ML12338A467
| ML12338A467 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 04/15/2005 |
| From: | Kalyanam N Office of Nuclear Reactor Regulation |
| To: | Venable J Entergy Operations |
| SECY RAS | |
| References | |
| RAS 22104, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 | |
| Download: ML12338A467 (18) | |
Text
United States Nuclear Regulatory Commission Official Hearing Exhibit ENT000088 Entergy Nuclear Operations, Inc. Submitted: March 28, 2012 In the Matter of:
(Indian Point Nuclear Generating Units 2 and 3)
ASLBP #: 07-858-03-LR-BD01 Docket #: 05000247 l 05000286 Exhibit #: ENT000088-00-BD01 Identified: 10/15/2012 Admitted: 10/15/2012 Withdrawn:
Rejected: Stricken:
Other:
April 15, 2005 Mr. Joseph E. Venable Vice President Operations Entergy Operations, Inc.
17265 River Road Killona, LA 70066-0751
SUBJECT:
WATERFORD STEAM ELECTRIC STATION, UNIT 3 - ISSUANCE OF AMENDMENT RE: EXTENDED POWER UPRATE (TAC NO. MC1355)
Dear Mr. Venable:
The Commission has issued the enclosed Amendment No. 199 to Facility Operating License No. NPF-38 for the Waterford Steam Electric Station, Unit 3 (Waterford 3). This amendment consists of changes to the Technical Specifications (TSs) in response to your application dated November 13, 2003, as supplemented by letters dated January 29, March 4, April 15, May 7, May 12, May 13, May 21, May 26, July 14, July 15, July 28, August 10, August 19, August 25, September 1, September 14, October 8 (2 letters), October 13, October 18, October 19, October 21, October 29 (2 letters), November 4, November 8, November 16, and November 19, 2004, and January 5, January 14, February 5, February 16, and March 17, 2005. Entergy Operations, Inc., (Entergy) requested changes to the Facility Operating License and TSs for Waterford 3.
The amendment increases the maximum steady-state reactor core power level from 3441 megawatts thermal (MWt) to 3716 MWt, which is an increase of approximately 8 percent.
The increase is considered an extended power uprate (EPU).
By supplemental letter dated July 15, 2004, Entergy decided to implement an Alternative Source Term (AST), as permitted by 10 CFR 50.67, Accident source term, for calculating accident offsite doses and doses to control room personnel. This request has been reviewed by the U.S. Nuclear Regulatory Commission staff and the amendment was issued on March 29, 2005.
The staff is not providing a technical evaluation of Entergys dose analyses using the original licensing source term in the attached safety evaluation (SE) (Section 2.9) for the EPU, and has referred to the SE for the AST license amendment. The staff's finding of acceptability for the proposed increase in power uprate is based on the AST application meeting the requirements of 10 CFR 50.67 and General Design Criterion 19, and the staff's approval of the request for a full-scope implementation of an AST for Waterford 3 via letter dated March 29, 2005.
In the supplemental letter dated February 5, 2005, Entergy has a commitment as follows:
Prior to exceeding 3441 MWt, Entergy will submit, for NRC review and approval, a description of how Entergy accounts for instrument uncertainty for each Technical Specification parameter impacted by the Waterford 3 Extended Power Uprate.
J. Venable This commitment is included in the amendment as a license condition, as discussed during a telephone call with you on April 14, 2005. You will need to submit a separate license amendment request pursuant to 10 CFR 50.90 and then receive NRC approval of that request, via a separate license amendment, to complete this license condition.
We want to provide some observations on the overall conduct of this review that resulted in the unusually large expenditure of staff resources and the extended schedule. The completeness and thoroughness of the engineering work and project planning supporting your application appear to have evolved during the NRC's review rather than having been developed up front.
There were many problems, changes, and errors that arose during the course of the review, some identified by the staff and others by Entergy, that could and should have been anticipated and addressed before you submitted the amendment application. Similarly, we believe you could have taken fuller advantage of your Arkansas Nuclear One, Unit 2, EPU experience. We are conducting a lessons-learned evaluation to assess our review experience with the new EPU review standard and to determine whether we could have detected these issues in your application during our acceptance review. We hope that you too will critically review your performance for any useful lessons learned.
