ML12335A401

Official Exhibit - RIV000024-00-BD01 - Entergy Engineering Report, Operating Experience Review Report, IP-RPT-06-LRD05, Rev. 3 (2008), IPEC00186046 (Entergy Op Ex Rev Report)

ML12335A401
Person / Time
Site:	Indian Point
Issue date:	06/10/2008
From:	Entergy Corp
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 21600, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML12335A401 (121)

Text

United States Nuclear Regulatory Commission Official Hearing Exhibit In the Matter of:

Entergy Nuclear Operations, Inc.

(Indian Point Nuclear Generating Units 2 and 3)

ASLBP #: 07-858-03-LR-BD01 Docket #: 05000247 l 05000286 Exhibit #:

Identified:

Admitted:

Withdrawn:

Rejected:

Stricken:

Other:

RIV000024-00-BD01 10/15/2012 10/15/2012 RIV000024 Submitted: December 22, 2011 v\\.~p." REGU{.q",

/~j~\\

0 I-

~

~

i V'~

0' An ACHMENT 9.1 VENDOR DOCUMENT REVIEW STATUS ENTERGY NUCLEAR MANAGEMENT MANUAL EN-OC-149

1.

~ ACCEPTED, WORK MAY PROCEED

2.

ACCEPTED AS NOTED RESUBMITIAL NOT REQUIRED, WORK MAY PROCEED

3.

ACCEPTED AS NOTED RESUBMITIAL REQUIRED

4. D NOT ACCEPTED Acceptance does not constitute approval of design details, calculations, analyses, test methods, or materials developed or selected by the supplier and does not relieve the supplier from full compliance with contractual negotiations.

Print Name I

• Eng i neering S upervisor---=.B->...;...' :-:-Ut_' {J;r_*_..... 1----"""---'---'---'--_f_'r:7fz-'-----7---~-----'---'--__ _f__(

Print Name L ________________________________________________________________________

~

EN-DC-149 REV 2 IPEC00186046

VENDOR DOCUMENT COMMENT RESOLUTION Rev. No:.]

5/30/2008 Print Name/ Signature Date EC No: IP2-06-32959

\\N!A lor NP)

Ext. 914-827-7735 I Comment I Page I Section I Comment:

No:

. No:

No:

1 Disposition

) Resolution:

1110*

i 1

N/A N/A As the IPEC OE Coordinator. I reviewed 1

the changes identified in IP-RPT I LRD05 rev 3 and found the changes to 1

be acceptable and to support the I

report's conclusion. I was not provided l the original document, or the questions that drove the revisions so I was not I

able to review the responses from that I

perspective. However, as this report has 1

been appropriately prepared, reviewed I and approved, I have no further comments.

~*

i

/

I i

I

~

I I

I I

I I

I

~

I

~

~

~

I I

~

/

I I

/

v I

• I=

0=

EN-DC-149 REV 2 IPEC00186047

IPI IPEC00186048

Revision Number 0

1 2

3 IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 2 of 119 REVISION DESCRIPTION SHEET Description Pages and/or Sections Revised Initial Issue Clarified the OE discussion for CR-IP2-Table 3.1.2 2002-10408 Clarified OE discussions in several Sections 4.1.1, 4.1.2, 4.1.4, 4.1.5, areas, based on feedback from peer 4.1.6, 4.1.8, 4.1.14, 4.1.15, 4.1.18, review of IPEC LRA.

4.1.22, 4.1.23, 4.1.27, 4.1.29 and references 5.269 and 5.270 Deleted non-applicable OE for MEB Section 4.1.18 and references 5.151 Inspection Program.

and 5.152 Added OE for PSPM activities on Section 4.1.21 and references 5.263 eves charging pumps.

through 5.268 Added OE for Heat Exchanger Section 4.1.31 and references 5.258 Monitoring Program.

through 5.262 Clarified discussion of the methodology Sections 2.1, 3.2.1.1, 3.2.1.2, 3.2.2, and results of the review of condition 3.2.3 reports (CRs)

Tables 3.1.1, 3.1.2, 3.1.3, 3.1.4 Clarified discussion of the methodology Section 2.1 for the review of condition reports (CRs)

Corrected document numbers for Section 2.2 AMPERs.

Clarified the OE discussion for CR-IP3-Table 3.1.1 2002-01175.

Added additional OE for Aboveground Section 4.1.1 and reference 5.272 Steel Tanks Program.

Added additional OE for MEB Table 3.1.4 and Section 4.1.18 and Inspection Program (Region I reference 5.271 inspection items #520 and #530).

Added additional OE for Service Water Section 4.1.25 and reference 5.273 Integrity Program.

IPEC00186049

3 IPEC License Renewal Project Operating Experience Review Report Added name of Bolting Integrity program owner interviewed.

IP-RPT LRDOS Revision 3 Page 3 of 119 IPEC00186050

IPEC License Renewal Project Operating Experience Review Report TABLE OF CONTENTS IP-RPT LRDOS Revision 3 Page 4 of 119 1.0 Purpose................................................................................................................. 6 2.0 Method.................................................................................................................. 7

2. 1 AERM OE Review............................................................................................................ 7 2.2 AMP OE Review.............................................................................................................. 8 3.0 AERM OE Evaluation and Conclusions............................................................ 11 3.1 AERM OE Evaluation..................................................................................................... 11 3.2 AERM OE Conclusions.................................................................................................. 67 3.2.1 Comparison of OE Review Results with Mechanical Tools............................... 67 3.2.2 Comparison of OE Review Results with Structural Tools.................................. 67 3.2.3 Comparison of OE Review Results with License Renewal Electrical Handbook67 4.0 AMP OE Evaluation and Conclusions.............................................................. 68 4.1.1 Aboveground Steel Tanks Program.................................................................. 68 4.1.2 Bolting Integrity Program................................................................................... 68 4.1.3 Boraflex Monitoring Program - Unit 2............................................................... 69 4.1.4 Boral Surveillance Program-Unit 3................................................................. 69 4.1.5 Boric Acid Corrosion Prevention Program......................................................... 70 4.1.6 Containment lnservice Inspection (CII) Program............................................... 70 4.1.7 Containment Leak Rate Program...................................................................... 71 4.1.8 Diesel Fuel Monitoring Program........................................................................ 72 4.1.9 Environmental Qualification (EQ) of Electric Components Program.................. 73 4.1.1 0 External Surfaces Monitoring Program.............................................................. 7 4 4.1.11 Fatigue Monitoring Program.............................................................................. 74 4.1.12 Fire Protection Program.................................................................................... 75 4.1.13 Fire Water System Program.............................................................................. 76 4.1.14 Flow-Accelerated Corrosion Program................................................................ 77 4.1.15 Flux Thimble Tube Inspection Program............................................................. 78 4.1.16 lnservice Inspection (lSI) Program.................................................................... 79 4.1.17 Masonry Wall Program...................................................................................... 79 4.1.18 Metal-Enclosed Bus Inspection Program........................................................... 80 4.1.19 Nickel Alloy Inspection Program........................................................................ 81 4.1.20 Oil Analysis Program......................................................................................... 82 4.1.21 Periodic Surveillance and Preventive Maintenance Program............................ 82 4.1.22 Reactor Head Closure Studs Program.............................................................. 84 4.1.23 Reactor Vessel Head Penetration Inspection Program..................................... 84 4.1.24 Reactor Vessel Surveillance Program............................................................... 85 4.1.25 Service Water Integrity Program....................................................................... 86 4.1.26 Steam Generator Integrity Program.................................................................. 88 4.1.27 Structures Monitoring Program.......................................................................... 90 4.1.28 Water Chemistry Control-Auxiliary Systems Program.................................... 91 4.1.29 Water Chemistry Control-Closed Cooling Water Program............................. 91 4.1.30 Water Chemistry Control-Primary and Secondary Program........................... 92 4.1.31 Heat Exchanger Monitoring Program................................................................ 92 5.0 References.......................................................................................................... 94 IPEC00186051

Tables:

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 5 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems.............. 11 Table 3.1.2 Operating Experience Applicable to Class 1 Mechanical Systems...................... 42 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components....... 45 Table 3.1.4 Operating Experience Applicable to Electrical, Instrumentation, and Control Components..................................................................................................................... 64 Attachments: -System Engineers Interviewed - Program Owners Interviewed - Air and Gas Systems -Insulation - Bolting IPEC00186052

1.0 Purpose IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 6 of 119 Industry guidance documents for performing aging management reviews are based on evaluations of the operating history of U.S. nuclear plants and identify aging effects requiring management (AERM) considered common to nuclear power plants. However, each applicant for license renewal must review available operating experience (OE) to determine if there are plant-specific materials, environment, and stressors that are associated with structures, components or commodity groups under review that would not be identified through application of the industry guidance documents. (Ref. 5.1, 5.4, 5.5, 5.6) 1 Each applicant must also provide objective evidence to support the conclusion that the effects of aging will be managed so that intended functions will be maintained during the extended period of operation. (Ref. 5.1)

Therefore, the objectives of this review are to:

determine if there are AERM that are not identified by the industry guidance documents for implementing the license renewal rule (Ref. 5.4, 5.5, 5.6) 1

, and demonstrate the existing aging management programs (AMPs) credited for license renewal are effective for the management of aging effects.

1 The mechanical tools were not written to specifically identify aging effects requ1nng management in Class 1 systems.

However, use of the mechanical tools is appropriate where materials and environments are the same as non-Class 1 materials and environments.

Other industry guidance documents, including NUREG-1801, Generic Aging Lessons Learned (GALL) Report, and other NRC documents, identify Class 1 aging effects requiring management not identified in the mechanical tools. (Ref. 5.3)

IPEC00186053

2.0 Method IPEC License Renewal Project Operating Experience Review Report 2.1 AERM OE Review IP-RPT LRD05 Revision 3 Page 7 of 119 To determine if there are AERM that are not identified by the industry guidance documents for implementing the license renewal rule, an assessment of five years of Indian Point Energy Center (IPEC) OE for Unit 2 and Unit 3, from 2001 through 2005, was performed. This period overlaps the period over which OE was accumulated for the industry guidance documents, and therefore, provides reasonable assurance IPEC AERM are identified. (Ref. 5.4, 5.5, 5.6)

IPEC condition reports (CRs) document failures, malfunctions, deficiencies, deviations, defects, non-conformances, and OE from external sources. Therefore, the corrective action database maintained in the paperless condition reporting system (PCRS) provides the single most explicit source of documentation of the operating history of IPEC. The conservatively low threshold for issuing CRs at IPEC provides justification for excluding other corrective action documentation (e.g., maintenance requests) from the OE review. Therefore, CRs in PCRS were reviewed to identify AERM not included in the industry guidance documents. (Ref. 5.12)

External OE applicable to IPEC is identified and processed using a CR and is included in PCRS.

Therefore, OE documented in licensee event reports, NRC generic letters, NRC information notices, INPO documents, etc., that has occurred since the industry guidance documents were written does not require a separate review. (Ref. 5.13)

Interviews with plant staff supplemented the CR review.

Experience based interviews, in accordance with EPRI TR-110089, "Experience-based Interview Process for Power Plant Management," are an innovative method to gather information, develop an understanding, and obtain expert insight into aging issues. Over time, those individuals involved in the day-to-day activities that maintain and operate nuclear plant structures, systems, and components acquire unique knowledge and experience regarding the overall performance history and degradation phenomenon affecting the structures, systems, and components. (Ref. 5.11)

Therefore, the AERM OE review included a review of CRs from 2001 through 2005 and interviews with systems engineers.

CRReview Keyword searches of the data contained in the description, keywords, corrective actions, and operability determination data fields in PCRS were used to locate CRs related to aging effects.

The electronic queries limited the results to CRs initiated from the beginning of 2001 to the end of 2005. Keywords were selected that would most likely reveal aging effects not included in industry guidance documents, such as "aged or aging", "generic", "degraded or degradation",

"industry experience", "operating experience", "crack", "corrosion or corrode", "thinning", "rust",

"erosion", "rupture", "spray", "seep", and "leak."

The CRs were screened to separate those related to aging effects or programs from the total population of search results.

If the CR description, operability determination, or corrective actions documented a potential aging effect, or if the CR applied to an existing aging management program, the CR was retained for further evaluation. CRs were excluded if they were applicable to administrative controls not linked to AMPs, were written against systems not in the scope of license renewal (unless they had generic implications), were written against IPEC00186054

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 8 of 119 components not subject to aging management review (e.g., non-pressure boundary components, unless they had generic implications), or documented design deficiencies or event-driven conditions.

CRs retained for further evaluation are discussed in Section 3.1, AERM OE Evaluation.

System Engineer Interviews Responsibility for the operational integrity of plant systems, structures, and components lies with the system engineers. An engineer is assigned to each plant system as a means of establishing ownership.

System engineers have hands-on experience with plant components and walkdowns by the engineers provide effective analyses of the material condition of systems.

Thus, interviews with systems engineers provide a means of identifying plant-specific aging effects. (Ref. 5.15)

The interviews consisted of open discussions of aging effects on plant systems and structures.

Aging mechanisms, aging effects, and adverse environments identified in the industry guidance documents were reviewed with the system engineers.

Interviewers prompted the system engineers to discuss unusual or unique materials, environments, and aging effects.

The system engineers were also asked about problems that may be age-related. lists the systems engineers interviewed.

The system engineers' responses received an evaluation to determine if further review was necessary.

System engineer responses related to potential or observed aging effects, aging mechanisms, adverse plant environments, and component failures were retained for further evaluation.

System engineer interview responses retained for further evaluation are discussed in Section 3.1, AERM OE Evaluation.

2.2 AMP OE Review The CR keyword searches performed in the AERM OE Review identified conditions applicable to existing aging management programs.

However, since condition reports are used to document failures, malfunctions, deficiencies, deviations, defects, and non-conformances, objective evidence that a program is effective is not always contained in the corrective action database. Thus, to demonstrate the existing AMPs credited for license renewal are effective for the management of aging effects, a review of program-specific documentation was performed for each existing AMP in LRD02, LRD07, LRD08, LRD09 Aging Management Program Evaluation Reports.

Also, plant personnel responsible for implementing AMPs were interviewed.

Therefore, the AMP OE review included a program-specific document review and interviews with program owners.

Program-Specific Document Review CRs identified during the AERM OE review as applicable to an AMP were retained for further evaluation. However, program-specific information is necessary to demonstrate that an AMP is effective for the management of aging effects.

IPEC00186055

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 9 of 119 AMPs can be categorized as either inspection or monitoring programs. Inspection programs check components within the program for evidence of aging effects.

Monitoring programs maintain system conditions within specific parameters to prevent aging effects on components.

For inspection programs, reports of recent inspections, examinations, or tests were located and reviewed to determine if aging effects have been identified on applicable components.

Also, for many programs, supplemental keyword searches of PCRS were used to locate CRs related to components within the program.

Keywords were selected that would most likely reveal CRs related to the applicable components. For example, for the Flux Thimble Tube Inspection Program, keywords "flux thimble", "instrument guide tube," and "instrument nozzle" were selected. The CRs resulting from this search were reviewed and retained for further evaluation if they applied to the AMP. A CR written against a component was not retained for further evaluation if it applied to an event or design-driven condition outside the control of the AMP.

For monitoring programs, trending reports of sample results were located and reviewed to determine if parameters are being maintained as required by the program.

For these programs, supplemental keyword searches of PCRS were used to locate CRs related to parameters monitored by the program. Keywords were selected that would most likely reveal CRs related to program parameters.

For example, for the Boraflex Monitoring Program, keywords "boraflex", "BADGER", and "areal" were selected.

The CRs resulting from this search were reviewed and retained for further evaluation if they applied to the AMP.

Program-specific document review results retained for further evaluation are discussed in Section 4.0, AMP OE Evaluation and Conclusions.

Program Owner Interviews Program owners are responsible for assuring implementation of each program in accordance with NRC expectations and site commitments.

Since OE is often a factor in revisions to program requirements, program owners are an excellent source of knowledge regarding performance of programs.

Interviews with program owners consisted of open discussions of program effectiveness.

Interviewers prompted the program owners to discuss program changes and reasons for the changes. Program owners were asked to provide evidence of successful implementation and performance of their program.

Program owners related evidence of program success or weakness and identified self-assessments, QA audits, peer evaluations, and NRC reviews applicable to their program. lists the program owners interviewed. The program owners' responses were evaluated to determine if further review was necessary. Program owner responses related to potential or observed aging effects, aging mechanisms, adverse plant environments, component failures, program success, and program failure were retained for further evaluation.

For existing programs where the program owner was unavailable for an interview, keyword searches and documentation reviews, CRs, audits, surveillances, and assessment results were utilized to gather OE applicable to the program.

IPEC00186056

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 0 of 119 Program owner interview responses retained for further evaluation are discussed in Section 4.0, AMP OE Evaluation and Conclusions.

IPEC00186057

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 11 of 119 3.0 AERM OE Evaluation and Conclusions AERM OE reviews identified OE applicable to non-class 1 mechanical, class 1 mechanical, structural, and electrical components.

License renewal project personnel performing aging management reviews evaluated the OE to determine whether the specific condition needs to be addressed in an AMRR. The evaluations are summarized in Section 3.1 and conclusions are presented in Section 3.2.

3.1 AERM OE Evaluation The OE from the CR and interview responses was compared for consistency with the industry guidance for performing AMRs.

Evaluations for non-Class I mechanical systems are presented in Table 3.1.1, evaluations for Class I mechanical systems are presented in Table 3.1.2, evaluations for structural components are presented in Table 3.1.3, and evaluations for electrical components are presented in Table 3.1.4.

In one case, a system engineer interview indicated an aging effect that was not documented by a CR until 2006; therefore it was not included in the 2001-2005 CR review. This CR (CR-IP2-2006-00150) was added to Table 3.1.1 for review.

Conclusions drawn from this evaluation are discussed in Section 3.2, AERM OE Conclusions.

Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200100017-Main Generator Hydrogen Loss of material is an aging effect 2001-00017 Cooler 22 South section has indication of a identified in the mechanical tools for tube leak. 100% Hydrogen gas is present carbon steel, stainless steel or copper when venting cooler section.

alloys in raw water.

CR-IP2-200100623 -The stainless steel drain This CR further evaluated what originally 2001-00623 pipes on the bottom of the service water appeared to be "rust" on stainless steel zurn strainers show indications of rust near and determined it was due to only surface the welds on these pipelines. This was contamination and possibly improper post noted during walkdown of the zurn strainer weld cleaning of the stainless steel. The pit during walkdown with NRC on surface was cleaned. No aging effects 1/19/2001.

were identified by this CR.

CR-IP2-200101741-There is a through wall leak No aging effects are evident based on 2001-01741 on #21 MBFP discharge piping evaluation of this issue; leak was caused immediately downstream of the pump and by a casting void during fabrication. No upstream of the check valve.

aging effects were identified by this CR.

CR-IP2-200101899 -The 6" Aux Steam Supply Loss of material is an aging effect 2001-01899 Header to the Unit #1 Screenwell identified in the mechanical tools for House/Dock has a Pinhole leak under the carbon steel in treated water or steam.

insulation. The leak is located at chest level, on 5' in the Utility Tunnel past the sewage pit area approx. one fourth of the way to the Screenwell House.

IPEC00186058

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 12 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200101924-UHT-1 0-248 (auxiliary steam Loss of material is an aging effect 2001-01924 trap) is a bucket trap that has a plug on the identified in the mechanical tools for top with an allen wrench center that has a carbon steel in treated water or steam.

leak. The leak appears to be a through wall leak in the middle of the plug.

CR-IP2-200101994 - Discovered excessive steam Loss of material is an aging effect 2001-01994 leaks on Dock Steam line, 5' section of identified in the mechanical tools for Utility Tunnel. The area of one leak was a carbon steel in treated water or steam.

one foot section corroded almost completely through.

CR-IP2-200102051 -Location: 15' south side of Loss of material is an aging effect 2001-02051 loading well by janitor supply cage.

identified in the mechanical tools for carbon steel in treated water or steam.

Elbow in aux steam line leaking.

CR-IP2-200102140 -Through wall piping leak on Loss of material is an aging effect 2001-02140 Main Steam line from 22A Moisture identified in the mechanical tools for Separator Reheater Vent Chamber to 26A carbon steel in treated water or steam.

Feedwater Heater approximately 1 foot from tie toMS line from 21A MSR Vent Chamber (leak located close to 26A FWH, near valve MS-645).

CR-IP2-200102187 -The 2" City Water supply This is retired equipment in the Unit 1 2001-02187 piping from the 12" City Water Header, in water plant. Loss of material is an aging the Unit 1 Water Factory, to the retired effect identified in the mechanical tools Resin Storage Tank is corroded & has 2 for carbon steel in treated water.

clamps and black electrical tape holding it together.

CR-IP2-200102451 -Through wall leak between Loss of material is an aging effect 2001-02451 valves 387 and 310 inside valve gallery identified in the mechanical tools for PAB. Noted fresh boron buildup on top of stainless steel in treated water.

piping in between 310 and 387. Found no other source of leakage above the piping that could have dripped on the pipe.

CR-IP2-200102482 -The 1/2 pipe downstream of Loss of material is an aging effect 2001-02482 CT-843 connected to 3EX-1 0-1, route stop identified in the mechanical tools for 23b feed water heater drain. The pipe is carbon steel in treated water or steam.

welded to 3EX-1 0-1 and is leaking condensate around the weld.

CR-IP2-200102483 -The flange down stream of WO IP2-01-20650 indicates that this was 2001-02483 21 primary air ejector inlet has a steam a gasket leak that required a new gasket leak.

be installed. No aging effects were identified by this CR.

IPEC00186059

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 13 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200102668 -The house fill tank Loss of material is an aging effect 2001-02668 (CYW20KHWT) has been isolated and identified in the mechanical tools for drained since 12/27/00 because of a leak carbon steel in treated water.

in the piping associated with the tank. The piping leak is under the tank in the overhead on 135' elevation.

CR-IP2-200102685 - 23 Component Cooling No aging effects are evident based on 2001-02685 Water Pump Pedestal Drain is blocked evaluation of the issue; Likely that debris and is filling up/overflowing from seal has plugged the drain.

leakoff. Water has a corrosion inhibitor in it. Water was observed in pedestal area without any water observed coming from drain line.

CR-IP2-200102703 -The physical condition of 21-This CR shows a lack of proper 2001-02703 26 traveling screens is horrendous. All 6 housekeeping and maintenance. No traveling screens have numerous flange aging effects were identified by this CR.

leaks. The flushout connections on the north side of each screen(4 on the lower side of each fiberglass shell) are in poor condition.

CR-IP2-200102730 -While securing a lineup for#

Loss of material is an aging effect 2001-02730 14 Waste distillate tank noted a leak at identified in the mechanical tools for valve LW-674 ( #14 WDTP suction stop) stainless steel or carbon steel in water.

The valve has a 1 /16" hole on the bottom of the valve body.

CR-IP2-200102822-LW-710 has a pinhole leak Loss of material is an aging effect 2001-02822 on the down stream side. LW-71 0 is the identified in the mechanical tools for recirc flow control valve for 14 Waste stainless steel or carbon steel in raw Distillate transfer pump. With this pump water.

unavailable we are not able to recirc or release a waste distillate tank.

CR-IP2-200103043-MS 105-15, MST 4 Steam Loss of material is an aging effect 2001-03043 Trap Inlet Valve, has an active steam leak identified in the mechanical tools for coming from under its insulation.

carbon steel in treated water and steam.

CR-IP2-200103608 -While performing daily Loss of material is an aging effect 2001-03608 rounds found on 21 House service boiler, identified in the mechanical tools for soot blower drain line upstream of valve carbon steel in treated water and steam.

AS-1408 dripping. Could not pinpoint exact location of leak due to insulation/lagging on the pipe.

CR-IP2-200103681 -Steam leak on the No aging effects are evident based on 2001-03681 crossunder inlet pipe to 21A Moisture evaluation of this issue. Insulation Separator Reheater has evidence of steam removed and no leak found. The condensate dripping on the floor coming moisture may have been a result of off the lagging. The leak is located at 53' residual water from a roof leak in the turbine hall building, north of 21A MSR.

past, however, this was not validated.

IPEC00186060

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 14 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200103734 -While walking down up-Loss of material is an aging effect 2001-03734 coming jobs I noticed a steam leak on a identified in the mechanical tools for one inch line leaking from the one inch carbon steel in treated water and steam.

union located between valve tag number, (HD&V 5EX-512 HOT LC-5004s root stop) and (HDTLC LC-5004s)

CR-IP2-200103887 -There is a leak of several Loss of material is an aging effect 2001-03887 drops per second that appears to be identified in the mechanical tools for coming from the pipe cap on the down carbon steel in treated water and steam.

stream side of valve 5EX-35-15. The valve is located on the underside of Moisture Separator Drain Tank 21A's level controller (LC-11 05S).

CR-IP2-200104083-Air leak from AOM-9. Found This CR indicates an internal leak in an 2001-04083 EDG building louvers open. Air leak may air motor that was replaced. No be enough to keep these louvers open. No identification of corrosion or aging effects tag found on air motor.

were identified on passive mechanical components subject to aging management review in CR or WO IP2-01-21412 CR-IP2-200104232 - 24A FWHTR outlet WO IP2-01-21607 indicates that this was 2001-04232 temperature indicator thermowell has a threaded connection that was repaired small leak. Repair/replace thermowell as by applying new tread sealant and required.

tightening. No aging effects were identified by this CR.

CR-IP2-200104776-While performing PI-M2 VC CR corrective actions indicate that this 2001-04776 inspection found boron encrustation on the condition appears to have been due to a packing gland needs to be cleaned for packing leak. No aging effects were valve 9550.

identified by this CR.

CR-IP2-200104959 -The Auxiliary Condensate Loss of material is an aging effect 2001-04959 return header just upstream of valve UW-identified in the mechanical tools for 88 near the Toolroom on 15 foot elevation carbon steel in treated water.

has a through the wall leak at the twelve o'clock position. Please repair.

CR-IP2-200105054 - On 5/18/01, while attempting Loss of material is an aging effect 2001-05054 to perform a soot blow of 21 HSB, it was identified in the mechanical tools for noted that there was a through wall leak in carbon steel in treated water.

the piping upstream of AS-1408 condensate drain for the front soot lance on 21 HSB.

IPEC00186061

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 15 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200105412 - Water was observed to be NOTE: This CR was originally evaluated 2001-05412 leaking from the ceiling at HP-1 in the in Table 3.1.3 "Operating Experience vicinity of emergency light ELUI-1. An Applicable to Structures and Structural arcing sound was heard and the Components."

emergency light illuminated. This appeared to indicate an interruption of the This CR identifies a piping leak into an light's normal AC power supply. [NOTE:

electrical box for an emergency light.

further information is provided in PCRS The source of the leak was identified as a CR-1 P2-1998-09094]

Unit 1 city water line. Loss of material is an aging effect identified in the mechanical tools for carbon steel in treated water (internal) and condensation (external).

CR-IP2-200105904 - Seal Oil Vacuum Pump No aging effects are evident based on 2001-05904 evaluation of the issue. Insulation Oil sampled on the Seal Oil Vacuum removed and no leak found. CR Pump Gear Box indicating large amount of identifies an operation/maintenance built up oxidized sludge. Oxidized sludge problem on the oil only and does not promotes corrosion and deterioration of involve aging effects on passive the oil. The gearbox oil is changed every mechanical components subject to aging three months.

management review. No aging effects were identified by this CR.

CR-IP2-200105968-While doing a survey in the Loss of material is an aging effect 2001-05968 utility tunnel I noticed that the discharge identified in the mechanical tools for pipe to the river is scaled with rust in one carbon steel in air.

section. This is the pipe that contaminated the tunnel in the past.

CR-IP2-200106470- LCV-11270 has a through No aging effects are evident based on 2001-06470 wall leak. This is a large Heater Drain evaluation of the issue. This leak was Tank dump to 23 condenser. This valve is determined to be a flange leak due to being isolated. Initiate work order to improper maintenance [wire drawn (cut) repair.

by steam]. No aging effects were identified by this CR.

CR-IP2-2001064 76 - Hydrogen cooler #22 south Loss of material is an aging effect 2001-06476 section inlet relief valve SWT-62 located identified in the mechanical tools for on the east side of 36' near the Service stainless steel in raw water Water manual throttle valves has a service water through wall leak at elbow weld.

CR-IP2-2001067 40 - 24 Service Water Pump Loss of material is an aging effect 2001-06740 Vacuum Breaker SWN-9-3 Failed its PMT identified in the mechanical tools for due to leak at threaded fitting at top of carbon steel in raw water. (The valve valve body.

was later replaced with a stainless valve under WO IP2-04-22058.)

Reference CR# 200100463.

IPEC00186062

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 16 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200107107 - Following performing WO NP-01-22701 indicated that this was 2001-07107 chlorination on Circulating Water Pump a newly installed component that bays 21, 22, & 23, it was discovered that apparently had internal leakage. It was PCV-7979 has evidence of leakage repaired by installing a new seal (residue on side of valve, residue stalactite assembly on the valve internals. No forming on bottom of valve, and residue aging effects were identified by this CR.

on pump casing).

CR-IP2-200107232-LCV-1127C Heater Drain Loss of material is an aging effect 2001-07232 Tank Large Dump Valve to 22 Condenser identified in the mechanical tools for has a through wall leak on the east side of carbon steel in treated water.

the valve body. This is the second of the three large dump valves to have a leak.

(LCV-1127D is already isolated CR#01-06470)

CR-IP2-200107951 - LCV-1127D Heater Drain Loss of material is an aging effect 2001-07951 Tank Large Dump to 23 Condenser, has identified in the mechanical tools for through wall leak on piping located directly carbon steel in treated water.

below the valve.

CR-IP2-200108270- GT-3, # 4 basket fuel oil WO IP2-01-23542 corrected this coupling 2001-08270 supply line coupling closest to the nozzle is leak by tightening fasteners. No aging leaking at 1 drip/minute during Gas effects were identified by this CR.

Turbine operation, investigate and repair.

CR-IP2-200109058-While performing an Loss of material is an aging effect 2001-09058 Environmental/Safety tour of the Utility identified in the mechanical tools for Tunnel, it was discovered that the 20" Fuel carbon steel external surfaces.

Oil Fill Line is being severely eroded by in leakage of "sweet" water.

CR-IP2-200109241 -During the Annual Walkdown Loss of material is an aging effect 2001-09241 on the Gas Turbines it was found on the identified in the mechanical tools for GT3 Blackstart diesel that its exhaust carbon steel in exhaust gas, indoor air or stack has a minor exhaust leak located at outdoor air.

the joint between the expansion joint and the lower end of the muffler. Also found a Change in material properties is identified degraded rubber expansion joint between in the mechanical tools for rubber in an the air filter and the turbocharger.

air environment.

CR-IP2-200109482 - #12 ignition oil pump is WO IP2-01-20743 replaced the packing 2001-09482 leaking from the bottom of the pump of the pump. No aging effects were casing.

identified by this CR.

CR-IP2-200109593 - DPI-5000S, 21 Service This CR indicated that further 2001-09593 Water Strainer Differential Pressure low investigation determined that there was side impulse line has a minor leak at the no leak at this threaded connection. No threaded connection on the housing, this is aging effects were identified by this CR.

causing corrosion of surrounding components, repair same.

IPEC00186063

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 17 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200109653 -There is a thru wall pipe leak Loss of material is an aging effect 2001-09653 downstream of AS-1 076. Pipe is severely identified in the mechanical tools for corroded and needs to be changed from carbon steel in steam and treated water the steam trap and to include the check and on carbon steel external surfaces in valve and AS-1 076.

air.

CR-IP2-200109659-RW-132 heat exchanger 12 Loss of material is an aging effect 2001-09659 tube side drain and RW-126 heat identified in the mechanical tools for exchanger 11 tube side drain have both carbon steel in raw water.

broken off the heat exchangers. The threaded nipples corrode and rot away.

CR-IP2-2001097 43 - Leaks exist at three locations Loss of material is an aging effect 2001-09743 on 22 House Service Boiler (22 HSB) at identified in the mechanical tools for the interface of the mud drum and Firebox carbon steel in steam and treated water.

outer casing. Each leak is approximately two drops per second.

CR-IP2-200109797 - Hot water return inlet stop Loss of material is an aging effect 2001-09797 UH-344 to heat exchanger HE-1 in MOB identified in the mechanical tools for HVAC room is severely corroded and has carbon steel in treated water.

a packing leak.

CR-IP2-200109821 -The 1 0" piping just below Loss of material is an aging effect 2001-09821 LCV-1127C has a thru wall steam leak.

identified in the mechanical tools for This leak is in addition to the thru wall carbon steel in treated water.

body leak on the valve.

NOTE: This condition is the same as the steam leak on LCV-1127D which is to be worked under 01-22963.

CR-IP2-200110925 - Request a more immediate Loss of material is an aging effect 2001-10925 response to repair of Dock Steam. The identified in the mechanical tools for condensate return line associated with this carbon steel in steam and treated water.

is corroded and leaks badly. This is rendering Dock Steam out of service.

CR-IP2-200111779-In an effort to reduce the This CR requests a stress analysis for the 2001-11779 effect of Flow Accelerated Corrosion in the stainless steel piping that is replacing the secondary piping, the Wet Steam Piping carbon steel piping due to FAC. Loss of Replacement Project was created as part material due to FAC is identified for of the IP2 Flow Accelerated Corrosion carbon steel piping in the secondary (FAC) Program.

plant. No additional aging effects were identified by this CR.

CR-IP2-200111861 -The inside fish spray header Loss of material is an aging effect 2001-11861 on #22 TSC has a thru wall leak at the identified in the mechanical tools for elbow just down stream of the stop valve stainless steel in raw water.

WW-103.

CR-IP2-200200013 -The 2 inch Trough drain This CR was closed to work order IP2 2002-00013 waste water line threaded fitting on 23 19443 which replaced the subject piping.

Charging pump is leaking at a rate of 1 Loss of material is an aging effect drip/ 10 seconds at the 90 degree elbow identified in the mechanical tools for before the vertical section of piping stainless steel or carbon steel in treated causing a housekeeping issue in the cell.

water IPEC00186064

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 18 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200200818-While performing Corrective Loss of material is an aging effect 2002-00818 Maintenance (NP-98-05617 Replace identified in the mechanical tools for Piping upstream of FP-2) there was stainless steel or carbon steel in treated excessive corrosion observed on the water.

inside of the fire piping. The wall thickness of the piping is heavily degraded.

CR-IP2-200201055 -The welded elbow Loss of material and cracking are aging 2002-01055 downstream of AS-1 075 has a significant effects identified in the mechanical tools steam leak as well as a union downstream for carbon steel in treated water or steam.

of this elbow. There exists a deficiency (See Note 1 and WO IP2-02-25391) tag on or around AS-1 075 however I was unable to read it due to steam impinging on the tag.

CR-IP2-200201199 - Leak at end bell on CCC side WO IP2-02-25838 inspection determined 2002-01199 of Heat Exchanger. Leak appeared during there was no leak. This was verified later isolation of heat exchanger to change out by WO IP2-04-11953. No aging effects zinc plugs.

were identified by this CR.

