ML11083A054

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Lr Hearing - Slides from ACRS Subcommittee Meeting on March 4, 2009
ML11083A054
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 03/06/2009
From: Kimberly Green
Division of License Renewal
To: Eddy P
State of NY, Dept of Public Service
References
Download: ML11083A054 (92)
v • d • e


Text

1 Stuyvenberg, Andrew From:

Green, Kimberly Sent:

Friday, March 06, 2009 9:01 AM To:

paul_eddy@dps.state.ny.us Cc:

McNamara, Nancy

Subject:

Slides from ACRS Subcommittee Meeting on March 4, 2009 Attachments:

IPEC-ACRS-Final_Extra Slides.pdf; IPEC-ACRS-Final.ppt; ACRS-Indian Point-Presentation 03-04-09.ppt

Dear Mr. Eddy,

As requested, please find attached the presentation slides from both the NRC staff and Entergy from the ACRS Subcommittee Meeting held on March 4, 2009. The pdf file contains 2 additional slides that Entergy displayed during the meeting but were not included in the handouts.

Sincerely, Kimberly Green Safety PM (301) 415-1627 kimberly.green@nrc.gov

SBO Recovery IP2 Offsite Power Scoping Diagram

48

SBO Scoping Buchanan Substation

50

SBO Recovery IP2 Offsite Power Scoping Diagram

48

SBO Scoping Buchanan Substation

50

Indian Point Energy Center Indian Point Energy Center ACRS License Renewal Subcommittee March 4, 2009 1

Indian Point Energy Center Indian Point Energy Center Personnel in Attendance Personnel in Attendance Joe Pollock Vice President, Site - IP Fred Dacimo Vice President, License Renewal - IP John McCann Director, Licensing Don Mayer Director, Emergency Planning Rich Burroni Manager Programs and Components Rich Burroni Manager, Programs and Components Garry Young Manager, License Renewal Tom McCaffrey Manager, Design Engineering y

g g

g g

John Curry Project Manager, License Renewal - IP Mike Stroud Project Manager, License Renewal Alan Cox Technical Manager, License Renewal Bob Walpole Manager, Licensing Rich Drake Supervisor Civil/Structural Engineering 2

Rich Drake Supervisor, Civil/Structural Engineering Nelson Azevedo Supervisor, Code Programs

Agenda

  • Background
  • Background
  • Operating History Major Plant Impro ements
  • Major Plant Improvements
  • Scoping Discussion A

li ti f NUREG 1801

  • Commitment Process
  • Topics of Interest
  • Questions 3

IPEC Site Description Westinghouse NSSS UE&C (AE) - WEDCO (Constructor)

IP2 - Westinghouse low pressure turbines, Siemens HP g

p turbine, GE generator IP3 - ABB low pressure turbines, Siemens HP turbine, Westinghouse generator g

g PWR, large dry containment 3216 MW thermal power p

1078 MWe - IP2, 1080 MWe - IP3 Once-through cooling from Hudson River IP2 dual speed circulating water pumps with Ristroph screens IP3 variable speed circulating water pumps with Ristroph screens 4

Staff complement: approximately 1100

IPEC Operating History Indian Point Unit 2

  • Construction permit October 14, 1966
  • Operating license September 28, 1973 p

g p

  • Commercial operation August 1, 1974
  • Uprated power licenses
  • Uprated power licenses 11.4% (3071 MWt)

March 7, 1990 1 4% (3114 MWt)

M 22 2003 1.4% (3114 MWt)

May 22, 2003 3.26% (3216 MWt)

October 28, 2004 5

IPEC Operating History IPEC Operating History Indian Point Unit 3

  • Construction permit August 13, 1969
  • Operating license December 12, 1975 p

g

  • Commercial operation August 30, 1976
  • Uprated power licenses
  • Uprated power licenses 10.0% (3025 MWt)

August 18, 1978 1 4% (3067 MWt)

N b

26 2002 1.4% (3067 MWt)

November 26, 2002 4.85% (3216 MWt)

March 24, 2005 6

IPEC Operating History IPEC Operating History License Transfers

  • IP3 Con Edison to NYPA December 24, 1975 IP3 NYPA to Entergy November 21, 2000 IP2 Con Edison to Entergy September 6, 2001
  • LR application (IP2 & IP3)