A copy of our related SE is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.
Sincerely,
/RA by T. Alexion for/
N. Kalyanam, Project Manager, Section 1 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-382
Enclosures:
- 1. Amendment No. 199 to NPF-38
- 2. Safety Evaluation cc w/encls: See next page
J. Venable This commitment is included in the amendment as a license condition, as discussed during a telephone call with you on April 14, 2005. You will need to submit a separate license amendment request pursuant to 10 CFR 50.90 and then receive NRC approval of that request, via a separate license amendment, to complete this license condition.
We want to provide some observations on the overall conduct of this review that resulted in the unusually large expenditure of staff resources and the extended schedule. The completeness and thoroughness of the engineering work and project planning supporting your application appear to have evolved during the NRC's review rather than having been developed up front.
There were many problems, changes, and errors that arose during the course of the review, some identified by the staff and others by Entergy, that could and should have been anticipated and addressed before you submitted the amendment application. Similarly, we believe you could have taken fuller advantage of your Arkansas Nuclear One, Unit 2, EPU experience. We are conducting a lessons-learned evaluation to assess our review experience with the new EPU review standard and to determine whether we could have detected these issues in your application during our acceptance review. We hope that you too will critically review your performance for any useful lessons learned.
A copy of our related SE is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.
Sincerely,
/RA by T. Alexion for/
N. Kalyanam, Project Manager, Section 1 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-382
Enclosures:
- 1. Amendment No. 199 to NPF-38
- 2. Safety Evaluation cc w/encls: See next page DISTRIBUTION: See next page Accession No.: ML051030068 TS/License pages: Package: ML051030082
- Minor/Editorial Changes from SE input **with change to cover letter OFFICE PDIV-1/PM PDIV-1/LA EMCB/A EMCB/B EMCB/C EMEB/B EEIB/A NAME TAlexion for DJohnson MMitchell JTC for LLund KManoly AMarinos NKalyanam TChan DATE 4/11/05 4/11/05 2-17-05 2-28-05 2-24-05 2-23-05 2-24-05 EEIB/B** SPLB/A SPLB/B SPSB/C SRXB/B IROB/B IEPB/A SPSB/BC*
RJenkins SJones SWeerakody RDennig DCoe DTrimble DThatcher MTschiltz 2-28-05 2-24-05 3-3-05 2-23, 23, 24-05 2-25-05 3-14-05 2-24-05 10-7-04 SRXB/BC PDIV-1/SC PDIV/D OGC DLPM/D** NRR/D JWermiel AHowe HBerkow APHodgdon nlo TMarsh JDyer 4-5-05 email 4/11/05 4/11/05 3-25-05 4/12/05 4/15/05 OFFICIAL RECORD COPY
Distribution for letter dated: April 15, 2005
SUBJECT:
WATERFORD STEAM ELECTRIC STATION, UNIT 3 - ISSUANCE OF AMENDMENT RE: EXTENDED POWER UPRATE (TAC NO. MC1355)
DISTRIBUTION:
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J. Medoff J. Tsao R. Davis C. Wu T. Scarbrough N. Trehan J. Lazevnick H. Li A. Stubbs J. Tatum N. Iqbal R. Lobel M. Hart L. Brown C. Liang S. Miranda F. Orr W. Lyons P. Clifford J. Cai S. Dennis R. Pettis M. Stutzke J. Stang L. Raghavan
-i-TABLE OF CONTENTS Page
1.0 INTRODUCTION
