ML021650543

Amendment No. 149, Power Uprate (Non-Proprietary Safety Evaluation)

ML021650543
Person / Time
Site:	Clinton
Issue date:	04/05/2002
From:	NRC/NRR/DLPM
To:
Hopkins J, DLPM/NRR, 415-3027
References
-nr, TAC MB2210
Download: ML021650543 (103)

Text

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 149 TO FACILITY OPERATING LICENSE NO. NPF-62 AMERGEN ENERGY COMPANY, LLC CLINTON POWER STATION, UNIT 1 DOCKET NO. 50-461 ENCLOSURE 2

TABLE OF CONTENTS 1.0 OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0 REACTOR CORE AND FUEL PERFORMANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 Fuel Design and Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 Thermal Limits Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.1 Minimum Critical Power Ratio Operating Limit . . . . . . . . . . . . . . . . . . 2.2.2 Maximum Average Planar Heat Generation Rate (MAPLHGR) and Maximum LHGR Operating Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 Reactivity Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.1 Power/Flow Operating Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4 Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 Reactivity Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.1 Control Rod Drive (CRD) System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6 Onsite Audit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.1 Reactor Core and Fuel Performance . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.1.1 Fuel Design and Operation . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.1.2 Thermal Limits Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.1.3 Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.1.4 Anticipated Transient Without Scram (ATWS) Stability . . . . 2.6.2 Reactor Safety Performance Evaluations . . . . . . . . . . . . . . . . . . . . . 2.6.2.1 Reactor Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.2.2 Design-Basis Accidents . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.0 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS . . . . . . . . . . . . . . 3.1 Nuclear System Pressure Relief . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Reactor Overpressure Protection Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Reactor Pressure Vessel and Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.1 Reactor Vessel Fracture Toughness . . . . . . . . . . . . . . . . . . . . . . . . 3.3.2 Reactor Vessel Integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.3 Reactor Vessel Internals Structural Evaluation . . . . . . . . . . . . . . . . . 3.3.4 Flow-Induced Vibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.5 Steam Separator and Dryer Performance . . . . . . . . . . . . . . . . . . . . 3.4 Reactor Recirculation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 Reactor Coolant Pressure Boundary Piping . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.1 Pipe Stresses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2 Flow-Accelerated Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6 Main Steam Flow Restrictors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 Main Steam Isolation Valves (MSIVs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8 Reactor Core Isolation Cooling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9 Residual Heat Removal System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.1 Shutdown Cooling Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.9.2 Suppression Pool Cooling Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3 Containment Spray Cooling Mode . . . . . . . . . . . . . . . . . . . . . . . . . . 3.10 Reactor Water Cleanup System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.0 ENGINEERED SAFETY FEATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 Containment System Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.1 Containment Pressure and Temperature Response . . . . . . . . . . . . . 4.1.1.1 Long-Term Suppression Pool Temperature Response . . . . 4.1.1.2 Short-Term Containment Gas Temperature Response . . . . 4.1.1.3 Short-Term Containment Pressure Response . . . . . . . . . . . 4.1.2 Containment Dynamic Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.2.1 LOCA Containment Dynamic Loads . . . . . . . . . . . . . . . . . . 4.1.2.2 Safety/Relief Valve Loads . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.2.3 Subcompartment Pressurization . . . . . . . . . . . . . . . . . . . . . 4.1.3 Containment Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.4 Generic Letter 96-06 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 Emergency Core Cooling System (ECCS) . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.1 High-Pressure Core Spray System . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.2 Low-Pressure Coolant Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3 Low Pressure Core Spray System . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.4 Automatic Depressurization System . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.5 Net Positive Suction Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 Emergency Core Cooling System Performance Evaluation . . . . . . . . . . . . . 4,4 Main Control Room Atmosphere Control System . . . . . . . . . . . . . . . . . . . . . 4.5 Standby Gas Treatment System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.6 Post-LOCA Combustible Gas Control System . . . . . . . . . . . . . . . . . . . . . . . 5.0 INSTRUMENTATION AND CONTROL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1 Suitability of Existing Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Instrument Trip Setpoint and Allowable Values . . . . . . . . . . . . . . . . . . . . . . 5.3 TS Changes Related to the Power Uprate . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.0 ELECTRICAL POWER AND AUXILIARY SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . 6.1 Alternating Current (AC) Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.2 Grid Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.3 Main Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.4 Power Transformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5 Isolated Phase Duct . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.6 Emergency Diesel Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 Direct Current (DC) Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Fuel Pool Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4 Water Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.1 Service Water Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.1.1 Safety-Related Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.1.2 Non-Safety-Related Loads . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.2 Main Condenser, Circulating Water, and Normal Heat Sink System Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.3 Component Cooling Water System . . . . . . . . . . . . . . . . . . . . . . . . .