April 23, 2007 pp

(

)

p

  • Operating license expires IP2 September 28 2013

- IP2 September 28, 2013

- IP3 December 12, 2015 7

Major Improvements Major Improvements Indian Point Unit 2 1978 One additional station battery and inverter 1978 One additional station battery and inverter 1981 Fan cooler unit heat exchangers One additional station battery and inverter 1982 Rebuilt control room with human factors and new computers 1985 Dual speed circ pumps & Ristroph screens 1985 Dual speed circ pumps & Ristroph screens 1990 Main generator 1995 Titanium condenser 1996 Implemented 24 month fuel cycle 1997 Converted to best estimate LOCA analysis Replaced NaOH spray additive with 8

Replaced NaOH spray additive with TSP baskets in containment

Major Improvements Major Improvements Indian Point Unit 2 (cont) 1998 Low pressure turbines 1999 Autocatalytic hydrogen recombiners 2000 Steam generators 2000 Steam generators Feedwater heaters Converted to alternate source term Converted to alternate source term 2004 High pressure turbine Moisture separator reheaters p

2006 Main transformers Containment sump improvements 9

2008 SBO / Appendix R diesel generator

Major Improvements Major Improvements Indian Point Unit 3 1981 4th battery charger / inverter 1981 4th battery charger / inverter 1982 Two new fire water tanks and pumps 1983 Fan cooler unit heat exchangers 1984 SBO / Appendix R diesel generator 1985 Variable speed circulating water pumps 1986 Rebuilt control room with new computers 1986 Rebuilt control room with new computers and human factors One main transformer 1987 Titanium condensers 1989 Steam generators Condensate polishing system and blowdown 10 Condensate polishing system and blowdown recovery Feedwater heaters

Major Improvements Major Improvements Indian Point Unit 3 (cont) 1993 L

t bi 1993 Low pressure turbines 1995 Implemented 24 month fuel cycle 1997 Thermal hydrogen recombiners 1997 Thermal hydrogen recombiners 2003 Converted to best estimate LOCA analysis 2005 High pressure turbine g

p Moisture separator reheaters Converted to alternate source term 2007 Second main transformer Containment sump improvements 2008 S

11 2008 Sodium tetraborate baskets

Major Improvements Major Improvements Site 1987 Training building 1997 Water treatment facility 2005 Generation support building 2007 Dry fuel storage IP1 - 160 fuel assemblies IP2 - 96 fuel assemblies 2008 E-plan siren system Planned Emergency operations facility 12

IPEC Plant Status IPEC Plant Status Current Plant Status Both units on-line at full power IP2 continuous days on line - 274 IP3 continuous days on line - 672 Next outages Spring 2009 (IP3)

Spring 2010 (IP2) 13

Indian Point Energy Center 14

IPEC Generation 15

IPEC License Renewal Project IPEC License Renewal Project LRA Development

  • Incorporated lessons learned from previous
  • Incorporated lessons learned from previous applications
  • Peer review conducted - NEI and other Peer review conducted NEI and other utilities
  • LRA internal reviews (Safety Review C

itt d QA)

Committees and QA)

  • LRA prepared by experienced, multi-discipline Entergy team (utilized corporate discipline Entergy team (utilized corporate and on-site resources)
  • All comments resolved prior to submittal 16 p

Application of NUREG-1801 Aging Management Reviews

f AMR li it d

t A

E (

i t t

  • 90% of AMR line items used notes A - E (consistent with NUREG-1801, Rev 1) 17

Application of NUREG-1801 Aging Management Programs

- 31 existing programs

- 10 new programs

- 8 plant-specific programs p

p p

g

- 33 NUREG-1801 programs

Commitment Process

R fi d d i

dit / i ti

- Refined during audit / inspection process

- IP commitment management process

  • Commitment management process established consistent with industry guidance consistent with industry guidance E t i di ll i t

it t

  • Entergy periodically inspects commitment management process 19

Implementation Fleet Approach

  • Employing fleet approach to implementation for Entergy plants that have submitted an LRA
  • Develop schedule for Entergy plants as renewed licenses approved licenses approved
  • Several common fleet implementing procedures are 20 Several common fleet implementing procedures are being developed for Entergy plants

SER Open Items SER Open Items Item Status IP2 Fire Protection - yard hose houses y

and chamber housings Ready IP2 & IP3 Main Feedwater System -

stop valves Ready stop valves Ready IP2 Auxiliary Feedwater Pump Room Fire Event Scoping Ready Electrical and Instrumentation & Control Systems - SBO scoping NRC review Fire Protection Program - inaccessible g

fire barrier penetration seals Ready Structures Monitoring Program -

IP2 reactor cavity NRC review 21 IP2 reactor cavity NRC review Structures Monitoring Program -