1.1 Application 1 1.2 Background 1 1.3 Licensees Approach 3 1.4 Plant Modifications 3 1.5 Method of NRC Staff Review 3 2.0 EVALUATION 2.1 Materials and Chemical Engineering 2.1.1 Reactor Vessel Material Surveillance Program 5 2.1.2 Pressure-Temperature Limits and Upper-Shelf Energy 8 2.1.3 Pressurized Thermal Shock 10 2.1.4 Reactor Internal and Core Support Materials 12 2.1.5 Reactor Coolant Pressure Boundary Materials 14 2.1.6 Leak-Before-Break Evaluation 16 2.1.7 Protective Coating Systems (Paints) - Organic Materials 18 2.1.8 Flow-Accelerated Corrosion 19 2.1.9 Steam Generator Tube Inservice Inspection 22 2.1.10 Steam Generator Blowdown System 23 2.1.11 Chemical and Volume Control System 25 2.1.12 Water Chemistry Evaluation 26 2.2 Mechanical and Civil Engineering 2.2.1 Pipe Rupture Locations and Associated Dynamic Effects 27 2.2.2 Pressure-Retaining Components and Component Supports 29 Nuclear Steam Supply System Piping, Components, and Supports Balance-of-Plant Piping, Components, and Supports
- ii -
TABLE OF CONTENTS Reactor Vessel and Supports Control Element Drive Mechanism Steam Generators and Supports Reactor Coolant Pumps and Supports Pressurizer and Supports 2.2.3 Reactor Pressure Vessel Internals and Core Supports 37 2.2.4 Safety-Related Valves and Pumps 39 2.2.5 Seismic and Dynamic Qualification of Mechanical and Electrical Equipment 41 2.3 Electrical Engineering 2.3.1 Environmental Qualification of Electrical Equipment 42 Containment Accident Conditions High-Energy Line Breaks Radiological Conditions - Reactor Auxiliary Building 2.3.2 Offsite Power System 44 Grid Stability Main Generator Main Transformers Unit Auxiliary Transformers Startup Transformers Plant Load Changes for Power Uprate Evaluation Iso-Phase Bus and Bus Duct Generator Output Breakers 2.3.3 Alternating Current Onsite Power System 47 2.3.4 Direct Current Onsite Power System 48 2.3.5 Station Blackout 49 2.3.6 Three-Second Time Delay Between Steam Generator Tube 50 Rupture and Loss-of-Offsite Power
- iii -
TABLE OF CONTENTS 2.3.7 Implementation 57 2.4 Instrumentation and Controls 2.4.1 Reactor Protection, Safety Features Actuation, and Control Systems 58 Suitability of Existing Instruments Instrument Setpoint Methodology Generic Concern Regarding Method 3 Acceptability of Proposed Changes 2.5 Plant Systems 2.5.1 Internal Hazards 62 2.5.1.1 Flooding 2.5.1.1.1 Flood Protection 2.5.1.1.2 Equipment and Floor Drains 2.5.1.1.3 Circulating Water System 2.5.1.2 Missile Protection 2.5.1.2.1 Internally Generated Missiles 2.5.1.2.2 Turbine Generator 2.5.1.3 Pipe Failures 2.5.1.4 Fire Protection 2.5.2 Pressurizer Relief Tank 68 2.5.3 Fission Product Control 69 2.5.3.1 Fission Product Control Systems and Structures 2.5.3.2 Main Condenser Evacuation System 2.5.3.3 Turbine Gland Sealing System 2.5.4 Component Cooling and Decay Heat Removal 71 2.5.4.1 Spent Fuel Pool Cooling and Cleanup System 2.5.4.2 Station Service Water System 2.5.4.3 Reactor Auxiliary Cooling Water Systems
- iv -
TABLE OF CONTENTS 2.5.4.4 Ultimate Heat Sink 2.5.4.5 Emergency Feedwater System 2.5.5 Balance-of-Plant Systems 78 2.5.5.1 Main Steam 2.5.5.2 Main Condenser 2.5.5.3 Steam Bypass 2.5.5.4 Condensate and Feedwater 2.5.6 Waste Management Systems 82 2.5.6.1 Gaseous Waste Management Systems 2.5.6.2 Liquid Waste Management Systems 2.5.6.3 Solid Waste Management Systems 2.5.7 Additional Considerations 85 2.5.7.1 Emergency Diesel Engine Fuel Oil Storage and Transfer System 2.5.7.2 Light Load Handling System (Related to Refueling) 2.6 Containment Review Considerations 2.6.1 