6.4.4 Turbine Building Closed Cooling Water System . . . . . . . . . . . . . . . . 6.4.5 Ultimate Heat Sink . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5 Standby Liquid Control System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6 Power-Dependent Heating Ventilation And Air Conditioning Systems . . . . . 6.7 Fire Protection Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.8 Systems Not Impacted or Insignificantly Impacted by EPU . . . . . . . . . . . . . 7.0 POWER CONVERSION SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1 Turbine-Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2 Miscellaneous Power Conversion Systems . . . . . . . . . . . . . . . . . . . . . . . . . 8.0 RADWASTE SYSTEMS AND RADIATION SOURCES . . . . . . . . . . . . . . . . . . . . . . 8.1 Liquid Waste Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2 Gaseous Waste Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1 Offgas System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3 Radiation Sources in the Core . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 Radiation Sources in the Reactor Coolant . . . . . . . . . . . . . . . . . . . . . . . . . . 8.5 Radiation Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.6 Normal Operation Off-Site Doses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.0 REACTOR SAFETY PERFORMANCE EVALUATION . . . . . . . . . . . . . . . . . . . . . . 9.1 Reactor Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2 Design-Basis Accidents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.1.1 Plant-Specific Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.1.2 Development of Plant-Specific Scaling Factors . . . . . . . . . . 9.2.1.3 Application of Scaling Factors to Pre-EPU Analyses . . . . . . 9.2.2 Control Room Doses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3 Special Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.1 Anticipated Transient Without Scram . . . . . . . . . . . . . . . . . . . . . . . . 9.3.2 Station Blackout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.0 ADDITIONAL ASPECTS OF EXTENDED POWER UPRATE . . . . . . . . . . . . . . . . . 10.1 High Energy Line Breaks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2 Moderate Energy Line Breaks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3 Equipment Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3.1 Electrical Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3.2 Mechanical Equipment With Nonmetallic Components . . . . . . . . . . 10.3.3 Mechanical Components Design Qualification . . . . . . . . . . . . . . . . . 10.3.3.1 Equipment Seismic and Dynamic Qualification . . . . . . . . . 10.3.3.2 Safety-Related SRV and Power-Operated Valves . . . . . . . 10.4 Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.1 Generic Test Guidelines for GE BWR EPU . . . . . . . . . . . . . . . . . . . 10.4.2 CPS Testing Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.3 Large Transient Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.3.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.3.2 Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5 Risk Implications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10.5.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.2 Internal Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.2.1 Initiating Event Frequency . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.2.2 Component Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.2.3 Success Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.2.4 Operator Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.2.5 Summary of Internal Events Evaluation Results . . . . . . . . 10.5.3 External Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.3.1 Seismic Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.3.2 Fires . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.3.3 High Winds, Floods, and Other External Events . . . . . . . . 10.5.3.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.4 Shutdown Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.5 Quality of PRA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.6 Risk Evaluation Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6 Human Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6.1 Scope of Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6.2 Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.0 CHANGES TO FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1 Changes to Facility Operating License . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2 Changes to Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

15.0 REFERENCES

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TABLE 1: CPS Radiological Analysis Results, REM . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1.0 OVERVIEW 1.1 Introduction By letter dated June 18, 2001, AmerGen Energy Company, LLC (the licensee), submitted an amendment request that would allow an increase in the licensed power from 2894 megawatts thermal (MWt) to 3473 MWt for Clinton Power Station (CPS). This change represents an increase of approximately 20 percent above the current licensed power at CPS, and is considered an extended power uprate (EPU). The proposed amendment would also change the operating license and the technical specifications (TSs) appended to the operating license to provide for implementing uprated power operation.

The power uprate is planned to occur over two refueling outages, because of the numerous modifications that have to be performed to achieve the 20 percent uprate. Following the first refueling outage in 2002, the licensee expects to operate at a seven percent higher power level.

The remaining 13 percent uprate in power will be achieved following the second refueling outage expected to commence approximately in February 2004. Attachment G of the initial submittal contains a list of the planned modifications.

The application was supplemented by letters dated September 7 and 28, October 17, 23, 26, 26, and 31, November 8 (2 letters), 20, 21, 29, and 30, and December 5, 6, 7, 13 (2 letters), 20, 21, and 26, 2001, January 8, 15, 16, and 24, and March 15, 22, and 29, 2002.

1.2 Background

CPS is currently licensed to operate at a maximum reactor power level of 2894 MWt. The licensee, in conjunction with General Electric Company (GE), undertook a program to uprate the maximum reactor power level by 20 percent to 3473 MWt. At the uprated reactor power level, the generator electrical output will increase approximately 186 megawatts electric (MWe).

The CPS safety analysis of the proposed EPU was provided in NEDC-32989P, Safety Analysis Report for Clinton Power Station Extended Power Uprate (PUSAR), September 24, 2001 (Ref.

