbon steel. Justify excluding an AMP to manage the -water chemistry of the treated water environmentfor the carbon steel sightflowp indicator, Table 3.3.2-8, page 3.3-106.

I&M Response to RAI 3.3.2.1.8-2:

Consistent with other carbon steel components containing treated water as identified in LRA Table 3.3.2-8, the Water Chemistry Control Program manages loss of material of the carbon steel sight flow indicator. The Water Chemistry Control Program was inadvertently omitted from the component type, "Sight flow indicator," in LRA Table 3.3.2-8.

Attachment to AEP:NRC:4034-06 Page 8 RAI 3.3.2.1.9-1:

Table 3.3.2-9, page 3.3-115 and page 3.3-120, identifies loss of material as an aging effect of stainless steel fittings and stainless steel/carbon steel piping in a soil environment.

The applicant identifies System Testing, B.1.37, page B-i 14, as an applicable AMP for managing these aging effects.

System Testing, B.1.37, does not define fitting or pipe condition or approximate rate of degradation as recommended in NUREG-1801, XI.M28 or XI.M34 for buried fittings/piping. Provide justification for exclusion of buried piping/fitting condition assessment in B.1.37 in accordance with NUREG-1801 or revise the AMP accordingly.

I&M Response to RAI 3.3.2.1.9-1:

The items referred to in LRA Table 3.3.2-9 are associated with the security diesel underground fuel oil tank and associated underground piping and fittings. The security diesel underground fuel oil tank and associated underground piping and fittings are periodically tested for leakage using timed system pressure tests. Leakage above the acceptance criteria or other degraded conditions would be discovered such that corrective actions can be taken priorto loss of the system intended functions.

RAI 3.3.2.1.9-2:

Table 3.3.2-9, page 3.3-117, identif es the Preventive Maintenance Program, B.1.25, page B-82 of the LRA, as managing change in material properties and cracking of flex hoses with an internal environment offuel oil and treated water. The program states that it will manage these aging effects by visual inspection and replacement as necessary. It is not apparent from the program description if internal and external surfaces will be inspected. Due to different internal and external environmental conditions, external examination may not be representative of internal component condition. Explain how the visual examination referred to in the Preventive Maintenance Program, B.1.25, will ensure management of internal aging effects of these components.

I&M Response to RAI 3.3.2.1.9-2:

The Preventive Maintenance Program will manage the aging effects of change in material properties and cracking of the security diesel elastomer flex hoses exposed internally to fuel oil and treated water environments by performing visual inspection of both internal and external surfaces of these flex hoses, or replacement, as appropriate.

Attachment to AEP:NRC:4034-06 Page 9 RAI 3.3.2.1.9-3:

Table 3.3.2-9, page 3.3-118, identifies the System Testing, B.1.37, page B-114 of the LRA, as being credited in managing fouling of copper alloy heat exchanger tube components. For the same environment, component, and material, the Table 3.3.2-8, page 3.3.101, identifies Oil Analysis and Mater Chemistry Control AMPs to manage fouling and loss of material. Justify the exclusion of Water Chemistry Control and Oil Analysis in managing the security diesel heat exchanger tube heat transferfinction in Table 3.3.2-9.

I&M Response to RAI 3.3.2.1.9-3:

Although not explicitly credited in LRA Table 3.3.2-9 for managing fouling of the security diesel heat exchanger tubes, the Auxiliary Systems Water Chemistry Control Program includes the security diesel jacket cooling water system, as described in LRA Section B.1.40.3, and the Oil Analysis Program includes the security diesel lube oil

system, as described in LRA Section B.1.23. These two programs were inadvertently omitted from LRA Table 3.3.2-9.

Additionally, during system testing, engine parameters, such as jacket water temperature, are monitored to assure the heat exchangers are capable of removing heat loads.

Therefore, monitoring performed by the System Testing Program, in conjunction with the Water Chemistry Control and Oil Analysis Programs, effectively manages fouling of the heat exchanger tubes.