Primary Containment Functional Design (Containment Isolation) 87 2.6.2 Subcompartment Analyses 88 2.6.3 Mass and Energy Release 89 2.6.3.1 Mass and Energy Release Analysis for Postulated Loss-of-Coolant 2.6.3.2 Mass and Energy Release Analysis for Secondary System Pipe Rupture 2.6.4 Combustible Gas Control in Containment 92 2.6.5 Containment Heat Removal (Emergency Core Cooling System and Containment Spray System Pump Net Positive Suction Head) 93 2.6.6 Pressure Analysis for Emergency Core Cooling System Performance Capability 94
-v-TABLE OF CONTENTS 2.6.7 Generic Letter 96-06 95 2.7 Habitability, Filtration, and Ventilation 2.7.1 Control Room Habitability System 96 2.7.2 Engineered Safety Feature Atmosphere Cleanup 97 Containment Fuel Handling Building Control Room Shield Building 2.7.3 Control Room Area Ventilation System 100 2.7.3.1 Control Room Area Ventilation System 2.7.3.2 Reactor Auxiliary Building Normal Ventilation System 2.7.3.3 Spent Fuel Pool Area Ventilation System 2.7.3.4 Turbine Area Ventilation System 2.7.3.5 Engineered Safety Feature Ventilation System 2.8 Reactor Systems 2.8.1 Fuel System Design 106 Fuel Rod Clad Collapse Fuel Rod Clad and End Cap Weld Fatigue Fuel Clad Stress Clad Strain Plenum Spring Seizure Rod Maximum Internal Pressure 2.8.2 Nuclear Design 109 2.8.3 Thermal and Hydraulic Design 111 2.8.4 Emergency Systems 112 2.8.4.1 Functional Design of Control Element Drive System 2.8.4.2 Overpressure Protection During Power Operation
- vi -
TABLE OF CONTENTS 2.8.4.3 Overpressure Protection During Low Temperature Operation 2.8.4.4 Shutdown Cooling System 2.8.4.5 Nuclear Steam Supply System Design Transients 2.8.4.6 Station Blackout 2.8.5 Accident and Transient Analyses 119 2.8.5.1 Increase in Heat Removal by the Secondary System 2.8.5.1.1 Decrease in Feedwater Temperature, Increase in Feedwater Flow, Increase in Steam Flow, and Inadvertent Opening of a Steam Generator Relief or Safety Valve 2.8.5.1.2 Steam System Piping Failures Inside and Outside Containment 2.8.5.2 Decrease in Heat Removal by the Secondary System 2.8.5.2.1 Loss of External Load, Turbine Trip, Loss of Condenser Vacuum, and Steam Pressure Regulator Failure 2.8.5.2.2 Loss of Nonemergency Alternating Current Power to the Station Auxiliaries 2.8.5.2.3 Loss of Normal Feedwater Flow 2.8.5.2.4 Feedwater System Pipe Breaks Inside and Outside Containment 2.8.5.3 Decrease in Reactor Coolant System Flow 2.8.5.3.1 Loss of Forced Reactor Coolant Flow 2.8.5.3.2 Reactor Coolant Pump Rotor Seizure and Reactor Coolant Pump Shaft Break 2.8.5.4 Reactivity and Power Distribution Anomalies 2.8.5.4.1 Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Startup Condition
- vii -
TABLE OF CONTENTS 2.8.5.4.2 Uncontrolled Control Element Assembly Withdrawal at Power 2.8.5.4.3 Control Element Misoperation 2.8.5.4.4 Startup of an Inactive Loop at an Incorrect Temperature 2.8.5.4.5 Chemical and Volume Control System Malfunction that Results in a Decrease in Boron Concentration in the Reactor Coolant 2.8.5.4.6 Spectrum of Rod Ejection Accidents 2.8.5.4.7 Inadvertent Loading of a Fuel Assembly Into an Improper Position 2.8.5.5 Inadvertent Operation of Emergency Core Cooling System and Chemical and Volume Control System Malfunction that Increases Reactor Coolant Inventory 2.8.5.6 Decrease in Reactor Coolant Inventory 2.8.5.6.1 Inadvertent Opening of Pressurizer Pressure Safety Valve 2.8.5.6.2 Steam Generator Tube Rupture 2.8.5.6.3 Emergency Core Cooling System and Loss-of-Coolant Accidents 2.8.5.6.4 Small Primary Line Break Outside of Containment 2.8.5.7 Anticipated Transients without Scram 2.8.5.8 Asymmetric Steam Generator Transient 2.8.6 Fuel Storage 158 2.8.6.1 New Fuel Storage 2.8.6.2 Spent Fuel Storage 2.9 Source Term and Radiological Consequences Analyses 159 2.10 Not Used 2.11 Human Performance 161