2), prepared by General Electric Nuclear Energy (GENE). This report described the plants ability to operate at the higher power level and to respond to anticipated operational occurrence transient and accident conditions as designed and analyzed. The licensee also evaluated the effect of the increased thermal power on the capability and performance of systems, structures, and components important to safe operation of the plant.

In general, the licensees plant-specific engineering evaluations supporting the power uprate were performed in accordance with guidance contained in the GE licensing topical report (LTR)

NEDC-32424P, Generic Guidelines for General Electric Boiling Water Reactor (BWR)

Extended Power Uprate (ELTR1). This topical report was previously reviewed and endorsed by the U. S. Nuclear Regulatory Commission (NRC) staff. For some items, bounding analyses and evaluations provided in GE LTR, NEDC-32523P, Generic Evaluations of General Electric Boiling Water Reactor Extended Power Uprate (ELTR2), were cited. The staff has also approved ELTR2. The ELTR2 generic evaluations assume (a) a 20 percent increase in the thermal power, (b) an increase in operating dome pressure up to 1,095 psia, (c) a reactor coolant temperature increase to 556 degrees Fahrenheit, and (d) a steam and feedwater flow increase of about 24 percent.

In general, the licensee followed the guidelines in ELTR1 and ELTR2 for the CPS EPU evaluation. However, the CPS EPU safety analysis deviates from the ELTR1 and ELTR2 guidelines in the stability analyses, the loss-of-coolant accident (LOCA) analysis, and transient analyses. In the licensees approach, the limiting transient analyses, the long-term stability suppress and detection solution, and the LOCA analysis will be performed during the reload analysis. The deviations are discussed in the following areas:

Stability (Section 2.4)

Emergency core cooling system (ECCS) performance (Section 4.3)

Reactor transients (Section 9.1)

Testing (10.4) 1.3 Approach The approach to achieving the EPU consists of (1) an increase in the core thermal power with a more uniform power distribution achieved by better fuel management techniques to create increased steam flow, (2) a corresponding increase in the feedwater system flow, (3) no increase in maximum core flow, and (4) reactor operation primarily along the maximum extended load line limit analysis (MELLLA) rod/flow lines. This approach is based on, and is consistent with the NRC-approved BWR EPU guidelines that are in ELTR1/2.

An increase in the electrical output of a BWR is accomplished primarily by supplying a higher steam flow to the turbine generator. Most GE BWRs, as originally licensed, have the ability to accommodate steam flow rates at least 5 percent above the original rating. In addition, continuing improved analytical techniques and computer codes, operating experience, and improved fuel designs have resulted in a significant increase in the design and operating margins, between the results of the safety analysis calculations and the licensing limits. The larger margins, combined with the as-designed equipment, system, and component capabilities, have allowed many BWRs to increase their thermal power ratings by 5 percent (stretch uprate) without modifying any nuclear steam supply system (NSSS) hardware and to increase power up to 20 percent (extended power uprate) with some hardware modifications.

These power increases do not significantly affect safety analyses of the plants as originally licensed.

The method for achieving higher power at GE BWRs is to extend MELLLA power/flow map, and to increase core flow along the resulting flow control line extension. The proposed CPS EPU will not increase the operating pressure or the current licensed maximum core flow. The plant has made, or will make, modifications to the power generation equipment, pressure controls and turbine flow capabilities to control the pressure at the turbine inlet.

1.4 Staff Evaluation The NRC staffs review of the CPS EPU amendment request used applicable rules, regulatory guides, Standard Review Plan (SRP) sections, and NRC staff positions on the topics being evaluated. Additionally, the NRC staff evaluated the EPU application for conformance with the generic BWR EPU program as defined in ELTR1 and ELTR2. ELTR1 and ELTR2 have previously been accepted by NRC as providing appropriate guidelines for EPU applications.

The licensee took exceptions to certain previously approved generic positions in these topical

reports. The staff has reviewed the exceptions and the staffs conclusions about their acceptability are given in the applicable sections of this safety evaluation (SE). The NRC staff also used the 1998 SE for the Monticello Nuclear Generating Plant EPU as a guide on the scope and depth of the review.

The scope of the staffs review for the CPS EPU request included lessons learned from past power uprate amendment reviews. In reviewing the licensees request for EPU, the staff considered the recommendations of the report of the Maine Yankee Lessons Learned Task Group (SECY-97-042, Response to OIG Event Inquiry 96-04S Regarding Maine Yankee, February 18, 1997). The task groups main findings centered on the use and applicability of the computer codes and analytical methodologies used for power uprate evaluations. The staff requested that the licensee identify all codes and methodologies used to obtain safety limits and operating limits and explain how they verified these limits were correct for the uprate core.