RAI 3.3.2.1.9-4:

Table 3.3.2-9, page 3.3-119, identifies the System Testing, B.1.37, page B-114 of the LPA, as being credited in managing loss of material of copper alloy heat exchanger tube components in a treated water external environment. For the same environment, component, and material, the Table 3.3.2-8, page 3.3-102, identifies Heat Exchanger Monitoring and Mater Chemistry Control AMPs to manage loss of material and loss of material-wear. Justify the exclusion of mater Chemistry Control and Heat Exchanger Monitoring AMPs in managing the security diesel heat exchanger tube pressure boundary function in Table 3.3.2-9.

I&M Response to RAI 3.3.2.1.9-4:

The security diesel is a non-seismic, nonsafety-related system. Since a major component of the Heat Exchanger Monitoring Program will be monitoring the seismic qualification of heat exchangers, this program is not credited for the non-seismic security diesel engine coolant heat exchangers or lube oil coolers. The security diesel engine coolant heat exchanger shell internal surfaces and tube external surfaces are exposed to treated water from the Lake Township water system. Lake Township water chemistry is not included in a Water Chemistry Control Program.

Consequently, neither the Heat Exchanger Monitoring Program, nor the Water Chemistry Control Program would be appropriate for managing loss of material in these heat exchanger tubes.

Attachment to AEP:NRC:4034-06 Page 10 The security diesel engine lube oil cooler shell internal surfaces and tube external surfaces are exposed to lube oil, which is monitored by the Oil Analysis Program, as described in LRA Section B.1.23. The Oil Analysis Program detects and controls contaminants (primarily water and particulates), thereby preserving an environment that is not conducive to corrosion, cracking, or fouling. Presence of engine coolant in the lube oil would be indicative of degradation of the lube oil cooler tubes. Additionally, during the periodic security diesel testing in accordance with the System Testing Program, operating parameters, such as oil pressure and jacket water temperature, are monitored. Abnormal indications and failure to meet acceptance criteria would result in corrective action being taken. Therefore, since the Oil Analysis and System Testing Programs monitor the parameters that would provide an indication of unacceptable aging effects, these programs are adequate for managing the effects of aging on the security diesel heat exchangers.

RAI 3.3.2.1.9-5:

Table 3.3.2-9, page 3.3-124, identifies the Preventive Maintenance Program, B.1.25, page B-82 of the LRA, as managing change in material properties and cracking of flex hoses with an internal environment offuel oil. The program states that it wvill manage these aging effects by visual inspection and replacement as necessary. It is not apparent from the program description if internal and external surfaces will be inspected. Due to different internal and external environmental conditions, external examination may not be representative of internal component condition. Explain howv the visual examination referred to in the Preventive Maintenance Program, B.1.25, will ensure management of internal aging effects.

I&M Response to RAI 3.3.2.1.9-5:

The elastomer tubing listed in LRA Table 3.3.2-9, on Page 3.3-124, refers to plastic material used in the security diesel day tank level gauges. The internal surface of the clear plastic gauge used for local indication is evident during visual inspections. The internal surface of the plastic tubing used for remote indication is exposed to fuel oil and air. The Preventive Maintenance Program will manage the aging effects of change in material properties and cracking of this tubing by performing visual inspection of both internal surfaces (at the connection point) and external surfaces of the tubing, or replacement, as appropriate. (Note: Aging management of the security diesel system flex hoses is discussed in I&M's response to RAI 3.3.2.1.9-2.)

RAI 3.3.2.1.9-6:

Table 3.3.2-9, page 3.3-118, identifies the System Testing AMP, B.1.37, to manage the loss of material on the internal surface of the security diesel heat exchanger shell in a treated water environment. The System Testing program manages these aging effects by periodically starting

Attachment to AEP:NRC:4034-06 Page I l the security diesel and operating it in accordance with manufacturer's recommendations and monitoring system flow and system pressure. Describe howv the System Testing program manages aging effects on the internal surfaces of the heat exchanger shell.