CR-IP2-200201457-Drain plug for BFD-4-2 (26C This leak at a drain plug that was 2002-01457 Feedwater Heater outlet stop) has a small corrected by cleaning and tightening per drain plug leak.

CR corrective action. No aging effects were identified by this CR.

CR-IP2-200201628 -This condition was found WO IP2-02-26013 indicated that when 2002-01628 during SA0-141 Walkdown. Water is the valve was fully closed the leak leaking from a threaded cap connection stopped. No aging effects were identified downstream of valve 5EX-23 onto floor.

by this CR.

Valve 5EX-23 is a Heater Drain & Vent dump line header drain stop valve located on the 5' elevation of the turbine building.

CR-IP2-200201820 - MSR-22A Vent Chamber line This CR indicates that valve internal 2002-01820 drain stop leaks-by. It is located on the 15' components are leaking by. No through el. by moisture pre-separator tank.

wall leaks in the pressure boundary are evident. No aging effects were identified by this CR.

CR-IP2-200202368 -The steam supplied wall Loss of material is an aging effect 2002-02368 heater on the South wall of the Ignition Oil identified in the mechanical tools for Tank Room has an elbow leak at the outlet carbon steel in treated water or steam.

of the heater. Condensate was leaking (See Note 1 and WO IP2-02-00403))

onto the floor and under the tanks.

CR-IP2-200202864-During field inspections Loss of material is an aging effect 2002-02864 noted 21 Main Boiler Feed Pump suction identified in the mechanical tools for piping had water dripping out of the carbon steel in treated water.

insulation about three feet above the pump (See Note 1 and WO IP2-02-39401) casing. Possible through the wall leak on the suction piping of 21 MBFP.

IPEC00186065

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 19 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200204664-Insulation needs to be WO IP2-02-00499 indicates that when 2002-04664 removed from in between SEX-4 and SEX-insulation was removed, this was 3 in order to identify possible thru wall leak identified as a leak at the flange. No on extraction steam line.

aging effects were identified by this CR.

CR-IP2-200204951 - Small steam leak located at This CR indicates a leak at an inspection 2002-04951 238 MSR inlet inspection/access port at port and may not have been due to aging north end of MSR 53' Turbine Hall. Leak is effects. However, loss of material is an located under lagging. Maximo work order aging effect identified in the mechanical

1. 02-02851.

tools for carbon steel in water or steam.

(See Note 1 and WO IP2-02-02851)

CR-IP2-200205463-SWN 77-6 has a thru wall Loss of material is an aging effect 2002-05463 leak at the vent valve.

identified in the mechanical tools for carbon steel in raw water.

CR-IP2-200205472-There is a thru wall leak on Loss of material is an aging effect 2002-05472 the piping approx. 3 feet to the west FW-identified in the mechanical tools for 226.

carbon steel in water.

CR-IP2-200205524 -A through wall leak has Loss of material is an aging effect 2002-05524 developed on 12 house tank fill pump identified in the mechanical tools for suction piping immediately downstream of carbon steel in water.

suction valve FP-68.12 house tank fill pump was already out of service via tagout 2000N-14395, which isolated the pump discharge.

CR-IP2-200206004-The piping between WW-178 Loss of material is an aging effect 2002-06004 and Pl-6987 has a 0.5 gpm leak when 28 identified in the mechanical tools for traveling screen is washing. The insulation stainless steel in raw water.

needs to be removed to determine the location of the leak. Most likely the elbow weld is leaking.

CR-IP2-200206358 - Noted during field This CR indicates that high cycle 2002-06358 inspections small leak (2-3 drops/minute) vibration was a component specific on the suction piping going to #23 design deficiency. Evaluations have Charging pump. Thru wall leak is down been completed as part of the CR stream of valve 284 (suction stop) on weld corrective actions and the effected piping just upstream of C-7 drain valve has been resupported. This was a design deficiency with no aging effects identified in this CR.

CR-IP2-200207210- During PM of R-46 four of Loss of material is an aging effect 2002-07210 the casing studs and nuts were found identified in the mechanical tools for unacceptable due to corrosion. Couplings carbon steel with condensation.

for the upper and lower manifolds are unacceptable due to damaged threads.

IPEC00186066

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 20 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-Found 22 HZFP (22 Hydrazine Feed WO IP2-02-1266 indicated that this pump 2002-07731 Pump) leaking at pump casing onto floor.

was repaired by installing a new seal About 500 cc of dilute Hydrazine from package. No aging effects were identified Chemical addition tank has leaked onto by this CR floor. Pump was taken out of service and valves isolated, chemical spill tape was placed around tank.

CR-IP2-FAC (Flow Accelerated Corrosion)

Loss of material is an aging effect 2002-08136 component FAC-1 B-VCD17 has wall identified in the mechanical tools for thickness readings below allowable limits carbon steel in steam and treated water.

per FAC procedure SE-SQ-12.318 (Tmin =

0.135", Tmeas = 0.11 0"). Component is a 3" 90-degree elbow directly downstream of valve HCV-50688 on the MSR.

CR-IP2-FAC (Flow Accelerated Corrosion)

Loss of material is an aging effect 2002-08370 component FAC-2B-VCD39 has wall identified in the mechanical tools for thickness readings below allowable limits carbon steel in steam and treated water.

per FAC procedure SE-SQ-12.318 (Tmin =

0.135", Tmeas = 0.134). Component is a 3" elbow directly downstream of valve MS-618.

CR-IP2-PI-M9 aboveground petroleum tanks A review of the work orders determined 2002-08676 inspection failed due to oil leaks. Main these were minor packing and fitting boiler feed pump wrt IP2-02-02798, Main leaks and not related to aging effects on turbine oil conditioner wrt IP2-02-02713, passive mechanical components. No IP2-02-02714, IP2-02-02794, IP2 aging effects were identified by this CR.

00349, AND CR200203880, 200201990, 200202090, AND 006360.

CR-IP2-Piping downstream of steam trap AST-20 This CR indicates that this leak is from a 2002-08823 is leaking. Leak seems to be coming from coupling. Work Order IP2-02-57060 coupling downstream of steam trap.

indicated that there was no leakage when Steam trap is located in front of 15' elev this coupling was inspected. No aging Tool Room.

effects were identified by this CR.

CR-IP2-22 Containment Spray Pump continues to High copper content in oil may be due to 2002-08858 show evidence of large amounts of copper wear on the moving parts, but does not in the oil from the pump reservoir.

indicate an aging effect on pressure Inspection was performed in July with no boundary components. No aging effects visible anomalies identified. Copper is still were identified by this CR.

being generated from an unknown source.

CR-IP2-While examining the zinc anodes on #21 Loss of material is an aging effect 2002-09024 EDG JWC & LOC it was observed that the identified in the mechanical tools for recently replaced expansion joint SWN-66 stainless steel in raw water has a thru wall leak of less than one drop per min.

IPEC00186067

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 21 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-Found 24 SWP Zurn strainer blowdown Loss of material is an aging effect 2002-09073 piping flange bolts badly rusted during identified in the mechanical tools for performance of PI-3Y13. This is the 3"-150 carbon steel with condensation or raw psig pressure boundary flange downstream water.

of the strainer and upstream of SWN-594.

All the other strainers have stainless steel bolting.

CR-IP2-During performance of PI-3Y13 for 24 Loss of material is an aging effect 2002-09074 SWP epoxy delamination was found identified in the mechanical tools for downstream of SWN 3 along the entire carbon steel in raw water. The epoxy is spool piece from flange to flange. The air not credited with prevention of aging pocket created by delamination is causing effects in the aging management review.

the discharge piping to corrode at an accelerated rate.

CR-IP2-Corrosion and evidence of thru wall Loss of material is an aging effect 2002-09076 leakage was observed on EDG 21 SW identified in the mechanical tools for stainless steel expansion sleeve SWN stainless steel in raw water.

3. This examination was performed as part of the Extent of Condition response for CR 20002-09024 to inspect the lower SW expansion sleeves.

CR-IP2-Calculated wear rate (see EVAL# 15P-Loss of material is an aging effect 2002-09115 MST-24(b)) indicated the predicted identified in the mechanical tools for thickness (Tp) for component MST-24 will carbon steel in steam and treated water.

reach the component's minimum required thickness (Tmin) within the next operating cycle. It is recommended that the component be replaced.

CR-IP2-Valve 8978 has at least one stud that has This CR indicates that the small amount 2002-09781 some amount of degradation found during of degradation on the studs was later the Section XI bolted Connection determined to actually be a stain from Inspection Program. The back side of the some previous leakage. No aging effects valve is inaccessible and therefore has not were identified by this CR.

been inspected.

CR-IP2-16" Flange face that mates to FCV-1112 Loss of material is an aging effect 2002-09869 has an area of degradation approximately identified in the mechanical tools for 1/8" depth, 4-1/2" long around inner carbon steel in raw water.

circumference at 8 o'clock position, and 1" wide. This is on the west side flange of the valve.

CR-IP2-18" lower flange that mates to SWN-39 Loss of material is an aging effect 2002-09949 has an area of concrete lining that is identified in the mechanical tools for missing on the interior. The missing area carbon steel in raw water. The concrete of concrete is about a 3 inch width right lining is not credited with prevention of near the flange face and extends about aging effects in the AMR. (See Note 1) half way around the circumference of the pipe.

IPEC00186068

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 22 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-Visual inspection performed of piping at Loss of material is an aging effect 2002-10043 location of SWN-2 which was removed for identified in the mechanical tools for a valve PM. This inspection revealed a carbon steel in raw water.

cement lining defect on the upstream flange at 7 o'clock position.

CR-IP2-There is a crack in the air line leading to WO IP2-01-21241 indicated that no air 2002-10920 MPS-758 (MPS Tank B Non Return Inlet leakage was found. No aging effects check valve). The crack is in the first were identified by this CR.

elbow upstream of the valve. MPS-758 is located in the 32' elev mezzanine of the Turbine Bldg on the north side under the HP Turbine.

CR-IP2-Today while conducting a test on the fire This is a CR concerning debris and not a 2002-10965 supply to the Service Center the pre test loss of pressure boundary. No aging flush discharged significant amounts of effects were identified by this CR.

rust and other debris. Such debris could potentially clog fire nozzles and damage equipment.

CR-IP2-

1. 2 Fuel Oil Header in the utility tunnel is Loss of material is an aging effect 2002-11024 degraded. The lagging and flashing were identified in the mechanical tools for removed from the carbon steel fuel oil carbon steel with air on external surfaces.

header in the utility tunnel.

CR-IP2-The CPO sample cooler for the sodium WO IP2-02-01793 indicated that no leaks 2002-11154 and hydrazine analyzer has a shell leak.

were found. No aging effects were This cooler has a service water cooling identified by this CR.

supply.

CR-IP2-The Boric Acid Building Make-up Air Unit WO IP2-02 02039 indicated that the 2002-11159 Heater Coil is leaking. UH-684 is closed heating coil was leaking and the leaking and water is still coming out of the base of tube was brazed closed. Loss of material the fan and forming a puddle on the floor.

and cracking are aging effects identified The water then seeps through the floor and in the mechanical tools for copper alloys puddles on the lower elevation.

in treated water or steam.

CR-IP2-Extraction Steam line to EST-18 down WO IP2-02-01676 indicated that the 2002-11169 stream of 3EX-37-4 is leaking from under deteriorated 12" section of pipe was the insulation and has increased from the replaced. Loss of material is an aging original report (see WRT-IP2-02-01676, effect identified in the mechanical tools 1 0/4/02). There is steam and water coming for carbon steel in treated water or steam.

from the insulation at one end and water dripping from the other.

CR-IP2-At the union to 26B Feedwater Heater low A review of the root cause analysis in this 2002-11194 level column there is a pinhole leak in the CR determined that this condition was weld.

due to a defective field weld and not due to aging effects. No aging effects were identified by this CR.

IPEC00186069

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 23 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-Found pin hole leak thru a weld on valve Loss of material is an aging effect 2002-11229 5EX-48-1, HOT Dump To Cond. 22 Drain identified in the mechanical tools for Stop, on 5ft. of the Turbine Hall. This stainless steel in treated water or steam.

condition could have possible dissolved (See Note 1 - this CR indicates that the oxygen level increase.

leak may be attributed to a deficient weld.)

CR-IP2-Drain valve 5EX-48-1, the drain on LCV-Loss of material is an aging effect 2002-11266 1127C (HOT large condenser dump to 22 identified in the mechanical tools for condenser) was reported in CR 200211229 carbon steel in treated water or steam.

to have a pin hole leak in the weld.

(See Note 1 and WO IP2-02-64927)

CR-IP2-There is approximately a 1 drop per Loss of material is an aging effect 2002-11594 second leak upstream of SWT-47-10 (22 identified in the mechanical tools for Hydrogen Cooler North Section Vent stainless steel in raw water.

Stop). The leak is dripping from the first elbow out of the 22AHC hydrogen cooler.

CR-IP2-The Unit 1 LW-828 Sphere Foundation Loss of material is an aging effect 2003-00003 pump discharge drain valve upstream identified in the mechanical tools for piping is corroded. Failure of this pipe will carbon steel in raw water.

cause CSB 14' to be flooded. LW-828 is where the back-up Air Driven pump discharge is connected.

CR-IP2-Attempted to flush 21 Condenser Vacuum This CR summarizes an event for follow 2003-00088 Pump moisture separator tank. First flush up and not a loss of pressure boundary.

brought down the sodium to 9 PPB from No aging effects were identified by this 40 PPB.

CR.

CR-IP2-Strainer downstream of AS-1261, This CR indicates that the house service 2003-00341 atomizing steam to 22 HSB, failed due to a boiler 22 is no longer used by the site and through wall crack from the bottom threads this leak was not investigated or repaired.

to middle of body. This failure caused the However, cracking is an aging effect room to fill with steam while I & C identified in the mechanical tools for personnel were in room troubleshooting 21 carbon steel in steam and treated water HSB.

(See Note 1).

CR-IP2-During the restoration of the unit 1 dock Loss of material and cracking are aging 2003-00587 steam header the following leaks were effects identified in the mechanical tools identified in the utility tunnel AS-27 had a for carbon steel in steam and treated leak on a welded union. The dock steam water.

aux condensate header in the utility tunnel had a pinhole leak.

CR-IP2-24 inch service water lines 405 and 409 This CR indicates that this condition was 2003-00941 have corrosion buildup near the tops of the localized surface corrosion probably due pipes. The ceiling of the steam generator to the exterior surface of the pipes blowdown tank room shows no evidence of sweating at certain times of the year.

leakage directly above the pipes.

Loss of material is an aging effect identified in the mechanical tools for carbon steel with condensation on external surfaces.

IPEC00186070

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 24 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-A through-wall leak was found on the This CR determined to be a pinhole leak.

2003-02016 stator winding cooling water system. The Loss of material is an aging effect leak is on line 2"YRCF at 45 degree elbow identified in the mechanical tools for just North of the staircase near the weir.

stainless steel in treated water. (See Note Presently about one drop per second is

1) leaking and appears to be increasing.

CR-IP2-Lube oil valve, L0-1, outlet flange leaks.

WRT-03-05298 indicates that this was a 2003-02020 Documented under PI-M9 (DEC tank flange leak that was eliminated by inspection).

tightening bolting. No aging effects were identified by this CR.

CR-IP2-21 House Service Boiler steam drum WO IP2-03-06852 indicates that the 2003-02310 leaking slightly. The water is evaporating gasket was changed out to eliminate this before it reaches the floor.

leak. No aging effects were identified by this CR.

CR-IP2-Steam Generator Slowdown Tank outlet Loss of material is an aging effect 2003-02794 pipe down stream of SWN-53 has a small identified in the mechanical tools for through wall leak at the weld where the carbon steel in treated water pipe is connected to the Service Water Outlet. Leak is a couple of drops per minute.

CR-IP2-Noted through wall leak at elbow Loss of material is an aging effect 2003-02798 downstream of MS-1 02-63 (MST-45 inlet identified in the mechanical tools for stop). Insulation has been removed carbon steel in steam and treated water.

previously due to water accumulation in area of MS-1 02-63.

CR-IP2-Request for carbon steel bolt inspection.

Loss of material is an aging effect 2003-02870 identified in the mechanical tools for During the performance of a safety carbon steel in air.

injection pump surveillance, we observed that the carbon steel flange bolts for FE-950 (Recirculation to refueling water storage tank) are rusted.

CR-IP2-During tours noted a thru wall steam leak The root cause analysis of this CR 2003-03384 just up stream of MS-208 on 22 Main indicated that the cause of the condition Steam lead 36' elevation north end of was a weld imperfection. No aging Turbine Hall in overhead. (PT-1134-3 root effects were identified by this CR.

stop)

CR-IP2-An epoxy coating defect was found on The epoxy coating is not credited with the 2003-03849 21 EDLC when performing the 6 month prevention of aging effects in the aging clean/inspect PM per work order IP2 management review. Loss of material is 42966. The defect is approximately a 1 an aging effect identified in the inch long by 1/16 inch wide chip in the mechanical tools for carbon steel in raw epoxy at the under side of the channel end water.

divider plate.

CR-IP2-There is a minor steam leak just upstream This CR indicated that this condition was 2003-04031 of MSR-29 (21A MSR LP Inlet Press Root a flange leak and is not likely due to a Stop) at a flanged connection. The leak is loss of material. No aging effects were evident from the top and bottom of the identified by this CR.

flange (east side) through the insulation.

IPEC00186071

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 25 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-WO IP202461 and CR 200304031 written The FIN team was assigned this repair.

2003-04633 on 6/22/03 describes the LP steam inlet (hi This was a flange leak and is not likely to press turbine exhaust) to 21A MSR flange be due to a loss of material. No aging leak. The leak appears to have worsened.

effects were identified by this CR.

CR-IP2-A rusty nipple was found to be leaking on Loss of material is an aging effect 2003-05306 the bottom of the 1 0-inch Service Water identified in the mechanical tools for Return line for the station EDG's just carbon steel in raw water.

upstream of the 1176 valves. It is believed that the nipple used to belong to SWN-76-1.

CR-IP2-During the tagout of 11 fresh water cooling The leaking tubes were plugged per IP2-2003-06224 heat exchanger to replace drain valve 03-18720. Loss of material is an aging RW-127 under work order IP2-02-04630, it effect identified in the mechanical tools was discovered that 11 fresh water heat for heat exchanger tubes.

exchanger has tube leakage.

CR-IP2-During the performance of changing out The root cause analysis determined the 2003-06567 the zincs and endbell gasket on 23SIP cause to be a casting flaw or improper lube oil cooler under work order 03-19020, maintenance. No aging effects were a small crack was found in the lower zinc identified by this CR.

hole. The crack was thru wall and down the length of the threads.

CR-IP2-Ultrasonic thickness reading taken on line Loss of material is an aging effect 2004-00213 405, outlet piping from #21 CCW HT ETX identified in the mechanical tools for was found to be below 87.5% (.328") of carbon steel in raw water or treated water.

the nominal wall. Reading as low as.250" were observed on the first elbow downstream from SWN-35.

CR-IP2-Replacement piping and Victualic coupling Loss of material is an aging effect 2004-01401 on city water line, 43' Unit 1 Utility Tunnel identified in the mechanical tools for is extremely corroded. This is due to the carbon steel with condensation or same ground water action that exposed to water on the external necessitated the original piping environment.

replacement.

CR-IP2-Section of pipe upstream of valve SWN-Loss of material is an aging effect 2004-01738 62-4 is coated with rust. Location is the identified in the mechanical tools for bottom of the pipe between the 1st & 2nd carbon steel with condensation on elbow downstream of the service water external surfaces header.

CR-IP2-There is a pin hole leak on 21 SJE-C first Loss of material is an aging effect 2004-02281 stage ejector for 21 SJAE located about 6 identified in the mechanical tools for inches below the elbow going to SJAE carbon steel in steam and treated water.

condenser. The leak is a steady stream and has created a 2 scfm air leak.

CR-IP2-During Flow Accelerated Corrosion (FAC)

Loss of material is an aging effect 2004-02954 examination (WO IP2-03-26606) FAC identified in the mechanical tools for point 214-25P, wall thinning was noted.

carbon steel in steam and treated water.

IPEC00186072

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 26 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-Air In-Leakage is elevated at Unit 2.

This is a recording of a measured 2004-04010 Latest air in-leakage results from 8/29/04 inleakage rate and not a specific instance indicate a total of 9.85 scfm. (21 of a loss of pressure boundary. No aging Condenser air in-leakage-7.5 scfm, 22 effects were identified by this CR.

Condenser air in-leakage-.65 scfm and 23 Condenser air in-leakage-1.7 scfm)

CR-IP2-While flushing 22 BATP prior to hanging Evaluation documented in the CR 2004-04011 PTO 2-CVCS-22BA TP determined this was due to packing REBUILDNARIOUS WORK REV 0-0, leak(s). Verified to no longer be leaking water was noted coming out of the by WO IP2-04 09525. No aging effects insulation under valve 3558.

were identified by this CR.

CR-IP2-During the Service Water Radiography of Loss of material is an aging effect 2004-04446 Line 410, Weld F-1574, one area of identified in the mechanical tools for degradation in the form of erosion was carbon steel in raw water. Erosion was identified. The area of erosion measured identified as one mechanism for loss of approx. 1" wide by 2" long.

material in the SW AMRR.

CR-IP2-Service water is leaking from the nipple Loss of material is an aging effect 2004-04556 downstream of valve SWT 823 which is on identified in the mechanical tools for the outlet side of HPFW sample cooler at copper alloy in raw water.

the SWAP.

CR-IP2-Main steam thru wall leak downstream of Loss of material is an aging effect 2004-04565 valve MS-667-X1 Inlet Isolation Valve on identified in the mechanical tools for FT-5058 on 23A MSR. This is located on carbon steel in steam and treated water.

the south end of 23A MSR on the Main Steam Inlet piping.

CR-IP2-While performing 2Y inspection of the From the CR description or WO IP2 2004-04691 CCR HVAC UNIT21 MTR under WO IP2-09744, it does not appear that either of 02-64800 it was discovered that the flare the known cracking mechanisms for nut on the TXV equalizing line has a crack bolting (stress corrosion cracking and its entire length and thru wall.

fatigue) was present. Since no other examples of cracking of non-Class 1 flare nuts was found, this isolated case is judged to reflect a manufacturing defect in this flare nut. No aging effects were identified by this CR.

CR-IP2-During UT inspection of component MS-Loss of material is an aging effect 2004-05358 1 826 (90 ELBOW) in the main steam line identified in the mechanical tools for wall thinning was detected below the carbon steel in steam and treated water.

administrative screening criteria of 70% of nominal wall thickness. The nominal thickness and the screening criteria of the component is 0.432.

CR-IP2-CR written to document results of Loss of material is an aging effect 2004-05794 evaluation performed on piping between identified in the mechanical tools for valves 6EX-3 and 6EX-4, Extraction steam carbon steel in steam and treated water.

non-return check valves for 26FWH.

When the valves were opened up for inspection, a rust bloom was found in bottom of pipe between the two valves.

IPEC00186073

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 27 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-During performance of PWT# IP2 Loss of material is an aging effect 2004-06150 15373, lnservice inspection for leakage of identified in the mechanical tools for various service water system piping, carbon steel with condensation on valves, and components, identified the external surfaces.

following; On 22 EDG Service Water Supply from the 1-2-3 header, located on a horizontal piping run upstream of SWN 4, there is a considerable build up of rust on the underside of the pipe.

CR-IP2-Chemical trends indicate an active This is an indication of overall system 2004-06162 corrosion mechanism in the Unit 2 CCW.

water chemistry although not related to a Copper and iron concentrations have specific component. However, loss of increased significantly.

material is an aging effect identified in the mechanical tools for carbon steel and copper in treated water CR-IP2-This is to record and track the as-found Loss of material is an aging effect 2004-06238 condition of the main boiler feed water identified in the mechanical tools for pump lube oil coolers 22FPLOC and carbon steel in raw water, lube oil and 21 FPLOC. There was some corrosion indoor air.

damage on the channel heads of both of them.

CR-IP2-During the Extent Of Condition inspection Loss of material is an aging effect 2004-06741 of the Service water line welds to the identified in the mechanical tools for EDGs today, it was determined that the 6" carbon steel in raw water.

line from the 1-2-3 header to 21 EDG has a weld below minimum thickness that will need to be removed and replaced.

CR-IP2-Flange below LC-5206-2S is leaking.

WR IP2-05-1 0392 indicated that this 2004-06830 flange leak was repaired by installing a new gasket. No aging effects were identified by this CR.

CR-IP2-The preliminary UT reports for the 9 welds Loss of material is an aging effect 2004-06776 upstream of valve SWN-62-6 on the 1-2-3 identified in the mechanical tools for header of the 23 EDG has indications carbon steel in raw water.

below the minimum wall calculated.

CR-IP2-Unit Heater 246 has a steam leak in the Although the unit heater was replaced 2004-06796 coil area.

and a specific aging effect was not determined, loss of material and cracking are aging effects identified in the mechanical tools for any metal in steam and treated water. (See Note 1)

CR-IP2-During a routine PM of Vacuum Breaker Loss of material on bolting is an aging 2004-06847 SWN-9-3 (IP2-02-32450) the nuts and effect identified in the mechanical tools studs attaching the Stainless Steel elbow for carbon steel or stainless steel bolting to the 24 Service Water discharge header with condensation on external surfaces.

was found to be severely corroded. No leakage is present.

IPEC00186074

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 28 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-Through Wall leak on weld for CD-98-1.

The root cause was identified as an 2005-00162 21 MBFP suction line vent valve. Leak improper weld and evaluated further in can be isolated by removing 21 MBFP CR-IP2-2005-266. No aging effects were from service and applying PTO."

identified by this CR.

CR-IP2-Flange upstream of MS-1 064 has a steam This was a flange leak and is not likely to 2005-00294 leak.

be due to a loss of material. No aging effects were identified by this CR.

CR-IP2-The following documents the eddy current Loss of material (which includes pitting) is 2005-00812 inspection results of the CCW HX #21 an aging effect identified in the (WO #IP2-04-13053). No operability mechanical tools for copper alloys in issues are involved. Internal corrosion water pitting on the tubes was identified.

CR-IP2-Discovered piping leak, during PT-031 B, The root cause analysis performed under 2005-01130 from brass elbow downstream from Valve CR determined these elbows were 4224 (Suction test line 22 ACCW Pump components that were installed to allow root stop).

use of quick disconnects during testing and were not properly installed. No aging effects were identified in this CR.

CR-IP2-22 RHR pump base carbon steel bolting is The boron encrusting was due to a pump 2005-01312 boron encrusted in the area around the seal leak. This experience is consistent seal of the pump on the southwest and with leakage determinations in the BAC northwest side.

program. No aging effects were identified by this CR.

CR-IP2-During performance of 2-PI-M002 WO IP2-05-17454 and CR description 2005-01803 observed that valve 890A has Boron indicate that these were packing leaks encrusted on the body, packing gland nuts and not due to aging effects on passive and the floor beneath it. There was also a mechanical components. No aging small amount of Boron on valve 890B effects were identified by this CR.

packing gland.

CR-IP2-While removing PTO for R-59, a Loss of material is an aging effect 2005-01862 significant Fresh Water leak on the heat identified in the mechanical tools for all exchanger was noted.

metals in raw water.

CR-IP2-888B has Boron encrusted around the CR description and WR IP2-05-1155 2005-02547 entire circumference of the valve bonnet.

indicates that this leak was resolved by This Boron in direct contact with the torquing nuts and not due to a leak in the Carbon steel bolts holding the valve passive mechanical pressure boundary together.

components. No aging effects were identified by this CR.

CR-IP2-This CR is to document the adverse trend This is to document overall condenser 2005-02960 in condenser air leakage. Operators leakage and does not identify any specific informed supervision of adverse trend in components. No aging effects were condenser air leakage. Beginning on identified by this CR.

07/11/05 air leakage was 7.8 scfm total which is normal.

IPEC00186075

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 29 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-This CR initiated by CA&A to copy a The pump leak was a packing leak 2005-03544 manual CR, which is attached to the repaired under WO IP2-05-22464 with no suggested action section below with the related aging effects. For the corrosion original paper operability review.

on the external surfaces, loss of material is an aging effect identified in the Test PI-M9 for aboveground tank mechanical tools for carbon steel in inspections failed due to leakage from indoor air and outdoor air.

MBFP oil conditioner circulating pump and corrosion of roof, piping and valves on FOST 11.

CR-IP2-21 SFP Pump has a small casing leak at The evaluation provided in WO IP2 2005-03718 the 0600 position.

00533 determined there was not a pump leak. No aging effects were identified by this CR.

CR-IP2-PI-M9 (Aboveground Petroleum Storage The corrosion on the external surfaces of 2005-03720 Tanks) is unsat. GT2/3FOT, 11 FOST and the piping is consistent with the loss of COST & DOST are unsat due to water in material identified as an aging effect their respective secondary containments.

identified in the mechanical tools for 11 FOST is also unsat due to the rusted carbon steel in air and outdoor air.

valves and piping.

CR-IP2-The Fire Protection piping in the Utility Loss of material is an aging effect 2005-04161 Tunnel is showing signs of excessive identified in the mechanical tools for corrosion due to the atmospheric carbon steel with air on external surfaces, conditions. Recommend performing Ultrasonic Testing to verify piping integrity.

CR-IP2-Maintenance was assigned to open and Loss of material is an aging effect 2005-04444 inspect SWN-1. During the as found identified in the mechanical tools for engineering inspection it was found that carbon steel or stainless steel in raw the upstream flange face had eroded.

water CR-IP2-During GT-1 run for PT-M38A, noticed fuel WO IP2-05-02436 indicates that the 2005-05315 oil leak from black start Diesel day tank breather cap was determined to a source when the system was pressurized.

of leakage, and repaired under minor WRT#05-02436.

maintenance No aging effects were identified by this CR.

CR-IP2-At about 2030, the Nuclear NPO was The apparent cause analysis determined 2006-00150 informed that Watch HP had reported a the cracking was a fatigue failure of this leak on 23 CHP. Upon investigation, the positive displacement cylinder. The HP related that the CAM monitor aligned aging effect for this component has been to the 23 CHP cell had begun alarming, accounted for in IPT-06-AMM07, eves.

and that a leak on the block was spraying water into the room. On inspection, there appeared to be a through wall crack approximately one-half inch long on the side of the main block, near the top of the side cover plate for the first cylinder.

IPEC00186076

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 30 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-During an erosion/corrosion examination Loss of material is an aging effect 2001-01045 wall thinning was noted on piping identified in the mechanical tools for downstream of HD-LCV-7003. This carbon steel in steam and treated water.

inspection was required as the valve is leaking and was noted by performance test personnel via PFM-59.

CR-IP3-During an erosion/corrosion examination Loss of material is an aging effect 2001-01096 (WR 00-04379-07), wall thinning was identified in the mechanical tools for noted on MSR Vent Chamber Drain piping carbon steel in steam and treated water.

downstream of MSR 328, located 2'6" south and 11 '6" west of F/20, approx. el.

45'.

CR-IP3-During an erosion/corrosion examination, Loss of material is an aging effect 2001-01285 (WR 00-04379-09, 01-PT-08), wall identified in the mechanical tools for thinning was noted on piping downstream carbon steel in steam and treated water.

of valve MS-HCV-416-2.

Valve and associated piping were replaced.

CR-IP3-During an erosion/corrosion examination, Loss of material is an aging effect 2001-01322 (WR 00-04523-02, 01-PT-24) wall thinning identified in the mechanical tools for was noted on piping downstream of Main carbon steel in steam and treated water.

Steam Trap MST-80 (Main Steam Balancing Line).

CR-IP3-During R09, R1 0, and pre-R11 NRC GL Loss of material is an aging effect 2001-01514 89-13 NDE inspections of insulated carbon identified in the mechanical tools for steel Service Water piping in the VC, a carbon steel with condensation.

condition has routinely been found of heavy metal exfoliation on the exterior of the 1 0" FCU supply and return lines.

CR-IP3-During the Generic Letter 89-13 Loss of material is an aging effect 2001-01593 inspections, location EOC-26, on the 24" identified in the mechanical tools for line 408 in the room with the rock area, carbon steel in raw water.

was found to have wall thinning. Minimum code thickness was.151 ", while a 1" length was found to be 0.132".

CR-IP3-During inspections of the fan cooler units, Loss of material is an aging effect 2001-01749 pin hole leakage or evidence of pin hole identified in the mechanical tools for leakage was found on six of the ten valves stainless steel in raw water that serve as isolation valves to the fan cooler unit motor coolers. The valves in question are: SWN-520; SWN-521; SWN-523.

IPEC00186077

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 31 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-A forced plant outage was necessary in This specific CR was traced to improper 2001-01887 Jan. 1997 due to feedwater heater tube water levels being maintained in these leaks in the #31 FWH's. Most of the tube IP3 feedwater heater tubes (that are not damage found was in the form of OD STAMR) and the associated localized thinning at the bottom of the inlet passes.

erosion. No aging effects were identified It was traced to steam erosion caused by that are directly applicable to other heat flashing on the shell side due to improper exchangers that are STAMR. The water levels.

possibility of erosion is evaluated for all heat exchangers based on their specific materials and environments.

CR-IP3-No piping replacement is required.

Loss of material is an aging effect 2001-01921 identified in the mechanical tools for During an erosion/corrosion examination, carbon steel in steam and treated water.

(WR 00-04521-01, 01-PT-5), wall thinning was noted on three (3) piping segments downstream of MS-PCV-1152 and MS-196.

CR-IP3-No piping replacement required.

Loss of material is an aging effect 2001-01985 identified in the mechanical tools for During an erosion/corrosion examination, carbon steel in steam and treated water.

(WR 00-05234-09, RHD-02.68-01 E), wall thinning was noted on an 8" elbow downstream of RHD-LCV-11 058.

CR-IP3-At the 5/15 day to night SW (Service The concrete liner is not credited in 2001-02124 Water) turnover, dayshift reported that maintaining pressure boundary or during the extent of condition flange face preventing aging effects in the AMR. No inspection the engineer noticed a missing aging effects were identified by this CR.

piece of concrete liner on the pipe near the flange.

CR-IP3-During the Service Water ISL T the Loss of material is an aging effect 2001-02319 following items were noted:

identified in the mechanical tools for carbon steel or stainless steel in raw PID 01065-SWT-238 Slowdown Hx 4 water.

relief valve inlet piping leak.

PID 01067-SWT-80 31 Exciter Air Cooler Inlet lsol. pipe leak.

PID 01068-31 MBFP Oil Cooler head has small leak.

CR-IP3-A pin-hole type leak was discovered just Loss of material is an aging effect 2001-02320 downstream of the downstream flange-to-identified in the mechanical tools for pipe weld at valve SWT-24. Leak rate is carbon steel in raw water.

approx. 2-3 drops/sec. Leak is in a non-safety-related, non-lSI section of the service water system.

IPEC00186078

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 32 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-PID 03521 stated:

This is leakage at a swagelock fitting that 2001-02324 was tightened and later verified to no Boron buildup I leak on Swagelok between longer be leaking. No aging effects were SP-AOV-956c and SP-AOV-956d, where identified by this CR.

IVSWS ties on PZR liquid space sample line.

