NRC-15-0021, License Renewal Application - Response to LR-ISG-2013-01

License Renewal Application - Response to LR-ISG-2013-01

ML15037A495
Person / Time
Site:	Fermi
Issue date:	02/05/2015
From:	Kaminskas V DTE Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LR-ISG-2013-01, NRC-15-0021
Download: ML15037A495 (27)

Text

Vito A. Kamiaskas Site Vice President DTE Energy Comany 6400 N. Dixie Highway, Newport, MI 48166 Teh 734.586.6515 Fax: 734.586.4172 Email: kaminskasv4dteenergy.com 10 CFR 54 February 5, 2015 NRC-15-0021 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington D C 20555-0001

References:

1) Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43

2) DTE Electric Company Letter to NRC, "Fermi 2 License Renewal Application," NRC-14-0028, dated April 24, 2014 (ML14121A554)

3) License Renewal Interim Staff Guidance LR-ISG-2013-01, "Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks," dated November 6, 2014 (ML14225A059)

Subject:

Fermi 2 License Renewal Application - Response to LR-ISG-2013-01 In Reference 2, DTE Electric Company (DTE) submitted the License Renewal Application (LRA) for Fermi 2. In Reference 3, the NRC issued the License Renewal Interim Staff Guidance (LR-ISG) 2013-01 regarding the aging management of loss of coating or lining integrity for internal coatings/linings on in-scope piping, piping components, heat exchangers, and tanks. Enclosure 1 to this letter provides the DTE response to LR-ISG-2013-01. Enclosure 2 to this letter provides the LRA revisions developed to address LR-ISG-2013-01. The revised sections of the LRA include Sections 2.1, 3.2 and associated tables, 3.3 and associated tables, 3.4 and associated tables, A.4, and B.0 and associated tables. LRA Sections A.1.45 and B.1.45 are new.

One new commitment is being made in this submittal. The new commitment, shown in Item 36 in LRA Table A.4 as indicated in Enclosure 2, is to implement the new Coating Integrity Program.

USNRC NRC-15-0021 Page 2 Should you have any questions or require additional information, please contact Lynne Goodman at 734-586-1205.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on February 5, 2015 Vito A. Kamidskas Site Vice President Nuclear Generation

Enclosures:

1) DTE Response to LR-ISG-2013-01

2) Fermi 2 LRA Revisions for LR-ISG-2013-01 cc: NRC Project Manager NRC License Renewal Project Manager NRC Resident Office Reactor Projects Chief, Branch 5, Region III Regional Administrator, Region III Michigan Public Service Commission, Regulated Energy Division (kindschl@michigan.gov)

Enclosure 1 to NRC-15-0021 Fermi 2 NRC Docket No. 50-341 Operating License No. NPF-43 DTE Response to LR-ISG-2013-01

Enclosure 1 to NRC-15-0021 Page 1

Background

On November 14, 2014, the NRC issued License Renewal Interim Staff Guidance (LR-ISG) 2013-01 "Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks."

As stated in License Renewal Application (LRA) Section 2.1.3, due to the timing of the issuance of LR-ISG-2013-01, it was not feasible to include recommended activities from this ISG into the Fermi 2 LRA as originally submitted. A review has now been completed, and revised LRA sections have been developed to reflect the guidance of LR-ISG-2013-01. The LRA revisions are provided in Enclosure 2.

Application of LR-ISG-2013-01 for the Fermi 2 LRA DTE identified internally-coated piping, piping components, heat exchangers, and tanks in systems within the scope of license renewal at Fermi 2. Revisions to affected LRA sections have been developed to indicate piping and components for which "loss of coating integrity" is considered an aging effect requiring management (AERM.).

For certain tanks, heat exchangers, and piping components with internal coatings, loss of coating integrity would not prevent satisfactory accomplishment of any of the component's or downstream component's current licensing basis (CLB) intended functions identified under 10 CFR 54.4(a)(1), (a)(2), or (a)(3). Thus, loss of coating integrity is not identified as an AERM for these tanks, heat exchangers, and piping components in this LRA revision. Technical justification is provided below for each such component.