I&M Response to RAI 3.3.2.1.9-6:

Testing of the security diesel generator is performed to demonstrate operability of the security diesel and to demonstrate the security diesel fuel oil system's ability to perform its intended functions. In addition to monitoring system flow, pressure, and temperature, monitoring for abnormal conditions, such as leakage, is also performed during the conduct of these system tests.

Malfunctioning equipment, leakage, or failures to meet acceptance criteria during system testing would result in corrective action being taken.

Loss of material on the treated water side of the heat exchanger shell would be detected in the form of pinhole leaks caused by isolated pitting or crevice corrosion. Monitoring for component leakage and system operating parameters under the System Testing Program provides assurance that loss of material from the internal surfaces of the heat exchanger shell will be identified during testing, prior to resulting in loss of function of the heat exchanger.

This level of monitoring is commensurate with the safety significance of this non-seismic, nonsafety-related component.

RAI 3.3.2.1.10-1:

Table 3.3.2-10, page 3.3-127, identifies the Preventive Maintenance Program, B.].25, page B-82 of the LRA, as managing change in material properties and cracking of flex hoses with an internal environment of oxygen. The program states that it will manage these aging effects by visual inspection and replacement as necessary. It is not apparent from the program description if internal and external surfaces wvill be inspected. Due to different internal and external environmental conditions, external examination may not be representative of internal component condition. Explain howv the visual examination referred to in the Preventive Maintenance Program, B.1.25, will ensure management of internal aging effects.

I&M Response to RAI 3.3.2.1.10-1:

The flex hoses listed in LRA Table 3.3.2-10 are small rubber hoses on the oxygen supply bottles.

These bottles store pure oxygen, which is used as a reagent for the hydrogen analyzers. The hoses are exposed to oxygen internally and ambient air externally. Degradation of rubber from cracking and change in material properties can be due to ultraviolet radiation, ionizing radiation, or thermal exposure. The internal hose surfaces are not exposed to ultraviolet radiation, since they are not exposed to light. The supply bottles and hoses are installed in a low radiation area.

Therefore, the component dose will be substantially lower than the radiation dose threshold for

Attachment to AEP:NRC:4034-06 Page 12 elastomers (10671 0Rad). Both internal and external hose surfaces are close to the ambient air temperature of the auxiliary building.

Since oxygen is also present in atmospheric (ambient) air, both internal and external surfaces of the hoses are exposed to oxygen. The external surface is exposed to an environment that is more severe than the internal environment (ultraviolet radiation); neither the internal nor external surfaces are exposed to elevated temperatures or high radiation. Therefore, inspection of the external surfaces is adequate to ensure detection of aging effects prior to loss of the pressure boundary intended function.

RAI 3.3.2.1.11-1:

Table 3.3.2-11, page 3.3-130 to43.3-152, identifies the System Walkdown, B.1.38, page B-119 of the LRA, for management of various aging effects for several components with different internal and external environments. The System Malkdown Program, Section B.1.38 of the LRA, states that the program is only applicable to situations where the internal and external environment is the same.

Component external condition may not be representative of internal material conditions in differing environments.

Justify utilization of the System Walkdovn Program, B.1.38, in managing aging effects for all components identified in Table 3.3.2-11 with differing internal and external environments. Also explain how a system walkdown can inspect and verify proper management of all internal aging effects.

I&M Response to RAI 3.3.2.1.11-1:

The statement in the LRA Section B.1.38 Scope section is, "The program is also credited with managing loss of material from internal surfaces, for situations where the external surface condition is considered representative of the internal surface condition and both have the same environment." This statement does not indicate that the System Walkdown Program is only applicable to situations where the internal and external environments are the same. The Scope section also states, "This program includes inspections of external surfaces of CNP structures and components within the scope of license renewal."