CR-IP3-Main Generator H2 leakage is above the This is a report of system leakage rate 2001-02419 action limit of 500 SCFD. Based on the and not a determination of a specific last 3 days the trend is up, with leakage aging effect. No aging effects were increasing from 600 CFD to 900 CFD.

identified by this CR.

CR-IP3-Plant personnel discovered that an elbow Loss of material is an aging effect 2001-02489 on a 2" drain line from the 1A (northeast) identified in the mechanical tools for moisture preseparator to the heater drain carbon steel in steam and treated water.

tank is leaking steam. Elbow is located about halfway between the line isolation valve MS-125-3 and the check valve MS-126-3.

CR-IP3-While measuring air in leakage on 32 Loss of material is an aging effect 2001-02534 condenser, it was observed that on 32 Air identified in the mechanical tools for Ejector Loop Seal Check Valve CV-49 had carbon steel in steam and treated water.

a thru wall leak. Leakage thru the valve was approx. one (1) drop every 4 seconds.

CR-IP3-1 /2" to 1" thick buildup of corrosion Loss of material is an aging effect 2001-02567 products was found on the inside of valve identified in the mechanical tools for bodies removed from MW-337 and MW-carbon steel (including gray cast iron) in 338 under corrective maintenance WRs treated water.

00-02670-00 and 00-02672-00.

CR-IP3-While performing RE-CCI-030 "Electrical Loss of material is an aging effect 2001-02620 Generator Hydrogen Survey" the identified in the mechanical tools for chemistry technician found a significant stainless steel in raw water. Heat leak around the bottom of 32 hydrogen exchangers were replaced in R12 with 6%

cooler.

moly SS tubes for increased corrosion resistance (see WO IP3-03-11820, 21, 22, and 23)

CR-IP3-During a routine Shift Manager tour 5HD-Loss of material is an aging effect 2001-02710 2-5 was found leaking. The valve, "33A identified in the mechanical tools for Moisture Separator Drain Tank to HOT" carbon steel in steam and treated water.

check valve has a through wall leak on the side of the valve.

CR-IP3-During rounds, NPO discovered a small Loss of material is an aging effect 2001-02751 pinhole, through-wall leak in the service identified in the mechanical tools for water pipe header to the CCW heat carbon steel or stainless steel in raw exchangers. This hole appears to be at water.

the toe of the weld on the cross-tie tee connection (between valves SWN-31 and SWN-33-2.

IPEC00186079

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 33 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-During routine rounds the conventional Loss of material is an aging effect 2001-02817 NPO identified a small leak on the MST-64 identified in the mechanical tools for strainer.

carbon steel in steam and treated water.

CR-IP3-While replacing 31 Potable Water Booster Loss of material is an aging effect 2001-03181 pump which had a through wall leak on identified in the mechanical tools for the casing, the mechanics bumped into the carbon steel in treated water.

adjacent 32 Potable Water Booster pump.

The discharge line on the pump completely sheared off probably due to corrosion.

CR-IP3-During removal of a PTO, an NPO Loss of material is an aging effect 2001-03440 discovered small service water leaks on identified in the mechanical tools for 32A and 32B condenser heads at the carbon steel in raw water.

piping welds. The leaks were approximately 2 to 6 drops/minute.

CR-IP3-Pinhole service water leak discovered on Loss of material is an aging effect 2001-04148 outlet of piping from 33 FCU.

identified in the mechanical tools for carbon steel or stainless steel in raw The leak is approx. 1 drop per minute water.

between the containment wall and the Containment isolation valve.

CR-IP3-Eddy current inspections were performed Loss of material is an aging effect 2001-04449 on the tube side (Service Water side) of identified in the mechanical tools for the #31 & #32 CCW heat exchangers as copper alloy in raw water part of scheduled PMs under WRs 99-04460-01 & 99-04461-01. In both heat exchangers, ID corrosion pitting was found resulting in the plugging of 2 tubes in #31 HTX and 5 tubes in # 32 HTX.

CR-IP3-While placing 31 Heating Coil on the PAB Loss of material and cracking are aging 2002-00174 supply fan in service, the NPO noticed that effects identified in the mechanical tools some of the coils were leaking. The for carbon steel or copper alloys in steam leaking coils were noted to be in the area and treated water.

of the 7 southern most coils of 31 heating coil.

CR-IP3-A maintenance person accidentally Loss of material is an aging effect 2002-00416 brushed up against a piece of service identified in the mechanical tools for water piping associated with the cyclone carbon steel in raw water.

separator to 33 Circulating Water pump.

The pipe broke off between valve SWT-119 and pressure indicator Pl-1703. The condition of the pipe was extremely rusted.

IPEC00186080

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 34 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-While rebuilding (2) spare BAST transfer This corrosion was due to leakage of 2002-01175 pumps found boron corrosion on frame borated water on the pump frame adapters. The seal areas are still adapters. This event does not constitute acceptable. Frame adapters should be an aging effect requiring management for replaced after next use.

the BAST transfer pumps. Loss of material due to corrosion of the frame adapters is identified in the mechanical tools and other industry documents for carbon steel in borated water.

CR-IP3-MS-253 (33 main turbine stop valve Loss of material is an aging effect 2002-01204 bypass) has a through wall leak on its identified in the mechanical tools for stuffing box.

carbon steel in steam.

CR-IP3-A minor thru wall steam leak was identified Loss of material is an aging effect 2002-01207 on valve MS-253, "Main Steam Stop Valve identified in the mechanical tools for MS-127-3 Bypass Isolation".

carbon steel in steam.

CR-IP3-A follow up UT was performed on the Loss of material is an aging effect 2002-01720 service water pinhole leak upstream of identified in the mechanical tools for TCV-11 OS within 90 days of the last carbon steel in raw water.

performed UT as per code. The results showed a growth in circumferential direction from 0.875 inches to 1.25 inches.

CR-IP3-When removing a section of condenser Loss of material is an aging effect 2002-01820 water box loop seal piping @ 12' elevation identified in the mechanical tools for in preparation of installation of new loop carbon steel in raw water.

seal tank found approx. 8ft of 6 in. piping full of rusU metallic debris.

CR-IP3-A boron ball approximately 3" dia. is As determined in WO 13-027709661, 2002-02120 forming on the bottom of the 32 Boric Acid there was no leak at this location. No Storage Tank. There is no visible leakage aging effects were identified by this CR.

and the area does not appear wetted.

CR-IP3-The City Water Line that leads to the EDG This external corrosion was due to 2002-02254 Expansion Tanks is corroded on the leakage at a specific location and is not a outside. The corroded section is just as it generic concern. Loss of material due to leaves the wall in the valve pit in the EDG corrosion is an aging effect identified in Valve Room. The corrosion has been the mechanical tools for carbon steel caused by occasional discharges from a external surfaces.

vacuum breaker.

IPEC00186081

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 35 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-One through wall pin hole leak and one After initial investigation it was found that 2002-02751 through wall 2" circumferential crack on there was no through wall pinhole leak or the body weld were found on the CT-LCV-crack, but rather a very minor leak at the 1158-2. This Valve is CAT I and Seismic gasketed joint of the valve body. The Class I.

confusion was caused due to paint that had been applied to the valve body area (including flanged gasket area) cracking over time making it look like a crack in the painted valve body. This area and an area where leakage occurred making it look like a pinhole leak began leaking water by the gaskets in two locations.

The bolting was re-torqued with some movement noted and the leakage stopped. No aging effects were identified by this CR.

CR-IP3-The following conditions were found during Loss of material is an aging effect 2002-02793 replacement of 36 CWP Motor cooling coil identified in the mechanical tools for under WO# 13-020087100:

stainless steel in raw water.

• Numerous corrosion-induced pinhole leaks were noted during as-found testing of the installed stainless steel cooling coil.

CR-IP3-Steam trap EST-4 downstream piping "T" Loss of material is an aging effect 2002-02886 has pinhole steam leak.

identified in the mechanical tools for carbon steel in steam and treated water.

CR-IP3-Service Water leakage discovered at Loss of material is an aging effect 2002-03132 threads where SWT-63-1, -3, -4, -5, and -6 identified in the mechanical tools for (Carbon Steel) threads onto the Bus Duct carbon steel and stainless steel in raw Cooling piping (Stainless Steel).

water.

CR-IP3-A steam leak was identified on the 16" As documented in CA001 and WO IP3-2002-03263 drain line from the moisture pre-separators 02-00813, this leak was due to a crack to the heater drain tank.

that was caused by vibration due to a design deficiency. A temporary modification was installed and a permanent modification DCP-01-3-072 stopped the vibration. No aging effects were identified by this CR.

CR-IP3-Found pinhole leak on weld upstream of Loss of material is an aging effect 2002-03622 SWN-34-1 (inlet to 31 CCW heat identified in the mechanical tools for exchanger).

carbon steel in raw water.

CR-IP3-A leak was identified on the 31 sparging This CR indicates that the leak was from 2002-03811 pump at the seal water connection tap.

a joint following pump replacement and was not due to an aging effect. No aging effects were identified by this CR.

IPEC00186082

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 36 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-32 Spent Fuel Pit Pump oil is darkened This CR is an indication of oil degradation 2002-03928 and appears opaque, indicative of aging and does not identify aging effects on and condition deterioration. Vibration passive mechanical components. Oil was inspection performed 9/25 sat with no three years old and was changed. No change in trend.

aging effects were identified by this CR.

CR-IP3-Steam leakage is suspected in the Loss of material is an aging effect 2002-04267 AUXILIARY STEAM cross-tie to UNIT 2 identified in the mechanical tools for (downstream SB-62) underground in the carbon steel in soil and internal carbon fenced area between UNIT 2 & 3 steel surfaces exposed to steam.

immediately west of the Ecolochem trailers. Leakage is evidenced by steam rising up from underground.

CR-IP3-While performing the 33 EDG Fuel Oil Loss of material is an aging effect 2002-04388 Storage Tank test (WO 13-020064600),

identified in the mechanical tools for Maintenance workers noticed significant carbon steel with air on external surfaces.

external corrosion /scale on the exposed 1-1/2" diameter Line 1050 EDG fuel oil fill line in the tank pit immediately downstream of Emergency Fill Connection Valve DF-20.

CR-IP3-CH-1 03, 33 Charging pump outlet vent, WO IP3-02-00478 determined there was 2002-04536 has boron buildup on body of valve. Due not a crack in this valve. A packing leak to a lack of a boron trail or other or external spill onto valve was expected indications, suspect a small crack in the to be the cause of boron buildup on body of the valve. The valve is oriented in valve. No aging effects were identified a manner which rules out a packing leak.

by this CR.

CR-IP3-RCDT manway has evidence of a CR actions and WO IP3-02-23081 2002-04556 circumferential leakage at 6 o'clock indicate that this was resolved by position extending approximately 8 to 12 tightening the cover bolting and later inches. Dry boron and rust are visible. No replacing the gasket (WO IP3-02-23890).

indication of moisture or dripping.

No aging effects were identified by this CR.

CR-IP3-During Area Ownership Walkdown the Loss of material is an aging effect 2002-04750 following deficiencies were identified:

identified in the mechanical tools for carbon steel in air.

1) On 5' elevation of the Turbine Building a number of expansion joints on the Hot Well Dump Pump pipelines are heavily painted and corroded and appear to be near end of life.

[Item (2) is evaluated in Table 3.1.3]

CR-IP3-Engineering area for improvement No aging effects were identified by this 2002-05086 identified by WANO team: Long term CR since these electrical components are degradation of the service water system active and therefore not subject to aging and of the Circulating Water Pump LCI management review.

drives has challenged operators. This has been caused, in part, by the lack of comprehensive and aggressive IPEC00186083

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 37 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-34 MSIV Flange is leaking water/steam WO 13-01038100 indicated that this repair 2003-00409 from its west side and leaking steam (2 only required a new gasket. No aging feet steam plume) from its east side. The effects were identified by this CR.

top 2 most west bolts are also leaking water/steam slightly.

CR-IP3-During FIN investigation of WRT IP3 Loss of material is an aging effect 2003-00423 01697 City Water line 001-JND-6" was identified in the mechanical tools for found to have a slight leak. After further carbon steel in treated water.

investigation it was determined that an approx. 30' section of this pipe should be replaced.

CR-IP3-The 31 PAB Heating Coil has developed a CA 001 for this CR indicates that this 2003-00508 leak and was removed from service. The condition is due to a procedure or design leak was a 3 foot steam plume and filled deficiency that was allowing water to the area with approximately 3 inches of accumulate in the coils and freeze. No standing water.

aging effects were identified by this CR.

CR-IP3-Brass plug between SWN-123 and PCV-Loss of material (including galvanic 2003-00556 1271-2 galvanically corroded to SS corrosion) is an aging effect identified in bushing. Problem discovered during the mechanical tools for copper alloys in performance of 3PT-R185B. Plug needs raw water.

to be removed and replaced with like sized plug of SS material.

CR-IP3-During a FAC examination (WO 13-Loss of material is an aging effect 2003-01071 010447602, 03-PT-03), wall thinning was identified in the mechanical tools for noted on an elbow downstream of VCD-carbon steel in steam.

PCV-7009 (32A MSR); specifically the elbow downstream of the Westinghouse control section at the entrance to the 31 condenser.

CR-IP3-Continuous Chlorination tank appears to The CR root cause analysis determined 2003-01176 be degrading. Pieces of fiberglass coating that the cracking of fiberglass was caused found floating in tank. Within the last week by buckling during the manufacturing the continuous chlorination system process. The delamination was identified became plugged with material.

as due to a "bad resin mix" during the manufacture. The entire tank was replaced. No aging effects were identified by this CR.

CR-IP3-During inspection of the Sodium The CR root cause analysis determined 2003-01186 Hypochlorite (NaOCI) tank, it was noted that the cracking of fiberglass was caused that bits of what appeared to be pieces of by buckling during the manufacturing fiberglass resin was found floating in the process. The delamination was identified tank. It appears that the tank may be as due to a "bad resin mix" during the degrading and is likely related to the manufacture. The entire tank was recent clogging.

replaced. No aging effects were identified by this CR.

IPEC00186084

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 38 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-During a FAC examination (WO IP3 Loss of material is an aging effect 2003-01327 23675, 03-PT-25), wall thinning was noted identified in the mechanical tools for on piping downstream of valve 5HD-LCV-carbon steel in steam and treated water.

1107 (31 B MS Drain Tank drain) at the Drains Collecting Tank.

CR-IP3-During inspection of 31 EDG east and west Loss of material is an aging effect 2003-01346 air start systems i.e. air start motor, carbon identified in the mechanical tools for steel pipe, pressure regulators and carbon steel in compressed air that strainers, rust particles were found in the includes condensation as is identified for east strainer cap and a small amount of the EDG air start subsystem.

water was found in the west air regulator.

CR-IP3-Nondestructive examination of Service Loss of material is an aging effect 2003-01362 Water erosion corrosion location IS-19 identified in the mechanical tools for (line # 1 086) identified wall thickness carbon steel or stainless steel in raw readings below the acceptance criteria water.

(0.135") of work order IP3-02-21 094. Two localized areas of degradation below the criteria were identified.

CR-IP3-The sodium hypochlorite tank was The CR root cause analysis determined 2003-01366 inspected and a three and a half ft crack that the cracking of fiberglass was caused was found on the interior wall. In addition by buckling during the manufacturing the fiberglass is delaminating in the area process. The delamination was identified of the crack. A four inch portion of the as due to a "bad resin mix" during the crack appears to be almost through wall.

manufacture. The entire tank was replaced. No aging effects were identified by this CR.

CR-IP3-During a FAC examination (WO IP3 Loss of material is an aging effect 2003-01927 24847, EX-02.9-02P), wall thinning was identified in the mechanical tools for noted on an elbow on the line from the carbon steel steam and treated water Moisture Separator 1 B to the extraction steam header.

CR-IP3-Visual inspection of the #35 & #36 main Loss of material is an aging effect 2003-02161 condenser inlet waterbox tubesheets identified in the mechanical tools for revealed that several of the existing tube copper alloys in raw water.

plugs were either missing the brass expanding screws or the screws showed signs of corrosion degradation.

CR-IP3-During a FAC examination, (WO IP3 Loss of material is an aging effect 2003-02319 1007 4, EX-02.2-02T) wall thinning was identified in the mechanical tools for found on a 1 0" X 18" tee in the line from carbon steel in steam and treated water.

the 2A preseparator to the extraction steam header.

IPEC00186085

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 39 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-While adjusting Batching Tank Aux Steam Loss of material is an aging effect 2003-03812 flow via the PCV Bypass a large spout of identified in the mechanical tools for water gushed through the wall of the outlet carbon steel in steam or treated water line for Batch Tank Aux. Steam Relief and the external carbon steel surface in valve. I immediately shut the valve and air. The pipe was replaced per 13-inspected the area of the leak. There is a 027709393.

hole through the pipe just over an inch long and about a half inch wide located behind Pl-1370, Batch Tank Aux Steam Pressure Gauge. Furthermore, the entire pipe is rusted so badly that there are large flakes of rust scaling off the exterior.

CR-IP3-During heat trace trouble shooting on line The CR root cause analysis indicated that 2003-04048 DF-1055 (fuel oil supply line to 31 EDG this condition was due to water getting day tank) a pinhole leak was found in the under the piping insulation onto the pipe wall approximately 10 inches from external pipe surface at a particular check valve DF-15-1.

location due to leakage. Although the water exposure on the pipe surface is an event, loss of material is an aging effect identified in the mechanical tools for carbon steel in air.

CR-IP3-When removing the PTO for 31 EDG oil WO IP3-03293 indicated that the 2003-04266 lines the cap for the drain valve DF-1 0-1 rethreading of the existing components could not be put back. The nipple on DF-was completed. Loss of material is an 10-1 is corroded.

aging effect identified in the mechanical tools for carbon steel in air.

CR-IP3-During the internal tank inspections of #31 The tank coating is not credited in the 2003-04873 Fire Water Storage Tank (FWST)

AMR with prevention of aging effects.

performed on 8/26 and 8/27/03, several Loss of material is an aging effect areas of localized coating failure and iron identified in the mechanical tools for nodules with underlying pitting were carbon steel in treated water.

identified on the tank floor. Many nodules were removed.

CR-IP3-On rounds the nuclear NPO found a This is a repeat of the event discovered in 2003-05443 through wall hole in the aux steam to boric CR-IP3-2003-03812. See the evaluation acid batch tank relief line. The hole is for CR-IP3-2003-03812.

about 1.5 inches long and.5 inch wide and is located directly behind Pl-1370.

CR-IP3-During the performance of the 5 year The tank coating is not credited in the 2003-05491 inspection (WO IP3-03-14198) of the 32 AMR with prevention of aging effects.

FWST (FP-T-2), the tank interior was Loss of material is an aging effect found to exhibit general coatings identified in the mechanical tools for deterioration and localized failures.

carbon steel in treated water.

CR-IP3-UH-T-599-8, Condensate Return from Unit Loss of material is an aging effect 2004-00179 Htr HSB-UH-9 Aux. Steam Trap, has a identified in the mechanical tools for through-wall steam leak with a 7" plume.

carbon steel or stainless steel in treated This component is in the water treatment water.

building. Trap was replaced under WR I P3-04-04817.

IPEC00186086

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 40 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-It was reported following inspection that This CR indicated minor leakage (5 drops 2004-01448 leak rate on Sl-7338, 31 Residual Heat per minute) from an internal valve Removal Heat Exchanger Discharge Line subcomponent (the valve bellows). A Relief Valve was 8 ml/min. This leakage is review of the WO IP3-03-03218 did not due to a cracked bellows is water from identify any root cause for the cracked RWST and not RCS. Operability bellows. Cracking is an aging effect Evaluation 04-09 germane.

identified in the mechanical tools for stainless steel in treated water. (See Note 1)

CR-IP3-During the replacement of 5EX-SOV-Loss of material is an aging effect 2004-01579 1252C found removed valve had identified in the mechanical tools for excessive erosion and steam cuts to body carbon steel or stainless steel in steam and seat areas.

and treated water.

CR-IP3-Ecolochem watch noticed a crack on the 6" The cracked PVC flange was likely due to 2004-02902 PVC inlet flange to the carbon bed.

improper loading of this vendor owned and controlled skid type equipment. No aging effects were identified by this CR.

CR-IP3-MW-473, City Water to north loading well The valve was replaced using a brass 2004-03378 hose connection isolation, has a body leak valve in WO IP3-04-05017. Loss of of about one drop per minute and has material is an aging effect identified in the significant rust and corrosion at the sight of mechanical tools for any metal in treated the leakage.

water.

CR-IP3-During the 33 CCW pump PTO removal The pump has an axial split casing. As 2004-03540 the pump casing was noted to be leaking.

described in this CR, the leak developed because the parting flange gasket was not properly aligned with the sealing surface while setting the pump upper half casing. No aging effects were identified by this CR.

CR-IP3-There is an Aux. Steam leak downstream As identified in WO IP3-05-1 0676 the 2005-00163 of UH-516 within the confines of Air coils were frozen. New coils were Handing Unit RS-AH-1 at the far side the installed. This appears to have been due heating coils near the floor. The leak is to improper design or operation. No causing multi-level flooding on the 73', 55',

aging effects were identified by this CR and 41' RAMS bldg.

CR-IP3-During the installation of temp indication Cap was replaced by FIN team in WO 2005-00235 for the power uprate, found the threads on IP3-06-00409. Loss of material is an MS-287, Moisture Preseperator 1 B Test aging effect identified in the mechanical Connection severely corroded with the last tools for carbon steel in air.

two threads on the pipe connection completely gone.

CR-IP3-During 3R13P FAC UT inspection of the Loss of material is an aging effect 2005-00613 1 0" X 14" expander downstream of valve identified in the mechanical tools for 5HD-LCV-1127B, (Heater Drain Tank carbon steel in steam and treated water.

Bypass to Condenser 33 LCV), wall thinning was detected below the administrative screening criteria of 70% of the nominal wall thickness (0.175").

IPEC00186087

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 41 of 119 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-During inspection of 31 main turbine lube A coating was applied per WO IP3 2005-01101 oil cooler. The outlet pipe flange face has 14288. Loss of material is an aging effect 4 areas of crevice corrosion.

identified in the mechanical tools for any metal in raw water.

CR-IP3-The tube bundle in the Main Boiler Feed The tube bundle was replaced under WO 2005-01366 Pump Lube Oil Cooler #32 is severely IP3-03-15696. Loss of material is an degraded due to corrosion pitting per eddy aging effect identified in the mechanical current inspection (see iTi Report No. PR tools for any metal in raw water.

No.32-134, dated 3-21-05). The vendor recommended tube bundle replacement.

CR-IP3-During inspection of the fuel oil supply Calculation IP3-CALC-EDG-03703 2005-03088 pipe to 32 EDG it was discovered that line indicates that there was corrosion on the 1053 had wall thickness loss in multiple external pipe surface at a specific areas of up to 0.056" due to corrosion.

location where the insulation was missing.

The extent of corrosion was primarily a location specific concern. Loss of material is an aging effect identified in the mechanical tools for carbon steel external surfaces.

CR-IP3-Inspection of the 31 FCU HX waterbox Loss of material is an aging effect 2005-05466 shows that the previously identified identified in the mechanical tools for deterioration of the cover plates by crevice stainless steel in raw water.

corrosion has progressed to the point that repairs are necessary to seal the waterboxes.

CR-IP3-Inspection of the 32 FCU HX waterbox Loss of material is an aging effect 2005-05558 shows widespread pitting corrosion of identified in the mechanical tools for cover plates to the point that repairs are stainless steel in raw water.

necessary to seal the waterboxes.

CR-IP3-Steam leak from flange on SW side of WO IP3-05-00769 indicated that this 2005-05832 Magnatrol, leak is audible, and visually repair only required a new gasket at the verified, hi level alarm is not in.

flanged connection. No aging effects were identified by this CR.

Note 1 -Although the documentation was inconclusive regarding the cause of this condition as it relates to aging effects, the CR description and corrective actions indicate that the condition can reasonably be attributed to the effects of aging.

IPEC00186088

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 42 of 119 Table 3.1.2 Operating Experience Applicable to Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-While performing seal inspections on This CR indicated that marks the 2002-10408 24RCP in work request IP2-01-23293 the inspector saw were not cracks. They VT-1 inspections on the# 1 Seal housing were machine marks made when the bolts, 6 bolts were found to be bolts were first fabricated. No aging unacceptable. Appears to be a crack in effects were identified by this CR.

the 6 bolts. This is the Section XI pressure boundary for the seals.

CR-IP2-This CR is written to ensure that the As identified in the CR description, these 2004-05474 potential corrosion and RCS leakage are seal leaks or cracking of the canopy issues associated with carbon steel reactor seal weld from sec. The review of pressure vessel heads, as evidenced by possibility of boric acid corrosion on the significant accumulation of boron external surfaces is consistent with the deposits on at least one CRD 'stalk' identification of the boric acid corrosion indicating a canopy seal leak and possibly prevention program for the Class 1 one Cono/CETNA seal, are adequately carbon steel components as identified in addressed and that the Boron deposits the Class 1 AMRRs.

both in front of the reactor head shroud and behind the reactor head shroud are properly evaluated, cleaned and dispositioned.

CR-IP2-Visual examination of the RPV upper head As identified in the CR for the associated 2004-05803 CRDM penetrations is being performed per analysis contained in CR IP2-2004-5674, W/0 IP2-03-23245. Preliminary results "It appears that these deposits were have revealed the following conditions:

caused by either canopy seal weld leaks or conoseal leaks." (These leaks are 1. What appears to be new boric acid attributed to SCC as discussed in CR-deposits at CRDM penetration #30.

IP2-2004-05474 above.) The review of possibility of boric acid corrosion on external surfaces is consistent with the identification of the boric acid corrosion prevention program for the Class 1 carbon steel components as identified in the Class 1 AMRRs.

CR-IP2-While making weld repairs to a RTD The root cause of this condition was 2004-06179 location on RCS 24 Cold Leg an adjacent evaluated in CR-IP2-2004-6147. The thermocouple location was observed to be root cause was determined to have been leaking.

improper installation of the RTDs during 2R16. No aging effects were identified by this CR.

CR-IP2-While performing the monthly inspection of This CR indicates that the cause of this 2004-06781 Unit 2 VC, we found on the seal table condition was seal leaks. Engineering valves L 13, L8, E9 have boron requests have been initiated to modify encrustation and an active minor leak with the high and low pressure seals to water visible. Also, valves J7, H4 N6, 8, eliminate this leakage at both IPEC L 1 0 have boron encrustations on them with Units." No aging effects were identified by no active leak visible.

this CR.

IPEC00186089

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 43 of 119 Table 3.1.2 Operating Experience Applicable to Class 1 Mechanical Systems Item Issue Evaluation CR-IP2-200109432-during VC inspection This CR indicates that these leakages 2001-09432 10/02/01, the leakages documented in CR were at seals or fittings. No aging effects 200108602 were still found to exist at the were identified by this CR.

seal table.

These were penetrations P9, L8 R8, H15, K12, L 10, P4 and 2 caps.

CR-IP2-While performing PI-M2 (VC online This CR indicates that these leakages 2003-06106 inspection) noted in the area of the seal were at seals or fittings. No aging effects table the following locations of fittings with were identified by this CR.

boron encrusted on & around them: N-2; N-13; N-14; M-7; L-15; L-13; H-15; F-3; E-9; B-13.

CR-IP2-During performance of PI-M2 monthly V.C.

This CR indicates that these leakages 2004-01782 inspection, N.P.O. found additional were at seals or fittings. No aging effects thimbles on seal table boron encrusted.

were identified by this CR.

These are B-6, D-12, J-8, K-12, cap to right of L-15, P-9, H-14, R-8 and P-4.

CR-IP3-Between January 1, 2000 and July 1, This is a record of industry experience as 2001-03019 2001, the industry reported approximately documented in the INPO SER and not 15 events involving leakage from reactor site specific events. Loss of material and coolant system (RCS) piping, penetrations, cracking are identified in the mechanical or components. Events reported included tools and other industry documents for leakage from control rod drive housings, stainless steel in treated borated water.

hot leg nozzles, etc.

CR-IP3-There are recent industry and NRC This is a record of industry experience 2002-04630 concerns with the RPV bottom head and not site specific events. Loss of penetrations as a potential leakage path material is identified in the mechanical due to issues at David Besse and Salem.

tools and other industry documents for carbon steel and stainless steel in indoor air. The review of boric acid corrosion on external surfaces is consistent with the identification of the boric acid corrosion prevention program for the Class 1 carbon steel components as identified in the Class 1 AMRRs.

CR-IP3-A visual inspection of the lower reactor This CR is an evaluation of some 2003-01659 vessel head did not reveal any signs of localized surface streaks on the vessel.

active leakage (i.e. no signs of moisture The CR indicates that, "these streaks are and no signs of boron). However thimble likely a result of light surface corrosion tubes Nos. 1, 10 and 45 had brownish caused by clean (i.e. non-borated) water streaks initiation at the tube to insulation since there was no evidence of boron junction.

deposits or any other RCPB degradation.

IPEC00186090

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 44 of 119 Table 3.1.2 Operating Experience Applicable to Class 1 Mechanical Systems Item Issue Evaluation CR-IP3-Inspection of the Reactor Vessel CRDM This CR indicates that the subject 2003-02115 canopy seal weld region performed as part staining is historical and has been of PT-R114A, identified the following extensively reviewed and evaluated The issues:

staining is the result of leakage or spillage from activities above the shroud

1. Nozzles #51, # 70, #49 and #56 were area. The fact that no boron is present identified as having brown stains on would indicate that the leakage or spillage approximately one third of the is not related to an RCS leak, or if so it is circumference.

historical in nature and any boric acid residue has been cleaned. With respect to the clamp at penetration #77, this is the penetration for Conoseal #4, which developed an RCS leak at the mechanical joint just prior to 3R11.

CR-IP3-During inspections in the cold leg of #32 As further evaluated in CR-IP3-2003-2003-02290 and # 34 steam generators 3 indications of 2225, "Three tubes had degradation that degradation was detected. For #32 SG the was detected in 1999 attributed to a degradation was sized at 20% for the tube historical anomaly of unknown origin.

in row 1 column 9, 28% for the tube in row Eight tubes had new degradation 1 column 66.

attributed to wear from sludge lance equipment used in 2001. See CR-IP3-2003-02288 for tube damage Root Cause attributed to sludge lance equipment."

Loss of material is identified as an aging effect requiring management for steam generator tubes. The ongoing steam generator integrity program tracks and monitors for degradation.

CR-IP3-The RPV bottom mounted Instrumentation The root cause analysis of this CR states 2005-01214 (BMI) head penetrations Visual that inspections performed on the lower Examination, being performed per W.O.

reactor vessel head indicated that minor IP3-04-12277, has identified indications of leakage has occurred over the years and tightly adhered staining I streaking of boric this leakage has resulted in boron streaks acid residue adjacent to a portion of the on the lower reactor vessel head. There head penetration.

was no indication of any through wall leaks (i.e. no popcorn-like boron residue) as a result of Primary Water Stress Corrosion Cracking (PWSCC) of either the BMI penetration tube or the attaching J-groove weld.

CR-IP3-During lSI ultrasonic examination of the six This CR states that the indication does 2005-01619 (6) RPV head meridional welds, recordable not exhibit any crack like characteristics indications were identified in weld # 2.

and is indicative of original fabrication Inspections on all six (6) welds are type reflectors such as slag. The complete.

observed indication meets the ASME Section XI, IWB 3000 requirements for acceptability and therefore no further action is required. There were no aging effects identified by this CR.

IPEC00186091

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 45 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-200100248-Safety Eng. from Williams The CR identifies spalled concrete in the 2001-Power contact the EH&S department today condenser area. The cause is determined 00248 1/9/01, about a piece of concrete which to be potential concrete placement disengaged from an 1-beam below 15' floor deficiencies during the construction of the by condenser 21. Area was barricaded off plant, a rather large concrete cover, and by Williams power workers. A piece of the continuous vibratory environment in concrete is lodged between a pipe and the the immediate vicinity of pumps. This is a wall, which has the potential of falling.

localized degradation and the CR does not identify any aging effects requiring management. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for concrete structures.

CR-IP2-200100329 - 13 and 14 WDST EHT The cause of water intrusion documented 2001-Chromolox controllers have a history of in the CR determined that the 00329 failures due to control cabinet water cabinet/interconnecting conduits in intrusion during periods of rain. Water is general are not properly compensated to detrimental to the Chromolox controllers resist the rain water. The conduits which which are composed of solid state/digital connect to the control cabinets are rusty components.

at the connections and may allow for water intrusion. Loss of material for galvanized steel (conduit) and carbon steel (control cabinet) are aging effects identified in the structural tools and the LRA.

CR-IP2-200100803 - During performance of PI-M2 As documented in the CR, the condition is 2001-(1-23-01), the operator noted that at 68' determined to be normal expected hairline 00803 where 23 feedwater line is supported by cracks on the reinforced concrete column installed stranded cable there is evidence support (buttress) for 23 feedwater line of cement cracking at the support bracket.

whip restraint that has no effect on the structural integrity of whip restraint of the column. As identified in the LRA, the aging management program manages aging effects on pipe whip restraint and concrete structures.

CR-IP2-200100846 - Several years ago the roof to The CR identifies a leaking roof in 2001-the PAB was repaired. But there is still Primary Auxiliary Building (PAB) which is 00846 areas that have problem with leaks when it caused by a deteriorated built-up roof.

rains, these areas are located on 80' PAB Roofing compounds are not addressed in (entrance to the VC).

the structural tools. Built-up roof materials are inspected as part of the roof decking and repaired or replaced as necessary.

Loss of material is aging effect identified in the LRA for roof decking.

IPEC00186092

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 46 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-200100981 - During the self-assessment of This CR does not identify aging effects 2001-the Fire Protection Program we determined but identifies a program enhancement 00981 that the radiant energy shielding (RES) that was completed. No new aging system associated with Alternate Safe effects were identified by this CR.

Shutdown System (ASSS) instrument cables for source range monitor and T-hot and T-cold temperature detector cables is not included in the Fire Protection Surveillance Tests.

CR-IP2-200101067-SAFETY CONCERN:

This CR identifies a leaking roof in the 2001-Hallway to Primary Auxiliary Building 01067 The hallway on 53' going up 80' PAB has a (PAB) due to cracks or other penetrations serious leak problem when it rains. There in the asphalt (i.e., fence posts) that may is constantly a mop and bucket staged in allow for water intrusion through the roof.

the hallway, which looks unsightly, but most Roofing compounds are not addressed in important, it's a safety issue.

the structural tools. Built-up roof materials are inspected as part of the roof decking and repaired or replaced as necessary.

Loss of material is aging effect identified in the LRA for roof decking.

CR-IP2-200103602 - 53' Banana hallway Health This CR identifies a leaking roof. Roofing 2001-Physics storage area has water leaking compounds are not addressed in the 03602 through the ceiling onto electrical panels.

structural tools. Built-up roof materials are There are open wires hanging from areas inspected as part of the roof decking and where equipment has been removed.

repaired or replaced as necessary. Loss About half of the lights in the room do not of material is aging effect identified in the work.

LRA for roof decking.

