ML20210D023
| ML20210D023 | |
| Person / Time | |
|---|---|
| Issue date: | 07/20/1999 |
| From: | Hoffman S NRC (Affiliation Not Assigned) |
| To: | NRC (Affiliation Not Assigned) |
| References | |
| PROJECT-690 NUDOCS 9907270110 | |
| Download: ML20210D023 (38) | |
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UNITED STATES g
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NUCLEAR REGULATORY COMMISSION 2
WASHINGTON, D.C. 30e06-0001
- l 4 J July 20,1999 ORGANIZATION:
Nuclear Energy Institute (NEl)
SUBJECT:
SUMMARY
OF MEETING WITH NEl ON LICENSE RENEWAL The Nuclear Regulatory Commission (NRC) staff met with the NEl License Renewal Task Force on July 13,1999, to discuss development of the standard format for license renewal applications. The discussions focused on the two formats contained in NEl's letter to the NRC,
" Standard License Renewal Application Format," dated June 17,1999. A list of meeting attendees is contained in Attachment 1.
The intent is to establish one standard format for license renewal applications to facilitate a stable and efficient license renewal process. Once established, the NRC staff's Regulatory Guide and Standard Review Plan for License Renewal, along with NEl's NEl 95-10, " industry Guideline for implementing the Requirements of 10 CFR Part 54 - the License Renewal Rule,"
will be revised to reflect the new standard. Both the staff and industry agree that the goal is to select an approach to organizing the application that will optimize the applicant's preparation as well as the staff's review of the application.
NEl's June 17,1999, letter contained two formats, referred to as Options A and B. NEl indicated that the two options reflect attemate ways of packaging the same information.
Option A, referred to as the system, structure, and component approach, is similar to the approach used by Duke Energy Corporation in preparing the Oconee Nuclear Station license renewal application. Option A is also similar to the formats transmitted to NEl by NRC letter dated Merch 15,1999, " License Renewal Safety Evaluation Report Format.' Because of the staff and industry's familiarity with this format, the discussion at the meeting focused primarily on Option B.
Option B is referred to by NEl as a commodity approach. For both Options A and D, the approach for scoping and screening in Sections 1 and 2 of the application are basically the same. Both options would include a table identifying the components and structures along with their associated intended functions, materials, environment, aging effects of concem, and the aging management program or activity. The main difference between options is primarily in the area of aging management review for mechanical components. With Option B, components are grouped into commodity groups and the aging management review is performed for the group, rather than referencing them back to their respective systems as is done in Option A. was provided by Southern Nuclear Operating Company to illustrate how the commodity approach would be applied for its Hatch plant.
The NRC discussed its review of the Calvert Cliffs and Oconee license renewal applications and stated that the review followed its traditional organizational structure, primarily by system. j) g The Division of Systems Safety and Analysis reviewed the scoping and screening performed to develop the list required by $54.21(a)(1), the $54.21(a)(2) methodology was reviewed by the Division of Inspection Program Management, and the Division of Engineering reviewed the
$54.21(a)(3) aging management review. However, portions of the staff's aging management
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q July 20, 1999 review were also conducted by program and, in some cases, by individual component. The pros and cons of Options A and B were discussed from the perspective of both the industry and the staff. The goal, that was accomplished at the meeting, was for both the industry and the staff to clarify how their respective license renewal activities are performed and for the staff to better understand the basis for Option B. The next action is for the staff to respond to NEl's June 17,1999, letter. If needed, an additional meeting will be scheduled to further focus the development of the standard format..
0#W85Wey i
Stephen T. Hoffman, Project Manager License Renewal and Standardization Branch Division of Regulatory improvements Program Office of Nuclear Reactor Regulation q
Project No. B90
' Attachments As stated l
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~7/2D/99 OFFICIAL RECORD COPY i
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.p NUCLEAR ENERGY INSTITUTE (License Renewal Steering Committee)
Project No. 690
. cc:
Mr. Dennis Harrison Mr. Robert Gill U.S. Department of Energy
- Duke Energy Corporation NE-42 Mail Stop EC-12R Washington, D.C. 20585 P.O. Box 1006 Charlotte, NC 28201-1006 Mr Ricard P. Sedano, Commissioner Mr. Charles R. Pierce State Liaison Officer Southern Nuclear Operating Co.
Department of Public Service 40 invemess Center Parkway 112 State Street BIN B064 Drawer 20 Birmingham, AL 35242 Montipelier, Vermont 05620-2601 Mr. Douglas J. Walters Mr. Barth Doroshuk Nuclear Energy Institute Baltimore Gas & Electric Company 1776 i Street, N.W.
1650 Calvert Cliffs Parkway Washington, DC 20006 Lusby, Maryland 20657-47027 DJW@NEl.ORG National Whistleblower Center Chattooga River Watershed Coalition 3233 P Street, N.W.
P. O. Box 2006 Washington, DC 20007 Clayton, GA 30525 Mr. William H. Mackay Entergy Operations, Inc.
Arkansas Nuclear One 1448 SR 333 GSB-2E
~ Russellville, Arkansas 72802
1 e
NRC STAFF MEETING WITH THE NUCLEAR ENERGY INSTITUTE ATTENDANCE LIST JULY 13,1999 NAME ORGANIZATION STEVE HOFFMAN NRC/NRR/ DRIP /RLSB SAM LEE NRC/NRR/ DRIP /RLSB LARA HELFER WINSTON & STRAWN STEPHANIE COFFIN NRC/NRR/DE/EMCB RAJ ANAND NRC/NRR/ DRIP /RLSB CHRIS GRATTON NRC/NRR/DSSA/SPLB R.M. LATTA NRC/NRR/DIPM/lOMB DON PALMROSE NUSIS DICK WESSMAN NRC/NRR/DE DON SHAW BGE FRED POLASKI PECO ENERGY DOUG WALTERS NEl CHARLES PIERCE SOUTHERN NUCLEAR JEFF MULVEHILL SOUTHERN NUCLEAR STEVE HALE FPL CHRIS GRIMES NRC/NRR/ DRIP /RLSB CHUCK HSU NRC/RES/DET/MEB DUC NGUYEN NRC/NRR/DE/EElB JENNY WEIL MCGRAW-HILL LYNN CONNOR DSA DEANN RALEIGH SERCH LICENSING BECHTEL NORlHISA YUKl NRC/NRR/ DRIP /RLSB WILLIAM RODILL VIRGINIA POWER JIT VORA NRC/RES/DET/MEB JIM BRAMMER NRC/NRR/DE/EMEB GOUTAM BAGCHI NRC/NRR/DE I
l APPLICATION FORMAT DISCUSSION
CONSTRAISTS ON INFORMATION:
- 1. Information in the sample is representative of the Option B process only.
- 2. The sample has not been reviewed for technical accuracy or completeness.
- 3. Level of detail has not been reviewed for consistency or accuracy.
4:
PACKAGE CONTENTS:
1.
Typical Option B. Template. Sections provided as part of the sample are printed in RED.
2.
Option B Sample-Executive Summary-a place to see the entire results summarized at a high level.