- viii -
TABLE OF CONTENTS 2.11.1 Human Factors 161
- 1. Changes in Emergency and Abnormal Operating Procedures
- 2. Changes to Operator Actions Sensitive to Power Uprate
- 3. Changes to Control Room Controls, Displays, and Alarms
- 4. Changes on the Safety Parameter Display System
- 5. Changes to the Operator Training Program and the Control Room Simulator 2.12 Power Ascension and Testing Plan 2.12.1 Approach to Extended Power Uprate Power Level and Test Plan 165
- 1. SRP 14.2.1,Section III.A. - Comparison of Proposed Test Program to the Initial Plant Test Program
- 2. SRP 14.2.1,Section III.B. - Post Modification Testing Requirements for Structures, Systems, and Components Important to Safety Impacted by Extended Power Uprate-Related Plant Modifications
- 3. SRP 14.2.1,Section III.C. - Justification for Elimination of Extended Power Uprate Power-Ascension Tests
- 4. SRP 14.2.1 Section III.D. - Adequacy of Proposed Testing Plans 2.13 Risk Evaluation 2.13.1 Risk Evaluation of Extended Power Uprate 178 Level 1 Internal Events Risk Evaluation Level 1 Internal Flooding Risk Evaluation Level 1 Internal Fire Risk Evaluation Level 1 Seismic Risk Evaluation Level 1 Other External Events Risk Evaluation Level 2 Internal and External Events Evaluation Shutdown Risk Evaluation PRA Model Quality
- ix -
TABLE OF CONTENTS 2.13.2 Additional Review Areas (Risk Evaluation) 198 3.0 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION CHANGES 198 4.0 REGULATORY COMMITMENTS 209 5.0 RECOMMENDED AREAS FOR INSPECTION 223
6.0 STATE CONSULTATION
224
7.0 ENVIRONMENTAL CONSIDERATION
224
8.0 REFERENCES
225
9.0 CONCLUSION
231
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 199 TO FACILITY OPERATING LICENSE NO. NPF-38 ENTERGY OPERATIONS, INC.
WATERFORD STEAM ELECTRIC STATION, UNIT 3 DOCKET NO. 50-382
1.0 INTRODUCTION
1.1 Application By application dated November 13, 2003, (Reference 1), as supplemented by letters dated January 29 (Reference 2), March 4 (Reference 3), April 15 (Reference 4), May 7 (Reference 5),
May 12 (Reference 6), May 13 (Reference 7), May 21 (Reference 8), May 26 (Reference 9),
July 14 (Reference 10), July 15 (Reference 11), July 28 (Reference 12), August 10 (Reference 13), August 19 (Reference 14), August 25 (Reference 15), September 1 (Reference 16), September 14 (Reference 17), October 8 (Reference 18 and Reference 19),
October 13 (Reference 20), October 18 (Reference 21), October 19 (Reference 22),
October 21 (Reference 23), October 29 (Reference 24 and Reference 25), November 4 (Reference 26), November 8 (Reference 27), November 16 (Reference 28), and November 19, 2004 (Reference 29), and January 5 (Reference 30), January 14 (Reference 70), February 5 (Reference 71), February 16 (Reference 72), and March 17, 2005 (Reference 75), Entergy Operations, Inc., (Entergy, the licensee) requested changes to the Facility Operating License and Technical Specifications (TSs) for the Waterford Steam Electric Station, Unit 3 (Waterford 3).