IP2 spent fuel pool NRC review

SER Open Items SER Open Items Item Status Containment Inservice Inspection -

p containment concrete aging mgmt NRC review Heat Exchanger Monitoring - visual inspection criteria Ready inspection criteria Ready Inservice Inspection Program - Lubrite sliding supports Ready Inservice Inspection Program -

ASME Code Section XI Ready Nickel Alloy Program - program y

g p

g clarification Ready Inservice Inspection Program -

CASS components Ready 22 CASS components Ready Service Water System - material /

environment clarification Ready

SER Open Items SER Open Items Item Status Periodic Surveillance and Preventive Maintenance - program elements Ready Auxiliary Feedwater Pump Room Fire Event - aging management NRC review Fire Event aging management NRC review Containment Structures -

water-cement ratios NRC review Concrete Structures - Aging management of concrete subject to elevated temperatures NRC review Structures and Component Supports -

p pp Groups B1 - B5 supports Ready Class 1 Fatigue - IP3 heatup and cooldown transients Ready 23 cooldown transients Ready

Topics of Interest

  • Remaining Open Items

- OI 2.5.1 SBO scoping

- OI 3.4-1 AMR results for systems used during auxiliary feedwater pump room fire

- OI 3.0.3.2.15-1 IP2 reactor refueling cavity structure

- OI 3.0.3.2.15-2 IP2 spent fuel pool structure

- OI 3.0.3.3.2-1 Exterior containment concrete aging management

- OI 3.5-1 Water-cement ratio for concrete

- OI 3.5-2 Aging management of concrete subject to elevated temperatures

  • Other Topics of Interest

- Reactor vessel integrity

- Buried piping aging management program 24 Buried piping aging management program

- IP2 containment liner - 1973 feedwater event

SBO Scoping OI 2.5-1 SBO Scoping SBO scoping for IP2 and IP3 meets the requirements SBO scoping for IP2 and IP3 meets the requirements of 10 CFR 54.4(a)(3)

Th LR SBO b

d i i d

ith The LR SBO recovery boundary is in accordance with the NRC guidance (NUREG-1800, Section 2.1.3.1.3 and 2.5.2.1.1)

The LR SBO recovery boundary is also in accordance with the proposed NRC guidance in LR-ISG-2008-01 (D

ft i d 3/5/2008)

(Draft issued 3/5/2008)

Both primary and alternate sources of offsite power 25 Both primary and alternate sources of offsite power are included for SBO recovery for IP2 and IP3

IP2 Auxiliary Feedwater Pump Room Fire Event OI 3.4-1 Component Aging Management Secondary systems credited for alternate flow path to steam generators for a period of one hour in the lik l t

f fi i

th unlikely event of fire in the room Normal plant operation directly demonstrates ongoing ability of the identified systems to perform license ability of the identified systems to perform license renewal intended function RAI requested additional detail on component types credited and aging management Provided requested information in letter dated January 27 2009 26 27, 2009

Structures Monitoring Program OI 3.0.3.2.15-1 IP2 Reactor Refueling Cavity Structural Integrity g

y Stainless steel liner leakage occurs only during refueling outages since late 1970s. Corrective ti i

l t d ith i

d lt actions implemented with mixed results Evaluation of concrete samples concluded concrete and rebar behind the cavity lining remain capable of and rebar behind the cavity lining remain capable of performing license renewal intended function New processes being researched to repair leaks in the reactor refueling cavity liner Aging management includes SMP inspections, core bore sample of concrete and inspection of rebar 27 bore sample of concrete and inspection of rebar

Structures Monitoring Program 28

Structures Monitoring Program OI 3.0.3.2.15-2 IP2 Spent Fuel Pool

  • Pool liner leakage first identified and repaired in Pool liner leakage first identified and repaired in 1992
  • 2005 during excavation for dry fuel storage, an t

i h i k k i t

ll f

d exterior shrinkage crack in concrete wall was found

  • 2007 liner leak found and repaired in transfer canal St t

l l

ti l d d th t th t

  • Structural evaluations concluded that the concrete and rebar remain capable of performing license renewal intended function

Structures Monitoring Program IP2 Spent Fuel Pool 30

Structures Monitoring Program OI 3.0.3.3.2-1 Exterior Containment Concrete Aging Management Isolated areas at Cadweld joints of rebar and at attachment points used for scaffolding during construction