Components where Loss of Coating Integrity is not an AERM In the cases below, the components are nonsafety-related and remote from safety-related (SR) components and components that are credited to perform a function that demonstrates compliance with the regulations identified in 54.4(a)(3). Detrimental downstream effects on SR components or components credited to support regulated events in the event of a coating failure are not credible.

• Condensate Backwash Tank This tank is located in the Turbine Building basement on the east side in its own room with labyrinth accesses on both the north and south ends. All SR equipment in the Turbine Building is at or above the 2 nd floor except for a SR door in the Turbine Building basement. This SR door is located on the west side of the Turbine Building which is more than 100' from the Condensate Backwash Tank room with no direct path between the two points. There are no components credited to support regulated events in the Condensate Backwash Tank room. In addition, detrimental downstream effects on SR.

components or components credited to support regulated events due to a coating failure

Enclosure I to NRC-15-0021 Page 2 are not credible. Therefore, the effects of aging for the Condensate Backwash Tank will be adequately managed with aging management programs (AMPs) that do not include inspections of internal coatings.

SHydrogen Seal Oil Vacuum Tank This tank is located on the south end of the Turbine Building 2 "d floor. It is separated by several walls and more than 100' from SR components which are located on the north side of the Turbine Building. The Hydrogen Seal Oil Vacuum Tank is located in an area that is open toward the south. There are no SR components, or components that support regulated events in the immediate area. In addition, detrimental downstream effects on SR components or components credited to support regulated events in the event of a coating failure are not credible. This tank operates at negative pressure and therefore any potential leak would be into the tank. Therefore, the effects of aging for the Hydrogen Seal Oil Vacuum Tank will be adequately managed with AMPs that do not include inspections of internal coatings.

• Main Generator Hydrogen Gas Coolers There are four coolers that are located in the Main Generator on the south end of the Turbine Building 3 rd floor. Each cooler has two water boxes, one located on the top of the generator, the other located on the underside of the generator. Concerning the top side water box, the generator is located in a large open area with no SR components or components credited to support regulated events nearby. There is a wall north of the generator hydrogen gas coolers between the generator and the turbine. This wall protects SR equipment located on the north end of the Turbine Building from potential spray should these coolers leak. The four water boxes on the generator underside are open to the 2 "d floor Turbine Building. Because of the location of these water boxes, the turbine/generator pedestal support structure limits spray resulting from a leak to the area directly below the generator. There are no SR components or components that support regulated events in this potentially affected area. The water boxes are accessible for observation. In addition, detrimental downstream effects on SR components or components credited to support regulated events in the event of a coating failure are not credible. Therefore, the effects of aging for the Main Generator Hydrogen Gas Coolers will be adequately managed with AMPs that do not include inspections of internal coatings.

• Reactor Recirculation Pump Seal Test Fixture The Reactor Recirculation Pump Seal Test Fixture is utilized during a pump seal rebuild.

It is not connected to the demineralized water system during plant operation. Further, loss of coating integrity would not have a detrimental downstream effect on SR components or components credited to support regulated events as there are no component connected downstream of the test fixture. Therefore, the effects of aging for the Reactor Recirculation Pump Seal Test Fixture will be adequately managed with AMPs that do not include inspections of internal coatings.