CR-IP2-200104100 - Water running down a wall This CR identifies a leaking roof. Roofing 2001-from the overhead into a contaminated compounds are not addressed in the 04100 area - Trying to regain area, but the roof structural tools. Built-up roof materials are leak is preventing the area from being inspected as part of the roof decking and released as a clean area. Location is 1 00' repaired or replaced as necessary. Loss NSB - Unit #1.

of material is aging effect identified in the LRA for roof decking.

CR-IP2-200104150 - Within the Service Water This CR identifies corrosion on base 2001-(SW) strainer pit area, some of the support plates and associated anchor bolts 04150 base plates and associated anchor bolts supporting the conduit box. Loss of and nuts show signs of corrosion. In material (LM) due to corrosion is an aging particular, corrosion is identified for the effect identified in the structural tools for base plates supporting the conduit boxes.

steel. Accordingly, LM is an aging effect identified in the LRA for steel (specifically the conduit supports including base plates and anchor bolts).

IPEC00186093

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 47 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-200104199-While performing SOP 11.5 This CR identifies rust (corrosion) on 2001-(space heating and winterization) found louvers. Loss of material (LM) due to 04199 manual louvers for 22 FATU rusted in place corrosion is an aging effect identified in and could not verify position. Louvers are the structural tools for steel. Accordingly, in overhead off of catwalk near roof.

LM is an aging effect identified in the LRA for steel (specifically the louvers).

CR-IP2-200104483 - ****SAFETY CONCERN****

This CR identifies extensive corrosion on 2001-stairwell (stringers). Loss of material due 04483 The stairwell leading from the 15' el screen to corrosion is an aging effect identified in well house to the sodium hypochlorite tank the structural tools for steel. Accordingly, pit is CLOSED. Several of the metal steps LM is an aging effect identified in the LRA have cracked in half. There is no safe way for steel (specifically the ladders).

to use the stairwell.

CR-IP2-200105412 - Water was observed to be This CR identifies a piping leak into an 2001-leaking from the ceiling at HP-1 in the electrical box for an emergency light. The 05412 vicinity of emergency light ELUI-1. An source of the leak was identified as a Unit arcing sound was heard and the emergency 1 city water line. This line item has been light illuminated. This appeared to indicate copied to Table 3.1.1 for evaluation along an interruption of the light's normal AC with other OE applicable to non-class 1 power supply. [NOTE: further information mechanical systems.

is provided in PCRS CR-IP2-1998-09094]

CR-IP2-200105695 - There is a crack in the base of This CR identifies minor delamination of a 2001-the concrete wall in the south west corner thin layer of concrete over a small area 05695 of the EDG building below the floor grating.

that does not affect the structural integrity of the wall. The most plausible root/apparent cause of the crack/delamination area is a potential deficiency during the initial placement and curing of the concrete wall. The vibratory environment of the EDG could also act to expand initial imperfections in the concrete wall cover. This CR does not identify aging effects requiring management. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for concrete structures.

IPEC00186094

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 48 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-200105698 - There are cracks in the This CR identifies hairline cracks on the 2001-concrete slab over the buried EDG fuel concrete slab over the buried EDG fuel 05698 tanks. They were identified and evaluated tanks. The cause is determined to be during a walkdown in April, 2001 by Civil minor settlement which is expected.

Engineering.

These hairline cracks do not prevent the slab from performing its intended function.

This CR does not identify aging effects requiring management. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for concrete slabs.

CR-IP2-200106768-While doing test PT-M55 This was minor grout repair of a 2001-condition found the grout around the doorframe and therefore the CR does not 06768 doorframe cracking and falling out, which is include a root cause analysis. This was a part of the test criteria. Refer to W.O. NP-localized cracking of a grouted doorframe 01-22198.

that was likely caused by mishandling (frequently slamming the door) or installation deficiencies (lack of good bound between the grout and door frame) specific to this door. This CR does not identify an aging effect requiring management.

CR-IP2-200107 483 - During engineering walkdown This CR identifies cracked and spalled 2001-the curbs which enclose the circulating curbs around the manholes located on the 07483 water pipe tunnel manholes were observed east side of the trailers on the dock. The to have cracked and spalling concrete.

purpose of these concrete curbs is for personnel safety and to protect the manholes from vehicles traffic and debris.

Over time, they are subject of physical impact by moving objects and consequently they are nicked, cracked, and spalled. Although the condition of these curbs identified by this CR does not effect the intended function of the manholes, they are repaired as necessary. This CR does not identify an aging effect requiring management.

However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for manholes.

IPEC00186095

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 49 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-200108728 - Box on backside of 24 EHT This CR identifies an aging effect (loss of 2001-control cabinet is severely corroded. Box material due to corrosion) on a steel 08728 cover cannot be mounted to box as screw electrical enclosure. Loss of material due holes on box have disintegrated.

to corrosion is an aging effect identified in the structural tools for steel. Accordingly, LM is an aging effect identified in the LRA for steel (specifically for steel electrical panels and enclosures).

CR-IP2-200109353-While removing EHT race This CR identifies an aging effect (loss of 2001-from 21 CWP seal water line, observed material due to corrosion) on steel pipe 09353 several carbon steel u-bolts severely support. Loss of material due to corrosion corroded in direct contact with stainless is an aging effect identified in the steel piping. I am unable to provide a line structural tools for steel. Accordingly, LM number because print A208368-29 does is an aging effect identified in the LRA for not give this information.

steel (specifically for pipe supports).

CR-IP2-200109973 - 80' Airlock Exterior door has a This CR identifies a deteriorated seal on 2001-leak on the upper right-hand side as you an airlock door. Cracking and change in 09973 look at the door from the PAB. It was material properties are aging effects noticed when the CCR had a high air flow identified in the structural tools for on Weld Channel #2. The weld channel elastomers. Accordingly, cracking and was maintaining 52.5 pounds, which is change in material properties are aging above its spec.

effects identified in the LRA for elastomers (specifically for lock seals).

CR-IP2-200201933 - In the Central Control Room This CR identifies a degraded fire barrier 2002-(in the north east corner), where the east caused by installation deficiency. The fire 01933 wall ties into the brick wall around the barrier was not sealed at portion of wall to locker room, there is a ?"X 20" gap in the floor interface (behind the false wall floor. The gap is through to the Cable panels). This CR does not identify an Spreading Room.

aging effect that requires management.

CR-IP2-200202401 - Replace sump pump base This CR identifies an aging effect (loss of 2002-plate. Plate is severely rusted. Large material due to corrosion) on the pump 02401 chunks of rust are falling off.

base. Loss of material due to corrosion is an aging effect identified in the structural tools for steel. Loss of material (LM) due to corrosion is an aging effect identified in the structural tools for steel. Accordingly, LM is an aging effect identified in the LRA for steel (specifically for base plates).

IPEC00186096

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 50 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-200204224-Industrial Safety performed a This CR identifies an area in the screen 2002-walk down in the Unit 1 Screen well House well ceiling where concrete has become 04224 5' and found:

loose (spalled) causing rebar to be exposed and develop surface rust. This is Loose and spalling concrete in overhead an initial construction issue as a result of south east side. No evidence of concrete insufficient concrete cover allowing the on floor, able to see rusted rebar's in bar to exfoliate, expand and pop the ceiling.

concrete cover. The condition was corrected and determined to have no effect on the structure. This has been identified since baseline monitoring per the Structures Monitoring Program (SMP) in 1996. This condition does not identify an aging effect requiring management.

However, as identified in the LRA, the structures monitoring program confirms absence of aging effects for screen well structures.

CR-IP2-200205637-During the Service Water lSI, Same as CR-IP2-2002-04224 (discussed 2002-it was identified that the ceiling and support previously), this CR identifies an area in 05637 structure for the Service Water Pump Pit is the screen well ceiling where concrete has severely degraded. Large chunks of become loose (spalled) causing the rebar cement were found on the plastic floor to be exposed and develop surface rust.

grating.

This is an initial construction issue as a result of insufficient concrete cover allowing the bar to exfoliate, expand and pop the concrete cover. The condition was corrected and determined to have no effect on the structure. This has been identified since baseline monitoring per the Structures Monitoring Program (SMP).

However, as identified in the LRA, the structures monitoring program confirms absence of aging effects for screen well structures.

CR-IP2-During inspections of the porcelain This CR identifies rusted plate and 2002-insulating standoffs on the lsophase buses missing bolt on the porcelain standoffs on 09907 in the transformer yard, found one with a the isophase bus in the transformer yard.

severely rusted baseplate and a missing This line item has been copied to Table bolt. This standoff is on the phase closest 3.1.4 for evaluation along with other OE to 21 main transformer.

applicable to electrical, instrumentation, and control components.

IPEC00186097

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 51 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-CR IP2 2002-10052 concerning reactor This CR requests evaluation of long term 2002-cavity leakage did not address the following effect of boric acid on concrete and rebar 10610 issues:

due to discovery of a borated water leak (an event) from the cavity liner during

1) Evaluate/investigate the structural long refueling. The evaluation indicates that, term effects of the boric acid on the since the boric acid leakage episodes are concrete and carbon steel rebar within the limited to the duration of the cavity concrete.

flooding, the overall exposure of the concrete to boric acid is significantly shorter than that employed in the tests, i.e., weeks or months versus years. As such, it is concluded that the effect of the boric acid leaks is limited in terms of both extent and depth of penetration in the concrete. Thus, the effect of this event (borated water leak) was determined to be minimal on concrete and reinforcing steel.

However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects on concrete structures (specifically the refueling canal floor slab and walls).

CR-IP2-There is a small leak in the staircase tunnel This CR identifies a small leak in Unit 1 2002-between the 53' elevation in the Nuclear staircase. This is determined to be a 11289 Service Building and the 80' elevation in minor leak causing safety hazard and not the Primary Auxiliary Building. The water an operability issue. The CR was closed is dripping along the wall on the 53' level to work order IP2-02-65333 which is still and onto the floor.

pending (most likely due to low priority).

The source reported by this CR is undetermined (piping leak or roof leak).

In the case of a leaking roof, roofing compounds are not addressed in the structural tools. Roofs are inspected as part of the roof decking under structures monitoring program and repaired or replaced as necessary. Loss of material is aging effect identified in the LRA for roof decking.

CR-IP2-27 Traveling Screen control panel door This CR identifies an aging effect (loss of 2002-latches has a door latch that has rusted off.

material due to corrosion) on steel control 11643 panel door. Loss of material (LM) due to corrosion is an aging effect identified in the structural tools for steel. Accordingly, LM is an aging effect identified in the LRA for steel (specifically for steel panels and enclosures).

IPEC00186098

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 52 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-In the Zurn strainer pit a uni-strut support This CR identifies loss of material on 2003-for a junction box to DPI-50028, at 23 galvanized steel support (including base 00396 SWPS, is so severely corroded that it has plate and anchor bolts) in the Zurn separated from the floor mounted base strainer pit for electrical junction box. Loss plate. The junction box which is not of material (LM) due to corrosion is an labeled has conduits E1/70 and E1/145 aging effect identified in the structural attached to it.

tools for galvanized steel exposed to fluid.

Accordingly, LM is an aging effect identified in the LRA for galvanized steel in fluid environment (specifically the conduit supports including base plates and anchor bolts).

CR-IP2-The Unit Two Refueling Cavity Liner has This CR identifies IP2 refueling cavity 2003-experienced cracks on numerous leakage through the stainless steel liner 00682 occasions. The SOER 02-4 investigative when the cavity is filled during the team has discovered that the cracks have refueling outages. The cavity is filled been repaired several times. Yet, cracks during the refueling activities, and other continue to appear.

times it remains dry. The source of the leak was found to be a pinhole leak on weld area, and repaired successfully. The cause of pinhole was determined to be a poor workmanship during original welding of the liner plate which had gone unnoticed. The repaired area and other suspect weld areas of the liner plate have been inspected (visual and UT) and tested (vacuum test) with satisfactory results.

Other welds were found to be of good quality and free of defect.

Industry operating experience from testing of reinforced concrete in a fuel pool wall exposed to borated water for 18 months due to an undetected leak at Florida Power & Light indicates such a leak has no significant effect on the concrete or rebar.

This CR does not identify an aging effect requiring management. However, as identified in the LRA, water chemistry control -primary and secondary is used to manage aging effects of refueling cavity (canal) liner plate. The structures monitoring program confirms the absence of significant aging effects on refueling cavity concrete structure.

IPEC00186099

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 53 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-The concrete base of 21 Condensate Pump This CR identifies a minor leakage from 2003-is weeping water. The water is reacting with the condensate pump that was rusting the 02031 steel and causing rust to deposit on the steel around the pump and also causing white floor below. This is also causing a potential slipping hazard. The leakage no potential slipping hazard that needs to be longer exists. Loss of material (LM) due to evaluated.

corrosion is an aging effect identified in the structural tools for steel. Accordingly, LM is an aging effect identified in the LRA for steel (specifically for component supports).

CR-IP2-NRC IN 2003-008, attached, notes that This CR documents a review of NRC 2003-water used during a fire test penetrated Information Notice regarding problems 05807 through a concrete floor that had numerous caused by placing anchor bolts too close "hairline" cracks and spalls caused by together. This CR does not identify aging expansion anchors placed too close effects requiring management.

together.

CR-IP2-During the performance of the App R Fire This CR identifies surface cracks on fire 2004-Barrier Seal inspection PI-V17-8, four (4) barriers constructed of concrete blocks.

01506 penetrations were indentified as having The deficiencies were corrected under cracks on the exposed surface. These work orders. Cracking is an aging effect cracks were not thru wall cracks, because identified in the structural tools and the the opposite end of each penetration were LRA for concrete blocks.

examined.

CR-IP2-Manhole 21 on the Intake Structure of unit The CR identifies a "damaged" manhole 2005-2 was identified to be damaged at the hub cover hub on the intake structure which 00711 area which could allow moisture into this could allow water intrusion into the manhole. This manhole is a splice box for manhole. The cause of damage is not Service Water Pump power feeds and must provided in the CR, however in case this be repaired.

condition is attributed to an aging effect, loss of material (LM) due to corrosion is an aging effect identified in the structural tools for steel. Accordingly, LM is an aging effect identified in the LRA for steel (specifically covers).

IPEC001861 00

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 54 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-THIS IS A SOER 02-4 RESPONSE ISSUE This CR identifies IP2 refueling cavity 2003-leakage through the stainless steel liner 00959 IP-2 has a long-term degradation issue with when the cavity is filled during the leakage from the Refueling Cavity Liner.

refueling outages. The cavity is filled The liner has experienced cracks on during the refueling activities, and other numerous occasions. The cracks have times it remains dry. The source of the been repaired several times, but the cracks leak was found to be a pinhole leak on continue to appear.

weld area, and repaired successfully. The cause of pinhole was determined to be a poor workmanship during original welding of the liner plate which had gone unnoticed. The repaired area and other suspect weld areas of the liner plate have been inspected (visual and UT) and tested (vacuum test) with satisfactory results.

Other welds were found to be of good quality and free of defect.

Industry operating experience from testing of reinforced concrete in a fuel pool wall exposed to borated water for 18 months due to an undetected leak at Florida Power & Light indicates such a leak has no significant effect on the concrete or rebar.

This CR does not identify an aging effect requiring management. However, as identified in the LRA, water chemistry control -primary and secondary is used to manage aging effects of the refueling cavity (canal) liner plate. The structures monitoring program confirms the absence of significant aging effects on the refueling cavity concrete structure.

CR-IP2-21 HDTP concrete base is spalling. Large This CR identifies spalling of concrete pad 2003-cracks are noticeable in the concrete pad.

under non safety related equipment (21 02033 This condition needs to be evaluated HDTP) in the turbine building. The CR before it becomes worse.

was closed to WO IP2-03-05253. This equipment is prone to vibration, thus the spalling is a localized occurrence due to a design deficiency at this location and not due to an aging effect. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects on equipment concrete pads.

IPEC001861 01

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 55 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-22 HDTP concrete base is spalling. There This CR identifies spalling of concrete pad 2003-are large cracks in the concrete base that under non safety related equipment (22 02034 need to be evaluated before they become HDTP) in the turbine building. The CR worse.

was closed to WO IP2-03-05254. This equipment is prone to vibration, thus the spalling is a localized occurrence due to a design deficiency at this location and not due to an aging effect. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects on equipment concrete pads CR-IP2-The TSC Diesel Room has numerous roof This CR identifies a leaking roof in the 2003-leaks that are depositing on the floor and Technical Support Building (TSC) diesel 02288 equipment below. Lime is also leaching out room. Roofing compounds are not of the cement and creating an eyesore on addressed in the structural tools.

Roofs the equipment in the room and floor.

are inspected as part of the roof decking and repaired or replaced as necessary.

Loss of material is aging effect identified in the LRA for roof decking.

As for lime deposit, loss of bond (loss of strength) for concrete due to leaching of calcium hydroxide is evaluated in the structural tools and the LRA. Due to design and construction of main concrete structures at IPEC in accordance with ACI 318, loss of bond due to leaching of calcium hydroxide is insignificant.

However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects on concrete structures.

CR-IP2-The Appendix 'R' panels between the This CR identifies cracking of an angle 2003-emergency diesel generators show cracks iron leg that supports 6 feet high Appendix 03195 in the vertical angle iron about eleven

'R' panel in vertical position. The cracking inches above the floor. This condition is determined to be due to improper affects both sets of panels and is readily design where the angle iron leg was apparent in the outermost two vertical overstressed by not being properly supports of each.

braced. The condition was corrected by adding braces. This CR does not identify an aging effect requiring management.

IPEC001861 02

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 56 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-Fuel Handling Building Roof leaked This CR identifies leaking roof in IP1 Fuel 2003-significantly onto 70 foot elevation near the Handling Building which is not within 03769 main Chem Systems Building hallway. The scope of license renewal. Roofing rain impinged upon the Unit 1 Vapor compounds are not addressed in the Containment Fire Detection Panel and structural tools. Roofs are inspected as entered the cabinet causing various part of the roof decking and repaired or erroneous alarms.

replaced as necessary. Loss of material is an aging effect identified in the LRA for roof decking.

CR-IP2-Unit 1 East Spent Fuel Pool (Empty)

This CR identifies surface degradation on 2004-Surface Degradation -As part of the U1 IP1 spent fuel pit (SFP), which is not in 00338 Stabilization Project, the empty east spent scope of the license renewal. This pool fuel pool concrete walls and floor were and its coating are not similar to the IP2 recently inspected to categorize their or IP3 SFPs. This CR does not identify present condition.

any aging effects that are applicable to IP2 or IP3 structures that are subject to aging management review (STAMR).

CR-IP2-The south side of the Containment dome in This CR identifies an area on the IP2 2004-the alley between the Fan building and VC containment where concrete had spalled, 01347 about 25 feet up is spalling in about 6-7 exposing reinforcing steel showing rust.

places. The rebar is exposed to the This condition was noted during the 2000 elements and is showing signs of rust. The IWL inspection. The 2005 IWL inspection openings into the concrete are about 12-14 found little or no changes of the condition inches.

observed in 2000. The spalls occur at locations where cadweld sleeves have insufficient concrete cover, attributed to original installation deficiency. Cadweld splices have diameters larger than the rebar, thus they have the least amount of concrete cover. The rusting is not active, and the spalls are in an area where the rebar stresses are low. This CR does not identify an aging effect requiring management. However, as identified in the LRA, the structures monitoring program confirms the absence of significant aging effects on containment concrete structure.

CR-IP2-Rain water is leaking through the roof onto This CR identifies a leaking roof in the 2004-the cable tray and subsequently onto the Primary Auxiliary Building (PAB). Roofing 03197 floor inside the east door of the MCC 26AA compounds are not addressed in the

& 26BB room. These MCCs control various structural tools. Built-up roof are inspected safety related equipment and the water on as part of the roof decking and repaired or the floor is a personnel safety concern.

replaced as necessary. Loss of material is an aging effect identified in the LRA for roof decking.

IPEC001861 03

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 57 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-The IP2 Reactor Cavity has a history of This CR identifies IP2 reactor cavity 2004-serious leakage through the stainless steel leakage through the stainless steel liner 05180 liner when the cavity is filled during refuel when the cavity is filled during the outages. The cavity liner is made from refueling outages. The cavity is filled stainless steel plates plug welded to during the refueling activities, and other structural steel and seam welded together.

times it remains dry. The cavity has been known to be leaking since the early 1990's. Engineering evaluation of the leakage determined that the liner seam, plug and structural attachment welds on the west wall were the most likely cause of the leakage.

The cavity is used for fuel handling operations during refueling outages. The damage to the liner is determined to have occurred during previous refueling outages due to poor cleanliness and maintenance control. This includes use of improper material and tools (wire brush contaminated with carbon steel and containing chloride coming in contact with stainless steel), as well as damage (cut) into the liner plate when removing (cutting out) the temporary attachments off the liner.

The cavity liner has gone through numerous inspections and tests. Repair attempts have not completely stopped the leak, which occurs only during flood up of the cavity during refueling outages (all other times the cavity is dry). The leak rate has lessened due to the repair attempts. Repair efforts are continuing, through the application of various permanent and temporary repairs.

Industry operating experience from testing of reinforced concrete in a fuel pool wall exposed to borated water for 18 months due to an undetected leak at Florida Power & Light indicates such a leak has no significant effect on the concrete or rebar.

However, as identified in the LRA, the structures monitoring program confirms the absence of significant aging effects on the reactor cavity concrete structure.

IPEC001861 04

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 58 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-Fire barriers going from the Baling station This CR identifies potential degradation of 2005-to 21 Charging pump cell are showing signs fire barrier penetration seals. Further 01431 of degradation and should be evaluated.

evaluation documented in the CR The Fire resistant material used to patch indicates the condition to be cosmetic in openings in the horizontal chases is starting nature involving minor surface to fall out leaving very small cracks.

imperfections from the original installation, and not an aging effect.

However, cracking and changes in material properties are aging effects identified in the structural tools for elastomer seals. Accordingly, as shown in the LRA, cracking and change in material properties are aging effects for fire barrier penetration seals and are managed by the fire protection program.

CR-IP2-This CR initiated by CA&A to copy a This CR identifies a hairline crack on the 2005-manual CR, which is attached to the IP2 spent fuel pool (SFP) south concrete 03557 suggested action section below with the wall. The condition was visually inspected original paper operability review.

and evaluated by design engineering. The crack was determined to be typical A hairline crack several feet in length was shrinkage crack developed during post-found at approximately 60 foot level of Unit installation concrete curing (this is not an 2 spent fuel pool.

unexpected condition in reinforced concrete structures). The condition was determined to be non-threatening to structural integrity of the SFP structure.

Concrete crack has been temporarily covered with a stainless steel collection box and the drain is routed to the PAB for periodic monitoring.

This CR does not identify an aging effect.

However, as identified in the LRA, structures monitoring program confirms absence of significant aging effects on SFP concrete structure.

IPEC001861 05

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 59 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP2-A remote visual examination of the Spent This CR identifies three potential leakage 2005-Fuel Pool liner identified three potential paths on IP2 spent fuel pool (SFP) 04433 leak paths located on the South West stainless steel liner plate welds. These vertical corner weld between approximately three and three additional indications were 17' and 20' from the top of the pool.

vacuum box tested with no indication of thru wall leakage. In addition these six locations were coated as preventive measure.

The evaluation of the root cause of this CR was completed under CR-IP2-2005-4787. Per CA0001 it was determined this was poor workmanship during original welding of the liner plate which had gone unnoticed.

Historically, a pinhole leak was found in the early 1990's and repaired successfully. The cause of the pinhole leak was determined to be poor workmanship during the re-rack modification, specifically during welding and removal (cutting) activities of temporary attachment to the liner plate.

The repaired area and other suspect weld areas of the liner plate have been inspected (remote) and tested (vacuum box) with satisfactory results.

Industry operating experience from testing of reinforced concrete in a fuel pool wall exposed to borated water for 18 months due to an undetected leak at Florida Power & Light indicates such a leak has no significant effect on the concrete or rebar.

This CR does not identify an aging effect.

However, as identified in the LRA, water chemistry control - primary and secondary and monitoring of SFP level per Technical Specifications are used to manage aging effects of the refueling cavity (canal) liner plate. The structures monitoring program confirms absence of significant aging effects on SFP concrete structure.

IPEC001861 06

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 60 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP3-During a QA inspection an electrical cable This CR identifies a degraded electrical 2001-penetration was discovered to be in a penetration seal. Cracking and changes in 01575 degraded condition. An evaluation needs material properties are aging effects to be performed to determine operability.

identified in the structural tools for The penetration is located behind panel elastomer seals. Accordingly, cracking SFF.

and change in material properties are aging effects identified in the LRA for elastomers (specifically for electrical penetration sealant).

CR-IP3-During a QC inspection of an electrical This CR identifies a degraded electrical 2001-penetration associated with DCP 00-005 penetration seal. Cracking and changes in 01578 (worked under WR 99-05022-02),

material properties are aging effects penetration # 1993 (in Cable Spreading identified in the structural tools for Room) was found to have an approximately elastomer seals. Accordingly, cracking 1/4" diameter pre-existing hole in it.

and change in material properties are aging effects identified in the LRA for elastomers (specifically for electrical penetration sealant).

CR-IP3-The cinderblock wall section near MCC-L, This CR identifies a crack on concrete 2002-off of Column Bb in the 15' Admin Building block wall (masonry wall). Cracking is an 00726 Warehouse Area, is able to move a small aging effect identified in the structural amount if pushed. It appears that the tools for concrete masonry structures.

concrete joint that bounds the wall to the Accordingly, cracking is an aging effect building support column (Bb) is cracked.

identified in the LRA for masonry walls.

CR-IP3-In the passage from the 33' turbine building This CR identifies cracking of the floor 2002-to the ABFP building the floor coating is coating in the passageway. Although not 00929 cracked and broken with portions of the discussed in the CR, cause is most likely concrete missing.

due to heavy traffic and equipment transportation. The purpose of floor coating is typically to facilitate decontamination, enhance appearance and efficiency of the area lighting. Over time however, these coatings are subject to abrasion due to falling or rolling objects, and subsequently they are damaged. It is not unusual for concrete surface beneath the coating to also get chipped or become dislodged during this process. The area is repaired and recoated. This CR does not identify an aging effect requiring management.

However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for concrete floors.

IPEC001861 07

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 61 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP3-The 1-beam steel work along both sides of This CR identifies an aging effect (loss of 2002-the discharge canal at the discharge canal material) for carbon steel 1-beam on 02170 bridge is deteriorated, rusted through in discharge canal bridge. Loss of materials many large areas, and bent.

(LM) due to corrosion is an aging effect identified in the structural tools for carbon steel. Accordingly, LM is an aging effect identified in the LRA for structural steel.

CR-IP3-During replacement of the 31 Discharge This CR identifies an aging effect (loss of 2002-Canal Oil Boom, the south rail beam was material) for carbon steel beam in 02836 found severely corroded approximately 8" discharge canal rail. Loss of materials below the water line at low tide, causing the (LM) is an aging effect identified in the oil boom slider to disengage from the track.

structural tools for carbon steel.

Accordingly, LM is an aging effect identified in the LRA for structural steel.

CR-IP3-32 Diesel/Generator Foundation has a This CR identifies a hairline shrinkage 2002-vertical crack visible from the east side crack that developed during the initial 03236 looking west, below the deck plate about curing period and it is common for centerline of the diesel. Oil is leaking concrete structures. This condition does through the crack about 1' off the bottom of not affect the integrity of the structure.

foundation.

This CR does not identify an aging effect requiring management. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for concrete floors (and foundations).

CR-IP3-During Area Ownership Walkdown the This CR identifies deterioration (cement 2002-following deficiencies were identified:

crumbled) of the sewage pump station 04750 cement housing. The condition and

[Item (1) is evaluated in Table 3.1.1]

quality of such building is not representative of the major concrete

2) On 15' at the Sewage Pump Station the structures at the site. Such buildings are cement housing was found crumbling and not of quality construction and are is now exposing rebar.

exposed to extreme harsh conditions.

This CR does not identify an aging effect requiring management. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for major concrete structures.

CR-IP3-A roof leak exists close to 1-beam above R-This CR identifies a leaking roof in the 2003-27 on the PAB 80' elevation.

Primary Auxiliary Building (PAB). Roofing 00525 compounds are not addressed in the structural tools. Built-up roof materials are inspected as part of the roof decking and repaired or replaced as necessary. Loss of material is an aging effect identified in the LRA for roof decking.

IPEC001861 08

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 62 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP3-During operator rounds, what appears to be This CR identifies a leak at construction 2003-a through wall leak was noted in the joint of the outfall structure caused by 00888 OUTFALL structure just past the point failure to provide an adequate seal during where the wall makes the turn and runs previous repair work (MOD 93-3-304, parallel to the river (approx. 10 feet past "Discharge Canal Wall and Gate Repair).

bend).

This CR does not identify an aging effect that requires management.

CR-IP3-An lSI visual examination of Support SW-This CR identifies an aging effect (loss of 2003-H&R-11 E-31 as shown on INT-3-3413, material due to corrosion) on pipe support 01826 Rev.2. Found that the anchor bolts were anchor bolts. Loss of materials (LM) is an corroded. This is a recordable indication.

aging effect identified in the structural The support is a riser type ring support tools for carbon steel. Accordingly, LM is anchored at 3 places at the base of 35 an aging effect identified in the LRA for FCU.

carbon steel (specifically anchor bolts).

CR-IP3-Attn: unit #3 turbine roof has large areas This CR identifies a leaking roof. Roofing 2003-where the tar coating is degraded ; these compounds are not addressed in the 03570 areas are dried air pockets that collapse structural tools. Built-up roof materials are while walking over; we will lay down 3/4 "

inspected as part of the roof decking and plywood to prevent damaging the repaired or replaced as necessary. Loss remaining integrity of the roof coating.

of material is aging effect identified in the LRA for roof decking.

CR-IP3-During the performance of PT-R1 00, "Fire This CR identifies a fire barrier that did 2003-Barrier Inspection", 2 fire stops were found not meet the design criteria due to 03681 (1684 and 1709) in the floor of the control improper installation. This condition was room that did not meet design. Fire stop found during the routine fire barrier 1684 exhibited a crack at the edge of the inspection.

stop.

The CR does not identify an aging effect that requires management.

CR-IP3-While conducting a Plant Tour, I This CR identifies loss of material on the 2004-discovered a hole approximately 6x2" at grade concrete (walkway) around the 03242 the south end of the Unit 2 discharge canal grating in the discharge canal area. The directly opposite the Unit 3 Polisher cause appears to have been due to building. This hole was apparently caused chemical (salt) attack (most likely due to by the erosion of the cement near the use of salt on walkways during winter).

grating.

This CR is a location-specific concern, and does not indicate a generic aging effect. However, as identified in the LRA, the structures monitoring program confirms absence of significant aging effects for the discharge canal concrete structure.

CR-IP3-Cracks are visible on the north and west This CR identifies a crack on concrete 2004-side of the unit 3 heater bay on the outside block wall (masonry wall). Cracking is an 04023 near the corner. It is possible that bricks aging effect identified in the structural may come loose and fall.

tools for concrete masonry structures.

Accordingly, cracking is an aging effect identified in the LRA for masonry walls.

IPEC001861 09

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 63 of 119 Table 3.1.3 Operating Experience Applicable to Structures and Structural Components Item Issue OE Evaluation CR-IP3-NRC inspector found support under valve This CR identifies corrosion of steel pipe 2005-SWN-1-4 more than 50% corroded away support in intake structure. Loss of 01728 and expressed concern whether the material (LM) due to corrosion is an aging corroded condition is acceptable and effect identified in the structural tools for covered by the evaluation done in 2003, steel. Accordingly, LM is an aging effect calculation IP3-CALC-SWS-02022, DRN-identified in the LRA for steel (specifically 04-00917.

pipe supports).

CR-IP3-During a walkdown of the Unit 3 Intake This CR identifies spalled concrete in the 2005-Structure with the Ultimate Heat Sink NRC intake structure. The deteriorated 03993 Inspector, two pieces of spalled concrete condition was previously identified during (approximately 1" diameter x 1 /2" thick) structure monitoring walkdown. The and some rust I scale were found on top of condition was determined not to be an the mat-covered grating on the 5' elevation.

operability concern or an aging effect.

Instead, this was a poor design where the reinforcement, being too close to the surface, has expanded and become exposed causing concrete to spall. The condition was corrected. However, as identified in the LRA, SMP confirms absence of significant aging effects for intake structure concrete.

IPEC0018611 0

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 64 of 119 Table 3.1.4 Operating Experience Applicable to Electrical, Instrumentation, and Control Components Item Issue OE Evaluation CR-IP2-200104107 - During the performance of This is plant OE on an active component, 2001-04107 corrective maintenance in the Pressurizer which is not subject to aging management Control Bank Heater cubicle in the electric review. However, this is an example of pen area, we found that two 480V reduced insulation resistance due to conductors in the cubicle have cracked cracking of conductor insulation exposed insulation and at least one of them is to adverse localized environments cracked through where you can see the identified in the electrical handbook. This conductor.

aging effect for passive commodities will be managed by the Non-EQ insulated cables and connections program.

CR-IP2-200104811 -Assigned to inspect the strip This is plant OE on an active component, 2001-04811 heaters on 21 emergency diesel which is not subject to aging management generators. Found all 9 strip heaters had review. However, this is an example of burned or cracked wiring.

reduced insulation resistance due to cracking of conductor insulation exposed Insulation on wiring was severely degraded.

to adverse localized environments We replaced 16 jumpers and 2 feed wires identified in the electrical handbook. This on strip heaters.

aging effect for passive commodities will be managed by the Non-EQ insulated cables and connections program.

CR-IP2-During inspections of the porcelain NOTE: This CR was originally evaluated 2002-09907 insulating standoffs on the lsophase buses in Table 3.1.3 "Operating Experience in the transformer yard, found one with a Applicable to Structures and Structural severely rusted baseplate and a missing Components."

bolt. This standoff is on the phase closest to 21 main transformer.

This CR identifies rusted plate and missing bolt on the porcelain standoffs on the isophase bus in the transformer yard.

The isophase metal enclosed bus (MEB) does not have a license renewal intended function, so it is not subject to aging management review. However, this CR identifies OE for a component similar to the non-segregated MEB that has a license renewal intended function. The rusted plate and missing bolt on the porcelain standoffs is the isophase bus internal bus bar insulator, which also provides support for the bus bar. Loss of material due to corrosion is an aging effect identified in the electrical tools for MEB. Accordingly, as shown in the LRA, aging effects (loosening of bolted connections and loss of material for steel) on MEB are managed by the electrical metal enclosure bus inspection program.

IPEC00186111

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 65 of 119 Table 3.1.4 Operating Experience Applicable to Electrical, Instrumentation, and Control Components Item Issue OE Evaluation CR-IP2-Found all of the bolts less then hand tight This degraded connection could have 2004-05748 on one bus joint on 21 EDG during pm wo been the result of incorrect installation ip2-02-33308. After torquing the bolts the (possibly over-torquing, or it could have micro ohm drop across the joint was 9 micr been related to thermal cyclic loads ohms. All other joints checked to this point associated with loading the EDG.

were 3 to 5 micro ohms Loosening of bolted electrical connections is described in the EPRI Electrical Handbook and identified in the IPEC LRA.