The proposed changes would increase the maximum steady-state reactor core power level from 3441 megawatts thermal (MWt) to 3716 MWt, which is an increase of approximately 8 percent. The proposed increase in power level is considered an extended power uprate (EPU).
1.2 Background The Waterford 3 site is located in southeastern Louisiana on the west bank of the Mississippi River near the town of Taft in Saint Charles Parish. The nearest population center is Kenner, 13 miles east of the site. New Orleans is approximately 25 miles east-southeast of the site.
Technical Evaluation The licensee stated that Waterford 3 Service Level 1 coatings in containment were selected and tested to meet design basis accident (DBA) and normal operating conditions. These coatings meet the requirements of American National Standards Institute (ANSI)
Standards N5.12, Protective Coatings (Paints) for the Nuclear Industry, dated June 20, 1974, and N101.2, Protective Coatings (Paints) for Light Water Nuclear Reactor Containment Facilities, dated May 30, 1972. The quality assurance during manufacturing, transportation, and storage is in compliance with ANSI Standard N101.4, Quality Assurance for Protective Coating Applied to Nuclear Facilities, dated November 1972, in conjunction with the general quality assurance requirements of ANSI Standard N45.2, Quality Assurance Program Requirements for Nuclear Power Plants. The licensee stated that the procurement, application, and maintenance of Service Level 1 protective coatings used inside the containment are consistent with the licensing basis and regulatory requirements. The requirements of 10 CFR Part 50, Appendix B, are implemented through specification and procedures that delineate appropriate technical and quality requirements for the Service Level 1 coatings program, including ongoing maintenance activities. The protective coatings are discussed in UFSAR Section 6.1.2.
The EPU conditions that can affect the qualification of the coatings are changes in pressure, temperature, radiation, and chemistry. The licensee concluded that changes in pressure, temperature, radiation, and chemistry for DBA and normal conditions due to the EPU are bounded by current DBA and normal conditions for these parameters. Consequently, the protective coatings remain qualified for EPU conditions.
On the basis of the NRC staff review, the NRC staff concludes that the protective coating systems are acceptable under the EPU conditions because the current DBA and normal conditions bound the EPU conditions for the pressure, temperature, radiation, and chemistry parameters.
Summary The NRC staff has reviewed the licensee's evaluation of the effects of the proposed EPU on protective coating systems and concludes that the licensee has appropriately addressed the impact of changes in conditions following a DBLOCA and their effects on the protective coatings. The NRC staff further concludes that the licensee has demonstrated that the protective coatings will continue to be acceptable following implementation of the proposed EPU and will continue to meet the requirements of Appendix B to 10 CFR Part 50. Therefore, the NRC staff finds the proposed EPU acceptable with respect to protective coating systems.
2.1.8 Flow-Accelerated Corrosion Regulatory Evaluation Flow-accelerated corrosion (FAC) is a corrosion mechanism occurring in carbon steel components exposed to flowing single- or two-phase water. Components made from stainless steel are not affected by FAC, and FAC is significantly reduced in components containing small amounts of chromium or molybdenum. The rates of material loss due to FAC depend on velocity of flow, fluid temperature, steam quality, oxygen content, and pH. During plant
operation, control of these parameters is limited and the optimum conditions for minimizing FAC effects, in most cases, cannot be achieved. Loss of material by FAC will, therefore, occur. The NRC staff has reviewed the effects of the proposed EPU on FAC and the adequacy of the licensees FAC program to predict the rate of loss so that repair or replacement of damaged components could be made before they reach critical thickness. The licensees FAC program is based on NUREG-1344, GL 89-08, and the guidelines in EPRI Report NSAC-202L-Revision 2 (Reference 39). It consists of predicting loss of material using the CHECWORKS computer code, and visual inspection and volumetric examination of the affected components.
The NRCs acceptance criteria are based on the structural evaluation of the minimum acceptable wall thickness for the components undergoing degradation by FAC.