This inspection of external surfaces addresses components subject to aging management review for 10 CFR 54.4(a)(2), as indicated in LRA Table 3.3.2-11, where the System Walkdown Program is credited as the sole aging management program regardless of the environment. For these components, the concern is the impact of spray or leakage from nonsafety-related components on safety-related equipment.

Providing the effect of nonsafety-related component failures on safety-related equipment is managed, safety-related equipment will continue to be capable of performing its required intended functions.

The System Walkdown Program, as described in LRA Section B.1.38, manages aging through visual inspections of systems and components. This program includes periodic walkdowns that will detect and correct failures that could result in long-term exposure to spray or wetting.

Attachment to AEP:NRC:4034-06 Page 13 Short-term exposure is not a concern for passive components such as valve bodies and piping.

Active safety-related component failures due to short-term exposure would be detected in the course of normal operation or through monitoring required by the Maintenance Rule and appropriate corrective actions would be taken to prevent recurrence. This is consistent with the NRC's position provided in the Statements of Consideration for the Final Part 54 Rule, which states "On the basis of consideration of the effectiveness of existing programs which monitor the performance and condition of systems, structures, and components that perform active functions, the Commission concludes that structures and components associated only with active functions can be generically excluded from a license renewal aging management review. Functional degradation resulting from the effects of aging on active functions is more readily determinable, and existing programs and requirements are expected to directly detect the effects of aging."

While this discussion pertains to detecting aging-related degradation of active components, it also applies to detecting degradation of the same active components due to aging-related degradation of nonsafety-related components.

Based on the information presented above, the System Walkdown Program is adequate as an aging management program because it includes periodic walkdowns that will detect conditions that could result in failures caused by exposure to spray or wetting regardless of the internal or external environments and their aging effects.

RAI 3.3.2.1.11-2:

Table 3.3.2-11, page 3.3-131, identifies the System Walkdowvn Program, B.1.38, page B-i19 of the LRA, as managing loss of material of a stainless steel filter housing in an untreated water with boron internal environment. This is an example of one of several stainless steel components that identify the System JMalkdown AMP, B.1.38, as managing loss of material in internal environments. System Walkdown Program, Section B. 1.38, page B-119 to B-121, does not credit the program with management of loss of material to stainless steel. Justify utilization of the System Malkdown Program, B. 1.38, in managing loss of material to stainless steel components exposed to an untreated -water with boron internal environment for each component in Table 3.3.2-1. Also, explain how a system walkdown can inspect and verify proper management of all internal aging effects.

I&M Response to RAI 3.3.2.1.11-2:

Management of internal loss of material in stainless steel components was an inadvertent omission from LRA Section B.1.38. This aging effect was included in the aging management review for filter housings in the radioactive waste disposal system cited in this RAI as well as other stainless steel components.

For the 10 CFR 54.4(a)(2) component types in LRA Table 3.3.2-11 that credit the System Walkdoinv Program, the concern is the impact of spray or leakage from nonsafety-related components onto safety-related equipment. Providing the effect of nonsafety-related component

Attachment to AEP:NRC:4034 06 Page 14 failures on safety-related equipment is managed, safety-related equipment will continue to be capable of performing its required intended functions.

The System Walkdown Program, as described in LRA Section B.1.38, manages aging through visual inspections of systems and components. This program includes periodic walkdowns that wvill detect and correct failures that could result in long-term exposure to spray or wetting.

Short-term exposure is not a concern for passive components such as valve bodies and piping.

Active safety-related component failures due to short-term exposure would be detected in the course of nonnal operation or through monitoring required by the Maintenance Rule and appropriate corrective actions would be taken to prevent recurrence. This is consistent with the NRC's position provided in the Statements of Consideration for the Final Part 54 Rule, which states, "On the basis of consideration of the effectiveness of existing programs which monitor the performance and condition of systems, structures, and components that perform active functions, the Commission concludes that structures and components associated only with active functions can be generically excluded from a license renewal aging management review.