CR-IP2-During the cubicle PM on 52/CRF1 a small This is plant OE on an active component, 2005-03981 hairline crack was found in the B phase which is not subject to aging management bottom insulator between the stud and the review. However, this is an example of a top left bolt.

maintenance/installation issue that caused reduced insulation resistance due to cracking of an insulator for stress applied during installation. There are no aging effects identified in the electrical handbook for these types of insulators.

This is an example of plant OE that supports the industry OE, and the OE search for IP2 and IP3 did not provide OE different to the industry OE.

CR-IP3-The maintenance department opened The manholes were pumped out, and the 2001-04270 several manholes at the request of the exact condition was investigated. In resident NRC inspector. The 2 manholes addition an investigation was performed CR-IP3-on the river road, SE corner of the intake to identify Cat. I and Cat. M cables, and 2002-00019 building and 2 manholes in the transformer cable splices in manholes where water yard were found partially flooded with intrusion is a problem. Additional water, and several electrical cables were manholes were opened as part of this submerged in water.

investigation. Manholes inspections were added to the PM program.

NRC Inspectors have identified a Green Finding for lack of monitoring for water The second CR was for documenting the intrusion or degradation of underground Green Finding.

splices in electrical cables associated with mitigating systems (Ref. Inspection Report This OE was reviewed during the aging 50-286/01-09).

management review of the medium-voltage cables, and it was determined that this plant OE was in accordance with the industry OE for medium-voltage cables. This OE supports the selection of the Non-EQ Medium-Voltage Cable program and the frequency of the manhole inspection. No aging effects were identified that are not addressed in the EPRI Electrical Handbook.

IPEC00186112

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 66 of 119 Table 3.1.4 Operating Experience Applicable to Electrical, Instrumentation, and Control Components Item Issue OE Evaluation CR-IP3-A heavy gauge cable, located in the heater This cable does not perform a license 2003-01617 bay showed large circumferential cracks in renewal intended function, but it is an the insulation.

example of reduced insulation resistance due to cracking of conductor insulation exposed to adverse localized environments identified in the electrical handbook. This aging effect will be managed by the Non-EQ insulated cables and connections program.

CR-IP3-The plastic sheathing for the electrical This cable does not perform a license 2003-04887 cable connected to SOV-1539 is damaged.

renewal intended function, but it is an The jacket is split exposing the rom ex type example of reduced insulation resistance cable beneath.

due to cracking of conductor insulation exposed to adverse localized environments identified in the electrical handbook. This aging effect will be managed by the Non-EQ insulated cables and connections program.

CR-IP3-While walking down BFD-FCV-427L it was This is an example of a maintenance or 2004-01658 noted that the insulation (mechanical) was design issue that is impacting the cable missing from the body to bonnet area of insulation. This is an example of reduced the valve. It was also noted that the cable insulation resistance due to cracking of from the positioner was resting on the hot conductor insulation exposed to adverse area, and has begun to degrade.

localized environments identified in the electrical handbook. This aging effect will be managed by the Non-EQ insulated cables and connections program, and validates to walkdown method to identify adverse localized environments.

IPEC00186113

IPEC License Renewal Project Operating Experience Review Report 3.2 AERM OE Conclusions IP-RPT LRD05 Revision 3 Page 67 of 119 The AERM OE review included a review of CRs from 2001 through 2005 and interviews with systems engineers to determine if there are AERM that are not identified by the industry guidance documents for implementing the license renewal rule. (Ref. 5.4, 5.5, 5.6)

Subsections 3.2.1, 3.2.2, and 3.2.3 provide conclusion of OE evaluations presented in Section 3.1 comparing site-specific OE with industry guidance for performing AMRs.

3.2.1 Comparison of OE Review Results with Mechanical Tools 3.2.1.1 Non Class 1 Mechanical Components Reviews of CRs from 2001 through 2005 and interviews with systems engineers identified one component specific aging effect not identified in the mechanical tools. The charging pumps have experienced cracking due to fatigue on the eves charging pump cylinder blocks as an aging effect requiring management. This aging effect is identified in the IP-RPT-06-AMMO?,

"Aging Management Review of the Chemical and Volume Control Systems".

3.2.1.2 Class 1 Mechanical Components Reviews of CRs from 2001 through 2005 and interviews with systems engineers did not identify plant specific OE different from the industry OE provided in the mechanical tools or other guidance documents. Therefore, Indian Point does not have aging effects not identified and discussed in the mechanical tools or other guidance documents.

3.2.2 Comparison of OE Review Results with Structural Tools Reviews of CRs from 2001 through 2005 and interviews with systems engineers did not identify plant specific OE different from the industry OE provided in the structural tools.

Therefore, Indian Point does not have aging effects not identified and discussed in the structural tools.

3.2.3 Comparison of OE Review Results with License Renewal Electrical Handbook Reviews of CRs from 2001 through 2005 and interviews with systems engineers did not identify plant specific OE different from the industry OE provided in the license renewal electrical handbook. Therefore, Indian Point does not have aging effects not identified and discussed in the license renewal electrical handbook.

IPEC00186114

IPEC License Renewal Project Operating Experience Review Report 4.0 AMP OE Evaluation and Conclusions IP-RPT LRD05 Revision 3 Page 68 of 119 Program reviewers evaluated applicable program-specific documentation and interview responses retained for further evaluation.

The evaluators compared the OE results with program objectives.

Evaluations and conclusions for each program are presented in the following subsections.

4.1.1 Aboveground Steel Tanks Program The Aboveground Steel Tanks Program is an existing program that manages loss of material from external surfaces of aboveground carbon steel tanks by periodic visual inspection of external surfaces and thickness measurement of locations that are inaccessible for external visual inspection such as tank bottom surfaces. (Ref. 5.8)

Visual inspections detected corrosion on the top of the IP3 condensate storage tank in 2003 and 2005 and on the IP2 condensate storage tank in 2004. Corrective actions were issued to clean and repaint the surfaces, which will prevent recurrence.

Visual inspections of the external surfaces of the gas turbine fuel storage tanks in December 2006 indicated no loss of material due to corrosion.

(Ref. 5.112, 5.114, 5.115, 5.129)

Thickness measurements of the gas turbine fuel storage tanks in April 2002 found pitting up to 60% through-wall, with no loss of intended function. This was repaired with a weld overlay.

(Ref. 5.226)

Inspections of the IP2 fire water storage tank (300KFPT) and the Training Center fire water storage tank (HTC-FP-T-1) in 2003 detected failure of the coating in several places, but no appreciable metal loss was identified. Corrective actions were issued to repair the coating.

Identification of degradation and corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects for passive components.

(Ref. 5.111, 5.113)

Inspections of the IP1 city water tank and the IP2 condensate storage tank in 2007 detected no loss of material due to corrosion. Absence of loss of material provides evidence that the program is effective for managing aging effects for passive components. (Ref. 5.272) 4.1.2 Bolting Integrity Program The Bolting Integrity Program is an existing program that relies on recommendations for a comprehensive bolting integrity program, as delineated in NUREG-1339, and industry recommendations, as delineated in the Electric Power Research Institute (EPRI) NP-5769, with the exceptions noted in NUREG-1339 for safety-related bolting. The program relies on industry recommendations for comprehensive bolting maintenance, as delineated in EPRI TR-104213 for pressure retaining bolting and structural bolting. (Ref. 5.8)

Visual inspections of bolted connections were documented during 2001 through 2005 at IP2 and I P3. Although corrosion products were found to have been deposited on some bolting materials, no situations were identified where loss of material had precluded the bolted connection from maintaining its intended function.

Corrective actions were completed to ensure future integrity of the bolted connection. Identification of degradation and performance IPEC00186115

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 69 of 119 of corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects for passive components. (Ref. 5.23, 5.27, 5.116, 5.117, 5.118, 5.119, 5.120, 5.121, 5.122, 5.123, 5.124, 5.125, 5.126, 5.127, 5.128, 5.130, 5.131, 5.136, 5.153, 5.154) 4.1.3 Boraflex Monitoring Program-Unit 2 The Boraflex Monitoring Program is an existing program for Unit 2 that assures degradation of the Boraflex panels in the spent fuel racks does not compromise the criticality analysis in support of the design of the spent fuel storage racks. The program relies on (1) gap formation measurements by areal density (BADGER) testing, (2) use of the EPRI RACKLIFE predictive computer code, (3) determination of boron loss through correlation of silica levels in spent fuel water samples, and (4) analysis of criticality to assure that the required 5% subcriticality margin is maintained. Corrective actions are initiated if the test results find that the 5% subcriticality margin cannot be maintained because of current or projected Boraflex degradation. (Ref. 5.8)

In 1990, the IP2 spent fuel racks (SFRs) were replaced with new SFRs to increase the on-site storage capacity for spent fuel. Panels of Boraflex are used to control the reactivity of the fuel.

Since Boraflex is susceptible to in-service degradation, a RACKLIFE model of the Indian Point 2 spent fuel pool was developed. The analysis indicated that areas of moderate dissolution of the Boraflex panels had likely occurred.

Accordingly, Boron-10 Areal Density Gage for Evaluating Racks (BADGER) testing was performed in February 2000, July 2003 and again in July 2006.

The results confirmed the predictions of the RACKLIFE computer model, and provide evidence that the program is effective for managing change in material properties (reduction in neutron-absorbing capacity) for Boraflex neutron absorber panels.

(Ref. 5.16, 5.17, 5.220) 4.1.4 Boral Surveillance Program - Unit 3 The Boral Surveillance Program is an existing program for Unit 3 that assures the Boral neutron absorbers in the spent fuel racks do not compromise the criticality analysis in support of rack design. The program relies on representative coupon samples mounted in surveillance assemblies located in the spent fuel pool to monitor performance of the absorber material without disrupting the integrity of the storage system. (Ref. 5.8)

Boral' is a boron-aluminum alloy manufactured by Brooks and Perkins.

It is typically manufactured in plates, with the B4C-AI alloy sandwiched between aluminum plates. These are inserted into the structure of the spent fuel racks (SFRs) at IP3. Results of an inspection of coupon samples in 2002 showed no significant degradation of Boral material. Absence of loss of material provides evidence that the program is effective for managing aging effects.

(Ref. 5.20, 5.32)

A review of this program was performed in 2004 with respect to the Seabrook Part 21 issue on Boral coupon blistering (NRC21-031006 Part 21). As a result, the procedure for IP3 Boral examinations was revised to test the same full-length Boral sample during the next inspection (2007) as was tested during the last inspection (2002). This will allow direct measurement of blister growth and will determine if the Boral blisters have reached equilibrium.

All other recommended actions have been completed, and this IP3 program was selected as the pilot plant for the EN N-NE fleet. Identification of areas for program improvements, and subsequent IPEC00186116

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 70 of 119 corrective actions, provide assurance that the program will remain effective for managing loss of material of the Boral neutron absorber. (Ref. 5.18, 5.19) 4.1.5 Boric Acid Corrosion Prevention Program The Boric Acid Corrosion Prevention Program is an existing program that relies on implementation of recommendations of NRC Generic Letter 88-05 to monitor the condition of ferritic steel, gray cast iron, copper alloy > 15% zinc, and electrical components on which borated reactor water may leak. The program detects boric acid leakage by periodic visual inspection of systems containing borated water for deposits of boric acid crystals and the presence of moisture; and by inspection of adjacent structures, components, and supports for evidence of leakage. This program manages loss of material and loss of circuit continuity, as applicable. The program includes provisions for evaluation when leakage is discovered by other activities. (Ref. 5.8)

A QA audit conducted in 2003 determined that implementation of the Boric Acid Inspection Program was effective. (Ref. 5.51)

Minor boron leakage was detected during inspections of the IP2 containment building in April 2005, November 2005, and May 2006. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components. (Ref. 5.21, 5.22, 5.136)

Boron leakage was detected in March 2005 during an inspection of reactor coolant boundary components at IP3 which may be subject to boric acid leakage and corrosion. Early detection of leakage precluded boric acid wastage of affected components and adjacent structures and components.

Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components. (Ref. 5.23, 5.24, 5.25, 5.26, 5.27, 5.28, 5.29, 5.30)

The Boric Acid Corrosion Prevention Program at IPEC has been recently enhanced to include recommendations of the Westinghouse Owner's Group WCAP-15988-NP "Generic Guidance to Best Practice 88-05 Boric Acid Inspection Program," EPRI Technical Report 1000975 "Boric Acid Corrosion Guidebook," and NRC Bulletin 2003-02 "Leakage from Reactor Coolant Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity."

Process improvements through incorporation of industry recommendations provide assurance that the program will remain effective for managing aging effects for passive components.

(Ref. 5.31) 4.1.6 Containment lnservice Inspection (CII) Program The Containment lnservice Inspection (CII) Program is an existing program encompassing ASME Section XI Subsection IWE and IWL requirements as modified by 10 CFR 50.55a.

Every 10 years the program is updated to the latest ASME Section XI code edition and addendum approved by the Nuclear Regulatory Commission in 10 CFR 50.55a. (Ref. 5.9)

Results of an IWE containment inspection performed at I P2 in 2004 and 2006 were satisfactory. However, a program review determined that the 2004 inspection report was not completed and submitted in a timely fashion as specified in the program requirements. The IPEC00186117

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 71 of 119 report was subsequently prepared and submitted as required.

Surface indications such as nicks, chipping, and pitting of the vapor containment (VC) liner were noted during the 2006 inspection and were evaluated as acceptable by engineering.

Determination of program weaknesses and subsequent corrective actions, along with engineering evaluation of inspection results, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.33, 5.34, 5.38, 5.39)

Minor surface corrosion was detected during an IWE containment inspection at IP3 in 2005, and was classified as "acceptable" under the program definitions. Work orders were initiated to repair the affected areas. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components. (Ref. 5.35, 5.40)

An IWL inspection at IP2 in 2005 revealed 91 recordable indications which were reviewed by engineering.

None of these indications, which were compared to the results of the 2000 inspection, represented a structural concern. An IWL inspection at IP3 in 2005 found minor spalling and other indications which had been noted in the 2001 inspection and which showed no signs of further degradation.

Lack of degradation, which could lead to possible failure, demonstrated through a regular program of inspections, provides assurance that the program is effective for managing aging effects for passive components. (Ref. 5.36, 5.37)

A self-assessment of the Containment lSI program was completed in October 2004.

All findings and recommendations from earlier EPRI assessments of the program were found to be controlled, tracked, evaluated, and corrected. Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.141) 4.1.7 Containment Leak Rate Program The Containment Leak Rate Program is an existing program. As described in 10 CFR Part 50, Appendix J, containment leak rate tests are required to assure that (a) leakage through reactor containment and systems and components penetrating containment shall not exceed allowable values specified in technical specifications or associated bases and (b) periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of containment, and systems and components penetrating containment. The IPEC program utilizes Option B and the guidance in NRC Regulatory Guide 1.163 and NEI 94-01. (Ref. 5.9)

The containment leak rate test at IP2 in 2006 (2R17) was completed successfully. A QA surveillance found that the test vendor's performance met all applicable requirements; however, administrative deficiencies were identified in the procedures used to calculate total leakage.

Confirmation of containment integrity, along with identification and resolution of program discrepancies, provides assurance that the program is effective for managing loss of material of components. (Ref. 5.43, 5.65)

Results of IP3 containment leak rate testing during 2001-2006 were satisfactory.

A QA surveillance of the containment leak rate test in 2005 (3R 13) found that the test vendor's performance met all applicable requirements.

Confirmation of containment integrity and IPEC00186118

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 72 of 119 program compliance provides assurance that the program is effective for managing loss of material of components. (Ref. 5.44, 5.64)

An industry benchmarking was performed for this program in 2004. Areas for improvement were identified and corrective actions were implemented. Identification of areas for program improvements, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.42)

A focused self-assessment of the program was performed in 2003. The focus of the self-assessment was to identify gaps between the IP2 and IP3 program procedures. Actions were generated that led to program improvement in several key areas. Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.41) 4.1.8 Diesel Fuel Monitoring Program The Diesel Fuel Monitoring Program is an existing program that entails sampling to ensure that adequate diesel fuel quality is maintained to prevent loss of material and fouling in fuel systems. Exposure to fuel oil contaminants such as water and microbiological organisms is minimized by periodic draining and cleaning of tanks and by verifying the quality of new oil before its introduction into the storage tanks. (Ref. 5.8)

Samples of diesel fuel delivered to the IPEC site on 7/14/2001, 8/22/01, 2/22/02, and 3/4/03 were found to not meet the ASTM D-975 specification for flashpoint. Corrective actions were taken to ensure that fuel in the three underground EDG storage tanks was still within specification.

Discussions were held with the fuel vendor to prevent recurrence.

Test protocols and QA requirements for the fuel supply contracts were compared and standardized between IP2 and IP3. (Ref. 5.45, 5.46, 5.47, 5.49)

Results of a test of an EDG Fuel Oil Underground Tank in 2003 were reported as out of specification for oxidation stability. Further review by the Chemistry staff determined that the vendor laboratory had submitted a test report with a typographical error.

The corrected oxidation stability level was found to be acceptable. (Ref. 5.48)

Results of a microorganism study performed by a vendor on a sample taken from an EDG underground diesel fuel tank reported heavy bacteria growth. The source of the bacteria was water intrusion through an overfill line spool piece incorrectly reassembled following maintenance. The water was removed from the tank and subsequent testing verified the absence of bacteria.

Identification of out-of-specification fuel conditions, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.50)

Other than the above instances, fuel oil sampling results from 2001 through 2005 reveal that fuel oil quality is being maintained in compliance with acceptance criteria. Continuous confirmation of diesel fuel quality provides assurance that the program is effective in managing loss of material of fuel system components. (Ref. 5.158)

IPEC00186119

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 73 of 119 Visual inspections of the external surfaces of the fire protection diesel tank, security diesel oil tank, and gas turbine 1 north and south tanks in December 2006 indicated no loss of material due to corrosion. (Ref. 5.129)

Visual inspection of the IP3 EDG #33 fuel oil storage tank was performed in 2001. The tank was cleaned and visually inspected. Visual and UT inspections of the EDG #31 and #32 fuel oil storage tanks were also completed in 2001. The IP2 fuel oil storage tanks were visually inspected in 2003. No significant degradation was identified. (Ref. 5.181)

The overall program was reported as effective during a QA surveillance in 2004.

One deficiency was noted due to a missed surveillance frequency.

Corrective actions were identified and implemented. Identification of program deficiencies, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.73, 5.74, 5.75) 4.1.9 Environmental Qualification (EQ) of Electric Components Program The IPEC EQ program manages the effects of thermal, radiation, and cyclic aging through the use of aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by 10 CFR 50.49, EQ components are refurbished, replaced, or their qualification is extended prior to reaching the aging limits established in the evaluation. (Ref. 5.1 0)

In August 2001, incorrect inputs were identified in EQ analysis. Corrective actions included update of calculations, evaluation of other program documents, and evaluation of environmental conditions.

Identification of incorrect inputs and timely corrective actions provide assurance that the program will remain effective in assuring that equipment is maintained within its qualification basis and qualified life. (Ref. 5.52)

In July 2002, a QA audit of the EQ Program identified considerable differences between the analytical tools used for HELB analyses at IP2 compared to those at IP3. Corrective actions included development of revised pressure/temperature profiles and thermal lag evaluations of specific equipment, and revisions to the EQ Program Plan and supporting calculations.

Comparison of analytic approaches, identification of program improvements, and timely corrective actions provide assurance that the program will remain effective in assuring that equipment is maintained within its qualification basis and qualified life. (Ref. 5.53)

The overall effectiveness of the EQ of Electric Components Program is demonstrated by the excellent OE for systems, structures, and components in the program.

A focused self-assessment in 2002 found that the program procurement and work control processes were found to be programmatically meeting the NRC's 10CFR50.49 requirements. Several areas for improvement were identified, and an EQ Program Enhancement Action Plan was developed. (Ref. 5.59, 5.61, 5.63)

Improper scheduling of EQ work orders was identified in January 2003. Corrective actions included a discussion of expectations for EQ work scheduling with the Work Week Managers and review of the specifications for the Maximo production system. Identification of program weaknesses and timely corrective actions provide assurance that the program will remain effective in assuring that equipment is maintained within its qualification basis and qualified life. (Ref. 5.54)

IPEC00186120

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 7 4 of 119 An impact review of the EQ Program with respect to the IP2 power uprate was performed in February 2003.

EQ files requiring update were identified and revised. An EQ Master List (EQML) validation project in 2003-2004 led to reviews of wiring diagrams and updates of the EQML.

A review of EQ Program administrative documents in 2005 identified gaps in the process for updating the EQML.

This resulted in tailgate discussions with the I&C Maintenance staff, development of new Maximo reports, and recommendations to the peer group in charge of the fleet-wide Work Control System. Timely update of program inputs and program documents, along with overall process improvements, provide assurance that the program will remain effective in assuring that equipment is maintained within its qualification basis and qualified life. (Ref. 5.55, 5.56, 5.57, 5.58, 5.60, 5.62) 4.1.10 External Surfaces Monitoring Program This External Surfaces Monitoring Program is an existing program that inspects external surfaces of components subject to aging management review. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. (Ref. 5.8)

System walkdowns between 2001 and 2005 identified evidence of aging effects, including corrosion and leakage.

Corrective actions were accomplished in accordance with the site Corrective Action Program. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components. (Ref. 5.66, 5.67, 5.68, 5.69, 5.70)

A review of best practices for system walkdowns at all Entergy sites was performed as part of the development of a fleet-wide program guidance procedure.

Comparison of program techniques and development of fleet-standard practices provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5. 71, 5. 72) 4.1.11 Fatigue Monitoring Program The Fatigue Monitoring Program is an existing program that tracks the number of critical thermal and pressure transients for selected reactor coolant system components.

The program ensures the validity of analyses that explicitly analyzed a specified number of fatigue transients by assuring that the actual effective number of transients does not exceed the analyzed number of transients. (Ref. 5. 7)

Industry experience has been factored into the IPEC fatigue monitoring program as appropriate, including thermal/operating stresses that were not considered in the original design of IPEC. These include evaluation of NRC Bulletin 88-11 pressurizer insurge/outsurge transients and NRC Bulletin 88-08 thermal stratification cycling due to valve leakage. The locations at which cumulative usage factors (CUFs) have been calculated include three of the six locations identified in NUREG/CR-6260. CUFs were not calculated for the ASME B31.1 pressurizer surge line, RCS piping, RHR piping, and charging and safety injection nozzles included in the reactor coolant pressure boundary. Further discussion can be found in Section 2.4 and 6 of IPEC Report LRD04, TLAA-Mechanical Fatigue. IPEC will continue to evaluate future industry experience on fatigue of Class 1 components.

IPEC00186121

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 75 of 119 For recent reactor shutdowns and startups, cycle limitations did not trend toward exceeding the allowable number of cycles. This demonstrates that the program continues to monitor plant transients and track the accumulation of these transients. (Ref. 5.89, 5.90)

The program has also included re-evaluation of usage factors as appropriate. For example, certain auxiliary transients related to charging and letdown that were approaching typical design cycle limits for the IP2 charging nozzles, during the current period of operation, were reevaluated. The impact of counts of thermal transient cycles on the IP2 nozzles was assessed based on comparison of plant specific moment loads against previously assumed moment loads and reconciliation of the cycle counts to design cycles used in previous analysis. The reevaluation concluded that the fatigue impact of transient cycles accumulated on the I P2 charging nozzles (through 1 0/99) is within that expected based on pro-rated typical operation of the charging system, and projected allowable cycles during the current period of operation. (Ref. 5.76)

Design transients for IP3 were reviewed in connection with the stretch power uprate. This updated transient information provides assurance that the program will continues to be effective in managing aging effects, such that the applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation. (Ref. 5. 77) 4.1.12 Fire Protection Program The Fire Protection Program is an existing program that includes a fire barrier inspection, an RCP oil collection system inspection, and a diesel-driven fire pump inspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump and its driver be periodically tested and inspected to ensure that diesel engine sub-systems including the fuel supply line can perform their intended functions. (Ref. 5.8)

Inspections of fire stops, fire barrier penetration seals, fire barrier walls, ceilings, and floors from 2001 through 2005, revealed signs of degradation such as cracks, gaps, voids, holes or missing material.

See Table 3.1.3, Operating Experience Applicable to Structures and Structural Components, for examples. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for fire barrier components.

Discrepancies in fire barrier wrappings were detected during periodic surveillances in 2001 and 2004.

Immediate actions were completed to repair these fire barriers.

Identification of deficiencies and timely corrective actions provide evidence that the program will remain effective for managing loss of material of components. (Ref. 5.84, 5.85)

A program self-assessment in 2003 identified deficiencies in the fire barrier inspection list at IP2. Corrective actions included review of the Type I fire barrier drawing against the inspection list in the procedure, followed by changes to the procedure and the drawing. Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.83)

IPEC00186122

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 76 of 119 QA audits in 2003, 2005, and 2006 revealed that the material condition of system equipment was good and met licensing requirements.

The audits revealed no issues or findings that could impact effectiveness of the program to manage aging effects for fire protection components. (Ref. 5.80, 5.81, 5.82)

A November 2005 inspection of the RCP oil collection system within the IP2 containment building found no indications of loss of material on system components. (Ref. 5.21)

The IP2 and IP3 diesel-driven fire pumps were observed while they were each running in November 2006.

No leaks or degradation of diesel engine sub-systems, including the fuel supply line, were noted. Continuing monitoring provides evidence that the program remains effective for managing aging of diesel-driven fire pump subsystem components. (Ref. 5.132, 5.133)

In August 2004, NRC completed a triennial fire protection team inspection at IP2 to assess whether the plant had implemented an adequate fire protection program and that post-fire safe shutdown capabilities had been established and were being properly maintained.

The inspection team also evaluated the material condition of fire area boundaries, fire doors, and fire dampers, and reviewed the surveillance and functional test procedures for the diesel fire pump and other components. Additionally, the team reviewed the surveillance procedures for structural fire barriers, penetration seals, and structural steel. No findings of significance were identified.

Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.78)

In January 2005, NRC completed a triennial fire protection team inspection at IP3 to assess whether the plant had implemented an adequate fire protection program and that post-fire safe shutdown capabilities had been established and were being properly maintained.

The inspection team also evaluated the material condition of fire area boundaries, fire doors, and fire dampers, and reviewed the surveillance and functional test procedures for the diesel fire pump and other components. The inspection team also reviewed the adequacy of selected total flooding C02 systems. Completed surveillance procedures were also reviewed to ensure appropriate periodic testing of the system was being accomplished. Additionally, the team reviewed the surveillance procedures for structural fire barriers and penetration seals.

No findings of significance were identified.

Confirmation of program compliance provides assurance that the program will remain effective for managing aging effects. (Ref. 5.79) 4.1.13 Fire Water System Program The Fire Water System Program is an existing program that applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, piping, and components that are tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards.

Such testing assures functionality of systems.

To determine if significant corrosion has occurred in water-based fire protection systems, periodic flushing, system performance testing and inspections are conducted. Also, many of these systems are normally maintained at required operating pressure and monitored such that leakage resulting in loss of system pressure is immediately detected and corrective actions initiated. In addition, wall thickness evaluations of fire protection piping are periodically performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. (Ref. 5.8)

IPEC00186123

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 77 of 119 Data obtained during the performance of a system performance test in 2002 indicated potentially degraded flow in a portion of the firewater distribution system. Actions were taken to monitor the flowrate to ensure that no downward trend was present. (Ref. 5.86)

During a system walkdown by the fire protection engineer, it was identified that the water spray system nozzles located above the day tanks in each of the three diesel generator rooms did not conform to the design drawings. It was later determined that the system would still meet its intended function. This attention to detail during a program inspection provides assurance that the program is effective for managing loss of material of components. (Ref. 5.87)

In August 2004, NRC completed a triennial fire protection team inspection at IP2 to assess whether the plant had implemented an adequate fire protection program and that post-fire safe shutdown capabilities had been established and were being properly maintained.

The inspection team reviewed the adequacy of selected pre-action and wet pipe sprinklers, including the adequacy of surveillance procedures. No findings of significance were identified.

Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.78)

In January 2005, NRC completed a triennial fire protection team inspection at IP3 to assess whether the plant had implemented an adequate fire protection program and that post-fire safe shutdown capabilities had been established and were being properly maintained.

The inspection team reviewed the adequacy of selected wet pipe sprinkler systems. Completed surveillance procedures were also reviewed to ensure appropriate periodic testing of the system was being accomplished. No findings of significance were identified. Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5. 79)

Visual inspections of fire hose station equipment in September 2005 at IP3 and in November 2006 at IP2 revealed no loss of material on hose station steel parts. One broken sprinkler nozzle was replaced as a result of the IP2 inspection.

Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for steel fire water system components. (Ref. 5.91, 5.93)

Flow tests of fire main segments and hydrant inspections during 2006 found no evidence of obstruction or loss of material.

Spray and sprinkler system functional tests and visual inspections of piping and nozzles in 2006 found no evidence of blockage or loss of material.

Confirmation of absence of degradation provides evidence that the program is effective for managing loss of material for fire water system components. (Ref. 5.92, 5.94, 5.95, 5.96, 5.97) 4.1.14 Flow-Accelerated Corrosion Program The Flow-Accelerated Corrosion Program is an existing program that applies to safety-related and nonsafety-related carbon and low alloy steel components in systems containing high-energy fluids carrying two-phase or single-phase high-energy fluid.2:. 2% of plant operating time.

The program, based on EPRI recommendations for an effective flow-accelerated corrosion program, predicts, detects, and monitors FAC in plant piping and other pressure retaining IPEC00186124

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 78 of 119 components. This program includes (a) an evaluation to determine critical locations, (b) initial operational inspections to determine the extent of thinning at these locations, and (c) follow-up inspections to confirm predictions, or repair or replace components as necessary. (Ref. 5.8)

Operating experience for IP2 and IP3 was used in the most recent updates of the IP2 and IP3 CHECWORKS FAC models. This includes inspection data from the outage inspections as well as the changes to FAC wear rates due to the recent power uprates. These updates further calibrate the model, improving the accuracy of the wear predictions. (Ref. 5.98, 5.1 00)

The FAC program for IP2 was audited in 2004. The audit team determined that this program was effective and in compliance with NRC regulations, ASME code, EPRI standards, and INPO guidelines.

Regular program audits and application of industry standards provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.1 05)

A focused self-assessment of the FAC program at IP2 and IP3 was performed in February 2006. This included a review of several pre-outage wall-thinning evaluations as well as UT examination data from 2003 through 2005 at IP2 and IP3. Wall thickness predictions from the pre-outage evaluations were validated by the examinations, and no unacceptable wall-thinning was detected. Verification of pre-outage evaluations provides evidence that the program is effective for managing loss of material in carbon steel components. (Ref. 5.99)

During 3R13 in March 2005, wall thinning was detected on vent chamber drain and high pressure turbine drain components which were replaced during that outage. These systems are susceptible to FAC and are closely monitored. Susceptible sections of these systems are being replaced with FAC resistant chrome-moly material. All remaining inspected components were found acceptable for continued service. During 2R 17 in May 2006, wall thinning was detected in an IP2 steam trap which was then replaced during that outage. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components. (Ref. 5.101, 5.1 02, 5.269, 5.270)

A review of best practices for the FAC Program at all Entergy sites was performed as part of the development of a fleet-wide program procedure. Guidance from the EPRI CHECWORKS User's Group (CHUG) has been applied to this procedure.

Comparison of program techniques, conformance to industry standards, and use of shared "best practices" in the development of fleet-wide procedures provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.88) 4.1.15 Flux Thimble Tube Inspection Program The Flux Thimble Tube Inspection Program is an existing program that monitors thinning of the flux thimble tube wall, which provides a path for the in-core neutron flux monitoring system detectors and forms part of the RCS pressure boundary. Flux thimble tubes are subject to loss of material at certain locations in the reactor vessel where flow-induced fretting causes wear at discontinuities in the path from the reactor vessel instrument nozzle to the fuel assembly instrument guide tube. An NDE methodology, such as eddy current testing (ECT), or other applicant-justified and NRC-accepted inspection method is used to monitor for wear of the flux IPEC00186125

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 79 of 119 thimble tubes. This program implements the recommendations of NRC Bulletin 88-09, "Thimble Tube Thinning in Westinghouse Reactors". (Ref. 5.7)

Flux thimble tube inspections were performed at IP2 in March 1989. Seven tubes were found to have some damage and were recommended for further monitoring. An inspection plan was developed using Westinghouse methodology. Use of program results to plan future inspection requirements is an indication that the program is effective for managing loss of material in these components. (Ref. 5.221, 5.225, 5.240)

Flux thimble tube inspections were performed at IP3 during April 1992, May 1997 (3R9), and May 2001 (3R11).

Comparison of 3R11 results to 3R9 results for each tube showing indications of wall loss revealed, in general, that tubes had either no significant increase in wall loss, or an increase of 20% or less over four years. All 2001 recorded wall losses were below the maximum allowed per vendor guidelines.

Identification of degradation prior to loss of function is an indication that the program is effective for managing loss of material in these components. (Ref. 5.222, 5.223, 5.224) 4.1.16 lnservice Inspection (lSI) Program The lSI Program is based on ASME Inspection Program B (IWA-2432), which has 1 0-year inspection intervals. Every 10 years the program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in 10 CFR 50.55a. The program consists of periodic volumetric, surface, and visual examination of components and their supports for assessment, signs of degradation, flaw evaluation and corrective actions.

Augmented inservice inspections are also included as required by 10 CFR 50.55a, the NRC, Response to RAis, or as deemed necessary by the lSI Program. (Ref. 5.7) lSI examinations at IP2 and IP3 were conducted during 2004 and 2005. Results found to be outside of acceptable limits were either repaired, accepted as is, or a replacement process was initiated for the next outage. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects.

(Ref. 5.1 06, 5.1 07)

A self-assessment of the lSI program was completed in October 2004.

Review of current scope for 2R 16 and 3R 13 verified that the proper inspection percentages had been planned for both outages. A follow-up assessment was held for IP2 in March 2006 to ensure that all inspection activities required to close out the third 1 0-year lSI interval were scheduled for 2R17.

Confirmation of compliance to program requirements provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.141, 5.142)

QA surveillances in 2005 and 2006 revealed no issues or findings that could impact effectiveness of the program. (Ref. 5.1 08, 5.1 09, 5.11 0) 4.1.17 Masonry Wall Program The Masonry Wall Program is an existing program that manages aging effects so that the evaluation basis established for each masonry wall within the scope of license renewal remains valid through the period of extended operation. The program includes all masonry walls identified as performing intended functions in accordance with 10 CFR 54.4. Included IPEC00186126

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 80 of 119 components are 10 CFR 50.48-required masonry walls, radiation shielding masonry walls, and masonry walls with the potential to affect safety-related components. Structural steel components of masonry walls are managed by the Structures Monitoring Program. Masonry walls are visually examined at a frequency selected to ensure there is no loss of intended function between inspections. (Ref. 5.9)

Inspections of the IP2 fan house in 2001 identified cracking and spalling in some walls. These conditions did not affect the structural integrity of the walls and were repaired. Slight corrosion of column to wall connections was noted. This corrosion did not affect the structural integrity of the connections and was listed for future monitoring. (Ref. 5.163)

Inspections of the IP2 fuel storage building in 2003 identified some hairline cracks and loose blocks which were found to be acceptable but listed for future monitoring. (Ref. 5.162)

Inspections of the IP2 control building in 2003 found indications of water intrusion, evidenced only by efflorescence on the concrete floor. This condition did not affect the structural integrity of the walls and was listed for future monitoring. (Ref. 5.165)

Inspections of the IP3 primary auxiliary building, fuel storage building, fan house, and turbine building in 2003 through 2005 noted minor cracking in some walls which had not changed from the baseline condition, and some leaking seals which were repaired.