Two Section 2.2 Mechanical System Results Samples
> Residual Heat Removal System
> High Pressure Coolant Injection System Two Section 3.2 Aging Management e
Review Results Samples
> Wrought Austenitic Stainless Steel, Primary Water >482 F, Inside
> Carbon Steel, Primary Water > 482 F, Containment Atmosphere Two Section 3.4 Aging Management e
Programs Samples
> Reactor Water Chemistry Control Program
> Protective Coatings Prog 1am
uCENSE RENEWAL APPLICATION TEMPLATE
)
GENERAL INFORMATION.
Name of Applicant (650.33(a))
Address ofApplicant (650.33(b))
Description of Business or Occupation of Applicant (650.33(c))
Organization and Management of Applicant (650.33(d)) [ address also $54.17 (b)]
Class of License Applied for, the use to which the facility will be put, the period of time for which the license is sought (650.33(c))
Earliest and latest dates for alterations, if proposed (650.33(h))
Listing of regulatory agencies havingjurisdiction and appropriate news publications (650.33(i))
Conforming changes to the standard indemnity agreement (654.19 (b))
- Restricted Data Agraamant (654.17 (f, g))
. Reference to Exhibits A, B, C, and D TABLE OF CONTENTS DEFINITIONS Exhibit A TECHNICALINFORMATION Executive Summary - a sunanary set of tables that presents the entire result, arranged by System: in-scope component / commodity group, component functions, internal and external environments, material, detrimental aging effects, and aging management progr ams.
1.0 Intmduction 1.1 Purpose 1.2 Technical Information Required for an Application-His section will describe what will be found where in the h= ants.
1.3 CLB Changes During NRC Review - Brie 0y describe the process for the required periodic update.
2.0 Structures and Components Subject to an Aging Managemant Review 2.1 Scoping and Screemng Methodology 2.2 MechanicalSystemResults (Eachjour-digit subsection will contain system information. including a short description.
i intendedfunctions components and commodines in scopefor each system. materials. and environmentsfor each componenticommodity) 1 2.2.1 Reactor 1
2.2.1.1 Reactor Assembly 2.2.1.2 Nuclear Boiler System 2.2.1.3 Fuel
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I 2.2.2 ReactorCoolant Systems 2.2.2.1 Reactor Recirculation System
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' 2.23 ' Engineered Safety Features 2.23.1 Standby Liquid Control 2.2.3.2 Remote Shutdown 2.2.3.3 Residual Heat Removal 2.23.4 Core Spray 2.2.3.5 HPCI 2.23.6 RCIC 2.23.7 PipingSpecialties 2.23.8 StandbyGasTreatment 2.23.9 Primary Contamment Purge and Inerting 2.23.10 Post LOCA Hydrogen Recombiner 2.2.4 Auxiliary Systems 2.2A.1 ControlRodDrive 2.2.4.2 Process Radiation Monitoring 2.2.43 RefuelingEquipment 2.2.4.4 Heat Trace 2.2.4.5 Insulation 2.2.4.6 Condensate Transfer and Storage 2.2.4.7 Sampling System 2.2.4.8 Plant Service Water 2.2.4.9 Reactor Bldg. Closed Cooling Water 2.2.4.10 Instrument Air 2.2.4.11 Primary Contamment Chilled Water 2.2.4.12 DrywellPneumatics 2.2.4.13 Plant Cnmmunications 2.2.4.14 Fuel Storage 2.2.4.15 ReactorBldg.HVAC 2.2.4.16 Traveling Water Screens /frash Rakes 2.2.4.17 Outside Stmetures HVAC 2.2.4.18 Fire Protection 2.2.4.19 ControlBldg.HVAC 2.2.5 Steam and Power Convenion 2.2.5.1 Main Condenser 2.2.6 Electric Power /I & C 2.2.6.1 Analog Transmitter Trip System 2.2.6.2 Nuclear Steam Supply Shutoff System
~
O 2.2.63 FeedwaterControl 2.2.6.4 Pnmary Contamment Isolation System 2.2.6.5 ReactorProtection System 2.2.6.6 MainControlRoomPanels 2.2.6.7 In-Plant Auxiliary Control Panels 2.2.6.8 Plant AC Electrical 2.2.6.9 Conduits, Raceways, Trays 2.2.6.10 Plant DC Electrical 2.2.6.11 EmergencyDieselGenerators 2.2.6.12 Uninterruptible Power Supply 2.2.6.13 PowerTransformers 2.2.6.14 Emergency Response Facilities 23 Structures Results
)
(Each three-digit subsection uill contain " system " information. including a short descnprion.
intendedJunctions. stnictural commodities in scope, materials, and environmentsfor each commodin-)
23.1 Access Doors 23.2 Pnmary Contamment 233 ReactorBuilding 2.3.4 Cranes, Hoists, Elevators 23.5 Tornado Vents 23.6 DrywellPenetrations 23.7 ReactorBldg. Penetrations 23.8 TurbineBldg.
23.9 Intake Structure 23.10 Yard Structures 23.11 Offgas Stack 23.12 EDG Bldg.
2.3.13 FuelOil 23.14 ControlBldg.
2.4 ElectricalCommodities (Electrical commodities are evaluated on a plant-uide basis, but intendedfunctions.
matenals, and environmentsfor each commodin.)
3.0 Aging Management Review Results (The overallprocess uill be revieu ed at a high level before section 3.1.)
3.1 Aging Management Review Process (The AMR process uill be described - not a methodology but a desenption tofacilitate l
NRC revieu of the results in section 3.2.)
3.2 Aging Management Review Results (The outlinefor sections 3.2.1 and 3.2.2 are Opical ofapproximately 100 commodin' groups.)
3.2.1 Commodity Group 1 i
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Description of Commodity Group Systems In Which Comma 6ty Group Is Located Commodity Group Materials Commodity Group External Environment Commodity Group Internal Environment Detrimental Aging Effects Aging Management Programs for Commodity Group 1 Demonstration of Aging Management for Commodity Group 1 3.2.2 Commodity Group 2 Description of Commodity Group Systems In Which Commodity Group Is Located Commodity Group Materials Commodity Group External Environment q
Commodity Group Internal Environment Detrunental AgingEffects Aging Managetr nt Programs for Commodity Group 2 Demonstration of Aging Management for Commodity Group 2 (Repeat the above information.for the approximately 100 commodin groups) 3.2.4 Commodity Group 4 - Wrought Austenitic Stainless Steel, Primary Water >482" F, inside 3.2.46 Commodity Group 46 - Carbon Steel, Primary Water > 482* F.
Containment Atmosphere 3.3 Process for Identifying Aging Effects (This section will describe theprocessfor aging effects determination.)
3.4 Aging Management Programs (This section will describe aging managementprograms credited in the application The following is sntended to represent some t)pical activities. Otherprograms' activities will be added as credited.)