Functional degradation resulting from the effects of aging on active functions is more readily determinable, and existing programs and requirements are expected to directly detect the effects of aging."

While this discussion pertains to detecting aging-related degradation of active components, it also applies to detecting degradation of the same active components due to aging-related degradation of nonsafety-related components.

Based on the information presented above, the System Walkdown Program is adequate as an aging management program, because it includes periodic walkdowns that will detect conditions that could result in failures caused by exposure to spray or wetting, regardless of the internal or external environments.

Electrical and Instrumentation and Controls RAI 2.5-1:

Interim Staff Guidance (ISG) 2, "NRC Staff Position on the License Renewval Rule (10 CFR 54.4) as it relates to The Station Blackout Rule (SBO) (10 CFR 50.63), " states, in part, that "The offsite power systems consist of a transmission system (grid) component that provides a source of power and a plant system component that connects that powver source to a plant's onsite electrical distribution system which powver safety equipment." For the purpose of the license renewal rule, the staff determined that the plant system portion of the offsite powver system that is used to connect the plant to the offsite powver source should be included within the scope of the rule.

This path typically includes the swvitchyard circuit breakers that connect to the offsite system powver transformers (startup transformer), transformers themselves, the intervening overhead or underground circuits between circuit breaker and transformer and transformer and onsite electrical distribution system, and the associated control circuits and structures. In this regard, the portion of the SBO path indicated on the offsite powver boundary drawing for license

Attachment to AEP:NRC:4034-06 Page 15 renewal does not include the transmission conductors and connections and the associated control cables from the first breaker (disconnect) from the 345 kV [kilovolt] and 765 kV swvitchyard buses to the 765 kV/34.5 kV and 345 kW34.5 kV transformers. Please revise this drawing.to include the above components indicating which components require an aging management review (AMR).

I&M Response to RAI 2.5-1:

The portion of the SBO path indicated on the license renewal offsite power boundary drawing, 12-LRA-Electricall, includes the switchyard circuit breakers that connect to the offsite system power transformers (startup transformers), the transformers themselves, and the intervening overhead or underground circuits between circuit breakers and transformers and between transformers and the onsite electrical distribution system.

As stated in LRA Section 2.5, switchyard items credited for the SBO path include the associated control circuits and structures in addition to the items shown on the boundary drawing. Consistent with the ISG excerpts in the RAI, the path from the switchyard circuit breakers that connect to the offsite power system transformers (startup transformers) to the 765 kV/34.5 kV and 345 kV/34.5 kV switchyard transformers is considered part of the transmission system (grid), which is not included in the scope of license renewal.

Therefore, the transmission conductors and connections and the associated control. cables from the first breaker (disconnect) from the 345 kV and 765 kV switchyard buses to the 765 kV/34.5 kV and 345 kV/34.5 kV switchyard transformers are not subject to aging management review. Therefore, no changes to the license renewal offsite power boundary drawing are required.

RAI 2.5-2:

Table 2.5-1 of the license renewal application (LRA) lists the electrical and instrumentation and control (I&C) components included in the AMR.

This list does not include transmission conductors, and uninsulated ground conductors listed in the LRA Table 2.1.1. With regard to transmission conductor and connectors, it is stated that the transmission conductors have been screened out because they have no aging effect. Transmission conductors have been known to have loss of conductor strength. The most prevalent mechanism contributing to the loss of conductor strength is corrosion, which includes corrosion of steel core and aluminum strand pitting. Explain wvhy no aging effects related to conductor corrosion have been identified that would cause a loss of finction for the extended period of operation. Also, explain why no significant aging effects related to wvind loading vibration or swvay on high voltage connections has been identified In addition, provide justification for excluding uninsulated ground conductors from the AMR.