A crack in the joint between the fuel storage building and the fan house was noted as acceptable with future monitoring. (Ref. 5.160)

Inspections of the city water metering house in 2004 identified some hairline cracks and loose blocks which were found to be acceptable but listed for future monitoring. (Ref. 5.164)

Inspections in 2004 discovered minor cracks and spalling in the IP2 turbine building which were listed for future monitoring. (Ref. 5.159)

Inspections of the IP3 control building in 2005 revealed hairline cracks in the battery room walls which were found to be acceptable with no affect on structural integrity. (Ref. 5.161)

Inspections of the IP3 fan house in 2006 found hairline cracks which did not affect the structural integrity of the walls and were listed for future monitoring. (Ref. 5.166)

Inspections of the IP3 fuel storage building in 2006 found minor shrinkage cracking along the mortar joints on the outside of the south wall, with no observable change in width since the baseline inspection. These conditions did not affect the structural integrity of the walls. (Ref.

5.167)

Identification of degradation, monitoring of indications, and corrective action prior to loss of intended function provide evidence that the program is effective for managing cracking of masonry walls and masonry wall joints.

4.1.18 Metal-Enclosed Bus Inspection Program The Metal-Enclosed Bus Inspection Program is an existing program that inspects the following non-segregated phase bus.

IPEC00186127

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 81 of 119 IP2/IP3-6.9kV bus between station aux transformers and switchgear buses 1/2/3/4/5/6 IP3-6.9kV bus associated with the gas turbine substation IP2-480V bus associated with substation A IP2/IP3 - 480V bus between emergency diesel generators and switchgear buses 2A/3A/5A/6A Inspections are performed for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. Bus insulation is inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation.

Internal bus supports are inspected for structural integrity and signs of cracks. Since bolted connections are covered with heat shrink tape or insulating boots per manufacturer's recommendations, a sample of accessible bolted connections is visually inspected for insulation material surface anomalies.

Enclosure assemblies are visually inspected for evidence of loss of material. (Ref. 5.1 0)

A comparison of techniques for the cleaning and inspection of metal-enclosed buses at IP2 and IP3 was performed to develop a site-wide program procedure. Input from a review of NRC Information Notice 2000-014 was also used for this procedure.

Comparison of program techniques and use of industry findings in the development of site-wide procedures provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.134, 5.135, 5.137, 5.138)

During a preventive maintenance check on #21 EDG in 2004, a loose MEB bolted connection was discovered. This was the only loose connection found during this PM, and a search of the CR database indicates that this was an isolated occurrence.

The CR description did not include a description of the visual appearance of this connection, nor did it provide an as-found micro-ohm reading.

This degraded connection could have been the result of incorrect installation (possibly over-torquing), or it could have been related to thermal cyclic loads associated with loading the EDG.

In any case, identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing the loosening of bolted connections described in the IPEC LRA. (Ref. 5.271) 4.1.19 Nickel Alloy Inspection Program The Nickel Alloy Inspection Program is an existing program that will manage aging effects of alloy 600/690 items and alloy 52/152 and 82/182 welds in the reactor coolant system that are not addressed by the Reactor Vessel Head Penetration Inspection Program, Section 4.6, and the Steam Generator Integrity Program, Section 4.9. The aging effect requiring management for nickel alloys exposed to borated water at an elevated temperature is cracking by primary water stress corrosion cracking (PWSCC).

The Nickel Alloy Inspection Program includes elements of the In-Service Inspection (lSI) Program, which specifies the NDE techniques and acceptance criteria applied to evaluation of identified cracks, and the Boric Acid Corrosion Control Program. (Ref. 5.7)

In response to NRC Bulletin 2003-02, a bare-metal visual examination of the lower head region of the reactor vessel was conducted in the fall of 2004 for IP2, and in the spring of 2005 for IP3. The area adjacent to each bottom mounted instrumentation (BMI) penetration was examined, including each Alloy 600 penetration, the nickel alloy weld pad and the circumference around the annulus between the penetration and weld pad. No evidence of IPEC00186128

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 82 of 119 leakage due to cracking was detected.

Absence of cracking provides evidence that the program is effective for managing aging effects. (Ref. 5.139, 5.140) 4.1.20 Oil Analysis Program The Oil Analysis Program is an existing program that maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. Activities include sampling and analysis of lubricating oil for detrimental contaminants, water, and particulates. (Ref. 5.8)

Analysis of oil samples taken in 1999 through 2006 from the #31 and #32 containment spray pump motors showed that the lube oil in these motors was within normal tolerances and was satisfactory for continued use.

Absence of wear particles and contaminants in a routine sampling program provides evidence that the program is effective in managing aging effects.

(Ref. 5.184)

Analysis of an oil sample from the #23 safety injection pump in April 2001 revealed moderate amounts of particulate and contaminates. Analysis performed on an oil sample from #24 RCP lower bearing in November 2002 indicated a high particulate level. In each case, the lube oil for these pumps was replaced on a priority basis. Use of warning level indicators to direct corrective actions prior to equipment degradation provides assurance that the program will remain effective in managing aging effects. (Ref. 5.185, 5.186)

Oil analysis results for samples from #32 EDG in April and May 2002 indicated increasing wear metals concentrations. Unit 3 Diesel Fire Pump engine crankcase oil analysis results in June 2003 indicated a trend of elevated wear metals. In each case, the lube oil was replaced and appropriate corrective actions were taken. Use of warning level indicators to direct corrective actions prior to equipment degradation provides assurance that the program will remain effective in managing aging effects. (Ref. 5.187, 5.188)

Oil samples from the #31 and #33 service water pump motors in 2006 were found to have total acid numbers and viscosity levels which met pre-established warning levels. A 2006 sample of lube oil from the #31 safety injection pump motor also had indication of a high total acid number. Work orders were planned and scheduled for replacement of the motor lube oil prior to component degradation. Use of warning level indicators to direct corrective actions prior to equipment degradation provides assurance that the program will remain effective in managing aging effects. (Ref. 5.183)

A Predictive Maintenance "gap analysis" was performed in June 2006 to compare best practices for oil analysis among all Entergy Nuclear Northeast sites.

An action plan was developed to establish common oil sampling frequencies and analysis techniques.

Comparison of program techniques and development of fleet-standard practices provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.182) 4.1.21 Periodic Surveillance and Preventive Maintenance Program The Periodic Surveillance and Preventive Maintenance Program is an existing program that includes periodic inspections and tests that manage aging effects not managed by other aging IPEC00186129

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 83 of 119 management programs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. (Ref.

5.8)

The following paragraphs discuss results from recent inspections and tests for existing periodic surveillance and preventive maintenance activities listed in Attachment 2 of Reference 5.8 AMC01 credited activities (Reactor Building)

Inspection of the IP2 reactor building polar crane in May 2006 found no indication of corrosion, cracking, or wear in the crane structural members. Inspection of the IP3 reactor building polar crane in February 2001 and again in March 2005 found no indication of corrosion, cracking, or wear in the crane structural members. (Ref. 5.244, 5.245, 5.246)

AMM01 credited activities (Containment Spray System)

Visual inspection of the IP3 sodium hydroxide (NaOH) storage tank #31 in August 2004 found no deficiencies.

Ultrasonic measurement of wall thickness was satisfactory.

(Ref. 5.227)

AMM03 credited activities (Safety Injection System)

Visual inspection of the #31 and #32 recirculation pumps and related system components in March 2005 found no deficiencies. Visual inspection of the #21 and

1. 22 recirculation pumps and related system components in May 2006 found no deficiencies. (Ref. 5.241, 5.242)

AMM07 credited activities (Chemical and Volume Control System)

No cracking or leakage of the casings of the IP2 and IP3 charging pumps was noted during the most recent inspections completed between November 2006 and March 2007. (Ref. 5.263, 5.264, 5.265, 5.266, 5.267, 5.268)

AMM08 credited activities (Plant Drains)

Inspection of the IP2 Diesel Generator Building floor drain sump float valves in October 2006 found no loss of material. (Ref. 5.247)

AMM17 credited activities (Emergency Diesel Generator System)

Inspections of #22 EDG in July 2006, #23 EDG in August 2006, #31 EDG in June 2005, #32 EDG in July 2005, and #33 EDGin August 2005 found no unacceptable loss of material. (Ref. 5.229, 5.230, 5.231, 5.232, 5.233, 5.234, 5.235, 5.236, 5.239)

AMM18 credited activities (Security Generator)

No significant corrosion or wear was detected during the January 2002 and December 2005 inspections of the security generator. (Ref. 5.237, 5.243)

IPEC00186130

IPEC License Renewal Project Operating Experience Review Report AMM22 credited activities (IP3 Appendix R Diesel Generator)

IP-RPT LRD05 Revision 3 Page 84 of 119 During the September 2006 and December 2006 inspections of the Appendix R diesel generator, no significant corrosion or wear was detected. (Ref. 5.228, 5.238) 4.1.22 Reactor Head Closure Studs Program The Reactor Head Closure Studs Program is an existing program that includes inservice inspection (lSI) in conformance with the requirements of ASME Section XI, Subsection IWB, and preventive measures (e.g. rust inhibitors, stable lubricants, appropriate materials) to mitigate cracking and loss of material of reactor head closure studs, nuts, washers, and bushings. (Ref. 5. 7)

ISI-IWB examinations at IP2 and IP3 were conducted during 2004 and 2005. Results found to be outside of acceptable limits were either repaired, accepted as is, or a replacement process was initiated for the next outage. Identification of degradation and corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects. (Ref. 5.1 06, 5.1 07)

A self-assessment of the lSI program was completed in October 2004.

Review of current scope for 2R 16 and 3R 13 verified that the proper inspection percentages had been planned for both outages. A follow-up assessment was held for IP2 in March 2006 to ensure that all inspection activities required to close out the third 1 0-year lSI interval were scheduled for 2R17.

Confirmation of compliance to program requirements provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.141, 5.142)

QA surveillances in 2005 and 2006 revealed no issues or findings that could impact effectiveness of the program. (Ref. 5.1 08, 5.1 09, 5.11 0) 4.1.23 Reactor Vessel Head Penetration Inspection Program The Reactor Vessel Head Penetration Inspection Program is an existing program that manages primary water stress corrosion cracking (PWSCC) of nickel-based alloy reactor vessel head penetrations exposed to borated water to ensure that the pressure boundary function is maintained. (Ref. 5.7)

Bare metal visual examination of no less than 95 percent of the IP2 reactor vessel head surface and 360 degrees around each head penetration nozzle was completed during November 2004 (2R16), consistent with the requirements of NRC Order EA-03-009 and approved relaxation request. There were no indications of reactor vessel head degradation or leakage due to cracking. Absence of cracking provides evidence that the program is effective for managing aging effects. (Ref. 5.143)

Bare metal visual examination of no less than 95 percent of the IP3 reactor vessel head surface and 360 degrees around each head penetration nozzle was completed during March 2005 (3R13), consistent with the requirements of NRC Order EA-03-009 and approved relaxation requests. There were no indications of reactor vessel head degradation or leakage due to cracking. A QA surveillance of these inspections found that all regulatory requirements were met. Absence of cracking provides evidence that the program is effective for managing aging effects. (Ref. 5.103, 5.144)

IPEC00186131

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 85 of 119 The most recent inspection of the IP2 reactor vessel head penetrations was completed in May 2006 (2R 17). The procedure used was written as a result of lessons learned during conduct of the 2R16 and 3R13 inspections. Input from EPRI/MRP Report 1006296 "Visual Examination for Leakage of PWR Reactor Head Penetrations" was used in this procedure. The results of this 2R17 inspection were satisfactory. Bare metal areas reviewed during this inspection were noted to have a significant improvement in the cleanliness in the base metal and annulus around the penetrations.

A QA surveillance of these inspections found that all regulatory requirements were met. A self-assessment of the inspection process identified improvements that should be made before the process is used in the future. Corrective actions were taken to implement these process improvements.

Absence of cracking, along with continuous improvement of material condition, provides assurance that the program is effective for managing aging effects. Use of recent OE and industry guidance in the development of site-wide procedures, along with site QA oversight and continuous process improvement, provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.1 04, 5.145, 5.155, 5.156, 5.157) 4.1.24 Reactor Vessel Surveillance Program The Reactor Vessel Surveillance Program is an existing program that manages reduction in fracture toughness of reactor vessel beltline materials to assure that the pressure boundary function of the reactor pressure vessel is maintained for the period of extended operation. The program is based on ASTM E-185-82, "Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels", and includes an evaluation of radiation damage based on pre and post-irradiation testing of Charpy V-notch and tensile specimens. Irradiation of the specimens will be higher than the irradiation of the vessel because the specimens are located in the vicinity of the core corners and are closer to the core than the vessel itself. (Ref. 5. 7)

Updated fluence data for IP2 was submitted to the NRC in January 2002. This data and the associated evaluations were shown to fall well within the criterion specified in NRC guidance for determining pressure vessel neutron fluence, thus supporting the validation of the evaluations for managing reduction in fracture toughness of reactor vessel beltline materials.

(Ref. 5.146)

An updated reactor vessel surveillance capsule withdrawal schedule for IP2 was submitted to the NRC in November 2004.

Information from the surveillance program throughout the operating history of IP2 was included in this request to change the previous schedule. The NRC staff determined that the new withdrawal schedule met the criteria in ASTM E-185-82 and was in compliance with 10CFR50 Appendix H.

Review of the surveillance requirements against industry standards, confirmed through NRC oversight, provides assurance that the program will remain effective in managing reduction in fracture toughness of reactor vessel beltline materials. (Ref. 5.147)

Updated fluence data for IP3 was submitted to the NRC in July 2004. All beltline materials were shown to exhibit a more than adequate upper shelf energy level for continued safe plant operation, thus validating the ability of the program to manage reduction in fracture toughness.

(Ref. 5.150)

A summary of IP3 surveillance capsule exposure evaluations was prepared in November 2003 during the fluence evaluation for power uprate. This was used to provide projections of the IPEC00186132

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 86 of 119 neutron exposure of the reactor vessel for future operating periods at the uprated power level.

The surveillance capsule lead factors provided in this calculation will be used as the basis for development of future capsule withdrawal schedules. Review of the surveillance program with respect to the changes created by the power uprate provides assurance that the program will remain effective in managing reduction in fracture toughness of reactor vessel beltline materials.

(Ref. 5.148, 5.149) 4.1.25 Service Water Integrity Program The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed for the period of extended operation. The program includes component inspections for erosion, corrosion, and blockage to verify the heat transfer capability of the safety-related heat exchangers cooled by service water. Chemical treatment using biocides and sodium hypochlorite and periodic cleaning and flushing of redundant or infrequently used loops are the methods used to control or prevent fouling within the heat exchangers and loss of material in service water components. (Ref. 5.8)

In July 2003, a peer assessment of the IP3 service water program was conducted by EPRI.

Some areas for improvement were identified. Corrective actions taken included changes to chlorination practices and evaluation of new software tools for heat exchanger performance analysis. Assessment of existing practices by offsite review groups, followed by appropriate corrective actions, provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.195)

Focused self-assessments of the IP2 and IP3 ultimate heat sink (GL 89-13 Program) were performed in April 2004 and June 2005. The focus of the self-assessment was to ensure that ultimate heat sink subcomponents are adequately maintained and operate within plant design basis.

Actions were generated that led to program improvement in several key areas.

Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.196, 5.198)

In December 2005, NRC completed an ultimate heat sink performance review at IP2 to verify that Entergy was monitoring performance of the instrument air closed cooling water (IACCW) heat exchangers on a continuing basis and to ensure that any potential deficiencies which could mask degraded performance were identified. The inspectors reviewed the design basis documents and Final Safety Analysis Report (FSAR) to validate that testing acceptance criteria were appropriate. The inspectors also reviewed the latest inspection reports for both the 21 and 22 IACCW heat exchangers, evaluated the results of eddy current testing, and ensured that the appropriate tube plugging criteria were used. In addition, the inspectors verified that Entergy was maintaining their commitments from Generic Letter 89-13 concerning heat exchanger inspection and testing. No findings of significance were identified. Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.189)

On November 8, 2005, NRC observed the condition of the 32 Component Cooling Water (CCW) heat exchanger after it was opened for periodic inspection and cleaning.

This observation was performed as part of the ultimate heat sink performance review at IP3. The IPEC00186133

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 87 of 119 inspectors observed and reviewed maintenance activities of this safety-related heat exchanger inspection and cleaning to assess the adequacy of preventive maintenance to minimize the effects of biofouling on heat exchanger performance. The inspectors visually examined the heat exchanger when it was first opened to assess the adequacy of Entergy's periodic cleaning to avoid excessive fouling. The inspectors also reviewed the as-found eddy current testing results and compared it to previous testing data.

No findings of significance were identified.

Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.191)

The service water integrity program procedure was revised in February 2006 to standardize "best practices" between IP2 and IP3. The eddy current inspection program was revised in September 2006 to include the latest EPRI guidance for data trending, and to standardize "best practices" between IP2 and IP3. Conformance to industry standards and use of shared "best practices" in the development of site-wide procedures provide assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.192, 5.193, 5.194)

In March 2006, a snapshot self-assessment was performed to evaluate the effectiveness of the IP2 GL 89-13 program.

Actions were generated that led to program improvements.

Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.197)

In June 2006, NRC completed an ultimate heat sink performance review at IP3 to verify that Entergy was using the periodic maintenance method outlined in Electric Power Research Institute (EPRI) document NP-7552, "Heat Exchanger Performance Monitoring Guidelines" for the Unit 3 EDG lube oil coolers. The inspector reviewed the results of the last inspections and eddy current tests for each of the lube oil coolers. No findings of significance were identified.

Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.190)

In June 2006, NRC completed an ultimate heat sink performance review at IP2 which included the #21 component cooling water heat exchanger, the # 22 component cooling water heat exchanger, and the #22 EDG jacket water and lube oil heat exchangers.

The inspector reviewed documents to ensure that potential common cause heat sink performance problems that had the potential to increase risk were identified and corrected by Entergy. The inspector also reviewed records to ensure that potential macro fouling (silt, debris, etc.) issues and biofouling issues were closely examined by Entergy. To ensure adequate implementation of NRC Generic Letter 89-13, the inspector reviewed Entergy's inspection, cleaning, and eddy current testing methods and frequency with the responsible system engineers. The inspector compared surveillance test and inspection data, including as-found conditions and eddy current summary sheets, to the established acceptance criteria to verify that the results were acceptable and that system heat exchanger operation was consistent with design. The inspector reviewed heat exchanger design basis values and assumptions, plugging limit calculations, and vendor information to verify that they were incorporated into the heat exchanger inspection and maintenance procedures.

The inspector reviewed a sample of condition reports related to the component cooling water and emergency diesel generator heat exchangers, and the service water system to ensure that Entergy was appropriately identifying, IPEC00186134

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 88 of 119 characterizing, and correcting problems related to these systems and components.

No findings of significance were identified.

Confirmation of program compliance provides assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.207)

During 2R18 in March and April 2008, approximately 10% of the scheduled GL 89-13 program volumetric weld examinations were conducted on nonsafety-related service water system piping welds, and approximately 25% of the scheduled GL 89-13 program visual inspections were conducted on nonsafety-related SWS piping. Inspection results indicated no need for further inspections in some locations, while follow-up inspections were planned for other locations.

Use of inspection results to manage aging effects for nonsafety-related service water system piping provides assurance that the program can be used for both nonsafety-related and safety-related applications. (Ref. 5.273) 4.1.26 Steam Generator Integrity Program The Steam Generator Integrity Program is an existing program.

In the industry, steam generator (SG) tubes have experienced tube degradation related to corrosion phenomena, such as primary water stress corrosion cracking, outside diameter stress corrosion cracking, intergranular attack, pitting, and wastage; along with other mechanically-induced phenomena, such as denting, wear, impingement damage, and fatigue.

Nondestructive examination techniques, such as eddy current testing, are used to identify tubes that are defective and need to be removed from service or repaired in accordance with the guidelines of the plant technical specifications. (Ref. 5.7)

In reviewing operating experience for Indian Point steam generators, the following dates are relevant:

IP2 steam generators were replaced in December 2000, IP2 began operating at extended power uprate (EPU) level in November 2004, IP3 steam generators were replaced in 1989, and IP3 began operating at EPU power level in April2005.

An IP3 SG degradation assessment completed in March 2003, per the provisions of NEI 97-06 Revision 1 and the EPRI PWR Steam Generator Examination Guidelines Revision 5, summarized the inspection results of IP3 replacement steam generators since their installation in 3R7, compared this to industry OE, and listed a 3R12 inspection plan based on this input.

Use of unit-specific OE, industry OE, and industry guidance in the development of an inspection plan provide assurance that the program will be effective for managing aging effects for passive components. (Ref. 5.202)

Inspections of the IP3 steam generators were conducted in March 2003 (3R12). All indications in these inspections were below the calculated integrity limits provided in the pre-outage degradations assessment. Absence of unacceptable degradation provides evidence that the program is effective for managing loss of material of components. (Ref. 5.209, 5.21 0)

In March 2003 (3R12), NRC inspectors evaluated the SG integrity assessment program, and compared it with the NRC accepted guidance contained in the EPRI PWR Steam Generator Examination Guidelines Revision 5. To evaluate how the SG assessment program was implemented, the NRC inspectors witnessed the remote visual survey of the #31 SG tube sheet to verify that the eddy current data collection station was correctly positioned and that the robotic probe placement was correct. The inspectors also witnessed the calibration IPEC00186135

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 89 of 119 verification of an eddy current probe used in the #31 SG and verified that the eddy current "C" scan representations corresponded with the correct location on the calibration standard. The inspectors witnessed the eddy current data being extracted from the #31 SG, and also witnessed the independent qualified data analyst review of indications.

The inspectors discussed with the licensee's technical lead the loose parts monitoring and removal program for the SGs. The inspectors also reviewed with responsible vendor personnel the visual survey of the secondary side of the SGs. No findings of significance were identified. Confirmation of program compliance provides assurance that the program is effective for managing aging of passive components. (Ref. 5.203)

In June 2005, the IP2 program procedure was revised to incorporate the results of the September 2004 INPO Steam Generator Review Visit.

In July 2005, the IP3 program procedure was revised to incorporate the latest EPRI guidelines. Review of existing practices by industry groups, implementation of process improvements, and incorporation of industry guidelines provides assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.200, 5.204)

In December 2005, the IP2 and IP3 procedures for steam generator eddy current data analysis were replaced with a single procedure developed to establish consistency in the analysis process and to ensure that examination results are in compliance with regulatory and industry requirements.

Use of shared "best practices" in the development of a site-wide procedure provides assurance that the program will remain effective for managing aging effects for passive components. (Ref. 5.201)

An INPO-assisted self-assessment of the IP2 and IP3 steam generator programs was performed in September 2004. Actions were generated that led to program improvement in several key areas. Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.206)

An IP2 steam generator degradation assessment completed in April 2006, per the provisions of NEI 97-06 Revision 1 and the EPRI PWR Steam Generator Examination Guidelines Revision 6, summarized the inspection results of IP2 replacement steam generators since their installation in December 2000, compared this to industry OE, and listed a 2R17 inspection plan based on this input.

Use of unit-specific OE, industry OE, and industry guidance in the development of an inspection plan provide assurance that the program will be effective for managing aging effects for passive components. (Ref. 5.205)

A QA surveillance of IP2 steam generator eddy current testing was conducted during 2R17 (2006).

This surveillance determined that the program met all applicable technical specification and procedural requirements, including those for data collectors and data evaluators. No deficiencies were noted. Conformance to procedural requirements provides assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.199)

Inspections of the IP2 steam generators were conducted in April 2006 (2R17). All indications in these inspections were below the calculated integrity limits provided in the pre-outage IPEC00186136

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 90 of 119 degradations assessment. Absence of unacceptable degradation provides evidence that the program is effective for managing loss of material of components. (Ref. 5.208)

In April 2006 (2R17), NRC reviewed portions of the steam generator management plan, degradation assessment, and the final operational assessment to evaluate the steam generator inspection and management program. The inspector reviewed plant specific steam generator information, tube inspection criteria, integrity assessments, degradation modes, and tube plugging criteria. Entergy conducted eddy current testing of tubes in all steam generators to identify and quantify tube degradation mechanisms and to confirm tube integrity following the completion of two fuel cycles of operation. The inspector observed a sample of tubes examined from each generator to verify Entergy's examination of the entire length. The inspector interviewed data management and data acquisition personnel and resolution analysts. Also, the inspector reviewed examination data for selected tubes from each of the Unit 2 steam generators. These were selected by the inspector for review since they were noted to be representative of tubes which would most likely approach the tube plugging limit within the next three cycles. The inspector reviewed the characterization and disposition of the indications to assess the implementation of the steam generator inspection program.

No findings of significance were identified.

Confirmation of program compliance provides assurance that the program remains effective for managing aging of passive components.

(Ref. 5.207) 4.1.27 Structures Monitoring Program The Structures Monitoring Program is an existing program that performs inspections in accordance with 10 CFR 50.65 (Maintenance Rule) as addressed in Regulatory Guide 1.160 and NUMARC 93-01. Periodic inspections are used to monitor the condition of structures and structural components to ensure there is no loss of structure or structural component intended function. The program monitors the condition of structures and structural components within the scope of the Maintenance Rule, such that there is no loss of structure or structural component intended function. (Ref. 5.9)

Inspections of structural steel, concrete exposed to fluid, and structural elastomers, from 2001 through 2005, revealed signs of degradation such as cracks, gaps, corrosion (rust), and flaking coatings.

See Table 3.1.3, Operating Experience Applicable to Structures and Structural Components, for examples. Identification of degradation and corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects for structural components.

Structural monitoring of concrete structures and components from 2001 through 2006 revealed minor cracks that did not affect the structural integrity of the components.

Monitoring of structural steel members revealed minor corrosion only. Inspection intervals were adjusted as necessary to ensure future inspections identify degradation prior to loss of intended function.

Identification of degradation and corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects for structural components.

(Ref. 5.159, 5.160, 5.161, 5.162, 5.163, 5.164, 5.165, 5.166, 5.167, 5.168, 5.169, 5.170, 5.171, 5.172, 5.173, 5.174, 5.175, 5.176, 5.177, 5.178, 5.179, 5.180)

IPEC00186137

IPEC License Renewal Project Operating Experience Review Report 4.1.28 Water Chemistry Control -Auxiliary Systems Program IP-RPT LRD05 Revision 3 Page 91 of 119 The Water Chemistry Control -

Auxiliary Systems Program is an existing program that manages loss of material, cracking, and fouling for components exposed to treated water.

Program activities include sampling and analysis to minimize component exposure to aggressive environments for NaOH components in the containment spray system (IP3 only),

security generator cooling water system, city water components, and stator cooling water.

(Ref. 5.8)

QA audits of the chemistry control program in 2005 and 2006 found that compliance with all EPRI and INPO guidelines for chemistry performance was satisfactory, and that sufficient parameters are measured to detect abnormal conditions or changes to conditions.

All chemistry parameters were found to be maintained within specified bands, and auxiliary systems were found to be treated and controlled to industry guidelines.

Adherence to chemistry specifications provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.211, 5.212) 4.1.29 Water Chemistry Control - Closed Cooling Water Program The Water Chemistry Control - Closed Cooling Water Program is an existing program that includes preventive measures that manage loss of material, cracking, or fouling for components in closed cooling water systems (component cooling water (CCW), instrument air closed cooling (IACC), emergency diesel generator cooling, Appendix R/SBO diesel generator cooling, conventional closed cooling (CCC) (IP2 only), and turbine hall closed cooling (THCC)

(IP3 only). These chemistry activities provide for monitoring and controlling closed cooling water chemistry using IPEC procedures and processes based on EPRI guidance for closed cooling water chemistry. (Ref. 5.8)

In June 2003, it was noted that CCW corrosion chemistry control (molybdate concentration) had been out of specification 50% of the time since the new specification was issued in March 2003, due to dilution when water was added to this system to compensate for leaks and work activities.

Corrective action was taken to fix the leaks and perform a chemical addition to restore the molybdate concentration to specification.

Subsequently, corrosion inhibitor concentration has been satisfactory.

Identification of out-of-specification conditions and corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects for passive components. (Ref. 5.214)

A QA audit of the plant chemistry program was conducted in August 2003.

This audit identified the control of closed cooling water chemistry at IP2 as one of the specific areas which had improved since the last audit.

Continuous program improvement provides assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.213)

Reports of CCW chemistry control indicators (corrosion inhibitor and hardness) show that IP2 and I P3 CCW chemistry was within specification throughout 2006 except for part of May when the IP2 system was in maintenance status during 2R17. A review of online chemistry data during 2002 to 2005 revealed similar results. Adherence to chemistry specifications provides assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.215, 5.249)

IPEC00186138

IPEC License Renewal Project Operating Experience Review Report 4.1.30 Water Chemistry Control - Primary and Secondary Program IP-RPT LRD05 Revision 3 Page 92 of 119 The Water Chemistry Control - Primary and Secondary Program is an existing program that manages aging effects caused by corrosion and cracking mechanisms. The program relies on monitoring and control of reactor water chemistry based on the EPRI guidelines in TR-105714, Rev. 5, Pressurized Water Reactor Primary Water Chemistry Guidelines and TR-102134, Rev.

6, Pressurized Water Reactor Secondary Chemistry Guidelines. (Ref. 5.8)

A QA audit of the primary and secondary plant chemistry program was conducted in August 2003.

This audit noted that monitoring and processing requirements for Primary and Secondary water chemistry complied with both IP2 and IP3 technical specifications, implementing procedures, and the IP3 Technical Requirements Manual (TRM). In addition, the chemistry processes were effective in implementing industry guidelines, such as EPRI and INPO, designed to extend the operating life of primary and secondary systems and components.

Conformance to procedural requirements and industry guidelines provides assurance that the program will remain effective for managing loss of material of components.

(Ref. 5.213)

Reports of primary chemistry control indicators (lithium, chlorides, fluorine, sulfites) show that IP2 lithium was out of specification during March through August 2006 due to high dilution rates related to 2R 17 activities. Reports of secondary chemistry control indicators (hydrazine and pH control) show that IP2 hydrazine was out of specification low in part of October November 2006 during condenser backwashing, and ethanolamine (ETA) was out of specification high immediately following plant startup. IP3 primary and secondary chemistry were within specification throughout 2006. A review of online chemistry data during 2002 to 2005 revealed similar results. Adherence to chemistry specifications provides assurance that the program will remain effective for managing loss of material of components. (Ref. 5.216, 5.217, 5.218, 5.219, 5.249) 4.1.31 Heat Exchanger Monitoring Program The Heat Exchanger Monitoring Program is an existing plant-specific program that inspects heat exchangers for loss of material through visual or other non-destructive examination. Heat exchanger tubes are inspected at frequencies based on plant-specific and application-specific knowledge, as well as past history, heat exchanger operating conditions, and heat exchanger availability.

Inspection frequencies may be changed based on engineering evaluation of inspection results. (Ref. 5.8)

Results of eddy current testing of the tubes for several different IP2 heat exchangers during 2000 through 2006 have been used to make decisions for which tubes should be plugged, thus preventing the loss of the pressure boundary intended function.

Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components. (Ref. 5.258)

A review of the IP2 heat exchanger inspection plan was completed in September 2003. This review compared the scope of the IP2 inspections planned for 2R16 against the typical scope of inspections planned for an IP3 refueling outage.

Recommended changes in the IP2 inspection scope were identified and implemented.

Program documentation similar to that originally developed for IP3 was produced. Use of shared "best practices" in the development IPEC00186139

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 93 of 119 of inspection plans provides assurance that the program will remain effective for managing aging effects for passive components.

(Ref. 5.259)

Results of eddy current testing of the tubes for several different IP3 heat exchangers during 1997 through 2004 have been used to make decisions for which tubes should be plugged, thus preventing the loss of the pressure boundary intended function.

Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects for passive components.

(Ref. 5.260)

A review of inspection intervals for IP3 components was performed in April 2003. This review was used to construct Revision 14 of the "Eddy Current Program Action Plan." This ongoing plan includes programmatic and technical activities for a wide range of heat exchangers at IP3, and is used to track improvements and corrective actions for the program. Identification of program weaknesses, and subsequent corrective actions, provide assurance that the program will remain effective for managing loss of material of components. (Ref. 5.261, 5.262)

IPEC00186140

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 94 of 119 5.0 References 5.1 Industry Guideline for Implementing the Requirements of 10 CFR Part 54 -

The License Renewal Rule, NEI 95-10, Revision 6, June 2005 5.2 IPEC-LRPG-12, Operating Experience Review 5.3 NUREG 1801, Generic Aging Lessons Learned (GALL) Report, Revision 1, September 2005 5.4 Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, EPRI, Palo Alto, CA: 2006. 1010639 5.5 Aging Effects for Structures and Structural Components, Revision 1, EPRI, Palo Alto, CA: 2003. 1002950 (Structural Tools) 5.6 License Renewal Electrical Handbook: EPRI, Palo Alto, CA: 2001. 1003057 5.7 IP-RPT-06-LRD02, Aging Management Program Evaluation Results -

Class 1 Mechanical 5.8 IP-RPT-06-LRD07, Aging Management Program Evaluation Results -

Non Class 1 Mechanical 5.9 IP-RPT-06-LRD08, Aging Management Program Evaluation Results-Structural/Civil 5.10 IP-RPT-06-LRD09, Aging Management Program Evaluation Results-Electrical 5.11 EPRI TR-110089, Experience Based Interview Process for Power Plant Management, With a Pilot Application to Aging of Outage Support Equipment, March 1999.