- First documented during the initial IWL inspection in 1995 Evaluation of structural impact - reinforcing steel provides Evaluation of structural impact reinforcing steel provides most of the strength, observed surface degradation has no impact on ability of containment to perform its intended function function Areas are monitored by Structures Monitoring Program Commitment for program enhancement to better 31 p

g characterize observed degradation through the use of optical aids for improving trending capabilities

Structures Monitoring Program OI 3.5-1 Water-Cement Ratio for concrete NUREG-1801 identifies aging effects for concrete in outdoor air g g environment Recommends evaluation considering water-cement ratio IPEC t

t ti f

t t id NUREG IPEC water-cement ratios for concrete are outside NUREG-1801 recommended range ACI 318-63, original design spec for IPEC, provides two methods to determine the required concrete strength IPEC used method 2 for testing of concrete mixtures for containment concrete IPEC actual test reports confirm the compressive strength of concrete was above the required 3000 psi of ACI 318-63 32

Structures Monitoring Program OI 3.5-2 Aging management of concrete subject to elevated temperatures Concern that IP2 hot piping penetrations are allowed to operate at temperatures greater than 200o F NUREG 1801 allows local area concrete temperature greater NUREG-1801 allows local area concrete temperature greater than 200o F with a plant specific evaluation IP2 plant specific evaluation for the effects of temperatures up t

250o F f

d to 250o F was performed

  • Engineering evaluations determined that a maximum of 15% reduction in the strength of concrete for temperatures up to 250o F
  • Concrete tests showed actual strengths more than 20%

above design strength of 3000 psi 33 g

g p

Topic of Interest IP2 Reactor Vessel Integrity Vessel was manufactured by Combustion Engineering Limiting Upper Shelf Energy (USE) location is Plate B2002-3 at 48.3 ft-lbs. Although less than the Appendix G screening criteria of 50 ft-lbs, it exceeds the 43 ft-lbs required by the WOG i

l t

i l

i equivalent margin analysis.

Limiting RTPTS location is circ weld 34B009 at 269 4o F which is Limiting RTPTS location is circ weld 34B009 at 269.4 F which is less than the screening criteria of 300o F.

34

Topic of Interest IP3 Reactor Vessel Integrity Vessel was manufactured by Combustion Engineering Limiting Upper Shelf Energy (USE) location is Plate B2803-3 at 49 8 ft lb Alth h thi i l th th A

di G i

49.8 ft-lbs. Although this is less than the Appendix G screening criteria of 50 ft-lbs, it exceeds the 43 ft-lbs required by the WOG equivalent margin analysis.

Limiting RTPTS location is plate B2803-3 at 279.5o F which exceeds the screening criteria of 270o F.

As required by 10CFR50.61, IP3 will submit a plant-specific q

y p

p safety analysis at least three years prior to exceeding the screening criterion 35

Topic of Interest Buried Piping Aging Management F

li l IP i itt d t NUREG 1801 For license renewal, IP is committed to NUREG-1801 program Section XI.M34 Program includes consideration of operating experience og a c udes co s de a o o ope a g e pe e ce An inspection in Fall of 2008 examined six pipe sections (i.e.

three sections at each of two locations)

Inspections revealed some coating degradation. Pipe wall thickness was measured with UT UT indicated that the piping remains at full thickness.

The coating was repaired and the holes were backfilled.

36

Topic of Interest Buried Piping Aging Management

  • Recent underground leakage in an 8 condensate line due to external corrosion which led to a through-wall defect.
  • The location was excavated, the areas of concern were repaired or replaced and the line was returned to service.
  • A failure analysis is on-going on the removed section of piping to establish additional inspection scope as well as future re-inspection frequency.

scope as well as future re inspection frequency.

  • This operating experience is being reviewed to establish the scope and frequency of future buried pipe inspections 37 pipe inspections.

Topic of Interest IP2 Containment Liner 1973 Feedwater Event November 1973 - plant trip from 7% power Flashing steam impinged on the containment liner causing a bulge to develop bulge to develop Piping was repaired, other modifications made, and liner deformation restored leaving a slight permanent deformation During last outage, 2008, visual inspection confirmed liner still in as-left configuration Continuous weld channel pressurization and ILRTs confirm Continuous weld channel pressurization and ILRTs confirm liner integrity Commitment made to perform a one-time visual inspection prior to entering the period of extended operation 38 prior to entering the period of extended operation

Comments and Questions 39

Advisory Committee on Reactor Safeguards License Renewal Subcommittee Indian Point Nuclear Generating Unit Indian Point Nuclear Generating Unit Nos. 2 and 3 Safety Evaluation Report with Open Items March 4, 2009 Kimberly Green, Project Manager Office of Nuclear Reactor Regulation