3.4.1 Structural Monitoring Program 3.4.1.1 Progre.mDescription 3.4.1.2 Included SSCs and Functions 3.4.1.3 Detnmental Aging Effects 3.4.2 BatteryRackInspections 3.4.2.1 Program Description 3.4.2.2 Included SSCs and Functions 3.4.2.3 Detnmental AgingEffects 3.4.3 Chemistry Control Program 3.4.3.1 Program Description 3.4.3.2 License Renewal In-Scope SSCs and Functions
3.4.33 Detrimental Aging Effects 3.4.4 Coatings Program 3.4.4.1 Program Description 3.4.4.2 included SSCs and Functions 3.4.43 Detrimental Aging Effects 3.4.5 Containment Inservice Inspection Plan 3.4.5.1 ASME Section XI, Subsection IWE Framinations - Program Description 3.4.5.1.1 ProgramDescription 3.4.5.1.2 Included SSCs and Functions
~ 3.4.5.13 Detrimental Agmg Effects 3.4.5.2 ASME Section XI, Subsection IWL Eraminations - Program Description 4.5.2.1 Program Description 4.5.2.2 Included SSCs and Functions 4.5.23 Detnmental Aging Effects 3.4.6 Contamment Imk Rate Testing Program 3.4.6.1 Reactor Building Type A Integrated Imk Rate Test 3.4.6.1.1 ProgramDescription 3.4.6.1.2 Included SSCs and Functions 3.4.6.13 Detrimental AgingEffects 3.4.6.2 Reactor Building Type B Local Imk Rate Test 3.4.6.2.1 ProgramDescription 3.4.6.2.2 Included SSCs and Functions 3.4.6.23 Detrimental Aging Effects 3.4.7 CraneInspectionsProgram 3.4.7.1 ProgramDescription 3.4.7.2 Included SSCs and Functions 3.4.73 Detrunental AgingEffects 3.4.8 Quality Assurance Program 3.4.8.1 Corrective Action 3.4.8.2 Document Control 3.4 9 Electrical Bus Inspection Program 3.4.9.1 ProgramDescription 3.4.9.2 Included SSCs and Functions 3.4.93 Detrimental Aging Effects 3.4.10 Fire BarrierInspections
.3.4.10.1 Program Description 3.4.10.2 Included SSCs and Functions 3.4.10 3 Detnmental Aging Effects 3.4.11 Inservice Inspection Plan 3.4.11.1 ASME Section XI, Subsection IWB and IWC Inspections 3.4.11.2 Cast Austenitic Stainless Steel Flaw Evaluations 3.4.11.2.1 Reactor Coolant Pump Casing and Cover
3.4.11.2.2 Reactor Vessel Internals 3.4.11.2.3 Summary 3.4.11.3 ASME Section XI, Subsection IWF Inspections 3.4.11.4 Included SSCs and Functions 3.4.11.5 Detnmental Aging Effects 3.4.12 New Program Required for License Renewal 4.0 Time-Limited Aging Analyses and Exemptions Review 4.1 Time-Limited Aging Analyses Review 4.2 Exemptions Review EXHIBIT B: UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Discussion Unit 1 New Chapter 15 Unit 2 New Chapter 18 EXHIBIT C: TECHNICAL SPECIFICATION CHANGES EXHIBIT D: PROPOSED OPERATING LICENSES EXHIBIT E: ENVIRONMENTAL REPORT 1
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OPTION B SAMPLE 1
Executive Summtry A License Renewal application using an approach consistent with the NE! Option B approach will make the demonstration that detrimental aging effects are being managed for SSCs within the scope of the License Renewal Rule at the commodity level. These demonstrations are presented in Section 3.2 of the application document. However, an applicant may choose to summarize the resultant information in a series of 6-column tables to provide a picture of the overall aging management of the plant on a system-by-
' system basis. The Executive Summary provides a place for the applicant to concisely present this overview information. The details associated with each line item would appear within the applicable Section 3.2 review.
The review of mechanical components is performed on the basis of a systematic and rigorous evaluation using the parameters of component material, component internal environment, and component external environment to fonn evaluation groupings. The evaluations' draw from the extensive collection ofindustry information to identify detnmental aging effects - those aging effects requiring management in the period of extended operation.
The 6-column table format provides the following information:
Commodity identification -This column serves two purposes. First, an identification of the types of components included within the commodity grouping. Second, a unique identifier to cross-reference to the applicable subsection in 3.2-Aging Management Review Resuks.
Component Functions -Taken from the list of component functions provided in NEl 95-10, as augmented by additional component functions not listed in Rev. 0.
Material-This column identifies the commodity group material.
Internal / External Environment - This column identifies the internal and external e
environments to which the commodity group is subjected.
Aging Management Programs - This column identifies - at a high level-the plant activities credited for managing the detrimental effects of aging for the commodities evaluated as part of the commodity group during the period of extended operation.
Two sample tables are provided for illustration:
Table 19 presents resuhs for a BWR RHR (Ell) System's Mechanical components / commodities. Table 22 presents results for a BWR HPCI (E41) System's Mechanical compor.ents/ commodities.
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Section 2.2, Mech:nic1! Systems 2.2.3.3 RESIDUAL HEAT REMOVAL [ Ell]
System Description
' The residual heat removal (RHR) system is composed of several components and subsystems which are required to:
- Restore and maintain reactor vessel water level after a loss of coolant accident (LOCA).
I e Limit temperature and pressure inside the containment after a LOCA.
- Remove heat from the suppression pool water.
- Remove decay and residual heat from the reactor core to achieve and maintain a cold shutdown condition.
]
The RHR system consists of four pumps and mo heat exchangers divided into two loops of two pumps and one heat j
exchanger each, plus the associated instruments, valves, and piping. The RHR pumps take suction from the
. suppression pool or the reactor coolant recirculation loop. The pumps discharge into the recirculation loop, the suppression pool, the containment spray headers, the spent-fuel pool cooling and cleanup system, etc., depending upon the desired mode of system operation. ne RHR system interfaces with the recirculation system to provide a flow-path in support of shutdown cooling and low pressure coolant injection (LPCI). The RHR system is part of the reactor coolant pressure boundary; therefore, it also maintains the pressure boundary during normal operation, transients, and accident scenarios to prevent the release of radioactive liquid and gas.
De internal environment of the RHR ' ystem is normally reactor water taken either from the suppression pool s
during the LPCI and suppression pool cooling modes of operation or from the recirculation loop for shutdown cooling. Internal environment for the RHR service water (RHRSW) portion of the system is raw river water.
During plant conditions that require the operation of the shutdown cooling mode of RHR, reactor water can be cooled to approximately ll7'F via the RHR heat exchangers and recirculated back to the reactor through the RRS piping. During plant shutdown conditions, the water temperature la this piping can be as low as 70*F.
P rtions of the system are located in the drywell, the reactor building, and the intake structure, ne external environments for the system are primarily nonaggressive. The normal environmental conditions in the drywell are as follows: temperatures of 150*F maximum,135'F normal; pressure of-0.5 psig minimum and 2.0 psig maximum; and relative humidity between 40 percent and 90 percent. De radiation dose equivalent for the 60 year life is 9.17
' rem. The RHR pressure boundary components are insulated. Some RHRSW components are exposed to open air conditions at the intake structure, and portions of this piping are buried..
Intended Functions Within the Scope of License Renewal.
)
Low pressure Coolant injection (LPCI). The LPCI restores and maintains the coolant inventory in the reactor vessel so the core is adequately cooled following a design basis LOCA and other design basis events.
Containment Spray. Containment spray provides post accident containment atmosphere temperature acd pressure control by use of spray nozr.les located in both the drywell and the torus area.
RHRSW Vessel / Containment Injection. RHRSW providet a reliable supply of cooling water to the reactor pressure vessel (RPV) following a loss of RHR/ core spray or to flood the primary containment to provide cooling to the j
exterior of the reactor vessel using raw river water, j
Shutdown Cooling. Shutdown cooling removes decay and residual heat from the reactor during shutdown and cooldown when the reactor pressure is so low that the vacuum in the condenser cannot be maintained, rendering the condenser inoperable or the high pressure coolant injection (HPCI) and/or reactor core isolation cooling (RCIC) pumps inoperable due to a lack of steam.