5.12 EN-LI-102, Corrective Action Process, Revision 7 5.13 EN-OE-100, Operating Experience Program, Revision 2 5.14 IPEC-LRPG-07, Evaluation of Aging Management Programs 5.15 EN-MS-S-011-MULTI, Rev. 2, Conduct of System Engineering 5.16 NET-173-01, Criticality Analysis for Soluble Boron and Burnup Credit in the Con Edison Indian Point Unit No. 2 Spent Fuel Storage Racks 5.17 NET-217-01, BADGER Test Campaign at Indian Point Unit 2, 11/4/2003 5.18 CR-WP0-2004-0007, Review of the Boral surveillance programs for the ENN fleet, 1/22/2004 5.19 LO-OEN-2003-00391, Review of NRC21-031006 Part 21-Boral Spent Fuel Pool Test Coupons, 11/21/2003 5.20 3-PT-5Y5 Results, Surveillance Examination of Boral Neutron Absorber Material 5/6/2002 5.21 2-PI-M002 Results, Containment Building Inspection, 11/22/2005 5.22 CR-IP2-2005-01414, Minor leaks (evidence of leakage; i.e. boron buildup), 4/11/2005 5.23 3-PT-R114 Results, RCS Boric Acid Leakage and Corrosion Inspection, 3/11/2005 5.24 CR-IP3-2005-01 031, Reactor Coolant Pump main flange leak, 3/13/2005 5.25 CR-IP3-2005-01032, Reactor Coolant Pump main flange leak, 3/13/2005 5.26 CR-IP3-2005-01050, Reactor Coolant Pump main flange leak, 3/13/2005 5.27 3-PT-R114A Results, Reactor Vessel and Closure Head Boric Acid Leakage and Corrosion Inspection, 3/23/2005 5.28 CR-IP3-2005-01479, Indications of boric acid on RPV head, 3/24/2005 5.29 CR-IP3-2005-01214, Boric acid residue adjacent to a portion of the head penetrations, 3/17/2005 5.30 CR-IP3-2005-01487, Boric acid deposits at head penetrations, 3/24/2005 5.31 ENN-DC-319, Alloy 600 I Boric Acid Corrosion Control Program, Revision 3 5.32 NET-206-01, Inspection and Testing of BORAL Surveillance Coupons from the Indian Point Unit No. 3, Revision 1, 8/23/2002 IPEC00186141

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 95 of 119 5.33 IP-RPT-05-00397, Report of IWE Inspection for IP2 performed in 2004 5.34 CR-IP2-2005-02922, IP2 IWE 2R16 Containment Inspection not issued in a timely fashion, 7/14/2005 5.35 IP-RPT-05-00282 Report of IWE Inspection for IP3 performed in 2005 5.36 IP-RPT-06-00019, Report of IWL Inspection for IP2 performed in 2005 5.37 IP-RPT-06-00013, Report of IWL Inspection for IP3 performed in 2005 5.38 CR-IP2-2006-02795, IWE UT thickness of Liner Opening #9, 5/8/2006 5.39 CR-IP2-2006-03060, Surface indications noted on VC liner during IWE inspection, 5/15/2006 5.40 CR-IP3-2005-01587, IWE General Visual Containment Liner inspections, 3/26/2005 5.41 LO-IP3-L0-2003-00261, Focused Self-Assessment on Code Programs, 2/20/2003 5.42 LO-IP3-L0-2004-00223, Benchmark on valve scope for outages, 1/15/2004 5.43 CR-IP2-2006-02113, Results of Integrated Leak Rate Test, 4/24/2006 5.44 Results of U3 Containment Leak Rate Testing, 2001-2006 5.45 CR-IP2-2001-07431, EDG Fuel Oil Delivery received on 7/14/01, 7/26/2001 5.46 CR-IP2-2001-08468, EDG Fuel Oil Delivery received on 8/22/01, 8/31/2001 5.47 CR-IP2-2002-02529, EDG Fuel Oil Delivery received on 2/22/02, 3/7/2002 5.48 CR-IP2-2003-00612, Results of testing of EDG Fuel Oil Underground Tank, 1/31/2003 5.49 CR-IP2-2003-01511, EDG Fuel Oil Delivery received on 3/4/03, 3/14/2003 5.50 CR-IP2-2003-05797, Bacteria growth in EDG underground diesel fuel tank, 9/18/2003 5.51 QA Audit Report A03-03-I, Boron Inspection, May 2003 5.52 CR-IP2-2001-07815, Incorrect inputs in EQ analysis, 8/9/2001 5.53 CR-IP2-2002-06651, QA findings from audit of IP3 EQ Program, 7/3/2002 5.54 CR-IP2-2003-00149, Improper scheduling of EQ Work Orders, 1/9/2003 5.55 CR-IP2-2003-01023, Impact Review of EQ Program inputs for IP2 Power Uprate, 2/20/2003 5.56 CR-IP2-2003-05766, Findings from IP2 EQ Master List (EQML) validation, 9/17/2003 5.57 CR-IP2-2004-05010, Findings from IP2 EQ Master List (EQML) validation. 10/20/2004 5.58 CR-IP2-2005-00079, Review of EQ Program administrative documents, 1/7/2005 5.59 CR-IP3-2004-03027, EQ Program Action Plan, 8/30/2004 5.60 CR-IP3-2006-00080, EQ documentation deficiency, 1/10/2006 5.61 LO-IP3L0-2002-00056, Focused self-assessment on "EQ Program," 6/3/2002 5.62 WT-IP3-2004-00000 CA-00245, I&C actions for EQ Program, 6/2/2004 5.63 IDEE-APL-04-001, IPEC EQ Program Enhancements, 12/2/2004 5.64 QS-2005-IP-002, QA Surveillance of ILRT during 3R13, 3/28/2005 5.65 QS-2006-IP-003, QA Surveillance of ILRT during 2R17, 5/15/2006 5.66 CR-IP2-2001-04341, Corrosion noted at isophase bus heat exchangers, 5/3/2001 5.67 CR-IP2-2001-04881, Corrosion noted on baseplate at Oxygen Tank Farm, 5/17/2001 5.68 CR-IP2-2004-00837, Corrosion noted on sodium hypochlorite transfer pump (HFCLP-22), 2/19/2004 5.69 CR-IP2-2006-03917, Corrosion on Unit 2 SW discharge piping, 6/27/2006 5.70 CR-IP3-2003-01099, Steam leak noted on MS-186 (Auxiliary Steam supply to the Gland Sealing System check valve), 3/9/2003 5.71 EN-DC-178, System Walkdowns, Revision 0 5.72 EN-DC-178, System Walkdowns, Revision 1 5.73 QS-2004-IP-10, Technical Specification 3.8.3 Diesel Fuel Oil, 8/9/2004 5.74 CR-IP3-2004-02563, Diesel fuel oil samples, 7/21/2004 5.75 CR-IP3-2004-02567, Diesel fuel oil sample reports, 7/21/2004 IPEC00186142

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 96 of 119 5.76 WCAP-12191, Transient History Evaluation Report for IP2 Addendum 1, Revision 3, September 2003 5.77 Calculation SCS-03-19, Design Transients for IP3 Stretch Power Uprate, Revision 1, 5/23/2005 5.78 NRC Letter RA-04-064, Indian Point Unit 2 - NRC Triennial Fire Protection Inspection Report 05000247/2004005, 8/20/2004 5.79 NRC Letter RA-05-011, Indian Point Unit 3-NRC Triennial Fire Protection Inspection Report 05000286/2005006, 3/3/2005 5.80 QA-09-2005-IP-1, Fire Protection Program Audit, 12/12/2005 5.81 QA-09-2006-IP-1, Fire Protection Program Audit, 1/19/2006 5.82 A03-12-1, Fire Protection Program Audit, 10/21/2003 5.83 CR-IP2-2003-02253, Fire barrier inspection list deficiencies, 4/16/2003 5.84 CR-IP2-2004-01144, Discrepancies in fire barrier wrap, 3/10/2004 5.85 CR-IP3-2001-02863, Tear in fire barrier wrap, 7/12/2001 5.86 CR-IP3-2002-04716, Performance of 3PT-R113 indicates degraded flow in firewater distribution system, 11/27/2002 5.87 CR-IP3-2003-03608, Fire protection water spray system nozzles, 6/11/2003 5.88 ENN-DC-315, Flow Accelerated Corrosion Program, Revision 0 5.89 2-PT-2Y15 Results, Thermal Cycling Monitoring Program, 5/24/2005 5.90 3-PT-M051 Results, Plant Operation Information, 10/23/2006 5.91 2-PT-A017A Results, Fire Hose Stations, 11/26/2006 5.92 3-PT-A44 Results, Fire Hydrant Flow Check, 4/26/2006 5.93 3-PT-R47 Results, Fire Hose Station Surveillance, 9/13/2005 5.94 3-PT-R113 Results, High Pressure Water Fire Protection System Flush and Loop Flow Determinations, 7/29/2006 5.95 3-PT-SA27C Results, Wet Pipe Sprinkler Systems, 9/8/2006 5.96 3-PT-SA18 Results, Fire Hydrant Inspection, 4/26/2006 5.97 PT-A19 Results, Fire Hydrant Flow Test, 6/21/2006 5.98 Calculation No. 050714b-01, IP2 CHECWORKS FAC Model, 7/28/2005 5.99 LO-IP3L0-2006-0006, FAC Program Self-Assessment, 1/3/2006 5.100 Calculation No. 94-10.1-05, IP3 CHECWORKS Global Input, 1/29/2003 5.101 QS-2006-IP-013, QA Surveillance of FAC Program during 2R 17, 6/20/2006 5.102 QS-2005-IP-015, QA Surveillance of FAC Program during 3R13, 5/16/2005 5.103 QS-2005-IP-014, QA Surveillance of BMI and RVH Penetration Inspections during 3R13, 5/3/2005 5.104 QS-2006-IP-014, QA Surveillance of BMI and RVH Penetration Inspections during 2R17, 7/19/2006 5.105 QA-08-2004-IP-1, IPEC Engineering Programs Audit, 12/30/2004 5.106 IP-RPT-05-00242, 3R131nservice Inspection Report, 9/12/2005 5.107 IP-RPT-05-00243, 2R161nservice Inspection Report, 7/28/2005 5.108 QS-2006-IP-011, QA Surveillance of lSI during 2R17, 5/25/2006 5.109 QS-2005-IP-006, QA Surveillance of lSI at IP3, 2/28/2005 5.110 QA-08-2005-1 P-1, I PEC Unit 3 Engineering Programs Audit, 5/5/2005 5.111 CR-IP2-2003-06540, Inspection of IP2 Fire Water Storage Tank (300KFPT),

10/28/2003 5.112 CR-IP2-2004-06597, Atmospheric tank inspection at CST, 12/4/2004 5.113 CR-IP3-2003-04755, Inspection of fire water storage tank (HTC-FP-T-1), 8/18/2003 5.114 CR-IP3-2005-04312, Self-Assessment of AFW System, 9/8/2005 IPEC00186143

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 97 of 119 5.115 CR-IP3-2003-04041, Walkdown of the top of the CST, 7/3/2003 5.116 CR-IP2-2001-02199, Carbon steel bolting on top of charging pump, 3/5/2001 5.117 CR-1 P2-2002-08276, lSI of 23 SIS pump, 9/5/2002 5.118 CR-IP2-2002-09396, Bolted Connection Inspection, 10/21/2002 5.119 CR-IP2-2002-09397, Bolted Connection Inspection, 10/21/2002 5.120 CR-IP2-2004-01196, Shift Manager walk down, 3/12/2004 5.121 CR-IP2-2006-00591, Bolted Connection Inspection, 2/7/2006 5.122 CR-IP2-2006-00614, Bolted Connection Inspection, 2/8/2006 5.123 CR-IP2-2006-00669, Bolted Connection Inspection, 2/10/2006 5.124 CR-IP3-2001-01162, System Engineering walk-down, 4/2/2001 5.125 CR-IP3-2003-00075, Loose bolting found during PM, 1/7/2003 5.126 CR-IP3-2003-01624, VC inspection, CR-IP3-2003-01624 5.127 CR-IP3-2005-01305, lSI inspection of 31 Fan Cooler Unit, 3/19/2005 5.128 CR-IP3-2005-01308, lSI inspection of31 S/G hotleg bolting, 3/19/2005 5.129 2-PI-M009 Results, Aboveground Petroleum Storage Tanks, 12/10/2006 5.130 2-PT-R075 Results, RCS Integrity Inspection, 5/17/2006 5.131 3-PT-R131 Results, RCS Integrity Leak Test, 4/5/2005 5.132 2-PT-M040 Results, Diesel Fire Pump, 11/11/2006 5.133 3-PT-M042B Results, Diesel Fire Pump Test, 11/2/2006 5.134 CR-IP2-2000-07403, Review of NRC Information Notice 2000-14, 10/02/2000 5.135 WO-IP2-02-31082, Bus 2A Inspection, 5/1/2006 5.136 2-PT-R156 Results, RCS Boric Acid Leakage and Corrosion Inspection, 5/8/2006 5.137 0-ELC-403-BUS, Inspection and Cleaning of 480 Volt Bus Duct, Revision 0 5.138 0-ELC-404-BUS, Inspection and Cleaning of 6.9KV Bus Duct, Revision 0 5.139 NL-05-002, Reactor Vessel Lower Head Inspection Results at IP2 (2R16), 1/17/2005 5.140 NL-05-063, Reactor Vessel Lower Head Inspection Results at IP3 (3R13), 5/31/2005 5.141 LO-WPOL0-2004-00051, lSI snapshot assessment for IPEC, 10/19/2004 5.142 LO-WPOL0-2005-00046, lSI snapshot assessment for IP2, 04/28/2005 5.143 NL-05-001, Reactor Vessel Upper Head Inspection Results at IP2 (2R16), 1/17/2005 5.144 NL-05-044, Reactor Vessel Upper Head Inspection Results at IP3 (3R13), 5/31/2005 5.145 2-PT-R203 Results, Visual Examination of Reactor Vessel Head Penetrations and Head Surface for Leakage, 5/8/2006 5.146 NL-02-006, Response to RAI IP2 License Amendment Request for RCS Heatup and Cooldown Limitation Curves (TAC No.: MB2419), 1/11/2002 5.147 CORR-04-00246, IP2 Reactor Vessel Surveillance Capsule Withdrawal Schedule Change (TAC No.: MB5069), 11/16/2004 5.148 CN-RCDA-03-88, IP3 Stretch Power Uprate Evaluation for Reactor Vessel Integrity, 12/2/2003 5.149 CN-REA-03-50, IP3 RPV Fluence Evaluation for Uprate, 11/5/2003 5.150 NL-04-092, Capsule X Material Surveillance Report for IP3, 7/29/2004 5.151 not used 5.152 not used 5.153 Results of PT-R075 (IP2 VC) bolted connection inspections, May 2006 5.154 Results of PI-3Y17 (IP2 PAB) bolted connection inspections, February 2006 5.155 LO-IP3L0-2006-00318, Self-assessment of IPEC RPV Head Visual Examination Process, 8/9/2006 5.156 CR-IP2-2006-04771, 2R 17 feedback for 2-PT-R203, 8/9/2006 5.157 CR-IP3-2006-02483, 2R 17 feedback for 3-PT-R203, 8/9/2006 IPEC00186144

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 98 of 119 5.158 Results of diesel fuel oil sample analysis reports [hard-copy format in License Renewal Group files], 2001-2005 5.159 IP-RPT-05-00412 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for the Unit 2 Turbine Building, 3/6/2006 5.160 IP-RPT-05-00090 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP3, 8/24/2005 5.161 IP-RPT-05-00311 Revision 0, Maintenance Rule Structural Monitoring Inspection Report for IP3 Control Building, 12/30/2005 5.162 IP-RPT-05-00439 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP2 Fuel Storage Building, 9/28/2006 5.163 IP-RPT-05-00441 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP2 Fan House, 9/27/2006 5.164 IP-RPT-05-00442 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for City Water Metering House, 9/28/2006 5.165 IP-RPT-05-00444 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP2 Control Building, 9/27/2006 5.166 IP-RPT-06-00162 Revision 0, Maintenance Rule Structural Monitoring Inspection Report for IP3 Fan House, 11/15/2006 5.167 IP-RPT-06-00181 Revision 0, Maintenance Rule Structural Monitoring Inspection Report for IP3 Fuel Storage Building, 11/15/2006 5.168 IP-RPT-05-00414 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for GT1 Building, 9/27/2006 5.169 IP-RPT-05-00415 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP2 EDG Building, 3/6/2006 5.170 IP-RPT-05-00420 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for Utility Tunnel, 11/10/2006 5.171 IP-RPT-05-00425 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for Maintenance & Outage Building, 12/20/2005 5.172 IP-RPT-05-00427 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for Auxiliary Boiler Feedwater Building, 8/28/2006 5.173 IP-RPT-05-00428 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP2 Electrical Tunnel, 9/26/2006 5.174 IP-RPT-05-00434 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for Radiation Monitoring Building, 8/29/2006 5.175 IP-RPT-05-00435 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for GT3 Building, 9/7/2006 5.176 IP-RPT-05-00445 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP31 Turbine Building, 9/27/2006 5.177 IP-RPT-05-00446 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for Gas Turbine #2 & #3 Fuel Tank Foundation, 8/28/2006 5.178 IP-RPT-05-00447 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for GT2 Building, 9/7/2006 5.179 IP-RPT-05-00448 Revision 1, Maintenance Rule Structural Monitoring Inspection Report for IP2 Boric Acid Building, 8/24/2006 5.180 IP-RPT-05-00642 Revision 0, Maintenance Rule Structural Monitoring Inspection Report for Power Conversion Equipment Building, 12/30/2005 5.181 E-mail from John Whitney [EDG system engineer], 12/20/2006 5.182 Predictive Maintenance Action Plan, June 2006 IPEC00186145

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 99 of 119 5.183 Predictive Maintenance Watch Report, 10/6/2006 5.184 Oil Analysis Sample Reports, 1999-2006 5.185 CR-IP2-2001-04818, Oil sample from #23 Safety Injection Pump, 5/16/2001 5.186 CR-IP2-2002-09961, Oil analysis performed on #24 RCP lower bearing, 11/1/2002 5.187 CR-IP3-2002-02050, Oil analysis results for #32 EDG, 6/6/2002 5.188 CR-IP3-2003-03903, Unit 3 Diesel Fire Pump engine crankcase oil analysis, 6/26/2003 5.189 IP2 4Q2005 NRC Integrated Inspection Report, 2/7/2006 5.190 IP3 2Q2006 NRC Integrated Inspection Report, 7/24/2006 5.191 IP3 4Q2005 NRC Integrated Inspection Report, 2/8/2006 5.192 I P3-RPT -U NSPEC-03499 Revision 1, I P2 & I P3 Eddy Current Program, 9/7/2006 5.193 CR-IP2-2006-03974, Eddy Current Testing method, 06/29/2006 5.194 SEP-SW-001, GL 89-13 Service Water Program, 2/7/2006 5.195 LO-IP3L0-2003-00480, EPRI Peer Assessment on "IP3 Service Water System,"

09/25/2003 5.196 LO-IP3L0-2004-00167, Focused Self-Assessment on IP2 Ultimate heat Sink, 1/14/2004 5.197 LO-IP3L0-2006-00026, Snapshot Self-Assessment on IP2 GL 89-13 Program, 1/4/2006 5.198 LO-IP3L0-2005-00143, Focused Self-Assessment on IP3 Ultimate heat Sink, 1/27/2005 5.199 QS-2006-IP-001, QA Surveillance of Steam Generator Eddy Current Inspections during 2R17, 5/18/2006 5.200 IP-RPT-04-00206 Revision 1, IP2 Steam Generator Program, 6/29/2005 5.201 ENN-DC-190, Steam Generator Eddy Current Data Analysis, 12/8/2005 5.202 IP3-RPT-SG-03800, Steam Generator Degradation Assessment for IP3 3R12, 3/3/2003 5.203 IP3 2Q2003 NRC Integrated Inspection Report, 8/4/2003 5.204 IP3-RPT-SG-01796 Revision 7, IP3 Steam Generator Program, 7/1/2005 5.205 IP-RPT-05-00408 Revision 1, Steam Generator Degradation Assessment and Repair Criteria for 2R17, 4/18/2006 5.206 LO-WPOL0-2004-00044, IN PO Steam Generator Review Visit, 10/5/2004 5.207 IP2 2Q2006 NRC Integrated Inspection Report, 8/11/2006 5.208 NL-06-067, Steam Generator Examination Program Results 2R17, 6/14/2006 5.209 IP-RPT-05-00317, Steam Generator Examination Results (3R12) -

Secondary, 9/22/2005 5.210 IP-RPT-05-00318, Steam Generator Examination Results (3R12)- Primary, 9/22/2005 5.211 QA-02-2005-IP-1, Chemistry Program Audit, 7/1/2005 5.212 QA-02-2006-IP-1, Chemistry Program Audit, 10/31/06 5.213 A03-07 -1, Chemistry Program Audit, 8/13/2003 5.214 CR-IP2-2003-03987, CCW corrosion chemistry control, 6/20/2003 5.215 Chemistry Performance Indicator Report for CCW, November 2006 5.216 Chemistry Performance Indicator Report for IP2 Primary, November 2006 5.217 Chemistry Performance Indicator Report for IP3 Primary, November 2006 5.218 Chemistry Performance Indicator Report for IP2 Secondary, November 2006 5.219 Chemistry Performance Indicator Report for IP3 Secondary, November 2006 5.220 NET-217-01, BADGER Test Campaign at Indian Point Unit 2, 12/19/2006 5.221 Results of 1989 Flux Thimble Tube Inspection at IP2, 5/5/1989 5.222 IP-DSE-01-058, Review of 3R11 RPV Thimble Tube Eddy Current Inspection Results, 5/11/2001 IPEC00186146

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 00 of 119 5.223 IP-RPT-06-00182, Third Eddy Current Inspection of lncore Thimble Tubes at IP3, 4/26/1992 5.224 IP-RPT-06-001824, Fourth Eddy Current Inspection of lncore Thimble Tubes at IP3, 5/27/1997 5.225 E-mail from Nelson Azevedo [IPEC Code Programs Engineering Supervisor], IP2 Flux Thimble Tube Inspection Results Discussion, 1/10/2007 5.226 CR-IP2-2002-03598, GT2/3 Tank Inspection, 5/5/2002 [License Renewal shared directory]

5.227 NaOH Storage Tank #31 - 2004 Inspection Results, 8/23/2004 5.228 3-PT-M090 Results, Appendix R DG Functional Test, 12/11/2006 5.229 WO-IP2-04-14604, #22 EDG Inspection, 7/13/2006 5.230 WO-IP2-04-14607, #23 EDG Inspection, 8/9/2006 5.231 WO-IP2-04-14608, #23 EDG Inspection, 8/9/2006 5.232 WO-IP2-04-26645, #22 EDG Inspection, 7/11/2006 5.233 WO-IP3-02-20705, #32 EDG Inspection, 7/6/2005 5.234 WO-IP3-03-20054, #31 EDG Inspection, 6/8/2005 5.235 WO-IP3-02-20696, #31 EDG Inspection, 6/9/2005 5.236 WO-IP3-03-19574, #31 EDG Inspection, 5/9/2005 5.237 WO-IP3-05-10408, Security Generator Inspection, 12/16/2005 5.238 WO-IP3-02-22228, Appendix R DG Inspection, 9/21/2006 5.239 WO-IP3-02-20714, #33 EDG Inspection, 8/3/2005 5.240 RE-ICI-91 0625, Calculation of lncore Thimble Tube Wear, 6/25/1991 5.241 2-PT-R016 Results, #21 and #22 Recirculation Pump Tests, 5/15/2006 5.242 3-PT-R013 Results, #31 and #32 Recirculation Pump Tests, 3/26/2005 5.243 WO-IP2-01-21925, Security Generator Overhaul, 1/11/2002 5.244 WO-IP2-04-28200, IP2 Polar Crane Inspection, 5/17/2006 5.245 WO-IP3-04-16166, IP3 Polar Crane Inspection, 3/8/2005 5.246 WO-IP3-99-03493, IP3 Polar Crane Inspection, 2/2/2001 5.24 7 PT -SA 11 Results, I P2 Diesel Generator Building Check, 10/6/2006 5.248 CR-IP2-2006-05827, Create tasks to test floor drains, 1/16/2007 5.249 Online chemistry data for IP2 and IP3 5.250 NRC Generic Letter 88-14, Instrument Air System Supply Problems Affecting Safety-Related Equipment 5.251 NRC Information Notice 81-38, Potentially Significant Equipment Failures Resulting From Contamination of Air-Operated Systems 5.252 NRC Information Notice 87-28, Air Systems Problems at U.S. Light Water Reactors 5.253 NRC Information Notice 99-01, Deterioration of High Efficiency Particulate Air Filters in a Pressurized Water Reactor Containment Fan Cooler Unit 5.254 IN PO Significant Operating Experience Report 88-01, Instrument Air System Failures 5.255 NRC Information Notice 89-26, Instrument Air Supply to Safety-Related Equipment 5.256 INPO Significant Event Report 1-99, Air-Operated Valve Performance 5.257 NRC Information Notice 02-29, Recent Design Problems in Safety Functions of Pneumatic Systems 5.258 Online postings of heat exchanger eddy current (ET) test results 5.259 LO-IP3L0-2003-00478, Self-assessment of 2R16 Eddy Current Inspection Scope, 9/23/2003 5.260 IP3 Heat Exchanger ECT results thru April 2004 IPEC00186147

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page101of119 5.261 IP3 PEP-DPP-2003-021, 3R12 BOP Heat Exchanger Eddy Current Inspection Summary, 4/25/2003 5.262 PEP-APL-95-005 Revision 14, IP3 Heat Exchanger ECT Action Plan, 5/11/2004 5.263 2-PT-Q33C Results, #23 Charging Pump Inspection, 11/7/2006 5.264 3-PT-Q062A Results, #31 Charging Pump Inspection, 2/24/2007 5.265 3-PT-Q062B Results, #32 Charging Pump Inspection, 1/12/2007 5.266 3-PT-Q062C Results, #33 Charging Pump Inspection, 2/13/2007 5.267 PT-Q33A Results, #21 Charging Pump Inspection, 3/8/2007 5.268 PT-Q33B Results, #22 Charging Pump Inspection, 1/5/2007 5.269 CR-IP3-2005-01149, FAC on High Pressure Turbine Drain Piping, 3/16/2005 5.270 CR-IP3-2005-01446, FAC on 3-inch Elbow, 3/23/2005 5.271 CR-IP2-2004-05748, Loose bolts on #21 EDG bus joint, 11/6/2004 5.272 PI-SA 2 Results, Atmospheric Tanks Inspection, 9/7/2007 5.273 2R18 GL 89-13 Inspection Results IPEC00186148

IPEC License Renewal Project Operating Experience Review Report - System Engineers Interviewed System System Engineer Auxiliary Feedwater Juan Pineda Slowdown Tom Foley Civil/Structural Bulk Commodities Liz Lee CVCS-Chemical and Volume Tat Chan Control System Component Cooling Matt Johnson Compressed Air Mike Dries Containment Isolation Moto lmai Containment Penetrations Containment Spray Juan Pineda Diesel Generators John Whitney Electrical Commodities Chris Ingrassia Fire Protection - C02, Halon Steve Wilkie Fire Protection - Water Steve Wilkie Fuel Oil John Whitney HVAC, Control Room HVAC, Ivan Sinert Containment Cooling & Filtra.

Main Feedwater Tom Foley Main Steam Mike Kempski Nitrogen Matt Johnson Pressurizer Jim O'Driscoll Primary Makeup Liz Lee Residual Heat Removal Dean Shah Reactor Coolant System, Jim O'Driscoll Reactor Pressure Vessel, Reactor Vessel Internals Safety Injection Dean Shah Service Water Tom Beasley Spent Fuel Pool Cooling Matt Johnson Steam Generators Jim O'Driscoll IP-RPT LRDOS Revision 3 Page 1 02 of 119 IPEC00186149

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 03 of 119 - Program Owners Interviewed Program Program Owner Bolting Integrity Chuck Bristol Boraflex Monitoring Program-Unit 2 John Weiss Boral Monitoring Program-Unit 3 Floyd Gumble Boric Acid Corrosion Prevention Bob Herrmann Containment lnservice Inspection (CII)

Ed Rodriguez Program - Unit 2 Containment lnservice Inspection (CII)

Bob Dolansky Program - Unit 3 Containment Leak Rate-Unit 2 Chris Bergren Containment Leak Rate-Unit 3 Andy Mihalik Diesel Fuel Monitoring Program Dan Wilson EQ-Equipment Qualification Jim Tuohy, Abdul Bokhari, John Kaczor Fatigue Monitoring Nelson Azevedo Fire Protection Program Steve Wilkie Fire Water System Program Steve Wilkie Flow Accelerated Corrosion Harry Hartjen Flux Thimble Tube Inspection Nelson Azevedo lnservice Inspection (lSI) Program-Unit 2 Ed Rodriguez lnservice Inspection (lSI) Program-Unit 3 Bob Dolansky Masonry Wall Program - Unit 2 Dan Halama Masonry Wall Program - Unit 3 Rich Drake Metal Enclosed Bus Program Fred Schillinger, Lou Lubrano Nickel Alloy Inspection Nelson Azevedo Oil Analysis Jim Xenakis Reactor Head Closure Studs-Unit 2 Ed Rodriguez Reactor Head Closure Studs-Unit 3 Bob Dolansky Reactor Vessel Head Penetration Walt Wittich Inspection IPEC00186150

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 04 of 119 Program Program Owner Reactor Vessel Surveillance-Unit 2 Nelson Azevedo Reactor Vessel Surveillance-Unit 3 Floyd Gumble Service Water Integrity Joe Kayani Steam Generator Integrity-Unit 2 I Unit 3 Bob Cullen, Curt Ingram Structures Monitoring Program-Unit 2 Dan Halama Structures Monitoring Program-Unit 3 Rich Drake Water Chemistry Control -Auxiliary Dan Wilson Systems Program Water Chemistry Control -Closed Cooling Dan Wilson Water Program Water Chemistry Control-Primary &

Dan Wilson Secondary Program IPEC00186151

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRD05 Revision 3 Page 1 05 of 119 -Air and Gas Systems INTRODUCTION A

review of industry operating experience associated with nonsafety-related systems/components containing air/gas found six NRC documents and two INPO documents:

NRC Generic Letter 88-14 NRC Information Notices 81-38, 87-28, 89-26, 99-01, and 02-29 INPO Significant Operating Experience Report 88-01 INPO Significant Event Report 1-99 None of these documents described instances where nonsafety-related air/gas system leakage or ruptures adversely impacted safety-related equipment. (Ref. 5.250, 5.251, 5.252, 5.253, 5.254, 5.255, 5.256, 5.257)

A focused review of plant specific OE regarding air and gas systems is necessary to confirm that industry OE review results apply to the plant. If this is verified, then air and gas systems do not require an AMR under 10 CFR 54.4(a)(2).

METHOD Site operating experience during 2001-2005 was reviewed by performing keyword searches of IPEC CRs using the paperless condition reporting system (PCRS). Data fields included in the searches were those containing the condition description, summary description, closure description, and operability description. Keyword searches of operating history during 2001-2005 were performed using the keywords instrument air, gas, nitrogen, N2, oxygen, 02, hydrogen, H2, argon, Freon, halon, and carbon dioxide.

RESULTS The keyword searches resulted in over 2300 hits for IP2 and over 1400 hits for IP3. Search results were screened to determine whether the identified condition involved air or gas systems, see list below. The condition description, summary description, closure description, and operability description for the following condition reports were reviewed to determine if an aging mechanism or aging effect was linked to the reported condition.

CR-1 P2-2001-00017 Main Generator Hydrogen Cooler 22 South section has indication of a tube leak. 100% Hydrogen gas is present when venting cooler section.

CR-1 P2-2001-02159 13 and 14 WDST EHT Chromolox controllers have a history of failures due to control cabinet water intrusion. On Feb. 26 these cabinets were inspected by Maintenance and gaskets, conduits and face places were found to be in good condition.

CR-1 P2-2001-05830 During the restoration of tagout #14927 on #21 Instrument Air Compressor it was noted that the 3/4 inch union upstream of drain valve CC-60-2 was leaking closed coolant. The leak was probably caused by work which was done on the drain valve.

CR-1 P2-2001-08250 In the performance of PT-M63C, Rev #4, Gas Turbine #3 Batteries, It was discovered that the following cells, # 60, # 20, & #1 0, on the MAIN battery bank, had broken SPARK ARRESTORS. This does not constitute a failure of PT-M63C.

CR-1 P2-2001-09241 During the Annual Walkdown on the Gas Turbines it was found on the GT3 Blackstart diesel that its exhaust stack has a minor exhaust leak located at the joint between the expansion joint and the lower end of the muffler.

IPEC00186152

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 06 of 119 -Air and Gas Systems CR-1 P2-2001-09408 Condition report 200100086 stated that the H2/ 02 sample tubing lines 607 and 630 appear to be sagging between supports. Under work order NP 01-19831, the insulation was removed and an inspection confirmed that the lines were sagging.

CR-1 P2-2001-097 43 Leaks exist at three locations on 22 House Service Boiler (22 HSB) at the interface of the mud drum and Firebox outer casing. Each leak is approximately two drops per second.

CR-IP2-2001-1 0005 During PT -M38B performed on Oct. 18m it was noticed that the blankflange on the bottom of the GT2 turbine shell has a combustion air leak. This is not an operability issue. The air leak reduces the efficiency of the turbine.

CR-IP2-2001-1 0215 The level of contamination in the Instrument Air Closed Cooling (IACC)

Water system has increased due to the recent upsets and biological growth including iron related bacteria.

CR-IP2-2001-11852 While performing step 4.1.3.(2) (e) of SOP 24.2.1 Instrument Air Closed Cooling System the compression fitting on the end of the line out of UW-51 0, City Water Drain Stop, fell off.

CR-1 P2-2002-01232 Small oil leak at Tl-5284 ant Pl5283 on upper dome of R4D4 (main turbine lube oil separator). The pressure instrument is small bore piping, may need thread sealant. The temperature indicator may need a new gasket or soft washer.

CR-1 P2-2002-02013 Chemistry and Reactor Engineering are monitoring a slowly increasing fuel defect. This is evidenced by the slowly increasing dose equivalent iodine concentration and the reactor coolant gas activity.

CR-1 P2-2002-08092 Hydrogen consumption on the Main Generator recently took a large step change. Hydrogen consumption has increased over a several day period.

Plant personnel have been involved with searches and evaluations of possible Hydrogen leak points on the Main Generator.

CR-1 P2-2002-09269 The following flange connections have light gasket leaks (boron), these flanges were inspected as part of the 2002 Carbon Steel Bolting Program (CSB).

Flange F-1, Line 215 Dwg 227830 Flange F-3, Line 207 Dwg 227822

1. 23 Charging Pump Suction Flange CR-1 P2-2002-09623 During the chemical degas of the reactor coolant system, approximately twice the calculated hydrogen peroxide quantity was required to reduce hydrogen to the desired concentration.

CR-1 P2-2002-1 0586 CST2 dissolved oxygen out of spec. high-1 06ppb.

CR-1 P2-2002-11229 Found pin hole leak thru a weld on valve 5EX-48-1, HOT Dump To Cond. 22 Drain Stop, on 5ft. of the Turbine Hall. This condition could have possible dissolved oxygen level increase.

CR-1 P2-2002-11345 CST oxygen is out of spec at 176 ppb. Upper limit is 100 ppb.

CR-1 P2-2002-11389 A leak on the weld upstream of SWT-47-8 (22 HYDROGEN COOLER NORTH SECTION DRAIN STOP) is leaking at approximately 2 drops per second. Leak is between cooler and drain stop.

CR-1 P2-2002-11594 There is approximately a 1 drop per second leak upstream of SWT-47-1 0 (22 Hydrogen Cooler North Section Vent Stop). The leak is dripping from the first elbow out of the 22AHC hydrogen cooler.

CR-IP2-2002-11612 Identified a thru wall leak at the North H2 cooler vent valve. The leak is from a welded connection that is upstream of the isolation.