• Condensate Filter Demineralizers The Condensate Filter Demineralizers are located in individual enclosed rooms that are

Enclosure 1 to NRC-15-0021 Page 3 remote from SR components and components that are credited to support regulated events. An effluent strainer is located on each unit to prevent a major intrusion of resin from entering the condensate system in the event of a septa failure. High differential pressure on this strainer is alarmed in the Main Control Room. The effluent strainer would also prevent failed coatings from entering the condensate system. Detrimental downstream effects on SR components or components credited to support regulated events due to a coating failure are not credible. Therefore, the effects of aging for the Condensate Filter Demineralizers will be adequately managed with AMPs that do not include inspections of internal coatings.

o Reactor Water Cleanup Filter Demineralizers The Reactor Water Cleanup (RWCU) Filter Demineralizers are located on the Reactor Building 4 floor in individual enclosed rooms which are accessible only by removing concrete plugs on the 5t floor. They are isolated from SR equipment and components that are credited to support regulated events. Any leak in the demineralizer due to coating failure would be contained in the pit and will drain to a Reactor Building sump. For significant leaks the system would automatically isolate on delta flow. For smaller leaks, differences in delta flow and increasing sump level would alert operators to the leak. An effluent strainer is located on each unit to prevent a major intrusion of resin from entering the RWCU system in the event of a septa failure. High differential pressure on this strainer is alarmed in the Main Control Room. This effluent strainer would also prevent failed coatings from entering the RWCU system. Detrimental downstream effects on SR components or components credited to support regulated events due to a coating failure are not credible. Therefore, the effects of aging for the RWCU Filter Demineralizers will be adequately managed with AMPs that do not include inspections of internal coatings.

Program Exception NUREG-1801, as modified by LR-ISG-2013-01, recommends periodic inspections of internal coatings. In the case of the fire water system piping and piping components with internal coatings, the Fermi 2 Coatings Integrity Program will use opportunistic inspections. Justification for the use of opportunistic inspections rather than periodic inspections is provided in the new LRA Section B.1.45 contained in Enclosure 2.

Enclosure 2 to NRC-15-0021 Fermi 2 NRC Docket No. 50-341 Operating License No. NPF-43 Fermi 2 LRA Revisions for LR-ISG-2013-01 to NRC-15-0021 Page 1 The revisions to the License Renewal Application (LRA) to address LR-ISG-2013-01 are provided as follows. Revisions to text and tables in LRA Sections 2.1.3, 3.2, 3.3, 3.4, A.4, and B.0 are provided with additions shown in underline and deletions shown in strike-through. LRA Sections A.1.45 and B.1.45 are completely new and are shown in standard text.

Revise Section 2.1.3 discussion of LR-ISG-2013-01 as follows:

LR-ISG-2013-01 ( ,- t4 gity rma-e.

imwi-ewme~tdy-amennt A i aaegn oiqs teL- atin Ff _- U j .>! .' tU ( ?

T. i4Gpev a e -s posse-gce- teert eegin "es-2Xsa21-int iya e

] EL E 9 El3n A 4. ixg -' h Revise Section 3.2.2.1.2, Residual Heat Removal System, to add the following line items:

Aging Effects Requiring Management Aging Management Programs Revise Section 3.2.2.1.4, High Pressure Coolant Injection System, to add the following line items:

Aging Effects Requiring Management Aging Management Programs

• .Cntno nu rt to NRC-15-0021 Page 2 Revise Table 3.2.2-2, Residual Heat Removal System, to add the following line items:

Table 3.2.2-2: Residual Heat Removal System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes a i r - . C b Teted VQ4 rt er  ! (a*

? f1 C~.cM tIn ie . - -

Revise Table 3.2.2-4, High Pressure Coolant Injection System, to add the following line item:

Table 3.2.2-4: High Pressure Coolant Injection System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes I Tank l PrUssure Carhn? i_ i i infats I a tino Co tina nt arit --

to NRC-15-0021 Page 3 Revise Section 3.3.2.1.3, Service Water Systems, to add the following line items:

Aging Effects Requiring Management Aging Management Programs Revise Section 3.3.2.1.7, Fire Protection - Water System, to add the following line items:

Aging Effects Requiring Management Aging Management Programs Revise Section 3.3.2.1.10, Emergency Diesel Generator System, to add the following line items:

Aging Effects Requiring Management

• L2Jg of c 2 Aging Management Programs Revise Section 3.3.2.1.15, Fuel Oil Systems, to add the following line items:

Aging Effects Requiring Management Aging Management Programs to NRC-15-0021 Page 4 Revise Table 3.3.2-3, Service Water Systems, to add the following line items:

Table 3.3.2-3: Service Water Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Revise Table 3.3.2-7, Fire Protection - Water System, to add the following line items:

Table 3.3.2-7: Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes boundary jwtegrity to NRC-15-0021 Page 5 Revise Table 3.3.2-10, Emergency Diesel Generator System, to add the following line item:

Table 3.3.2-10: Emergency Diesel Generator System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Revise Table 3.3.2-15, Fuel Oil Systems, to add the following line item:

Table 3.3.2-15: Fuel Oil Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes bounsr v ini ritu s

to NRC-15-0021 Page 6 Revise Section 3.3.2.1.17, Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2),

to add the following line items:

Aging Effects Requiring Management Aging Management Programs

• C~c~h~ ~raqrlt to NRC-15-0021 Page 7 Revise Table 3.3.2-17-5, Reactor Water Cleanup System, Nonsafety-Related Components Affecting Safety-Related Systems, to add the following line item:

Table 3.3.2-17-5: Reactor Water Cleanup System, Nonsafety-Related Components Affecting Safety-Related Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Revise Table 3.3.2-17-15, Turbine Building Closed Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems, to add the following line item:

Table 3.3.2-17-15: Turbine Building Closed Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes eu v intearito to NRC-15-0021 Page 8 Revise Table 3.3.2-17-28, Reactor/Auxiliary Building HVAC System, Nonsafety-Related Components Affecting Safety-Related Systems, to add the following line item:

Table 3.3.2-17-28: Reactor/Auxiliary Building HVAC System, Nonsafety-Related Components Affecting Safety-Related Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes boundav T d _inrt fu Q a

<2~~ _____

to NRC-15-0021 Page 9 Revise Section 3.4.2.1.3, Miscellaneous Steam and Power Conversion Systems in Scope for 10 CFR 54.4(a)(2), to add the following line items:

Aging Effects Requiring Management Aging Management Programs e Coaina inteacrito to NRC-15-0021 Page 10 Revise Table 3.4.2-3-2, Condensate System, Nonsafety-Related Components Affecting Safety-Related Systems, to add the following line item:

Table 3.4.2-3-2: Condensate System, Nonsafety-Related Components Affecting Safety-Related Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Revise Table 3.4.2-3-5, Main Turbine Generator and Auxiliaries System, Nonsafety-Related Components Affecting Safety-Related Systems, to add the following line item:

Table 3.4.2-3-5: Main Turbine Generator and Auxiliaries System, Nonsafety-Related Components Affecting Safety-Related Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes housin bounriarv itet to NRC-15-0021 Page 11 Revise Table 3.4.2-3-6, Condenser and Auxiliaries System, Nonsafety-Related Components Affecting Safety-Related Systems, to add the following line item:

Table 3.4.2-3-6: Condenser and Auxiliaries System, Nonsafety-Related Components Affecting Safety-Related Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes sh* Sgndr

• i*

r Prure ho or*r rbn stee l TreatedJ non wate Loss of co inaqr n 3k ( aig ntcgit to NRC-15-0021 Page 12 Add new Section A.1.45, Coating Integrity Program, as follows

A.1.45 Coating Integrity Program The Coating Integrity Program is a new program that will include periodic visual inspections of coatings/linings applied to the internal surfaces of in-scope piping, piping components, heat exchangers, and tanks where loss of coating or lining integrity could prevent accomplishment of a license renewal intended function. For coatings/linings that do not meet the acceptance criteria, physical testing is performed where possible (i.e., sufficient room to conduct testing) in conjunction with visual inspection. The training and qualification of individuals involved in inspections of non-cementitious coatings/linings are in accordance with ASTM standards endorsed in RG 1.54. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.

Service Level 1 coatings are managed by the Protective Coating Monitoring and Maintenance Program (Section A.1.36).