2.21-
d Sectio:s 2.2, Mechxnic11 Systems Suppression Pool Cooling. Suppression pool cooling limits the water temperature in the suppression pool to ensure it has adequate heat capacity remaining in the event of a design basis LOCA, and removes heat post-accident and during testing of the HPCI and RCIC systems.
Alternate Shutdown Cooling. Alternate shutdown cooling provides an alternate means to ecol and depressurize the reactor vessel following a fire.
Commodities Requiring An Aging Management Review (See table 2.2.3.3-1) 2.2-2
=
Section 2.2, Mechtnic11 Systems 9
Table dI3 Residual Heat Removal System [ Ell) Mechanical Components, Component Functions, and Aging Management Review Cross Reference Commodity Aging Component Functions Management Review /
Mechanical Component Section 3.2 Cross-Reference Conductivity Element Fission Product Barrier, Pressure Boundary 030M Fasteners Pressure Boundary 030M,074M Flow Sensor Fission Product Barrier, Pressure Boundary 012M Heat Exchanger Fission Product Barrier, Pressure Boundary Ol7M,052M Piping Fission Product Barrier, Pressure Boundary 001M,003M,004M,042M, 044M,046M,052M,056M,
- 060M, Pumps Fission Product Barrier, Pressure Boundary 017M,052M,059M Restricting Orifice Fission Product Barrier, Pressure Boundary, Flow 012M,014M Restriction Strainers Debris Protection Ol3M Thermowell Fission Product Barrier, Pressure Boundary 052M Tubing Pressure Boundary 001M,003M,004M,014M, 107M Vacuum Breakers Fission Product Barrier, Pressure Boundary 00lM,003M,004M Valves Fission Product Barrier, Pressure Boundary 059M,056M, i
i N
J
Section 2.2, Mechsdc'11 Systems 2.2.3.5 HIGH PRESSURE COOLANTINJECTION [E41]
System Description
The high pressure coolant injection (HPCI) system supplies makeup coolant into the reactor vessel from a fully pressuriud to a preset depressuriud condition. Demineralind makeup water is supplied frorn the condensate storage tank (CST) or the suppression pool. He flow rate of the system will maintain the reactor vessel coolant inventory until the reactor pressure drops sufficiently to permit the low pressure core cooling systems to automatically inject coolant into the vessel.
He HPCI system consists of a turbine driven pump train, piping, valves, and controls which provides a complete and independent emergency core cooling system (ECCS). A test line permits functional testing of the system during normal plant operation. A minimum flow bypass line bypasses pump discharge flow to the suppression pool to protect the pump in the event of a stoppage in the main discharge line. Steam line B supplies reactor vessel steam to the turbine. Turbine exhaust steam is then dumped to the suppression pool.
The HPCI system is described in the Units I and 2 FSAR, sections 6.3. The internal environment of the HPCI system is primarily demineralind water from the CST. The system also has a second suction source of treated water from the suppression pool. The principal external environment is the reactor building. The reactor building is a mild environment with a normal operating temperature of 90 *F and normal relative humidity of 40 percent.
Because the system is normally on standby, the normal internal environment for the turbine and associated components is wetted nitrogen. This is due to a slight vacuum that occurs in the exhaust line as exhaust steam cools. This will draw nitrogen from the torus through the vacuum breaker piping and into the turbine (assuming minor check valve leakage).
Tne system contains primarily cart,on steel piping with some sections of stainless stest piping. He piping is designed to USAS B31.7, Class 11 and Ill criteria.
Intended Functions Within the Scope of License Renewsl Core Cooling. The HPCI system is provided to assure the reactor is adequately cooled to limit fuel-clad temperature in the event of a small break in the reactor coolant system and a loss of coolant which does not result in rapid depressurization of the reactor vessel. His function permits shutdown of the plant while main.taining sufficient reactor vessel water inventory until the reactor is depressurind.
Commodities Requiring an Aging Management Review (See table 2.2.3.5-1) l i
m 2.24
^
l Section.2.2, MechznicxlSystems Table 2.2.3.5-1
{
High Pressure Coolant Injection System [E41] Mechanical Components, Component Functions, and Aging Management Review Cross Reference j
Commodity Aging Component Functions Management Review / Section Mechanical Component 3.2 Cross-Reference Fasteners Pressure Boundary 074M
~
Piping Pressure Boundary 006M,007M,018M,021M, 028M,042M,044M,046M, 04BM,066M,127M Pumps Pressure Boundary 048M Restricting Orifice Pressure Boundary, Flow Restriction 001M,003M,004M,006M, 021M Rupture Disc Pressure Boundary 021M Turbine Pressure Boundary 066M Valves Pressure Boundary 001M,003M,004M,042M, 044M,046M,048M,049M,
- 066M, 2.2-5 t
Secti:n 3.2, Aging Magement Review Results 3.2.4 AMR Results For Commodity Group 4-Wrought Austenitic St:'aless Steel, Primary Water >482* F, inside Description This AMR covers E41, E51, B21, and N61 r>ystem components included in the following plant commodity group:
wrought stainless steels, primary water, > 482* F, inside. Twenty eight commodities fall under the guidance of this AMR. These commodities represent ASME Class 1 piping and valve bodies, Non-class 1 piping, valve bodies, thermowells, sensors, orifice plates, strainer baskets, and steam trap bodies located within the scope of license renewal for the materials and environment criteria which define this commodity group.
Applicable Systems E41 -HPCI E51 - RCIC B21 - Main Steam N61 - Main Condenser Internal Environments All components covered by this AMR are subjected to an internal environment of Primary Water at a temperature >
482 *F. This environment includes both liquid water and steam. Primary water is defined as any fluid meeting the requirements of Hatch chemistry control procedures which apply to water suitable for use in the nuclear steam supply system.
External Environments
.All components covered by this AMR are subjected to an external environment of"inside" or " containment atmocphere". Specifically, this term implies that the equipment is sheltered from the weather and protected from any freeze / thaw cycles. The equipment may also be located within the drywell. This environment does assume the presence of significant humidity and the presence of sufficient oxygen for any corrosion mechanism to occur.
External environment temperatures are limited to less than 200 *F at all times under normal operating conditions.
Aging Effects -Internal Two aging effects, caused by various mechanisms, have been identified for this commodity group:
1.) Cracking due to stress corrosion cracking, intergranular attack, thermal fatigue, vibrational fatigue; 2.) Loss of material due to crevice corrosion and pitting.
Aging Effects - Enternal E.xternal piping surfaces could be susceptible to SCC or IGA under certain conditions.
Aging Management Programs-laternal
- Both preventive / mitigative and component monitoring programs manage the identified aging effects.
l 1
3.2 1
]
Sectio:s 3.2, Aging Magement Review Results Mitigation Of Loss Of Material Due To Crevice Corrosion And Pitting Primary ' ater parameters and impurities are controlled through the chemistry control program. All systems to w
which this commodhy is applicable are covered by the requirements of this program. The program controls dissolved oxygen levels and halogens / sulfates, thereby preventing and mitigating loss of material due to crevice corrosion and pitting.