Introduction

  • Overview
  • Section 2: Scoping and Screening Review
  • Section 4: Time-Limited Aging Analyses (TLAAs) 2
  • Open Items

Overview

  • 3216 MWth, 1080 MWe
  • Operating license DPR-26 (IP2) expires Operating license DPR 26 (IP2) expires September 28, 2013
  • Operating license DPR-64 (IP3) expires December 12 2015 December 12, 2015
  • Located approximately 25 miles north of NYC limits 3

Overview

  • Safety Evaluation Report with Open Items was i

d J 15 2009 issued January 15, 2009

  • 20 Open items
  • 272 Audit Questions
  • 38 Commitments 4

Overview Scoping and Screening Methodology Audit

- October 8, 2007 - October 12, 2007 Aging Management Programs (AMP) Audit Aging Management Programs (AMP) Audit

- August 27, 2007 - August 31, 2007 Aging Management Review (AMR) & Time-Limited Aging Analysis (TLAA) Audit O t b 22 2007 O t b 26 2007

- October 22, 2007 - October 26, 2007

- November 27, 2007 - November 29, 2007

- February 19, 2008 - February 21, 2008 Regional License Renewal Inspections eg o a ce se e e a spect o s

- January 28, 2008 - February 1, 2008

- February 11, 2008 - February 14, 2008

- March 31, 2008 - April 2, 2008 J

2 2008 J

6 2008 d J 18 2008 5

- June 2, 2008 - June 6, 2008, and June 18, 2008

Open Items

  • SER issued with 20 open items

- 14 with requests for additional information

- 6 are still under review by staff

  • Applicant submitted additional information dated January 27, 2009
  • Staff can close out 13 Open Items 6

Section 2: Structures and Components Subject to Aging Management Review Section 2.1 - Scoping and Screening Methodology Subject to Aging Management Review

  • Based on audit and review staff concluded that the applicants methodology is consistent with the requirements of 10 CFR 54.4 and 54.21(a)(1) requirements of 10 CFR 54.4 and 54.21(a)(1)

Section 2.2 - Plant-Level Scoping Results

  • IP2 chlorination and IP3 H2 systems initially omitted from scope
  • Staff concluded applicant identified mechanical systems and structures within the scope of license renewal per 7

10 CFR 54.4(a).

Section 2.3 - Scoping and Screening Results:

Mechanical Systems Mechanical Systems

  • Mechanical Systems: 59 (IP2 ) and 87 (IP3)
  • Two Tier Review of Balance of Plant systems:

Two Tier Review of Balance of Plant systems:

- Tier 1 Review: Review LRA and UFSAR

- Tier 2 Review: Detailed review of LRA, UFSAR, and li l d i

license renewal drawings

  • 100% of mechanical systems identified by applicant as within the scope of license renewal applicant as within the scope of license renewal were reviewed 8

Section 2.3 - Scoping and Screening Results:

Mechanical Systems Mechanical Systems

  • Staff identified omission of nonsafety-related components from scope for IP2 containment components from scope for IP2 containment spray system
  • Applicant re-evaluated and identified 3 other Applicant re evaluated and identified 3 other systems (IP2 CCW, IP3 CCW, and IP3 BVS)
  • Amended LRA and added components to scope Amended LRA and added components to scope 9

Section 2.3 - Scoping and Screening Results Mechanical Systems Mechanical Systems

  • Three Open Items OI 2 3A 3 11 1 yard hose houses and chamber

- OI 2.3A.3.11 yard hose houses and chamber housings

- OI 2.3.4.2 feedwater isolation valves

- OI 2.3A.4.5 auxiliary feedwater pump room fire event systems

  • These OIs can be closed 10

Section 2.4 - Scoping and Screening Results:

St t

Structures

  • Staff concluded that there were no omissions of t

t t

t l

t f structures or structural components from scope of license renewal in accordance with 10 CFR 54 4(a) and no omissions from AMR in 54.4(a), and no omissions from AMR in accordance with 10 CFR 54.21(a)(1).