Technical Evaluation The licensee used EPRIs CHECWORKS code to estimate the effects of EPU on components that are susceptible to FAC. The licensee used changes to the plant operating parameters (e.g., increased flow rates, changes in steam quality, temperatures, and pressures) to determine the effects of the EPU conditions on FAC wear rates. The licensee updated the current CHECWORKS model with the EPU conditions for all modeled systems that are susceptible to FAC. The updated model also incorporates all inspection data for calibration of predicted wear rates. This study compared the current predicted wear rates and the post-EPU predicted wear rates of all modeled systems in the FAC program. The systems analyzed are FW, blowdown, HDRs, extraction steam, miscellaneous drains, and condensate drains. The results showed that the FAC wear rates after the EPU will increase by a low to moderate amount.
The licensee stated that during each outage inspections are performed to identify piping in need of replacement. The pipes are repaired to preclude falling below minimum wall thickness.
The increase in the FAC wear rate after EPU and consequent reduction in pipe wall thickness will be monitored via the FAC inspection program. The licensee stated that the piping will be replaced if the measured wall thickness at the current RFO and/or the projected wall thickness at the next RFO falls below the ASME Code-allowable wall thickness.
In Question 1 of its Request for Additional Information (RAI) dated January 28, 2004 (ML040330260), the NRC staff asked the licensee to provide a list of the components most susceptible to FAC, including initial wall thickness (nominal), current wall thickness, and the predicted wall thickness. By Reference 3, the licensee provided data of the wear rate on sample piping obtained in the pre- and post-EPU conditions. The data indicate the initial and current wall thickness of the (sample) piping that shows high wear rate and also contain predicted wall thickness of the piping in the current operating conditions and post-uprated conditions.
In Question 2, the NRC staff asked the licensee to provide examples of the piping components for which wall thinning is predicted by CHECWORKS based on the current operating conditions and confirmed measured NDE. The comparison of predicted wall thickness versus measured wall thickness would show the effectiveness of CHECWORKS in prediction. By Reference 3, the licensee submitted a comparison of predicted wall thickness vs. measured wall thickness of sample piping. The data show that the wall thickness prediction by CHECWORKS is conservative. Therefore, the NRC staff finds that the CHECWORKS prediction at Waterford 3 has been demonstrated to be adequate.
In Question 3, the NRC staff asked the licensee to discuss the inspection technique and inspection scope (e.g., how many piping systems are inspected) in the FAC program and specific subsection in the ASME Code by which the minimum wall thickness is calculated.
By Reference 3, the licensee responded that it uses ultrasonic testing as the primary inspection technique for FAC. The following systems are monitored in the FAC program: FW, blowdown, FW HDRs, extraction steam, main steam drain headers, condensate, steam bypass, cross-under pipe, and main steam. The licensee stated that its FAC inspection program is consistent with the recommendations in Reference 39.
The licensee stated further that for wall thinning in piping due to FAC that occurs in a localized region, the decision to replace the piping is based on comparing measured or projected wall thickness at the localized region with the allowable localized wall thickness. The allowable localized wall thickness is the minimum thickness, based on the geometry of the thinned location, calculated by ASME Code proximity criteria equations with allowables for Class 1 piping in ASME subarticle NB-3200. The acceptance criteria in Reference 39 are also based on the ASME Code Class 1 design rules that dictate screening criteria for identifying wall thinning.
The NRC staff's Question 4 asked the licensee to discuss the limit on the percentage of wall thickness below which the pipe is replaced, and discuss whether the pipe replacement due to FAC is consistent with ASME Code,Section XI, Case N597-1, which is referenced in RG 1.147, Revision 13, June 2003; and Reference 39.
By Reference 3, the licensee responded that its piping replacement criteria meet the EPRI Guideline Document (NP-5911SP), which recommends that piping be replaced when measured or projected wall thickness falls below 20 percent of nominal wall thickness. The piping is replaced or repaired when (1) the projected wall thickness is below 30 percent of nominal wall thickness for ASME Class 1 and 2 Piping, (2) the projected wall thickness is below 20 percent of nominal wall thickness for ASME Class 3 piping, and (3) the projected wall thickness is the lesser of 0.3 x nominal and 0.5 x minimum thickness for Class 3 low energy and B31.1 piping.