Baseline coating/lining inspections will occur inthe 10-year period prior to the period of extended operation. Subsequent inspections are based on an evaluation of the effect of a coating/lining failure on in-scope component intended functions, potential problems identified during prior inspections, and service life history.

to NRC-15-0021 Page 13 Revise Section A.4 License Renewal Commitment List, to add the following item:

Implementation No. Program or Activity Commitment Schedule Source w'f-vwh 2Q2 g ...g .onE

• lbid RAX"leiiadeg to NRC-15-0021 Page 14 Revise Table B-1, Table B-2, and Table B-3, to add the following items:

Table B-1 Aging Management Programs Program Section New or Existing Table B-2 Fermi 2 Aging Management Program Correlation with NUREG-1801 Programs NUREG-1801 Number NUREG-1801 Program Fermi 2 Program Exrre r Trns:

Table B-3 Fermi 2 Program Consistency with NUREG-1801 NUREG-1801 Comparison Consistent Plant-Program with Programs with Programs with Exception Name NUREG-1801 Enhancement to NUREG-1801 Specific Loating X to NRC-15-0021 Page 15 Add new Section B.1.45, Coating Integrity, as follows:

B.1.45 COATING INTEGRITY Program Description The Coating Integrity Program is a new program that will include periodic visual inspections of coatings/linings applied to the internal surfaces of in-scope piping, piping components, heat exchangers, and tanks where loss of coating or lining integrity could prevent accomplishment of a license renewal intended function. For coatings/linings that do not meet the acceptance criteria, physical testing is performed where possible (i.e., sufficient room to conduct testing) in conjunction with visual inspection. The training and qualification of individuals involved in inspections of non-cementitious coatings/linings are in accordance with ASTM standards endorsed in RG 1.54. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.

Service Level 1 coatings are managed by the Protective Coating Monitoring and Maintenance Program (Section B.1.36).

NUREG-1801 Consistency The Coating Integrity Program will be consistent with the program described in NUREG-1801,Section XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks, as set forth in LR-ISG-2013-01, "Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks," with the following exceptions.

Exceptions to NUREG-1801 The Coating Integrity Program will have the following exceptions.

to NRC-15-0021 Page 16 Element Affected Exception

4. Detection of Aging Effects NUREG-1801 recommends periodic inspections of internal coatings. The Fermi 2 program will use opportunistic inspections for fire protection system components.'

Exception Notes

1. Fire water system internally coated piping and components are buried.

Inspection of these components is highly intrusive and would require excavation and implementation of a complex temporary modification to maintain a functional fire water header. The internally coated piping inthis system consists of cement-lined portions of the system piping that provide water to several fire hydrants. Several recently replaced isolation valves also have internal coatings. Additional underground fire water system isolation valve replacements are planned. Management of the effects of aging for the fire water system is described in LRA Section B.1.19, "Fire Water System." In accordance with the Fire Water System Program, routine surveillance tests, including system flushes, are performed to ensure no flow blockage exists.

Evidence of flow blockage during these tests would be entered into the Corrective Action Program. The fire water system is maintained at required operating pressure. Alarm circuits monitor the system pressure and low pressure is annunciated in the Main Control Room. A loss or decrease in system pressure would be noted and corrective actions initiated.

to NRC-15-0021 Page 17 Element Affected Exception

7. Corrective Actions NUREG-1801 recommends that coatings/linings that do not meet acceptance criteria are repaired, replaced, or removed.