11

Section 2.5 - Scoping and Screening Results:

Electrical and Instrumentation and Control Electrical and Instrumentation and Control Systems

  • OI 2.5 Station blackout scoping
  • Issue is under staff evaluation
  • With exception of SBO OI scoping, staff concluded no omissions of electrical and concluded no omissions of electrical and instrumentation and control system components from the scope of license renewal in accordance with 10 CFR 54 4(a) and no omissions from with 10 CFR 54.4(a), and no omissions from AMR in accordance with 10 CFR 54.21(a)(1) 12

Section 2.6 - Conclusion for Scoping and Screening Screening

  • The applicants scoping and screening methodology is consistent with the requirements methodology is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1)
  • With exception of open items, the applicant adequately identified those SSCs within the scope of license renewal in accordance with 10 CFR 54 4(a) and those SCs subject to an AMR CFR 54.4(a), and those SCs subject to an AMR in accordance with 10 CFR 54.21(a)(1).

13

License Renewal Inspections License Renewal Inspections Glenn Meyer Glenn Meyer Region I Inspection Team Leader Region I Inspection Team Leader

Inspection Objectives p

j

  • Scoping of Non-safety SSCs
  • Followup: IP2 SBO DG, electrical cable o o up S O G, e ect ca cab e vault, and containment liner 15

Scoping Scoping

  • Scoping of non-safety SSCs - generally
  • Scoping of non-safety SSCs - generally accurate and acceptable
  • Structural and spatial interactions
  • Structural and spatial interactions reviewed AMP i

f d 2 t

i

  • AMP reviews found 2 component scoping errors 16

Aging Management Program Review g

g g

g Resolved by LRA Amendment 3:

  • Structural Monitoring
  • Oil Analysis Oil Analysis
  • Diesel Fuel Monitoring W t Ch i t
  • Water Chemistry
  • Metal-Enclosed Bus Inspection 17

Aging Management Program Review g

g g

g Resolved by LRA Amendment:

Resolved by LRA Amendment:

  • Selective Leaching N

EQ B l d C bl C

i

  • Non-EQ Bolted Cable Connections Resolved by LRA Commitment 37:
  • Exposed rebar on containment exterior 18 Exposed rebar on containment exterior

Aging Management Program Review g

g g

g Resolved Onsite:

  • Metal-Enclosed Bus Operating Experience
  • Instrument air heat exchangers g
  • AMR for transite material
  • Condition Reports on isolated degradation
  • Condition Reports on isolated degradation 19

Follow Up Inspections p

p

  • IP2 SBO diesel - scoping and system
  • IP2 SBO diesel - scoping and system review when operational
  • Electrical cable vault when accessible
  • Electrical cable vault - when accessible
  • Unit 2 containment liner - when accessible 20

Inspection Conclusions p

  • Non-safety SSC scoping and aging
  • Inspection results support a conclusion of bl th t i

ff t

reasonable assurance that aging effects will be managed and intended functions ill b i t i d

21 will be maintained

Current Performance

  • Both units - Licensee Response Column
  • All Findings - Green All Findings Green
  • All Performance Indicators (PIs) - Green 22

Section 3: Aging Management Review R

lt Results

  • Section 3.1 - Reactor Vessel & Internals
  • Section 3.2 - Engineered Safety Features
  • Section 3.3 - Auxiliary Systems
  • Section 3.4 - Steam and Power Conversion System
  • Section 3.5 - Containments, Structures and Component Supports
  • Section 3 6 Electrical and Instrumentation and Controls 23
  • Section 3.6 - Electrical and Instrumentation and Controls System

Section 3.0.3 - Aging Management Programs (AMP )

(AMPs)

  • 41 AMPs 10 New Programs

- 10 New Programs

- 31 Existing Programs

  • 15 consistent with GALL Report
  • 15 consistent with GALL Report
  • 10 consistent with GALL Report with enhancements
  • 8 with exceptions to GALL Report
  • 8 with exceptions to GALL Report
  • 8 plant-specific 24

Section 3.0.3 - AMPs 8 O It

  • 8 Open Items
  • The following 5 OIs can be closed

- OI 3.0.3.2.7 fire penetration seals

- OI 3.0.3.3.3 acceptance criteria for visual examinations

- OI 3.0.3.3.4 inspection methods, etc. for lubrite sliding supports

- OI 3.0.3.3.4 corrective actions for ISI

- OI 3.0.3.3.7 Periodic Surveillance and Preventive Maintenance Program 25

Section 3.0.3 - AMPs

  • The following 3 OIs are still under review

- OI 3.0.3.2.15 IP2 reactor refueling cavity leakage

- OI 3.0.3.2.15 IP2 spent fuel pool leak

- OI 3.0.3.3.2 Exterior containment concrete degradation degradation 26

Section 3.1 - Aging Management of Reactor Vessel, Internals, and RCS

  • 2 Open Items p

- OI 3.1.2 Nickel alloy components

- OI 3 1 2 2 7 Inspection of CASS OI 3.1.2.2.7 1 Inspection of CASS These 2 OIs can be closed 27