The licensee was also requested to identify and discuss any limitations imposed by the staff on the use of these codes and methodologies. In a letter dated October 31, 2001, the licensee identified all the codes and methodologies used for the CPS EPU analyses.

The licensee confirmed having reviewed the results of GE analyses to assure that the codes were used correctly by GE for EPU conditions and that the limitations and restrictions were followed appropriately by GE. The licensee confirmed that all the methods/methodologies were used appropriately for the CPS EPU evaluation. The staff has reviewed the information provided and determined that the Maine Yankee Lessons Learned recommendations were appropriately considered in the CPS EPU request.

The CPS EPU reload core will consist of both the existing GE-10 (8x8) fuel and GNF GE-14 (10x10) fuel. The EPU safety analyses and the cycle-specific reload analyses will be performed in accordance with NRC-approved GE analytical methodologies described in the latest version of GESTAR II. The licensing topical reports specifying the codes and methodologies used for performing the safety analyses are documented in Section 5 of the CPS TSs. The limiting anticipated operational occurrence (AOO) and accident analyses are reanalyzed or confirmed to be valid for every reload and the safety analyses of transients and accidents are documented in Chapter 15 of the CPS updated safety analysis report (USAR).

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The core thermal-hydraulic design and fuel performance characteristics are evaluated for each reload fuel cycle. The following sections address the effect of the EPU on fuel design performance, thermal limits, the power/flow map, and reactor stability.

2.1 Fuel Design and Operation Fuel bundles are designed to ensure that (a) the fuel bundles are not damaged during normal steady-state operation and AOOs; (b) any damage to the fuel bundles will not be so severe as to prevent control rod insertion when required; (c) the number of fuel rod failures during accidents is not underestimated during accidents; and (d) the coolability of the core is always maintained. For each fuel vendor, use of NRC-approved fuel design acceptance criteria and analysis methodologies assures that the fuel bundles perform in a manner that is consistent with the objectives of Sections 4.2 and 4.3 of the standard review plan and the applicable

general design criteria (GDC) of 10 CFR Part 50, Appendix A. The fuel vendors perform thermal-mechanical, thermal-hydraulic, neutronic, and material analyses to ensure that the fuel system design can meet the fuel design limits during steady-state, AOO, or accident conditions.

The licensees PUSAR states that the requested EPU would increase the average power density proportionally to the power increase, but the increased power density would be within the power density of existing GE-supplied BWRs. The plant is currently operating at an average bundle power of 4.64 MW/bundle. The average bundle power for EPU is 5.57 MW/bundle. The increased operating power would affect the operating flexibility and the reactivity characteristics of the core. The EPU is achieved by changes to the loading pattern of the reload core, and by use of larger reload batch sizes and new fuel designs (GE-14) for EPU operation.

The PUSAR states that, for operation at the currently licensed power or at the proposed EPU, the fuel and core design limits will continue to be met by varying the fuel enrichment and burnable poisons, supplemented by control rod pattern management. The reload core design will change the power distribution while limiting the absolute power in individual fuel bundles to currently allowable values. The licensee stated that it will use NRC-approved core design methods to analyze the core performance conditions at the proposed EPU operation.

The licensee performed the EPU fuel cycle calculations using a representative core with GE-10 and GE-14 fuel design to demonstrate the feasibility of operation at the higher thermal power and along the MELLLA rod line while maintaining the fuel design limits. Limits on the fuel rod linear heat generation rate (LHGR) will ensure compliance with the fuel mechanical design bases. The thermal-hydraulic design and the operating limits ensure an acceptably low probability of boiling-transition-induced fuel cladding failure in the core in the event of an AOO.

The licensee stated that the EPU fuel cycle design calculations demonstrated that these fuel design limits would be maintained and the subsequent reload core designs at the EPU power level would take these limits into account to ensure acceptable differences between the licensing limits and their corresponding operating values.

The licensee stated that the EPU operation might result in small changes in fuel burnup, in the amount of fuel used, and in the isotopic concentration of the radio-nuclides in the irradiated fuel compared to the original level of burnup. However, the currently approved fuel design burn up limits will not be exceeded. Based on the information submitted, and the responses to the staff requests for additional information (RAI), the staff concludes that the fuel design is acceptable.

2.2 Thermal Limits Assessment GDC 10 of 10 CFR Part 50, Appendix A, requires that the reactor core and the associated control and instrumentation systems be designed with appropriate margin to ensure that the specified acceptable fuel design limits (SAFDLs) are not exceeded during normal operation, including AOOs. Operating limits are established to assure that regulatory and/or safety limits are not exceeded for a range of postulated events (transients and accidents).

2.2.1 Minimum Critical Power Ratio Operating Limit The safety limit minimum critical power ratio (SLMCPR) ensures that 99.9 percent of the fuel rods are protected from boiling transition during steady-state operation. The operating limit minimum critical power ratio (OLMCPR) assures that the SLMCPR will not be exceeded as a result of an AOO.