Attachment to AEP:NRC:4034-06 Page 16 I&M Response to RAI 2.5-2:

Transmission conductors were screened out not because they have no aging effects, but because they do not perform an intended function for CNP. There are no transmission conductors in the credited SBO recovery path for either unit at CNP. Connections of the startup transformers to the offsite power system are through switchyard bus and underground 34.5 kV insulated cables rather than transmission conductors.

The 34.5 kV underground cables are medium voltage insulated cables, not transmission conductors.

Transmission conductors perform no license renewal intended function in other CNP applications. Therefore, this commodity type is not subject to aging management review.

Transmission conductors do not require aging management review as indicated in LRA Table 2.5-1; however, some transmission towers are included in LRA Table 2.4.4-1 for 10 CFR 54.4(a)(2) structural concerns.

As stated in LRA Section 2.5, uninsulated ground conductors do not perform an intended function, and are therefore not subject to aging management review.

RAI 2.5-3:

The paragraph leading to Table 2.1.1, page 2.1-17, reference to Table 2.1-1 which is notfound in the LRA. Please clarify if this is a typographical error.

I&M Response to RAI 2.5-3:

Consistent with the labeling convention for other LRA Section 2 tables, the table labeled 2.1'.1 on LRA Pages 10 and 2.1-17 should have been labeled Table 2.1-1. References to LRA Table 2.1.1 and references to LRA Table 2.1-1 are applicable to this table.

RAI 2.5-4:

LRA section 2.1.3.3, Long-Lived Screening, states that all electrical penetration assemblies are included in the environmental qualification (EQ) program and are not subject to aging management review Please confirm if this statement is applicable to all safety as lVell as non-safety related electrical penetration assemblies.

I&M Response to RAI 2.5-4:

Based on the referenced LRA section title, this question applies to LRA Section 2.1.2.3.3. All electrical penetrations, which include the penetration assemblies, are safety-related and are

Attachment to AEP:NRC:4034-06 Page 17 included in the Environmental Qualification of Electric Components Program described in LRA Section B.2.1.

RAI 2.5-5:

Explain how non-safety related cables (not in scope of the license renewal) that share conduits or raceways with in-scope cables included in the AMR will be treated?

I&M Response to RAI 2.5-5:

Those non-EQ insulated cables installed in structures within the scope of license renewal are included in the scope of license renewal regardless of safety classification.

As stated in LRA Section 2.1.1, "A bounding scoping approach was used for electrical equipment and systems. Electrical and I&C systems as well as electrical and I&C components in mechanical systems were within the scope of license renewal." Also, as stated in LRA Section 2.5, "The basic philosophy for electrical and I&C component IPA [integrated plant assessment] was that all components were included in the review.

Including components beyond those actually required is referred to as an 'encompassing' or a 'bounding' review. This method eliminates the need for unique identification of each component and its specific location. This method also assured components were not inadvertently excluded from an AMR." The commodity group "electrical cables and connections not subject to IO CFR 50.49 EQ requirements" contains non-safety related and safety-related cables. No cables were eliminated from this commodity type based on intended function.

Therefore, as part of the bounding approach, all non-EQ insulated cables will be treated the same for license renewal aging management programs.

RAI 3.6-1:

In response to audit team's question on fuse holders, you stated that you have completed an assessment to identify fiuse holders that are subject to AMR based on requirements of license renewal and Interim Staff Guidance (ISG)-5, "Identification and Treatment of Electrical Fuse Holders For License Renewal. " The assessment identified fuse holders in scope for license renewal, then screened infitse holders in-scope based upon whether: (1) they are included in an active component (panels, sivitchgear, or cabinet), (2) they perform an intendedfunction to meet the criteria of 10 CFR 54.4 (a) (i e., isolate safety loads from non-safety loads or are used as protective devises to ensure the integrity of containment electricalpenetrations), or (3) they have bolted connections, Which are not subject to the same aging stressors (i e., mechanical stress and fatigue) as spring loaded fuse holder clips. The assessment determined that fitse blocks are either an active components, do not perform a license renewal intendedfiunction, or have bolted connections. With regard to the fise holders that have bolted connections, please address the aging affects due to vibration, corrosion, andfatigue due to thermal cycling identified in the

Attachment to AEP:NRC:4034-06 Page 18 subject JSG and provide justification as to why an additional AMP for bolted connection fiuse holders is not required I&M Response to RAI 3.6-1:

The CNP aging management review of electrical systems eliminated fuses with bolted connections, since bolted connections do not have the issue associated with metallic fuse clamps.