IPEC00186153

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 07 of 119 -Air and Gas Systems CR-1 P2-2003-00695 Bulk hydrogen bank fittings and tubing are heavily coated with chemical precipitate leaching from the mortar of the Screenwell House. This substance might corrode and or degrade the material of the fittings, resulting in H2 leakage.

CR-1 P2-2003-01563 Unit #2 CST dissolved oxygen is high out of spec. This is due to the lowering of the level in the CST approx 2 ft in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

CR-1 P2-2003-02234 22 Hydrogen Cooler on the Main Generator is leaking water as identified by WRT IP2-03-05086. The repair is not scheduled until 7-21-03 and should be addressed sooner. The water drips on the side of the generator and is deteriorating the new paint job.

CR-1 P2-2003-0487 4 lnservice Large gas decay tank pressure is lowering slowly over the past 24hrs. In conjunction with eves HUT lo-pressure alarms we suspect a small leak on the vent header or eves HUT requiring more than normal make-up from the re-use header.

CR-1 P2-2003-05069 Condensate Storage Tank dissolved oxygen is out-of-spec high (1 03 ppb).

CR-1 P2-2003-05117 On 08/12/03 during routine walkdowns noted that there were leaks on weld joints on the 21 & 22 Degassing pumps. The leaks are located on drain lines located on the 53' and 36' elevations.

CR-1 P2-2003-05457 While performing ICPM 1458 (Nitrogen Supply to 100 PSI N2 Header), found PC-1 066 greater than 3 times out of specification (a/f 8.5 spec 1 0.6). This also was the case the last time the PM was performed in 2001.

CR-1 P2-2004-00272 Feedwater ETA increased above the limit of 3.0 ppm. Unit 2 CST recirculation rate was increased to approximately SOOgpm. ETA lowered to less than 3.0 ppm. Unit 2 CST Liquid Nitrogen consumption increased during this time frame. Transient N2 SOV was found to be open.

CR-1 P2-2004-02398 The Sl Accumulator# 23 is leaking nitrogen gas and it is being pressurized every 2 to 3 days since the beginning of this year. Since the Accumulator pressure is being maintained in spec by repressurizing with N2, the 23 Accumulator is operable.

CR-1 P2-2004-03584 The 22 Hydrazine feed pump was found airbound. The Secondary System Hydrazine concentration was 11 parts per billion (ppb). It must be maintained at least 8 times the Condensate Pump Discharge Dissolved Oxygen concentration (3.2 ppb)

CR-1 P2-2004-044 7 4 The Hydrazine concentration on the Condensate Pump Discharge (CPO) and the High Pressure Feedwater was found at 24 parts per billion (ppb). The CPO dissolved Oxygen was 4.57 ppb. The required minimum concentration is 8 times CPO dissolved oxygen. ( 8 x CR-1 P2-2004-05571 H2 leak north side of elbow upstream of HS-651. This is the brass elbow at the hose connection to the H2 fill line. The leak is on the valve side of the elbow not the hose side. The system is currently tagged & this leak should be repaired before the next CR-1 P2-2004-06198 The Main Turbine Lube Oil Reservoir was filled after work was completed on the Main Lube Oil Coolers. After placing the system in service an oil leak was identified on the North West End Bell. Also a service water leak was identified at the upstream flange of SWT-3. Service water and Lube Oil both had to be secured to the coolers and the Turbine Lube Reservoir was drained below the suction of the coolers. Another Tagout also had to be developed and applied. This resulted in a delay in restoring the system and subsequent systems such as Hydrogen Seal Oil.

IPEC00186154

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 08 of 119 -Air and Gas Systems CR-1 P2-2005-00034 After the water intrusion into the Instrument Air system/ Stator Cooling Water skid (see CR 05-00020), Operations performed the COL for the Instrument Air System in an attempt to identify the source of the water.

CR-1 P2-2005-00370 UT results indicated some nitrogen gas build-up in Safety Injection Piping line

1. 16 and Line# 56. Currently the 24 Sl Accumulator is leaking back to RWST about 0.14 gpm as documented in CR IP2-20004-06531.

CR-1 P2-2005-00466 The previous CR IP2-2005-00398 reported gas buildup in Safety Injection system due to 24 Sl Accumulator leak. In section 5.8 of the formal Operability Evaluation attached to that CR erroneously says "more recently all three Sl pumps were run."

CR-1 P2-2005-00532 CHEMISTRY DEFICIENCY: The Hydrazine reading for the Condensate Pump Discharge (CPO) at 7 parts per billion (ppb). It must be at least 8 times the CPO Dissolved Oxygen reading.

22 Hydrazine pump found vapor bound. The stroke set at 40%. Level: 37 inch CR-1 P2-2005-02958 Upstream of MS-1608 (22 BF Pump Turbine Trip Isolation Stop to RS-5),

Partial pipe break at elbow on 1-beam is allowing Instrument Air to escape.

CR-1 P2-2005-03797 Prerequisite sample to install modification to support resin sluice of U1, CT-13, Cation Purification lon Exchanger, indicated offscale % LEL and offscale hydrogen sulfide. Subsequent samples taken by Chemistry, indicated 30%

combustible gas.

CR-1 P2-2005-04139 Dissolved oxygen is trending up in the Unit 2 CST. SOP 20.5 Rev 5 does not contain steps to operate the new nitrogen mod that was installed at the CST.

COL 21.3 Rev 28 was issued but there is no completed portions of rev 28 in the completed copy of the COL.

CR-1 P2-2005-044 71 Condensate dissolved oxygen is currently 10.2 ppb. This is at least twice the value that is normally seen. The condensate dissolved oxygen has been increasing as the condenser air in leakage has increased.

CR-1 P3-2001-00524 DER-01-00524: TSC Compressor Freon Leak: TSC compressor is leaking freon at approximately 4 lbs/48 hrs from various system leaks. This leakage causes reduced cooling capability and forced a manual shutdown of CFMS A due to high temperature. NYSDEC notified.

CR-1 P3-2001-01 055 DER-01-01 055: Increasing chloride trend in the lA Closed Cooling Water Sys.: Chemistry data is indicating a constant average rise of.35 PPM per day in chlorides in the Instrument Air Closed Cooling Water system since Oct. 2000.

CR-1 P3-2001-01185 DER-01-01185: Operations Log for Liquid N2 Level Out of Spec Low: During performance of 3PT-D004 (Extended Plant Operations Surveillance Requirements), NPO recorded third consecutive reading out of spec low for Liquid Nitrogen Level CR-1 P3-2001-02620 DER-01-02620: Hydrogen Cooler Hydrogen leaks: While performing RE-CCI-030 "Electrical Generator Hydrogen Survey" the chemistry technician found a significant leak around the bottom of 32 hydrogen cooler.

CR-1 P3-2001-02915 DER-01-02915: 3PT-Q108 AS FOUND FAILURE AS LEFT PASSED:

DURING PERFORMANCE OF 3PT-Q108,TOXIC GAS MONITORING SYSTEM CALIBRATION, STEP 4.1.1.5 AS FOUND VALUE FOR THE CHLORINE MONITOR WAS OUT OF SPEC. AMMONIA AND OXYGEN AS FOUNDS WERE IN SPEC.

IPEC00186155

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 1 09 of 119 -Air and Gas Systems CR-1 P3-2001-03395 DER-01-03395: Freon 22 Lost From #31 CCRAC Unit, 5 3/4 Pounds Lost:

Freon 22 leaked out of the 31 CCRAC. A total of 5 3/4 pounds was lost.

This was discovered when troubleshooting and refilling the unit.

CR-1 P3-2002-03878 Minor N2 leak on swagelok fitting on downstream body side of IVSW-1434.

CR-1 P3-2002-04681 Since the startup there has been an upward trend in H2 Leakage that appears to be leveling off but further trending over the next few days is required. The current leakrate over the past 24 hrs was -1108 CFD.

CR-1 P3-2002-04685 During a Generator Hydrogen Survey, the Chemistry Department located a hydrogen leak of -3% around the manway gaskets of the generator.

CR-1 P3-2002-04 7 41 During operator rounds, it has been noted that air leaks have developed in similar locations on the air supply lines to the power operated check valve actuators on both the EXTRACTION STEAM LINES to 35A,B & C FEEDWATER HEATERS and 36A,B & C FWHs.

CR-1 P3-2002-05009 33A MSR manway has a small steam leak. Insulation removed and leak is at manway gasket lower left hand side.

CR-1 P3-2002-05048 At approximately 1520 a large "BANG" was heard in the vicinity of the Shift Managers office in the Turbine Building and was followed by an acrid odor.

Investigations revealed no damage or source of the disturbance. Hydrogen surveys and field walkdowns were conducted and the results were inconclusive.

CR-1 P3-2003-00368 The Ecolochem operator requested a decreased flowrate to the U3 CST due to increasing dissolved oxygen levels. Total flow at the time was 100 gpm to U2 and 100 gpm to U3.

CR-1 P3-2003-00453 At 10:45 found dissolved oxygen to IP3 from Ecolochem to be Out Of Spec high at 215ppb. The spec is 1 OOppb.

CR-1 P3-2003-00489 When the 31 Vacuum Degassifier Transfer pump was placed in service oil from the chicken feeder leaked excessively. The pump was stopped and the degassifier secured.

CR-1 P3-2003-00524 On 2/1/03 @ 15:24 Ecolochem effluent oxygen concentration was 138 ppb.

The spec for oxygen as found in RE-CS-012.4 is <1 OOppb. This CR is for trending.

CR-1 P3-2003-02172 Condensate Storage Tank dissolved oxygen high out of spec at 250 ppb.

The OPS-SD-04 spec for dissolved oxygen in the CST is <1 OOppb.

Suspected cause is CD-129 being PTO'd open for Aux Boiler Feed Pump Maintenance.

CR-1 P3-2003-02738 A service water leak was identified on the 31 MBFP oil cooler. Investigation identified a hole in the head gasket at the 10 O'clock position.

CR-1 P3-2003-02981 The Main Generator Purity was 94.9% as of 5/9/03 @ 0005. This is currently out of spec low and can not be addressed as the hydrogen truck does not have enough inventory to purge the machine.

CR-1 P3-2003-03535 Main Turbine Generator is being purged with hydrogen every 2 days. This is not typical. See WRT 03-03361 CR-1 P3-2003-03738 Out Of Spec low on molybdate (corrosion inhibitor) in Instrument Air Closed Cooling, following refill of 31 pump/cooler.

CR-1 P3-2003-04530 Liquid argon was released to the hallway outside the Chemistry Counting Room following activation of the rupture disc on the cylinder. Due to high ambient temperature, the high pressure relief valve froze, causing the disc to rupture to relieve the pressure.

IPEC00186156

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 11 0 of 119 -Air and Gas Systems CR-1 P3-2003-06163 The degraded condition and the extreme age of the sparging Nitrogen and Hydrogen bottles on nuclear side of the plant in the PAB constitute a safety issue and should be removed.

CR-1 P3-2004-00760 During performance of SOP-WDS-001 step 4.7.4.2, the gasket on 32 Sparging Pump discharge filter ruptured and sprayed about half a liter of potentially contaminated fluid in the area and onto personnel.

CR-1 P3-2004-01355 The response to CR-IP3-2003-06163 was inadequate. CR 06163 was written to document the aged and degraded condition of the PAB backup Hydrogen and Sparging Nitrogen Bottle Banks.

CR-1 P3-2004-01497 An adverse trend of Main Turbine Generator Hydrogen usage has been noted. The hydrogen usage has increased from <300 SCFM to >450 SCFM.

CR-1 P3-2004-02618 H2 Side Seal Oil Cooler has a leak from the south endbell drain plug fitting.

Leak rate is-2 drops/min.

CR-1 P3-2004-02836 Air leaking into the IACC system from the 32 lA Compressor. Suspect that the head gasket is degraded due to moisture at bottom of cylinder being pressed against the gasket allowing for a small air path into the closed cooling pipe at the bottom of the head.

CR-1 P3-2005-01 029 During performance of 3-SOP-CVCS-007, Degassing the Reactor Coolant System, section 4.2 Establishing N2 in the VCT, the anticipated reductions in H2 concentration were not achieved. The result was a loss of non-critical path time.

CR-1 P3-2005-03289 The monthly Ultrasonic Test (UT) of Safety Injection System-8" line #359 revealed a gas pocket. The gas pocket measured 5.5" circumferentially, this calculates to a void height of 0.706". This location was found full of water when last checked on 5/12 The review found no instances of failures in air or gas systems that caused the failure of other plant equipment or had the potential for adversely affecting safety-related plant equipment.

Component failures resulting in air or gas leakage were identified, but the leaks were such that they did not adversely impact safety-related equipment.

CONCLUSIONS The condition reports identified by the keyword search results do not identify failures due to aging of air or gas systems that adversely impacted accomplishment of a safety function.

IPEC00186157

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 111 of 119 - Insulation INTRODUCTION The Mechanical and Structural Tools do not evaluate aging effects for insulating materials; therefore, operating experience at IPEC was evaluated to determine if there have been any failures of insulation due to aging effects that have adversely impacted the accomplishment of a safety function.

METHOD Site operating experience during 2001-2005 was reviewed by performing keyword searches of IPEC CRs using the paperless condition reporting system (PCRS). Data fields included in the searches were those containing the condition description, summary description, closure description, and operability description. Keyword searches of operating history during 2001-2005 were performed using the keywords insulation, fiberglass, Aero-tube, Nukon, calcium silicate, fiber mat, mineral wool, and strata-fab.

RESULTS The keyword searches resulted in over 500 hits for IP2 and over 200 hits for IP3. Search results were screened to determine whether the identified condition involved failure of thermal insulation that may have been due to aging, see list below. The majority of the search results involved event-driven conditions that required no further review. The condition description, summary description, closure description, and operability description for the following condition reports were reviewed to determine if degradation was due to aging.

CR-1 P2-2001-02328 In the Aux Feedwater Bid, one elevation above the walkway on 53' coming from the Turbine Bid, there is suspected Asbestos Containing Material, similar to block-type white insulation.

CR-1 P2-2001-02761 While performing a cubicle inspection for the field breaker (41) for GT2, the cubicle inspection was acceptable, but a cursory inspection of the rest of the cabinet revealed a wire with seriously cracked insulation.

CR-1 P2-2001-041 07 During the performance of corrective maintenance in the Pressurizer Control Bank Heater cubicle in the electric pen area, we found that two 480V conductors in the cubicle have cracked insulation and at least one of them is cracked through.

CR-1 P2-2001-05651 Asbestos enclosures around the Monitor Tanks on the Nuclear Tank area have puddles coming from under each of the tanks with a chalk like material floating on the surface (insulation/PACM).

CR-1 P2-2001-07043 Conducted quarterly system health and monthly system monitoring walkdown on the Post Accident Containment Air Sampling System and found the following: Missing and degraded insulation on sample tubing.

CR-1 P2-2001-08511 LIC-11 01-S, Local Level Instrument for the Primary Water Storage tank insulation panel and piping wrap are degraded and may cause freezing when cold weather conditions exist.

IPEC00186158

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 112 of 119 - Insulation CR-1 P2-2001-08798 During performance of OPS-PM MST-5, Unit 2 Turbine Hall Main Steam Traps Operability, a portion of the insulation on the inlet piping to MST-24 was found to be deteriorated and needs to be encapsulated.

CR-1 P2-2001-12267 The insulation on the roofs of #11, #12 & #13 Condensate storage tanks is deteriorated. Old insulation needs to be removed and tank roofs need to be reinsulated and weather proofed.

CR-1 P2-2002-01908 The insulation strips, used to bind the ends of insulation blankets together, have started to peel off the main insulation on the #24 SW Pump Pedestal Vacuum Breaker.

CR-1 P2-2003-03739 During on going inspections of tanks and vessels in unit 1, housekeeping and industrial safety issues have been identified in infrequently accessed areas of the Chern Systems Building. Industrial safety issues include:

asbestos insulation in poor condition.

CR-1 P2-2003-06268 Condensate storage tank 2 dissolved oxygen monitoring cabinet is in need of repair. Fiberglass insulation aluminum backing is peeling, fiberglass is coming loose inside cabinet. Work order is needed.

CR-1 P2-2004-01322 While working WO IP2-04-14591, TSC Diesel silencer inspection support, an outer layer of cement type skim coat was encountered. This material is Presumed Asbestos Containing Material (the insulation material on the muffler is identified as Calcium Silicate.)

CR-1 P3-2001-00169 DER-01-00169: High S/G Sodium: The Steam Generator High Sodium Alarm was received in the CCR. Sodium in all four Steam Generators jumped from approximately.2 ppb to approximately 9 ppb in approximately 15 minutes.

CR-1 P3-2001-01266 DER-01-01266: PLANT VENT HEAT TRACE FUNCTIONAL 3PT-Q115 FAILURE: DURING PERFORMANCE OF 3PT-Q115(WR 00-3665-00)

TECHNICIANS FOUND AN AREA OF PIPE INSULATION THAT HAS DEGRADED.

CR-1 P3-2002-05030 During PM inspection of 36 SWP motor, WR 13-020207900, it was noted that the outer vinyl and lead layers of insulation were cracked open.

Repairs are being initiated.

CR-1 P3-2003-01366 The sodium hypochlorite tank was inspected and a three and a half ft crack was found on the interior wall. In addition the fiberglass is delaminating in the area of the crack. A four inch portion of the crack appears to be almost through wall.

CR-1 P3-2003-02267 Found Foam Station 264 at 15' turbine bldg by the lube oil coolers blocked by orange bags of insulation and welding screens. This is the second time in a week that this hose station has been found blocked (CR-IP3-2003-01911).

CR-1 P3-2004-02348 Insulation inside local RWST level instrumentation enclosure became unglued from door and is deteriorating. WRT IP3-04-06160 written.

Concern when weather gets cold.

CR-1 P3-2004-02953 Following the evolution to boron saturate 32 CVCS Mixed Bed Demineralizer, the 32 RCP Seal Return Flow dropped to <1.0gpm.

Increased Seal Injection Flow per the ODMI (RCP 32 LOW NUMBER 1 SEAL RETURN FLOW) to 11.5gpm.

IPEC00186159

IPEC License Renewal Project Operating Experience Review Report - Insulation IP-RPT LRDOS Revision 3 Page 113 of 119 The review found no instances of failures of thermal insulation due to aging effects that have adversely impacted the accomplishment of a safety function.

CONCLUSIONS The condition reports identified by the keyword search results did not identify aging effects requiring management for thermal insulation.

IPEC00186160

INTRODUCTION IPEC License Renewal Project Operating Experience Review Report - Bolting IP-RPT LRDOS Revision 3 Page 114 of 119 Cracking and loss of preload were not identified as aging effects requiring management for pressure boundary bolting for the period of extended operation.

The only aging effect identified during the plant operating experience review described in the body of this report was loss of material due to general corrosion of carbon steel bolting.

NUREG-1801 Revision 1 and EPRI 1010639, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4," identified cracking as an aging effect only for high strength bolting and did not identify loss of preload as an aging effect for non-Ciass-1 bolting. Also, the EPRI 1010639 determination that cracking is an aging effect only for high strength bolting and that loss of preload is not an aging effect for non-Class 1 bolting was in part based on an extensive operating experience review of the nuclear power industry. Based on the following evaluation of plant and industry operating experience, cracking and loss of preload were not identified as aging effects requiring management for pressure boundary bolting for the period of extended operation.

Cracking Stress corrosion cracking occurs through the combination of high stress (both applied and residual tensile stresses), a corrosive environment, and a susceptible material. For bolted closures and fasteners, susceptible material is bolting having a yield strength

> 150 ksi. In addition, stress corrosion cracking of high yield strength bolted closures in BWRs requires a corrosive environment that is typically attributed to leakage of pressure boundary joints or exposure to wetted ambient environments and the use of thread lubricant containing MoS2 (molybdenum disulfide).

Potentially susceptible mechanical bolting materials include alloy steels (ASTM A354 Grade BD, A540 and A 57 4) and high yield strength heat-treated alloy steels (heat-treated 4130, 4140 and 4340 material).

High yield strength heat-treated alloy steel bolting materials are not specified for flanged connections at IPEC.

High strength bolting of vendor-supplied equipment has not been identified for mechanical components (such as pump casing studs or valve body/bonnet studs) where the material specifications are available. Use of MoS2 thread lubricant is not allowed by site procedures. Therefore, maintenance on mechanical equipment would result in use of non-MoS2 thread lubricant. (Ref. 1, 2)

In summary, the aging effect "cracking" was not identified as an aging effect requiring management because neither the susceptible material nor the corrosive environment portions of the stress corrosion cracking mechanism is present. The review of IPEC operating experience described below supports this conclusion because it did not identify instances in which mechanical component failure was attributable to stress corrosion cracking of high strength pressure boundary bolting.

Loss of Preload EPRI 1010639, Appendix F, describes loss of preload as a design driven effect and not an aging effect requiring management. Bolting at IPEC is standard grade B7 carbon steel, or similar material, except in rare specialized applications such as applications IPEC00186161

IPEC License Renewal Project Operating Experience Review Report - Bolting IP-RPT LRD05 Revision 3 Page 115 of 119 where stainless steel bolting is utilized. Loss of preload due to stress relaxation (creep) would only be a concern in very high temperature applications (> 700°F) as stated in the ASME Code,Section II, Part D, Table 4.

No IPEC bolting operates at >700°F.

Therefore, loss of preload due to stress relaxation (creep) is not an applicable aging effect. Other issues that may result in pressure boundary joint leakage are improper design or maintenance issues. Improper bolting application (design) and maintenance issues are current plant operational concerns and not related to aging effects or mechanisms that require management during the period of extended operation. To address these bolting operational concerns, IPEC has taken actions to address NUREG-1339, "Resolution to Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants."

These actions include implementation of good bolting practices in accordance with EPRI NP-5067, Good Bolting Practices.

Proper joint preparation and make-up in accordance with industry standards is expected to preclude loss of preload.

In summary, the aging effect "loss of preload" was not identified as an aging effect requiring management because operating temperatures are significantly less than the temperature required for stress relaxation and the remaining non-aging operational concerns are addressed by normal design and maintenance practices. The review of IPEC operating experience described below supports this conclusion because it did not identify instances in which mechanical component failure was attributable to loss of pressure boundary bolting preload.

Operating experience at IPEC was evaluated as described below to determine if there have been instances in which mechanical component failure was attributable to stress corrosion cracking or loss of preload.

METHOD Site operating experience during 2001-2005 was reviewed by performing keyword searches of IPEC CRs using the paperless condition reporting system (PCRS). Data fields included in the searches were those containing the condition description, summary description, closure description, and operability description. Keyword searches of operating history during 2001-2005 were performed using the keywords bolt, stud, nut, anchor, thread, and torque.

RESULTS The keyword searches resulted in over 1900 hits for I P2 and over 1200 hits for I P3. Search results were screened to determine whether the identified condition was related to pressure boundary bolting that may have experienced cracking or loss of preload, see list below. The majority of the search results involved event-driven conditions that required no further review.

The condition description, summary description, closure description, and operability description for the following condition reports were reviewed to determine if cracking or loss of preload was the cause of the reported condition.

IPEC00186162

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 116 of 119 - Bolting CR-1 P2-2001-02981 Oil conditioner has six baskets with various mechanical problems. Noted during OPS PM to change the polishing filters and bags in the oil conditioner. Some baskets have siezed or galled threads, some have loose threaded rods, one is missing CR-1 P2-2001-03322 Valve block bolting for 21 charging pump cylinder closest to the suction has boron on the bolts and studs. This is from leak (referenced CR). Carbon steel bolting issue. PI-2Y2 finding. Corrosion is light at the present time.

CR-1 P2-2001-03332 The threads on the downstream side of 6160 are galled.They need to be chased or replaced before the next quarterly test of 22 Sl pump because this a test point for PT-Q29B and the connection will probably leak.

CR-1 P2-2001-06569 While performing lubrication of valve, the grease fitting came out. There were no threads left on the fitting.

CR-1 P2-2002-01227 While removing tagout and performing PMT's associated with 21 Conventional Closed Cooling Water Heat Exchanger, it was discovered that SWT-18 has severely corroded/rusted packing adjustment bolt, stem and follower.

CR-1 P2-2002-04977 200204977 - Casing bolt #3 leaks by threads. Casing bolt #4 is already written up as having leakage from threads. This was found during quarterly test on 23 AFW pump.

CR-1 P2-2002-07 426 While performing anchor removal work on spent fuel assembly G27 just moved to spent fuel pool location CK41, a small piece of foreign material was noted down in a thimble tube.

CR-1 P2-2002-07 461 WHILE PERFORMING CORRECTIVE MAINTENANCE BY CHANGING OUT NUMBER 22 DEGASSING PUMP CHECK VALVE, (CA-567), THE BUTTERFLY VALVE, ( CA-563), WHICH IS BOLTED TO THE INLET SIDE OF THE CHECK VALVE HAD TO BE REMOVED AND AFTER INSPECTION OF THE VALVE WE FOUND CR-1 P2-2002-08205 The following conditions were identified during PI-3Y41C, 23 Accumulator Tank lSI:

1) lt-934c Liquid side block vent threaded connection Boron encrusted minor in nature( white/dry).

2) L T-934C inline transmitter block inlet and outlet fitting threaded connections Boron encrusted minor in nature( white/dry).

CR-1 P2-2002-09411 The tank side flange on valve 844 has a light gasket leak found during the Section XI Bolted Connection Inspection Program. The boron was cleaned off and there is no material degradation. There is moderate rust on the bolting.

CR-1 P2-2002-09412 The tank side flange on valve 840B has a light gasket leak found during the Section XI Bolted Connection Inspection Program. The boron was cleaned off and there is no material degradation. The gasket edge has moderate rust.

CR-1 P2-2002-09413 Valve 1860 has a light gasket leak found during the Section XI Bolted Connection Inspection Program. It appears to be residual from a previous leak. The boron was cleaned off and there is no material degradation.

CR-1 P2-2002-09453 The flange for valve 296 has a light gasket leak and the bolts are corroded.

The bolts are acceptable. This is a non code item.

CR-1 P2-2002-094 77 The bolt holes in the equipment hatch face are in a very poor condition.

This requires an alternate approach to the equipment hatch removal process and will require a temp procedure change.

CR-1 P2-2002-09538 23 Auxiliary Feed Pump #4 Pump Casing Bolt leaks by its threads when pump is in operation. Leakage rate is about a drop every 10 seconds.

IPEC00186163

IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 117 of 119 - Bolting CR-1 P2-2002-09731 During performance of VT-3 inspection on MS-1-21 cover studs, 7 out of 20 studs were rejected due to damage or galled threads.

CR-1 P2-2002-09781 Valve 897B has at least one stud that has some amount of degradation found during the Section XI bolted Connection Inspection Program. The back side of the valve is inaccessible and therefore has not been inspected. The left side of the valve has a very CR-1 P2-2002-09916 Upon inspection of stud hole after removal of stuck stud from MS-2A, there were defects identified with some of the threads. Engineering was requested to evaluate the acceptability of the installation of the bonnet stud into this hole.

CR-1 P2-2002-09917 ENTERED NUMBER 23 CONDENSER TO INSPECT THE SPARGER AT THE END OF PCV-1123, HIGH PRESSURE STEAM DUMP PIPE.

FOUND THE SPARGER IN GOOD SHAPE WITH NO NOTICEABLE DAMAGE OR ABNORMALITIES. WHAT WE DID FIND WAS A PIECE OF THE DOG BONE OUTER PROTECTOR PLATE, 26" LONG AND 8" WIDE TORE OFF DUE TO ONE OF THE HOLD DOWN TABS BREAKING IN HALF WHERE IT BOLTS TO THE WALL.

CR-1 P2-2002-1 0307 During the performance of the Bus 6a pm inspection under w.o. 01-21964 the following conditions were noted:

1. In cubicle 8B there was a slight surface crack in the B phase stud that was evaluated by engineering.

CR-1 P2-2003-00341 Strainer downstream of AS-1261, atomizing steam to 22 HSB, failed due to a through wall crack from the bottom threads to middle of body. This failure caused the room to fill with steam while I & C personnel was in room troubleshooting 21 HSB.

CR-1 P2-2004-05634 During #3 Stop Valve disassembly the stelite seal ring on the cross shaft was found broken in at least 6 pieces. The disc retainer nut had worn threads and loose pins.

CR-1 P2-2004-05724 VT-3 examinations per PI-V1A of four snubbers indicated that they did not meet one of the test requirements to have threads visible in the turnbuckle sight holes.

Snubber SR-924-no threads visible, SR-809A-engagement 5/16" beyond sight hole, SR-112 CR-1 P2-2004-05791 During the 72 month PM inspection of MS-2B under work order IP2 13263, four of the cover fasteners galled up on the threads. The nuts were welded to the studs in an attempt to remove the studs using Hy-Torque equipment. Two of the studs were removed us CR-1 P2-2004-05895 SWN-1218 vent has galled threads.

CR-1 P2-2004-05934 During inspection and removal of the reactor head inner and outer o rings the following was noted:

1) Inner and outer 0-rings between stud Holes 27 and 28. There was discoloration which appears to be black deposits on both the inner and outer o rings.

CR-1 P2-2005-01 002 It has been identified that IPEC did not perform a required independent inspection of the stud elongation measurements of the Unit 2 reactor head at the conclusion of 2R16 RFO. This inspection is required by ANSI N.45.2.8, per section 4.4. Inspections.

CR-1 P2-2005-04593 PI-3Y1 00 Data sheet PI-3Y57, Charging Outside Containment lnservice Inspection, is unsat due to the presence of boron encrustation on various threaded fittings. These locations are: 1) The plug on the side of FT-128 (WRT# IP2-05-02475); 2) The cap fitting IPEC00186164

CR-1 P3-2001-01836 CR-1 P3-2001-01847 CR-1 P3-2002-01621 CR-1 P3-2002-02279 CR-1 P3-2003-01684 CR-1 P3-2003-01826 CR-1 P3-2003-02022 CR-1 P3-2003-02049 CR-1 P3-2003-02079 CR-1 P3-2003-02175 CR-1 P3-2003-02297 CR-1 P3-2003-02398 CR-1 P3-2003-02410 IPEC License Renewal Project Operating Experience Review Report IP-RPT LRDOS Revision 3 Page 118 of 119 - Bolting DER-01-01836: 2 RV Head Studs have recordable indication : lSI inspection found two RV Head studs (#6 & #18) with one recordable indication each at the shank area. The indications were found by visual exams and confirmed with MT exam.

DER-01-0184 7: EDG 32 Governor Support Bearing Casing Cracked/broken: During 32 EDG 8 year PM inspections, when removing the EGB governor the governor support bearing casing was found to be cracked and broken at one of the four hold down bolts.

Upon completion of Boral inspection test 3PT-SYS, one of the twelve bolts on the cover plate for the full length Boral strip could not be reused, due to apparent galling. This is an expected phenomenon, and allowance for failed bolts was considered.

City water piping has a 3 drop/minute leak. A heavily corroded section of line # 1033 was being prepared for Ultrasonic Thickness (UT) readings with hand tools when two wet areas were noticed.

IP3 PM Program requires stud stretch inspections to be performed on the RCP main flange studs every 6 years lAW PMP-037-RCS. WO 13-000276200 was scheduled in 3R11 to perform this PM and was closed as complete.

An lSI visual examination of Support SW-H&R-11 E-31 as shown on I NT-3-3413, Rev.2. found that the anchor bolts were corroded. This is a recordable indication. The support is a riser type ring support anchored at 3 places at the base of 35 FCU.

The top side (tapered side) of the washer for reactor stud #26 and the bottom side of the reactor stud nut #26 have moderate pitting 360 degrees around.

Inspection of Reactor Studs & Nuts revealed the following minor defects:

I consider these defects minor. It is not necessary that these be re-visual inspected, however that is site's option. These are being documented for future outage reference.

During the cleaning, inspecting and lubing of the 4th and 5th racks of Reactor Vessel Studs the following minor defects were noted. These are not to be considered significant defects. These are being documented for future outage reference.

Quality Control Had Been Notified for VT-1 Examination for Pressurizer Relief Valve No. RC-PCV-468 Inlet Flange Studs and Nuts. A Total of 12 Studs and 24 Nuts Had Been Removed From This Equipment. Only 9 Studs, and 20 Nuts Were Presented for Examination During a UT lSI examination (WO IP3-02-117536) of the Reactor Vessel Head to Flange weld, a recordable indication was detected between Stud Hole 23 and Meriodional weld 3 as depicted on lSI sketch INT-1-1300, Rev.4. This condition is documented.

An unusual degree & rate of corrosion was found on the nuts & washers used to support the Recirc Sump Screen galvanized steel framing. 10 nuts & washers showed a higher degree of corrosion than the associated end piece soft steel angle iron.

While replacing the post seal nuts on station battery 33 under WR 13-020132800 nodular corrosion was found on many (about 70%) of the positive posts on the battery. Also, after replacing the seal nuts, 75% of the cells did not pass the pressure test.

IPEC00186165

CR-1 P3-2003-02424 CR-1 P3-2003-02636 CR-1 P3-2003-04568 CR-1 P3-2005-01305 CR-1 P3-2005-01479 CR-1 P3-2005-01726 IPEC License Renewal Project Operating Experience Review Report - Bolting IP-RPT LRDOS Revision 3 Page 119 of 119 During the assembly of the Reactor Vessel a nuUwasher was replaced at location 26. It appears that refueling floor personnel/Westinghouse personnel did not recognize (as required by the work package) that this was an lSI component.

Following hot torquing and during reactor head inspection lAW 3PT-R131 discovered that the lower clamp assembly on conoseal #5 was leaking significantly and causing a large boron deposit on the stainless fittings.

While performing the slip torque inspection on the west side air start motor bendix the as found torque value was out of tolerance. As found was 230ft.lbs and it should have been between 275-300ft-lbs. Bendix was replaced with new.

During lSI inspection of 31 Fan Cooler Unit, heavy rust was found on the bolting on the flanges on the side of the FCU.

During inspection and removal of the reactor head inner and outer o rings the following was noted:

1) Inner 0-ring near stud hole 24. Very slight scratch noted across the inner o-ring sealing surface near a clip location. Indications of boric acid.

Stud elongation on 31 Steam Generator Hotleg Channel Head Manway stud #9 is 0.003" at the maximum torque of 1500 ft.lbs. The acceptance criteria is 0.0075" to 0.01 OS" in accordance with procedure SGS-008-RCS. This was measured during tightening of stud/nut The review found instances of loss of material due to corrosion and loose bolting due to improper maintenance practices, but no evidence of cracking or loss of preload for pressure boundary bolting.

CONCLUSIONS The condition reports identified by the keyword search results did not identify cracking or loss of preload as aging effects requiring management for pressure boundary bolting.

Although cracking and loss of preload are not identified as aging effects requ1nng management for the period of extended operation, plant procedures implement the recommendations of NUREG-1339, "Resolution to Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," for pressure boundary bolting in the scope of license renewal. Plant procedures address material and lubricant selection, design standards, and maintenance good bolting practices in accordance with EPRI 5067, Good Bolting Practices.

REFERENCES

1. 0-MS-411, Rev. 0, Torquing of Mechanical Fasteners

2. SE-Q-12.707, Rev. 0, Carbon Steel Fastener Inspection Program IPEC00186166