The licensee stated that the existing piping replacement criteria are consistent with the guidelines in Reference 39, and/or NRC guidance. ASME Section XI, Code Case N597-1, provides the requirements for analytical evaluation of pipe wall thinning. This Code case is supplemented by the provisions in Reference 39, for developing the inspection requirements, the method of predicting the rate of wall thickness loss, and the value of predicted remaining wall thickness. Piping components affected by FAC to which Code Case N597-1 is applied must be repaired or replaced in accordance with the construction Code of record and owners requirements, or a later NRC-approved edition of Section III of the ASME Code prior to the value of projected wall thickness reaching the allowable minimum wall thickness. The licensee stated that the inspection requirements, the method of predicting the rate of wall thickness loss, and the value of predicted remaining wall thickness meet the guidance in Reference 39.
The licensee compares the measured/projected wall thickness as obtained during the outage to the acceptable minimum wall thickness as discussed above. If the projected wall thickness is below the acceptable minimum wall thickness, the licensee performs a detailed engineering evaluation following a methodology for evaluating localized thinning in piping for ASME Section III, ANSI B31.7, and ANSI B31.1 carbon steel piping.
As discussed with members of the NRC staff on September 2, 2004, the licensee stated in Reference 17 that the heat balance used to assess the impact of EPU on FAC has been revised to incorporate precision pressure measurements for the throttle steam pressure and reheater heating steam pressures. Also, to better bound expected operating conditions, the heat balance has been run at a circulating water temperature of 42 oF, in addition to the circulating water temperature of 92 oF used previously. Running with a low circulating water temperature maximizes extraction steam flow in the low point FW heaters and therefore maximizes flow in the associated HDR lines. As a result, minor impacts may be seen on components enclosed inside the condenser. Therefore, Entergy will update the FAC program with the revised heat balance and reassess the EPU impact on FAC prior to EPU implementation.
By Reference 17, Entergy submitted a commitment (See Section 4.0 of this SE, Commitment 50), which reads: "Entergy will update the FAC program with the revised heat balance and reassess the EPU impact on FAC prior to EPU implementation..." The NRC staff finds the commitment acceptable.
The NRC staff finds that the FAC program is acceptable under the EPU because the program is consistent with the guidance in Reference 39, was demonstrated to be conservative in its application, and the program (i.e., the prediction method) has been adjusted to account for the EPU conditions.
Summary The NRC staff has reviewed the licensees evaluation of the effect of the proposed EPU on the FAC analysis for the plant and concludes that the licensee has adequately addressed changes in the plant operating conditions on the FAC analysis. The NRC staff further concludes that the licensee has demonstrated that the updated analyses will predict the loss of material by FAC and will ensure timely repair or replacement of degraded components following implementation of the proposed EPU. Therefore, the NRC staff finds the proposed EPU acceptable with respect to FAC.
2.1.9 Steam Generator Tube Inservice Inspection Regulatory Evaluation SG tubes constitute a large part of the RCPB. SG tube inservice inspection (ISI) provides a means for assessing the structural and leaktight integrity of the SG tubes through periodic inspection and testing of critical areas and features of the tubes. The NRC staffs review in this area covered the effects of changes in differential pressure, temperature, and flow rates resulting from the proposed EPU on plugging limits, potential degradation mechanisms (e.g., flow-induced vibration (FIV)), plant-specific alternate repair criteria, and redefined inspection boundaries. The NRCs acceptance criteria for SG tube ISI are based on 10 CFR 50.55a requirements for periodic inspection and testing of the RCPB. Specific review criteria are contained in SRP Section 5.4.2.2 and other guidance provided in Matrix 1 of Reference 31.
Additional review guidance is contained in Technical Specification (TS) 3/4.4.4, STEAM GENERATORS, for SG surveillance requirements; RG 1.121 for SG tube plugging limits; GL 95-03; BL 88-02 for degradation mechanisms, structural and leakage performance criteria in