Mitiga' ion Of Cracking Dae To IGA And SCC t
De Hydrogen Water Chemistry program mitigates the aging mechanisms ofIGA and SCC for Main Steam system components included in this commodity group.
Component Monitoring Programs De 151 program provides a means for the evaluation of system integrity at set intervals, and describes the requirements for the various systems to which this commodity is applicable. In addition, the HPCI and RCIC systems undergo system normal pressure tests every nine months.
The plant monitors and trends vibration levels of all safety related rotating machinery via plant procedures. His i
monitoring, along with prompt corrective actions provides assurance that small bore components near rotating machinery are not subject to undue vibrational stresses. In those cases where failures have occurred, analysis indicates that weld anomalies were a coNbuting factor in the failure. To address this issue, the plant provided increased weld control for fabrication of small bore socket welded joints.
Aging Management Programs - External nermal insulation used for piping included in this commodity group meets the requirements of NRC Reg. Guide 1.36, thereby preventing SCC and 1GA for external surfaces.
Operating Experience Demonstration De aging management programs and regulatory oversight effectively manage the aging effects such that there is reasonable assurance the component functions and supported intended functions are maintained consistent with the CLB for the period of extended operation.
3.2-2
d Section 3.2, Aging Mxnigemext Revie:r Results
~
AGING MANAGEMENT PROGRAM ASSESSMENT l
ATTRIBUTES AGING MANAGEMENT PROGRAM / PROCEDURE T
I Scope of the program includes the -
specific Structure, component or -
commodity (SCC)for the identified aging effect.
2 Preventive actions to mitigate or prevent aging degradation.
3 Parameters monitored orinspected are linked to the degradation of the '
particular SCC intended function.
4 The method of detection of the aging effects is described and performed in a timely manner.
5 Monitoring and trending for timely'.
corrective actions.
6.
Acceptance criteria are included.
7 Corrective act ons, including root cause determination and prevention of recurrence, are included.
8 Confirmation process is included.
9 Administrative controls should -
provide a formalreview and approval process.
10 Operating experience of the aging management program, including past corrective actions resulting in program enhancements or additional programs, are considered 11 Aging management programs and/or procedures are established by regulation and are subject to regulatory oversight.
i 1
j 3.2-3
}
l
f Secthn 3.2, Aging M:ntgement Review Results 4
1 3.2.46 - AMR Results For Commodity Group No. 046M
. Description
. His AMR covers components included in the following plant commodity group: carbon steel, primary water,
>482'F and located inside primary containment. nese commodities represent ASME Class 1 and 2 and ANSI B31.1 piping components, valve bodies, temperature elements, flow elements and nozzles, steam traps and strainers located within the scope of license renewal for the materials and environment criteria listed above.
The Unit I components are furnished to Ah31 B31.7, Class 1,1969 Edition and ANSI B31.1.0. He Unit 2
)
components are furnished to ASME Section III, Class 1,1971 Edition and ANSI B31.1.0.
Components covered by AMR046M are constructed from carbon steel. Weld material used in system fabrication and the metallurgical effects of the welding techniques employed are also included in this AMR.
Applicable Systems I
1,2 B21 Main Steam 1,2 E41 HPCI 1,2 E51 RCIC 2 N61 Main Condenser Internal Environments All components under the guidance of this AMR are subjected to an internal environment of primary water at a temperature greater 482*F. Primary water is defined by Hatch chemistry control procedures which apply to water suitable for use in the nuclear steam supply system (NSSS). Specifically, primary water must have low oxygen
)
content, low halogen content, low sulfate content, and a pH between 5.6 and 8.6.
l Esternal Environments i
All components covered by this AMR are subjected to an extemal environment of
- containment, inside the reactor building or turbine building." Specifically, this term implies that the equipment is located inside. His environment does assume the presence of significant humidity.
Aging Effects -Internal Internal aging effects identified for this commodity group are 1.) Cracking due to vibrational induced fatigue; 2.) Loss of material due to general corrosion, crevice corrosion, and pitting corrosion.
3.) Loss of material due to erosion-corrosion. His effect applies to all commodities except the main steam piping.
. Aging Effects-External None identified i
3.2-4 h
e Sectioa 3.2, Agi:g Mmgement Review Results Aging Management Programs -Internal 1
AGING MANAGEMENT PROGRAMS FOR VIBRATIONAL INDUCED FATIGUE i The support systems for small-bore piping are designed with all known loads and stressed accounted for, including
-vibration loads.' nese designs, in most cases, provide the necessary support to the piping to prevent failures due to vibration. However, a review of plant operating experience reveals a small number of small-bore piping failures attributable to VIF. The plant monitors and trends vibration levels of all safety related rotating machinery. This monitoring, along with prompt corrective actions provides assurance that small bore components near rotating machinery are not subject to undue vibrational stresses. In those cases where failures have occurred, analysis indicates that weld anomalies were a contributing factor in the failure. To address this issue, the plant provided increased weld control for fabrication of small bore socket welded joints. Dese controls provide assurance that
)
separate piping sections are fabricated in such a way as to minimia the risk of failure due to high cycle fatigue.
Numerous plant procedures provide requirements for the monitoring of the leak tightness of Class 1 and Non Class I systems pressure boundary, nese procedures provide additional assurance that the pressure boundary of these systems has not been compromised due to thennel or vibrational induced cracking.
De plant ISI Procedures provide guidance concerning leak tightness testing of the Class I systems. Tests are
. performed at the ccmpletion of each refueling outage at a pressure of 1035 psig. De acceptance criteria are as follows: "No evidence ofleakage within the reactor coolant inspection boundary with the exception of mechanical joints, valve packing, and gaskets. Any leaks from the inspection boundary must be itemind and their leakage rate described."
Unit I and 2 Inservice Inspection Program Third Ten Year Examination Plan, Volumes I thru 5 Provides guidance on implementation of ASME Section XI at the plant including the types and frequency of all ASME Section XI and Nureg 0313 inspections.
The plant procedure provides guidance conceming leak tightness testing of the Non-Class I portions of E41, E51, and N11 and meets the requirements of ASME Section XI for pressure testing (both functional and in-service test requirements). It is performed in accordance with the Unit I and 2 Inservice inspection Program, Volume 5.
Integrity of E41 and E51 system components is also monitored at 9-month intervals via operational performance
' leakage testing to identify any degradation of the pressure boundaries of these components between ISI pressure tests.
For those components included within the scope of this AMR that are located within the Drywell and are pressurimd at all times during operation, Technical Specification surveillance procedures monitor the type and quantity ofleakage. Violation of Technical Specification leakage limits is considered to be a Limiting Condition for Operation. If excessive leakage from unidentified sources were to occur during operation, the surveillance procedures require the source of leakage be identified. If the leakage cannot be identified within a time limit or if any leakage is identified as pressure boundary leakage, the unit must be shut down.
AGING MANAGEMENT PROGRAMS FOR GENERAL CORROSION General corrosion is the result of a chemical reaction between a material and an aggressive environment. General corrosion is normally characterind by uniform attach resulting in loss of material or corrosion buildup. Oxygen and moisture are both required for iron corrosion. The plant chemistry program for the Primary Water controls the primary water quality and chemistry according to technical specifications requirements which classifies the primary water as a non aggressive environment.' In additions, the designers of piping of this plant commodity group incorporated corrosion allowances inherent in the design process. The combination of water chemistry and the i
3.2-5
E Secthn 3.2, Agi:g Mmgemext Review Results corrosion allowances provides adequate aging management of general corrosion to ensure it does not compromise the intended functions of this plant commodity group.