Section 3.3 - Aging Management of Auxiliary Systems

  • One Open Item One Open Item

- OI 3.3 Clarification of material/environment/aging effect for titanium material/environment/aging effect for titanium components This OI can be closed This OI can be closed 28

Section 3.4 - Aging Management of Steam d P C

i S

t and Power Conversion Systems

  • One Open Item

- OI 3.4 AMR results for components needed during a fire in IP2 auxiliary feedwater pump room This OI is still under staff review This OI is still under staff review 29

Section 3.5 - Aging Management of C

t i t

St t

d Containments, Structures and Component Supports

  • 3 Open Items
  • The following 2 OIs are still under staff review OI 3 5 1 W t t

ti f

IP t

- OI 3.5 Water-cement ratio for IP concrete

- OI 3.5 Reduction of strength and modulus of concrete due to elevated temperatures 30

Section 3.5 - Aging Management of g g g

Containments, Structures and Component Supports Component Supports

  • The following OI can be closed

- OI 3.5 Aging management of concrete surrounding B1 supports 31

Section 3.6 - Aging Management of Electrical and I&C Systems

  • LRA identified no aging effects for IP2 138-kV hi h lt bl high-voltage cable
  • Staff issued RAI A

li t

d d LRA t dd bl t

  • Applicant amended LRA to add cable to Periodic Surveillance and Preventive Maintenance Program g

32

Section 3 7 - Conclusion Section 3.7 Conclusion With the exception of the Open Items, the li t h d

t t d th t i

applicant has demonstrated that aging effects will be adequately managed during the period of extended operation in the period of extended operation in accordance with 10 CFR 54.21(a)(3) 33

Section 4: Time-Limited Aging Analyses

  • 4.1 Identification of Time Limited Aging Analyses (TLAAs) g g

y (TLAAs)

  • 4.2 Reactor Vessel Neutron Embrittlement
  • 4.3 Metal Fatigue 4.3 Metal Fatigue
  • 4.4 Environmental Qualification of Electrical Equipment
  • 4.5 Concrete Containment Tendon Prestress
  • 4.7 Other Plant-Specific TLAAs 34

Section 4.2: Reactor Vessel Neutron Embrittlement - Upper Shelf Energy Embrittlement Upper Shelf Energy Limiting Beltline MaterialLower Shell Plate (B2002-3)

Unit 2

% CU 48 EFPY Fluence (E>1 MeV) at Initial Charpy V notch USE Value Irradiated Charpy V Acceptance Criterion per Unit 2

(

)

1/4T 1019 (n/cm2)

(ft-lb) notch USE Value at 48 EFPY (ft-lb) 10 CFR 50, App. G (ft-lb) 0.25 1.136 74 48.3

>50 35

Section 4.2: Reactor Vessel Neutron Embrittlement - Upper Shelf Energy Embrittlement Upper Shelf Energy Limiting Beltline MaterialLower Shell Plate (B2803-3)

Unit 3

% CU 48 EFPY Fluence (E>1 MeV) at Initial Charpy V notch USE Value Irradiated Charpy V Acceptance Criterion per Unit 3

(

)

1/4T 1019 (n/cm2)

(ft-lb) notch USE Value at 48 EFPY (ft-lb) 10 CFR 50, App. G (ft-lb) 0.24 0.9298 68 49.8

>50 36

Section 4.2: Reference Temperature for Pressurized Thermal Shock (PTS) Values Pressurized Thermal Shock (PTS) Values Limiting Beltline MaterialLower Shell Plate (B2803-3)

Unit 3

%CU

%Ni 48 EFPY Fluence (E>1 MeV)

(@clad/steel interface)

Initial Charpy RTNDT 0F RTPTS 0F Acceptance Criterion per 10 CFR 50.61

(@clad/steel interface) 1019 (n/cm2)

F 0F 0.24 0.52 1.56 74 279.5

<270oF 0.52 Commitment 32: As required by 10 CFR 50.61(b)(4), IP3 will submit a plant-specific safety analysis for plate B2803-3 to the NRC three years prior to reaching the RTPTS 37 safety analysis for plate B2803 3 to the NRC three years prior to reaching the RTPTS screening criterion. Alternatively, the site may choose to implement the revised PTS rule when approved.