Bolted connections on fuse holders are subject to the same aging effects as bolted connections included in the cables and connections commodity group. The CNP aging management review included bolted connections on fuse holders as connections in the cable and connections commodity group.

All of the fuse holders that were not part of an activre component and that were screened solely on the bolted connection criterion have the system code "26KAC" (electrical distribution system, 26,000 VAC). The 26KAC system is within the scope of license renewal, based on the bounding approach used for scoping electrical systems, and is listed in LRA Table 2.2-lb. This system contains the components associated with the 26 kV bus, which is the electrical distribution associated with the main generator. The main generator and step-up transformers do not perform a license renewal intended function; therefore, these fuse holders were determined not to be subject to an aging management review.

RAI 3.6-2:

With regard to non-EQ cables sensitive to a reduction in insulation resistance, please confirm consistency with the proposed ISG-15, Revision of Generic Aging Lessons Learned (GALL)

Aging management Program (AMP) XI.E2, "Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits."

I&M Response to RAI 3.6-2:

The exception to NUREG-1801,Section XI.E2, in LRA Appendix B, Section B.1.21, states,

"...the first reviews will be performed before the period of extended operation and every 10 years thereafter. Calibrations or surveillances that fail to meet the acceptance criteria will be reviewed at the time of the calibration or surveillance."

The intent of this exception is in agreement with the mark-up of ISG-15 provided to the NRC in the referenced Nuclear Energy Institute (NEI) letter dated December 15, 2003 (referenced below). The NRC has not yet issued a formal response to these industry comments. Therefore, it is the intent of this program to be consistent with NUREG-1 801,Section XI.E2 with the stated exception, which is consistent with the draft of ISG-15 provided in the referenced NEI letter.

Other elements of the Non-EQ Instrumentation Circuits Test Review Program are consistent with ISG-15.

Attachment to AEP:NRC:4034-06 Page 19

Reference:

Letter from A. Marion, NEI, to P. T. Kuo, NRC, "Industry Comments on License Renewal Interim Staff Guidance Documents," dated December 15, 2003. [ML033560253]

RAI 3.6-3:

In response to an audit team 's question on inaccessible medium voltage cables within the scope of license renewal that are exposed to significant moisture simultaneously with applied voltage, it was stated that the AMP for inaccessible medium voltage cables will test the cables as well as inspect for water in the manholes. It was also stated that inspection of water in the manholes associated the GALL XI.E3 AMP iould be performed every 10 years. The frequency to inspect for water in manholes every ten years may be too long. Justify the frequency of inspecting manholes for water every 10 years in addition, provide your current criteria for inspecting manholes for water.

I&M Response to RAI 3.6-3:

LRA Section B.1.20 states that the CNP Non-EQ Inaccessible Medium-Voltage Cable program will be consistent with NUREG-1801,Section XI.E3. NUREG-1801,Section XI.E3, Section 2, "Preventive Actions", states that, "Periodic actions are taken to prevent cables from being exposed to significant moisture, such as inspecting for water collection in cable manholes and conduit, and draining water, as needed. Medium-voltage cables for which such actions are taken are not required to be tested since operating experience indicates that prolonged exposure to moisture and voltage are required to induce this aging mechanism." This section implies that if periodic actions are not taken to prevent cable exposure to significant moisture, then testing is required. The Non-EQ Inaccessible Medium-Voltage Cable Program will require testing of all cables included in the program. The frequency of inspections for water is relevant only if it provides reasonable assurance that the cables are not exposed to significant moisture and therefore do not require testing. Since testing is to be performed regardless of inspection results, the inspection frequency is not relevant. The proposed testing frequency in the CNP aging management program is consistent with NUREG-1801, SectionXI.E3, for cables that are exposed to significant moisture.