. AGING MANAGEMENT PROGRAMS FOR PITTING AND CREVICE CORROSION Whenever dissolved Oxygen levels are maintained at established levels, loss of material due to crevice corrosion and pitting is prevented. Hatch chemistry procedures require that dissolved Oxygen content in the reactor feedwater be monitored daily.
' Total halogens and sulfate levels are closely monitored and controlled. Therefore, considering the chemistry controls in place, crevice corrosion and pitting are effectively mitigated for the penod of extended operation.
Operating history confirms this evaluation.
Plant procedures provide recommendations and guidance on lay-up of systems. Where possible, dry lay-up of systems is recommended during extended outages to further reduce potential corrosion effects. Components that cannot be isolated from the core car.not be placed in dry lay.up. However, monitoring of reactor coolant chemistry during shutdown prevents accumulation of dissolved oxygen and harmful impurities.
Therefore, considering the chemistry controls in place, crevice corrosion and pitting are effectively mitigated for the period of extended operation. Operating history confirms this svaluation.
AGING MANAGEMENT PROGRAMS FOR EROSION - CORROSION Due to the high flow, high temperatures above 200*F, the carbon steel piping components of this commodity are susceptible erosion / corrosion.
i Erosion / corrosion occurs when fluid or particulate matter is also conosive to the metal and high-velocity or turbulent conditions exist. Erosion / Corrosion of carbon steel under single phase flow conditions is affected the water chemistry / flow path, flow conditions and material composition. Erosion-corrosion rates are greatest at j
1 temperatures of 212 to 392F and decrease rapidly above and below this temperature range. Also, flow rates less that 6fi/sec will not cause erosion-corrosion of carbon and alloy steels.
\\
The plant has in place a program titled " Flow Accelerated Corrosion (FAC) Program (Reference 4) that was created to manage the loss of material due erosion and erosion / corrosion. His program is based on the elements as identified in the Electric Power Research Institute (EPRI) generated docunient NSAC/202L," Recommendations for Effective Flow Accelerated Corrosion Program" (Reference 6). The objective of the program is to:
(1) provide a high degree of assurance that each unit of the plant will operate during each fuel cycle without experiencing a FAC-related rupture.
(2) provide a high quality, systematic, and comprehensive techical approach for the evaluation and inspection of FAC-susceptible systems, and (3) maintain the program as a living, on going program which continually evaluates and incorporates the latest technologies, industry and in-house experience, and plant operational and design changes.
His program provides a methodical and systemic evaluation of the plant by providing criteria and/or guidelines for: selection of systems susceptible to FAC, evaluation ofinspection data, repair and replacement of components, and quality requirements, and documentation requirements as well as other criteria and guidelines.
i l
3.2-6
1 a
Secti:n 3.2, Agi g Minsgement Review Results Aging Management Programs - External
. None Identified Demonstration The aging management programs and regulatory oversight effectively manage the aging effects such that there is reasonable assurance the component functions and supported intended functions are maintained consistent with the CLB for the period of extended operation.
l O
\\
3.2-7
s Section 3.,, Agi::g Mzugeme:t Revie:s Results AGING MANAGEMENT PROGRAM ASSESSMENT ATTRIBUTES AGING MANAGEMENT PROGRAM /PR'OCEDURE I
Scope of the program includes the specific Structure, component or commodity (SCC)for the identifwd aging effect.
2 Preventive actions to mitigate or prevent aging degradation.
3 Pirameters monitored orinspected are linked to the degradation of the.
particular SCC intended function.
4 The method of detection of the aging effects is described and performed in a timely manner.
5 Monitoring and trending for timely corrective actions.
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6 Acceptance criteria are included.
7 Corrective actions, including root cause determination and prevention of recurrence, are included.
8 Confirmation process is included.
9 Administrative controls should provide a formalreview and approval process.-
10 Operating experience of the aging management program, including past i
corrective actions resulting in program enhancements or additional programs, are considered 1I Aging management programs and/or procedures are established by
~
regulation and are subjectto. ~ -
'~ ~
~~ -
regulatory oversight.
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Section 3.4, Aging Mwgemen Progrzms end Activilles 3.4 ACING MANAGEMENT PROGRAMS AND ACTIVITIES CHARACTERISTICS OF ACCEPTABLE PROGRAMS AND ACTIVITIES The plant programs and activities that are credited for aging management of a specific structure or component are considered acceptable within the framework of the license renewal rule because they all contain the following program elements.
- 1.. The scope of the programs and activities includes the specific structures and components subject to an aging management review for renewal.
2.
The programs specify preventive actions that mitigate or prevent aging degradation.
3.
Parameters monitored or inspected under plant programs are linked to the degradation of the particular structure J
and component intended function (s).
4.'
Plant programs and activities provide for detection of aging effects before there is a loss of the structure and component intended function (s).
5.
Where applicable, plant programs and activities provide for monitoring and trending such that they provide predictability of the extent of degradation and timely corrective or mitigative actions. The monitoring, inspection, testing frequency, and sample size have been shown to be appropriate for timely detection of aging effects.
6.
Plant programs and activities provide acceptance criteria, against which the need for corrective action will be evaluated, to ensure that the structure and component intended function (s) are maintained under all CLB design conditions during the period of extended operation.
7.
Plant programs and activities provide for timely corrective actions, including root cause determination and prevention of recurrence.
- 8. - Confirmation processes at the plant ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
9.
Administrative controls provide for formal review and approval of plant programs, activities and procedures.
- 10. Plant and industry operating experience, including past corrective actions have resulted in program enhancements or additional programs and activities. The results of these enhancements provide objective evidence that the effects of aging will be adequately mansged so that the structure and component intended
. function (s) will be maintained during the period of extended operation.
3.4.3 REACTOR WATER CHEMISTRY CONTROL PROGRAM 3.4.3.1 Program Description I
3.4.3.1.1-Purpose The Reactor Water Chemistry Control Program is a major part of the overall chemical control strategy for the plant.
It is a preventive or mitigating Aging Management Program (AMP) designed to maintain structural integrity of plant systems and components by controlling fluid purity and composition.
3.44
Section 3.4, Aghg Mxntgement Progr1ms and Activities 3.4.3.1.2 Seope By controlling water chemistry in the reactor coolant, condensate /feedwater cycle and the reactor water cleanup (RWCU) system, the plant reduces intergranular stress corrosion cracking (IGSCC) in reactor cooling system piping and reactor internals. Chemistry control also minimizes irradiation-assisted stress corrosion cracking (IASCC) and fuel cladding corrosion. Finally, water chemistry control helps decrease flow accelerated corrosion (FAC) in the reactor coolant system, as well as balance of plant systems.
3.4.3.1.3 Method The principal elements of the Reactor Water Chemistry Control program at the plant are regular sampling, results analysis and, when applicable, chemistry modification. These activities are further supported by trending, tracking and regular program evaluations.
'Ihe reactor coolant, condensate, and feedwater systems that normally supply reactor coolant makeup are closely monitored, and regularly sampled and analyzed by the Chemistry Section during all modes of plant operation.
In the event that established limits are exceeded, the time is tracked by the Chemistry Section.