NRC staff experience with several power uprates has shown that the change in OLMCPR resulting from a constant-pressure EPU is small and there is no need to perform evaluations with representative core design parameters. When the core design is complete, the OLMCPR will be determined with the real core design parameters. Because the licensee will use approved methods to evaluate these parameters, the staff concludes that this is acceptable.

The SLMCPR is established or confirmed every reload, based on the actual core configuration and operating conditions. A SLMCPR of 1.08 was calculated for CPS EPU conditions. This is not a significant change from the current TS SLMCPR limit of 1.09.

2.2.2 Maximum Average Planar Heat Generation Rate (MAPLHGR) and Maximum LHGR Operating Limits The MAPLHGR operating limit is based on the most limiting LOCA and ensures compliance with the ECCS acceptance criteria in 10 CFR 50.46. For every new fuel type, the fuel vendors perform LOCA analyses to confirm compliance with the LOCA acceptance criteria, and for every reload licensees confirm that the MAPLHGR operating limit for each reload fuel bundle design remains applicable.

As discussed in Section 4.3 of this SE, the licensee performed a LOCA evaluation, based on the representative GE-14 equilibrium core and operating at the EPU power level. The licensee stated that the LOCA analysis showed no change in the MAPLHGR or the LHGR limits for normal operation.

The licensee is required to ensure that plant operation is in compliance with the cycle-specific thermal limits (SLMCPR, OLMCPR, MAPLHGR, and maximum LHGR) and specify the thermal limits in a cycle-specific core operating limits report (COLR) as required by Section 5 of CPS TSs. In addition, while EPU operation may result in a small change in fuel burn up, the licensee is restricted from exceeding the NRC-approved burnup limits described in approved Topical Reports as referenced in the TS. Therefore, the NRC staff finds that the licensee has appropriately considered the potential effects of EPU operation on the fuel design limits, and the staff concludes that the current thermal limits assessment is acceptable for CPS steady state operation, AOOs, and accident conditions.

2.3 Reactivity Characteristics The licensee stated that operation at higher power with the proper core design could reduce the hot excess reactivity, typically by about 0.2 to 0.3 percent delta K for each 5 percent power increase. The loss of reactivity is not expected to affect the ability to manage the power distribution needed to meet the target power through the cycle. The lower hot excess reactivity can result in an earlier all-rod-out condition during the operating cycle; however, through reload

fuel cycle-specific core analyses, the core can be designed with sufficient excess reactivity to maintain the fuel cycle length. The increase in the hot reactivity may also result in less hot-to-cold reactivity difference, reducing the available cold shutdown margin. The licensee stated that the EPU core design would account for the loss of margin and, if necessary, a fuel bundle design with improved shutdown margin characteristics could be used for future cycles. The licensee added that the reload core analysis would ensure that the minimum shutdown margin requirements were met for each core design and that the current design and TS cold shutdown margin will be met. Based on the information submitted, and the responses to the staff RAIs, and since the licensee will continue to confirm that TS cold shutdown requirements will be met for each reload core operation, the staff concludes that this is acceptable.

2.3.1 Power/Flow Operating Map To achieve the 20 percent increase from the current rated power (CRP), the licensee proposes to operate at the MELLLA rod line. The EPU operating domain will be defined by: (a) the MELLLA upper boundary line extended up to the EPU rated thermal power, (b) the maximum EPU power level corresponding to 120 percent of the CRP, and (c) the existing 107 percent core flow line continued up to the EPU power. The previously analyzed core flow range will be extended so that the rated thermal power (RTP) will correspond to the EPU power level and the maximum core flow will not be increased. The proposed EPU operating domain power/flow map was submitted by the licensee.

2.4 Stability GDC 12 of 10 CFR Part 50, Appendix A, Suppression of reactor power oscillations, states that The reactor core and associated coolant, control, and protection systems shall be designed to assure that power oscillations which can result in conditions exceeding specified acceptable fuel design limits are not possible or can be reliably and readily detected and suppressed.

The licensee has taken exception to one of the generic guidelines in ELTR2, regarding thermal-hydraulic stability. In the staff SE on ELTR2, SER Section 3.2.2, Long-Term Solution, states: The prevention and detection/suppression features of the long term stability solutions are either demonstrated to be unaffected by power uprate or are modified and validated in accordance with the solution methodology. The ELTR2 staff SE requires that the thermal-hydraulic stability monitoring system be validated in accordance with the generic solution methodology using a representative equilibrium core design and included in the application for EPU. An equilibrium core evaluation of the stability option III oscillation power range monitor (OPRM) amplitude trip setpoint has not yet been performed for CPS.