RAI 3.6-4:

In response to an audit team 's question on inaccessible medium voltage cables, it was stated that the cables from transformer TR 201 AB to bus 2A run in conduits are sealed on both ends and have been inspected for water and that the lack of water precludes any aging mechanisms on the cables that would make them subject to an AMP. It is not clear to the staff howv often these seals are inspectedfor water damage and how often they are replaced. An AMP would be needed to assure that the seals remain intact to prevent intrusion of water in the conduits. Please provide a description of the AMP that will be relied upon to require periodic inspections of these seals or

Attachment to AEP:NRC:4034-06 Page 20 provide justification for not having an AMP. In addition, describe how the cables from (1) start-up transformers TR 201 CD, 101 AB, and 101 CD to the safety bases and (2) from transformers TR4 and TR5 to the start-up transformers, are routed.

I&M Response to RAI 3.6-4:

The cables associated with the sealed conduits were previously determined not to be subject to aging effects, because they are not exposed to significant moisture. These cables will be added to the'list of cables subject to the NUREG-1801,Section XI.E3, aging management program.

Consistent with the response to RAI 3.6-3, all of the cables included in LRA Section B.1.20 will be tested and will not require inspection f6r the presence of significant moisture. Therefore, inspection of the seals will not be relevant since the cables will be tested. An aging management program for conduit seal inspections is not required.

The Unit 1 reserve auxiliary transformers, TR1OlAB and TR1O1CD, and safety buses 1A, 113, IC, and ID are connected by a combination of switchyard bus and insulated feeder cables, which are not installed underground.

The Unit 2 reserve auxiliary transformers, TR201AB and TR201CD, and safety buses 2A, 2B, 2C, andl2D are connected by cables in underground conduits encased in a duct bank which is sealed on both ends.

Switchyard transformers TR4 (345 kV/34.5 kV) and TR5 (765 kV/34.5 kV) are not in scope for license renewal because they are beyond the first switchyard breaker boundary. Therefore, the connections between these switchyard transformers and switchyard breakers 12CD and 12AB are not in scope. Switchyard breakers 12CD and 12AB are connected to the reserve auxiliary transformers by underground insulated cables with segments of switchyard bus at the switchyard breaker connections.

RAI 3.6-5:

The updated FSAR [final safety analysis report] supplement description in the LRA for the non-EQ cable AMP does not provide an adequate description of the program as required by 10 CFR 54.21(d). The description of FSAR supplement for aging management of electrical and instrumentation and controls system should be consistent with Table 3.6-2 of NUREG-1800.

Please submit a revised FSAR supplement that is consistent with NUREG-1800 to satisfy 10 CFR 54.21(d).

I&M Response to RAI 3.6-5:

Based on a review of NUREG-1800, Table 3.6-2, and NUREG-1801, SectionXI.EI, the Non-EQ Insulated Cables and Connections Program description for the Updated Final Safety Analysis Report is revised as follows:

Attachment to AEP:NRC:4034-06 Page 21 A.2.1.25 Non-EO Insulated Cables and Connections The Non-EQ Insulated Cables and Connections Program will apply to accessible insulated electrical cables and connections installed in structures that are within the scope of license renewal and prone to adverse localized environments. An adverse localized equipment environment is a condition in a limited plant area that is significantly more severe than the specified service condition for the electrical insulated cable or connection. The program will visually inspect at least once every 10 years a representative sample of accessible insulated cables and connections for cable and connection jacket surface anomalies, such as embrittlement, discoloration, cracking, swelling, or surface contamination.

The Non-EQ Insulated Cables and Connections Program will be implemented prior to the period of extended operation.