3.4.3.1.4Sampie Size and Frequemey Reactor water sample frequencies and limits are operating mode dependent. Examples (not a complete list) of plant mode-dependent sample frequencies and limits are shown in Figures 3.4J.1-1 through 3.4.3.1-3. Sample sizes may vary in accordance with specific circumstances and applicable plant sampling procedures.
Figure 3.4.3.1 1: Reactor Water Chemistry - Cold Shutdown Parameter Frequency Achievable Action Levels Prior to TRM Value Startup Maximum 1
2 3
Conductivity Varies
$1.0 2.0 N/A N/A
$1.0
$ 10.0
( mhos/cm)
Chiri.E Daily
$ 20.0 100 N/A N/A
$100 U1 < 500 (ppb)
U2 < 100 pH Daily (FW) pH < 5.6 N/A N/A N/A pH > 5.6 5.6 $,pH pH < 8.6 58.6 pH > 8.6 Sulfate (ppb)
Daily
$100 100 N/A
> 10.0
< 100 N/A
\\
i l
i 3.4 2 a
Secti:n 3.4, Aging Minsgeme::t Prrgrams cnd Activities Figure 3.4.3.1-2: Reactor Water Chemistry-Startup/ Hot Standby and Hot Shutdown Parameter Frequency Achievable Action Levels Prior to TRM Value Operation Maximum 1
2 3
Conductivity Varies 50.5 N/A 1.0 N/A 51.0
< 5.0
( mhos/cm)
Chlorides Daily
$ 20.0 N/A
> 100 N/A 5 20
< 100 (PP )
b
)
pH Daily ~
(FW)
N/A pH < 5.6 pH < 3.4.6 N/A pH < 3.4.6 5.6 5,pH Or Or Or 58.6 pH > 8.6 pH > 9.0 pH > 9.0 Sulfate (ppb)
Daily
$ 20 N/A 100
> 200
$ 20 N/A Figure 3.4.3.1 3: Reactor Water Chemistry - Power Operations Parameter Frequency Achievable Action Levels TRM Maximum Value 1
2 3
Conductivit Continuous 50.5 N/A 1.0 N/A
< 5.0 y
(pmhos/cm) l Zine Daily.
5 - 10 N/A N/A N/A N/A (PP) b Chlorides Daily 5 20.0 N/A
> 100 N/A
< 100 (PP) b pH Daily (FW)
N/A pH <
pH < 3.4.6 pH < 3.4.6 5.6 SyH 5.6 or Or 58.6 Or pH > 9.0 pH > 9.0 pH >
8.6 Silica (ppb)
Daily
$200
> 200 N/A N/A N/A Sulfate Daily 5 20 N/A 100
> 200 N/A b
(PP )
Recire.
Continuous
< 500 N/A N/A N/A N/A Dissolved H2 (ppb)
ECP Continuous 5-230
>-230 N/A N/A N/A (mV, SHE) 3.4-3
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e Section 3.4, Aging M:n!geme: ipr:gr:ms cxd Activities 4
I As with reactor water, the specific condensate and feedwater parameters monitored, along with the sample frequencies, vary depending on the plant operational mode. Figures 3.4.3.1-4 and 3.4.3.1-5 provide examples (not a complete list) of the sample frequencies, applicable limits and action levels for condensate /feedwater.
l Figure 3.4.3.1-4: Condensate /Feedwater Chemistry - Startup/ Hot Standby Parameter Frequency Achievable Action Levels Prior to Operation Value 1
2 3
Feedwater Continuous 5 0.10
> 0.15 N/A N/A N/A Conductivity (pmhos/cm)
Feedwater Total Every
$15.0
> 100 N/A N/A
< 20 Metallic 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 1
Impurities b
(PP)
Feedwster Continuous20-200
> 200 N/A N/A
< 200 Oxygen b
i (PP )
Hotwell Continuous
$ 0.15 N/A N/A
> 10.0 N/A Conductivity (pmhos/cm) 1 3.4-4 1
Section 3.4, Agi:g M : :gement Pr:grims exd Activities Figure 3.4.3.1-5: Condensate /Feedwater Chemistry - Power Operations Parameter Frequency Achievable Action Levels Value 1
2 3
Feedwater Continuous 5 0.060
> 0.070 N/A N/A Conductivity (pmhos/cm)
Feedwater Total Weekly
$ 15.0
> 100 N/A N/A Metallic Integrated Impurities (PP )
b Feedwater Total Weekly 5 0.30
> 0.30 N/A N/A Copper Integrated (opb)
Feedwater Total Weekly 52.0
> 5.0 N/A N/A Iron Integrated b
(PP)
Feedwater Daily 20-50
< 15 or N/A N/A Oxygen
> 200 b
(PP )
Hotwell Continuous 5 0.0655
> 0.10 N/A
> 10.0 Conductivity (pmhos/cm) 3.4.3.1.51adustry Codes and Standards The framework for the Chemistry Control Program at the plant is based upon EPRI TR-103515,"BWR Water Chemistry Guidelines." The Hydrogen Water Chemistry es pment installed at the plant reflects EPRI NP 5283-SR-A," Guidelines for Permanent BWR Hydrogen Water Cknistry Installations".
Electric Power Research Institute (EPRI) document TR-108705,"BWR Vessel and Internals Project, Technical Basis for inspection Relief for BWR Internal Components with Hydrogen Injection" 3.4.3.1.6 Acceptance Criteria Figures 3.4.3.1-1 through 3.4.3.1 5 provide the maximum TRM values for plant reactor water chemistry, as well as examples of the procedural limits imposed by the Chemical Section procedures (not a complete list). The specific TRM requirements for reactor water chemistry are contained in TRM sections T3.4.1 TSR 3.4.1.1, TSR 3.4.1.2 and Table T3.4.1-1.
3.4.3.1.7 Corrective Action Corrective action is required at the specific Action Level values, such as the examples provided in figures 3.4.3.1 1 through 3.4.3.1-5 of this section. The specific actions to be taken at each of the three levels are described below.
3.4.3.1.B Action Level 1 If efforts to reduce the parameter below the Action Level I value within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> are not successful, then an evaluation is performed to determine the effects on the structural integrity of the reactor coolant system.
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Sectio 2 3.4, Aging himgemext Pr:gt:ms cxd Activities i
3.4.3.1.9 Aetion Level 2 If efforts to reduce the parameter below the Action Level 2 value within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are not successful, then an orderly shutdown will be initiated and the plant placed in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
3.4.3.1.10
- Action Level 3 If the Action Level 3 value is exceeded, then the reactor will immediately be shutdown, and will be placed in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
if a shutdown is based upon exceeding an Action Level 2 or 3 value, the incident will be reviewed and evaluated, and appropriate measures will be taken before the unit is restarted.
3.4.3.1.11 Administrative Control By procedure, the Chemistry Section is responsible for establishing and maintaining the program for sampling and monitoring plant systems, including the appropriate procedures and instructions. Chemistry is also responsible for making recommendations for corrective actions to avoid adverse trends.
When necessary, chemistry modification may be performed by Operations, Chemistry and Maintenance Sections, working together or separately, according to responsibilities assigned through plant procedures.