The staff concludes that this is acceptable for the following reasons:

(a) It has been fully demonstrated that the OPRM setpoint methodology is adequate and capable for an EPU performed in accordance with ELTR1 and ELTR2.

(b)

(c)

(d) For current operating BWRs, the staff has approved the demonstration of stability compliance with GDC 12 on a plant and cycle-specific basis for each long-term solution as part of the approval of Amendment 26 to NEDO-24011-P-A, dated March 29, 2000.

This position also applies to EPU operation.

CPS is currently operating under the requirements of reactor stability interim corrective actions (ICAs) and is in the process of implementing long-term stability solution Option III. The Asea Brown Boveri (ABB) CE Option III OPRM system was installed during the sixth refueling outage, but it has not yet been armed. The long-term stability solutions for BWRs are discussed in LTR NEDO-32465-A, BWR Owners Group Stability Solutions Licensing Basis Methodology and Reload Application, published in May 1995.

In the ELTR2 SE, the staff concluded that the existing stability corrective actions are applicable or adaptable to extended power uprate operation. The ICA stability boundaries are kept the same in terms of absolute core power and flow for EPU. The power levels, reported as a percentage of rated power, are rescaled to the uprated power.

If the Option III system is declared inoperable, the ICA procedures are initiated to restrict plant operation in the high-power, low-core-flow region of the power/flow map. The procedures contain specific operator actions in response to reactor operation in the defined restricted regions.

For the Option III solution, confirmation that the scram set point provides the safety limit MCPR protection is required to be performed at the first cycle in which the system is armed and for each subsequent reload. Since the system is not armed and the generic solution for the 10 CFR Part 21 issue has not been resolved by the Boiling Water Reactor Owners Group (BWROG), this deviation is acceptable to the staff.

The licensee stated in a letter dated September 6, 2001, that it intends to submit the proposed amendments for Option III implementation in the fall of 2002, and the licensee will continue to use the ICA procedures to mitigate reactor stability events until the OPRM system is armed.

This is acceptable to the staff.

2.5 Reactivity Control 2.5.1 Control Rod Drive (CRD) System The CRD system controls gross changes in core reactivity by positioning neutron-absorbing control rods within the reactor. The CRD system is also required to scram the reactor by rapidly inserting withdrawn rods into the core. The scram, rod insertion and withdrawal functions of the CRD system depend on the operating reactor pressure and the pressure difference between the CRD system hydraulic control unit (HCU), and the reactor vessel bottom head pressure.

The licensee stated that since there is no increase in the reactor operating pressure, the CRD scram performance and compliance with the current TS scram requirements are not affected by the operation at the EPU power level. The CRD system was generically evaluated in Section 5.6.3 and J.2.3.3 of ELTR1 and Section 4.4 of Supplement 1 to ELTR2. The licensee stated that since the generic evaluation concluded that the CRD systems for BWR/2-6 plants are acceptable for EPU as high as 20 percent above the original rated power, no additional plant-specific calculations are required beyond confirmatory evaluation. The licensee performed confirmatory evaluations of the performance of the CRD system at the EPU conditions based on a reactor dome pressure of 1005 psig with 35 psid added to account for the static head of water in the vessel.

The licensee stated that, for CRD insertion and withdrawal, the required minimum pressure between the HCU and the vessel bottom head is 250 psid. The licensee evaluated the CRD pump capability and determined that the CRD pumps have sufficient capacity to provide the required pressure difference for operation at the EPU conditions. The licensee also evaluated the required CRD cooling and drive flows for EPU operation and stated that the cooling and drive flows are assured by the automatic operation of the CRD system flow control valve, which would compensate for any changes in the reactor pressure. The licensee determined that the operation of the CPS CRD system is consistent with the generic evaluations in ELTR1 and ELTR2, and that the CRD system is, therefore, capable of performing its design functions of rapid rod insertion (scram) and rod positioning (insertion/withdrawal) during EPU operation.

In addition, scram time testing verifies the scram time for individual control rods. Therefore, the higher pressures that might occur as a result of EPU operations during isolation events will not have a significant effect on the scram function of the CRD system. The licensee has also evaluated the performance of the CRD insert, withdraw, cooling and drive functions. The staff SER for ELTR2 states that the plant-specific submittal for BWR/6 plants must provide assurance that the scram insertion speeds used in the transient analyses are slower than the requirements contained in the plant. During the audit of GENE, the staff verified that the correct scram insertion times are used in the analyses.

With regard to the mechanical design of the CRD system, the licensee stated that the control rod drive mechanisms (CRDMs) have been designed in accordance with the code of record, the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section III, 1971 Edition with addenda up to and including the summer 1973 addenda for CPS.