Section 4.3: Metal Fatigue Analyses

  • 60-year fatigue analyses were performed g

y for all NUREG/CR-6260 locations, except 2 locations (IP2) and 3 locations (IP3)

)

Section 4.3: Metal Fatigue Analyses Section 4.3 - Class 1 Fatigue g

y g

  • One Open Item

- OI 4 3 Number of IP3 plant heatups and

- OI 4.3 Number of IP3 plant heatups and cooldowns This OI can be closed This OI can be closed 39

Open Items Still Under Staff Review

  • OI 3.0.3.2.15 IP2 reactor refueling cavity leakage
  • OI 3.0.3.2.15 IP2 spent fuel pool leak
  • OI 3.0.3.3.2 Exterior containment concrete d

d ti degradation

  • OI 3.5 Water-cement ratio for IP concrete
  • OI 3.5 Reduction of strength and modulus of 40 concrete due to elevated temperatures

- Applicant revised LRA Figures 2.5-2 and 2.5-3, the Offsite Power Scoping Diagram(s) for IP2 and IP3 for primar and secondar offsite po er paths for primary and secondary offsite power paths

- By letters dated March 24, 2008 and August 14, 2008, the applicant revised and clarified its response pp p

- The staff is completing its review of the applicants information on the SBO scoping boundary and will d

t it l

i i

th fi l SER document its conclusion in the final SER 41

  • OI 3.0.3.2.15 IP2 reactor refueling cavity leakage IP2 ref eling ca it leaks at the pper ele ations of the stainless

- IP2 refueling cavity leaks at the upper elevations of the stainless steel cavity liner when flooded during refueling outages

- Attempts have been made to mitigate this condition

- An action plan is being developed for permanent fix

- Applicant has committed to perform one-time inspection prior to entering period of extended operation to confirm absence of degradation (Commitment 36)

- Applicant has not identified augmented inspections for period of extended operation

- Staff sent draft RAI to request how the AMP will monitor condition during period of extended operation 42

  • OI 3.0.3.2.15 IP2 spent fuel pool leak

- IP2 spent fuel pool (SFP) has experienced leakage

- IP2 SFP does not have leak chase channels Applicant committed to test the groundwater outside

- Applicant committed to test the groundwater outside IP2 SFP every 3 months (Commitment 25)

- Applicant does not plan to perform augmented pp p

p g

inspections of SFP during the period of extended operation.

St ff t d ft RAI t t h th AMP ill

- Staff sent draft RAI to request how the AMP will monitor this condition during period of extended operation 43

  • OI 3.0.3.3.2 Exterior containment concrete degradation degradation

- External surfaces of IP2 and IP3 containments have locations of concrete spalling

- Applicant explained that areas of spalling occur at cadweld sleeves and scaffolding anchor locations

- Applicant concluded there is sufficient design margin for exposed rebar

- Applicant committed to perform enhanced inspections of containment (Commitment 37)

- Staff sent draft RAI requesting information on how the applicant will use the above within its Containment Inservice Inspection Program 44

pump room fire event

- Applicant stated that systems are continuously in operation and monitored

- Applicant stated aging related degradation that occurs during 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is negligible

- Applicant concluded that there are no aging effects; therefore no pp g g AMPs are necessary

- Applicant provided additional information on January 27, 2009

- Staff is still evaluating applicants response Staff is still evaluating applicant s response 45

  • OI 3.5 Water-cement ratio for IP concrete

- LRA identified the water-cement ratios for IP concrete

- Staff identified a discrepancy and asked for clarification

- Applicant stated it used Method 2 in ACI 318-63 standard to Applicant stated it used Method 2 in ACI 318 63 standard to determine concrete strength

- Applicant stated that compressive strength > 3,000 psi Staff sent draft RAI to define water cement ratios and provide

- Staff sent draft RAI to define water-cement ratios and provide results of original concrete strength tests. Alternatively, the applicant may identify applicable aging effects and how they will be managed be managed 46

  • OI 3.5 Reduction of strength and modulus of concrete due to elevated temperatures p

- LRA stated concrete surrounding IP2 penetrations can reach 250 °F

- GALL Report recommends further evaluation to manage reduction of strength and modulus of concrete structures due to elevated temperature (>200 °F)

- Applicant concluded that reduction of strength and modulus is not an aging effect requiring management

- Applicant determined a reduction in strength of 15% from elevated temperatures which is acceptable

- Staff sent draft RAI about how strength margin was determined and if reduction in modulus of elasticity was considered Alternatively the reduction in modulus of elasticity was considered. Alternatively, the applicant may explain how the aging effect will be managed 47

Questions?

Questions?

48

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