'Ihe Chemistry Section reviews data and performs trend analysis. The plant Engineering Section assists Chemistry in performing evaluations of the structural integ' ity of the in-scope plant systems.
r All chemistry sampling and analysis is done in accordance with approved plant procedures and department instructions. Changes to any procedures credited during the Aging Management Review (AMR) process are controlled by
. This assures that those aging mitigation activities credited for license renewal will remain in place for during the extended license period.
3.4.3.1.12 Regulatory Basis Reactor water chemistry limits were originally included in the Technical Specifications, but were relocated to the Technical Requirements Manual (TRM) and plant procedures as part of the Technical Specifications improvement Program.
? 4.3.2 Licener RenewalIn Scope SSCs and Functions B11, B21, B31 (Information to correlate to AMRs).
3.4.3.2.1 Detrimental Aging Effects The aging effects prevented or mitigated by plant reactor water chemistry control methods are loss of material (MI) and cracking (M2).
3.4.4 PROTECTWE COATINGS PROGRAM 3.4.4.1 Proaram Description 3.4-6
i a,
Sectio:o 3.4, Agi:g M:n:gement Pr:gr:ms c:d Activities 3.4.4.1.1 Purpose ne plant Protective Coatings Program provides a means of preventing or minimizing aging effects that would I
otherwise result from contact of the base metal with the fluid environment. It is a mitigation and condition monitoring program designed to provide base metal aging management through surface application, maintenance and inspection of protective coatings on selected components and structures.
3.4.4.1.2 Scope ne Protective Coatings Program encompasses multiple in-scope structurcs and componerts. The service level breakdowns for these structures and components, along with the applicable environments, are shown below.
Service LevelI inside Primary Containment - Non-Immersion: Coatings applied to the suppression chamber and drywell airspace.
inside Primary Containment - Immersion: Coatings applied to the suppression chamber interior below the normal water level.
Service Level 11
)
Outside Primary Containment - Non Immersion: Coatings applied to systems, structures and components that are essential to intended operation.
Outside Primary Containment -Immersion: Coatings applied to components that store process fluids that will be introduced into non-safety related systems.
Service Level!!!
Outside Primary Containment-Non Immersion: Coatings applied on steel or concrete that might become detached and damage safety systems.
Outside Primary Containment -Immersion: Coatings applied to internals of systems containing process fluids required for safe shutdown of the reactor.
3.4.4.1.3 Method The plant Protective Coatings Program ensu'res that the integrity of such coatings is maintained through proper application, inspections, and maintenance.
Proper Application
- Inspections Maintenance 3.4.4.1.4 Sample Size and Frequency Protective coatings surveillance is normally performed once per operating cycle for Service Level I components.
Service Level 111 component surveillance is performed as determined by the Protective Coatings Specialist, based upon trends and operating experience.
3.4-7
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- Section 3.4, Aging Musgeme:t Progr:ms cad ActMeles 3.4.4.1.5 Industry Codes and Standards De following codes and standards were used in the development of the plant Protective Coatings Program.
ANSI N5.9 - 1967. Protective Coatin;s (Paints) for the Nuclear ladustry.
ANSI N5.12. - 1972, Protective Coatings (Paints) for the Nuclear Industry.
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ANSI N101.2 - 1972, Protective Costings (Paints) for Light Water Nuclear Reactor Containment Facilities.
)
ASTM, Section 6, Volume 06-02, Paints-Products and Applications; Protective Coatings; Pipeline Coatings 3.4.4.1.6 Acceptan'ce Criteria Costings application is not allowed to proceed until applicable solvent cleanine,, removal of stratified rust, loose mill scale, non-adherent paint, weld flux and splatter, and thick edge paint feathering has been verified. Prepared steel must conform to SSPC-SPil (Steel Structures Painting Council) visual standards SSPC-VIS3.
Afler cor. ting activities have been completed, responsible supervision completes a detailed walkdown to ensure that coatings have been applied in accordance with the Maintenance Work Order (MWO). Supervision also verifies that coatings have not been applied to any plant equipment that could be rendered inoperable because of the coating.
i 3.4.4.1.7 Corrective Action Deficiencies discovered during the performance of the plant Protective Coatings Program activities are required by plant procedures to be documented in accordance with the deficiency control program. Corrective action, as described in Chapter 17 of the Unit 2 FSAR is part of the Quality Assurance (QA) Program. All participants in the QA program, including suppliers and contractors, meet the appropriate sections of 10 CFR50, Appendix B.
De various components of the Corrective Action program provide for timely corrective actions, including root cause determination and prevention of recurrence. De QA program provides control over activities affecting the quality of systems, structures and components consistent with their importance to safety.
3.4.4.IJ Administrative Control Administrative controls provide for fonnal review and approval of plant programs, activities and procedures. The activt.ies and procedures described below are reviewed and approved at the Department Manager level.
Procedures are in place to establish the requirements and responsibilities for implementing, maintaining, and periodically assessing the effectiveness of the plant Protective Coatings Program. Procedures also define the qualification requirements for the responsible Protective Coating Specialist, inspection personnel, QA and maintenance personnel who apply or inspect coatings.
Appropriate controls are in place to ensure that quantities of non-acceptable primary containment Service Level I coatings assumed in various calculations are not exceeded. Any non-acceptable protective coating is tracked as degraded qualified coating by procedure.
' 3.4.4.1.9Regalatory Basis The Quality Assurance requirements for protective coatings used in the primary containment meet the requirements of Regulatory Guide 1.54, Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants (Reference 2).
J.4-g
- O Section 3.4, Agizg M:nigement Progrims c;'d Activities s
The regulatory documents shown below were also considered in the development of the plant Protective Coatings Program.
NRC Bulletin 96 03 Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors NRC Generic Letter 98-04, Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System After a Loss-of Coolant Accident Because of Construction and Protective Coating deficiencies and Foreign Material in Containment.
3.4.4.2 License RenewalIn-Scope SSCs and Functions The license renewal in-scope SSC aging effects are managed by the Protective Coatings Program are highlighted on the following Boundary Diagrams:
{
3.4.4.2.1 Boundary Diagrams T23 B01-001 T23 B01-007 T23 B01-013 T23 B01002 T23 B01-008 T23 B01-014 T23-B01-003 T23-B01-009 T23-B01015 j
T23 B01-004 T23-B01-010 T23-B01-016
)
T23-B01005 T23 B01-Oll T23-B01006 T23-B01-012 3.4.4.2.2 Fuaetions i
T23-01 3.4.4.3 Detrimental Aging Effects The aging effects mitigated and monitored thrcugh the plant Protective Coatings Program are
. Specific aging mechanisms are discussed in the applicable Aging Manag. ment Reviews.
3.4-9
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> L Date: July 20,1999 Distribution:
j Hard copy Docket File PUBLIC RLSB RF N. Dudley, ACRS - T2E26 E. Hylton i
E-mail:
R. Zimmerman W. Kane D. Matthews S. Newberry C. Grimes C. Carpenter B. Zaleman J. Strosnider R. Wessman E. Imbro W. Bateman J. Calvo H. Brammer T. Hiltz G. Holahan T. Collins C. Gratton B. Boger R. Correia R. Latta J. Moore J. Rutberg R. Weisman M. Mayfield S. Bahadur A. Murphy D. Martin W. McDowell S. Droggitis RLSB Staff G. Tracy A.Thadani J. Craig M. Federline C. Julian
' R. Gardner D.Chyu
.._ m. 3
.