The components of the CRDM, which form part of the primary pressure boundary, have been designed for a bottom head pressure of 1250 psig, which is higher than the analytical limit of 1130 psig for the reactor bottom head pressure.

The licensees evaluation indicated that the maximum calculated stress for the CRDM is less than the allowable stress limit. The analysis of the CRDM also showed that the calculated maximum cumulative usage factor (CUF) for the limiting CRD location is 0.15, which is less than the code-allowable CUF limit of 1.0.

Based on the information submitted, the responses to the staff RAIs, and the staff audit, the staff concludes that the CRD design is acceptable.

2.6 Onsite Audit During the week of September 10, 2001, four NRC staff members visited the GENE facility in San Jose, California to review analyses performed by GENE/Global Nuclear Fuel (GNF) for the CPS EPU licensing submittal. The purpose of this visit was to perform detailed on-site audit reviews of selected safety analyses and system and component performance evaluations used in the GENE safety analysis report, NEDC-32989P, to support the CPS EPU license amendment submittal.

Similar visits were made to the GNF engineering and manufacturing facility at Wilmington, North Carolina during the weeks of March 26, and June 18, 2001. The March audit focused on the Duane Arnold Energy Center EPU analyses, and the June audit focused on the Dresden Nuclear Power Station, Units 2 and 3, and the Quad Cities Nuclear Power Station, Units 1 and 2, EPU analyses.

Since CPS is the first BWR/6 to request an EPU, the staff wanted to verify the general applicability of ELTR2 to CPS. The licensee confirmed that the initial plant conditions (power, dome pressure, reactor coolant temperature, steam flow, and feedwater flow) assumed in the ELTR2 evaluations bound the initial conditions for the CPS EPU.

The licensee stated that the CPS EPU evaluation was based on ELTR1 and ELTR2; however, exceptions to the generic guidelines were not clearly identified. During the audit, the staff discovered deficiencies in the licensees original PUSAR. Based on the staffs findings, the licensee revised the PUSAR to clearly identify the exceptions to ELTR1 and ELTR2. The exceptions were taken in areas of thermal-hydraulic (T/H) stability, ECCS performance, and transient analysis.

2.6.1 Reactor Core and Fuel Performance 2.6.1.1 Fuel Design and Operation For the CPS EPU submittal, the scope of the staff audit included the analyses of the first GE-14 transition reload core design, in comparison with detailed fuel cycle calculations of a representative core design (full GE-14 core) demonstrating feasibility of EPU operation with respect to reload fuel and operating core design. Analyses performed for the first GE-14 transition reload core were reviewed by examination of the material from the Project Task Report and design record files for the CPS, Cycle 8 transition core, and by telephone discussions with GNF engineering personnel involved in the analyses. The staff finds that the material reviewed was complete and demonstrated that the reload fuel and core design was sufficient for transition to EPU operation.

2.6.1.2 Thermal Limits Assessment The audit scope was to review the analyses of the CPS first transition GE-14 reload core design in comparison with a representative equilibrium cycle core with respect to operating T/H limits. Analyses performed for the first GE-14 transition reload core were reviewed by examination of selected material from the design record files for the CPS Cycle 8 transition core, and by discussions with GENE/GNF engineering personnel involved in the analyses. The

staff finds that the material reviewed was complete and demonstrated that the thermal limits could be met during the transition to EPU operation.

2.6.1.3 Stability The licensees approach does not follow the generic guidelines regarding stability in ELTR2.

The resolution of this issue is described in Section 2.4 of this SE.

The licensee chose the Asea Brown Boveri (ABB) Combustion Engineering Option III OPRM system for CPS, which was installed during the sixth refueling outage. However, the system will not be armed until after resolution of the 10 CFR Part 21 issue, submitted on June 29, 2001 (ADAMS accession number ML012120034), involving the DIVOM (delta critical power ratio over initial critical power ratio versus oscillation magnitude) curve calculation. The licensee had requested an amendment to the TS for the OPRM instrumentation in a letter dated June 1, 2001, which was subsequently withdrawn in a letter dated September 6, 2001, due to the GE 10 CFR Part 21 issue. The staff has reviewed the design record file (DRF) for the CPS EPU Stability evaluation. These DRFs describe the specific inputs for the evaluation including the CPS EPU Power/Flow map, reactor protection system, OPRM system, CRD system, CPS EPU equilibrium core design, and the required outputs that are defined in the internal vendor thermal-hydraulic stability task report.

The staff also reviewed; (1) the Option III/Detect and Suppress Analysis, (2) the Option III/OPRM Trip Enabled Region, and (3) the ICAs. All evaluations were performed using NRC-approved methods. Item (1) evaluated the stability-related OLMCPR, determined the applicability of the hot bundle oscillation magnitude report, and determined the OPRM system setpoint for the scoping study. The OPRM system setpoint and applicability of the of the hot bundle oscillation magnitude report are cycle-specific and will be determined and confirmed for each reload cycle. Item (2) evaluated the licensing basis of the OPRM Trip Enabled Region and rescaled the Trip Enabled Region as appropriate. Item (3) assessed the licensing basis of the ICAs and rescaled the ICAs stability region as appropriate. All documents that were reviewed were complete and performed in conformance with the approved methodologies.