The Fermi 2 High Pressure Coolant Injection System lube oil reservoir internal coating will not be replaced or repaired.2 Exception Notes

2. Fermi 2 is an active member of the Nuclear Maintenance Application Center (NMAC) Terry Turbine Users Group. Lessons learned and improved maintenance practices for the Terry Turbine have been communicated at industry meetings facilitated by NMAC's Terry Turbine Users Group and are incorporated in the High-Pressure Coolant Injection (HPCI) Maintenance Guide. This guide is the basis for the HPCI Terry Turbine maintenance regime at Fermi 2. With respect to the lube oil reservoir, the guide states that paint defects should be removed and the tank should not be recoated.

to NRC-15-0021 Page 18 Element Affected Exception

7. Corrective Actions For coatings/linings exhibiting delamination and peeling that are returned to service, NUREG-1801 recommends physical testing, adhesion testing using ASTM International standards endorsed in RG 1.54, and follow-up inspections. In the Fermi 2 program, physical testing of delamination and peeling will consist of lightly tapping the coating, light hand scraping, light power tool cleaning, or adhesion testing. Destructive adhesion testing will not be conducted. Follow-up inspection and re-inspection intervals will be in accordance with NUREG-1801 recommendations unless longer inspection intervals are technically justified?

Exception Notes

3. It is preferable to leave delamination and peeling that has not progressed to the base material intact instead of removing the entire coating system down to bare metal. Some material protection will still be provided by the intact coating layers. This may also facilitate future repairs of the coating system in this location since a smaller number of coats would be required to achieve the desired dry film thickness. The performance of destructive adhesion testing may damage intact coating layers. Follow-up visual inspections of damaged areas will be conducted within 2 years from detection of the degraded condition, with re-inspection within an additional 2 years, or until the degraded coating is repaired or replaced. In cases where equipment history is known and understood, extending inspections and re-inspections beyond the NUREG-1801 recommendations may be made with technical justification.

Enclosure 2 to NRC-15-0021 Page 19 Element Affected Exception

7. Corrective Actions For blisters not repaired, NUREG-1801 recommends physical testing consisting of adhesion testing using ASTM International standards endorsed in RG 1.54. In the Fermi 2 program, for blisters not repaired, physical testing will consist of lightly tapping the coating, light hand scraping, light power tool cleaning, or adhesion testing.

Destructive adhesion testing will not be conducted. 4 Exception Notes

4. Destructive adhesion testing will remove potentially sound material surrounding a blister. Leaving this material intact will continue to provide some degree of protection. Additionally, the removal of sound coating material via destructive testing may increase the likelihood of base material degradation due to exposure.

Enhancements None Operating Experience The Coating Integrity Program is a new program. Industry operating experience will be considered inthe implementation of this program. Plant operating experience will be gained as the program is executed and will be factored into the program via the confirmation and corrective action elements of the Fermi 2 10 CFR 50 Appendix B quality assurance program.

As discussed in element 10 to NUREG-1801,Section XI.M42, the inspection techniques and training of inspection personnel associated with this program are consistent with industry practice and have been demonstrated effective at detecting loss of coating or lining integrity.

Inspection intervals have been established that are dependent on the results of previous plant-specific inspection results.

The review of operating experience at Fermi 2 concluded that no aging effects not considered in NUREG-1801 have been identified.

Although the Coating Integrity Program is a new program, Fermi 2 has in place basic elements of the program such as routine inspections, deficiency identification processes, and corrective actions. The following examples provide objective evidence that when the Coating Integrity Program is established, it will be effective in ensuring that intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

to NRC-15-0021 Page 20 In 2004 deficiencies in the Main Condenser water box coating were identified through visual inspections. Corrective actions were implemented.

In 2005 the RWCU Resin Feed Tank coating was observed to be flaking off. Corrective actions were implemented.

In 2007 during inspection of the Hydrogen Seal Oil Vacuum Tank, it was noted that paint flaked off several surfaces inside the tank. Corrective actions were implemented.

In 2014 during an inspection of the Upper Main Turbine Lube Oil Cooler localized coating damage was identified inthe bottom of the inlet and outlet channels near the channel to channel cover flange. The affected areas were recoated.

Conclusion The Coating Integrity Program will be effective at identifying and managing loss of coating integrity because it incorporates proven monitoring techniques, acceptance criteria, corrective actions, and administrative controls. The Coating Integrity Program provides reasonable assurance that the effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.