Additionally, the staff reviewed the DRF file for Licensing Basis Hot Bundle Oscillation Magnitude for Clinton. The licensee confirmed that the OPRM system information contained in the detect and suppress analysis validates the applicability of the DIVOM curve for GE 14 fuel.

Based on the audit of the DRFs, the staff concludes that the licensee has taken an appropriate approach to correctly set its OPRM system. The GE 10 CFR Part 21 report issue involving the DIVOM curve is scheduled to be resolved in the second quarter of 2002 through the BWR Owners Group. Following license amendment review and approval, CPS will arm the OPRM.

In the interim, CPS will continue to use the ICAs. Following the ICAs until license amendment approval to arm the OPRM system is acceptable to the staff.

2.6.1.4 Anticipated Transient Without Scram (ATWS) Stability Unstable power oscillations can occur during plant maneuvers or under transient conditions and long-term stability solutions have been developed to detect and suppress these power oscillations. To address concerns that arose regarding unstable power oscillations during an ATWS, the BWROG submitted two topical reports to the staff: NEDO-32047-A, ATWS Rule Issues Relative to BWR Core Thermal-Hydraulic Stability, and NEDO-32164, Mitigation of BWR Core Thermal-Hydraulic instabilities in ATWS. On the basis of these evaluations, the BWROG and GE concluded that the mitigation strategies effectively prevent fuel failures and boron injection terminates the instability. In an SE dated February 5, 1994, the staff reviewed and accepted the two topical reports. With its acceptance of these two reports, the staff concluded that the recommended operator actions (e.g., lowering water level below the feedwater nozzles and initiating the standby liquid control (SLC) system early in the event) are appropriate to mitigate an ATWS event with oscillations.

In a letter dated January 24, 2002, the licensee stated that the CPS ATWS emergency operating procedures (EOPs) actions are based on the generic Emergency Procedure Guidelines/Severe Accident Guidelines (EPG/SAG), Revision1. The CPS ATWS EOPs are not changed for EPU. During an ATWS, the reactor pressure vessel (RPV) water level would be lowered to reduce core inlet subcooling and then level is controlled within a band between the top of the active fuel (TAF) and 2 feet below the feedwater sparger. The CPS ATWS EOPs are consistent with the ATWS operator actions delineated in EPG/SAG, Revision1 up to the point where water level is lowered to TAF. EPG/SAG, Revision 1 directs the operator to lower the RPV water level below TAF with the reactor vessel pressurized. The CPS EOPs do not direct the operator to lower the water level below TAF. If the RPV water level cannot be maintained above TAF, the CPS procedure directs the operator to depressurize the vessel and then maintain the level above the minimum steam cooling water level as read from the fuel zone instruments. The licensee took this deviation due to the inaccuracy of the fuel zone instrumentation at high reactor pressure.

In the staff SE dated June 6, 1996, Acceptance of proposed modifications to the BWR EPG, the staff addressed the optimal water level control strategy for ATWS. The BWROG recommended strategy for deliberate reduction in RPV water level below the TAF was compared to the level control strategy proposed by Pennsylvania Power and Light Company (PP&L) for the Susquehanna plant. PP&L preferred a higher water level control strategy (above TAF) to reduce the risk of core uncovery and fuel damage associated with the lower water level control. In the SE, the staff concluded that ...control at any level between minimum steam cooling water level and 2 feet below the feed water sparger to be acceptable. This evaluation was based on BWR/4 plants which inject boron solution through a standpipe below the core. Since CPS boron injection is through the core spray sparger, with better boron mixing, this conclusion can be conservatively applied to CPS. Based on the information submitted, the responses to RAIs, and the staff SE issued on level control strategy for ATWS, the staff concludes that the CPS deviation from EPG/SAG, Revision 1 is acceptable.

The staff evaluated the applicability of the generic ATWS instability analyses described in the two topical reports to CPS. A plants instability response is influenced by its physical design, core and fuel characteristics, and operating conditions. The CPS EPU operation includes changes in the reactor power, a flatter power distribution, a different fuel design (GE14 instead

of GE8X8), and an increased feedwater flow, all of which could affect the plants instability response.

The staff evaluated information that the licensee provided regarding the applicability of the key parameters assumed in the NEDO-32047-A analyses, the potential impact of differences that may exist, and whether any of the differences would impact the effectiveness of the required operator actions. Since the ATWS instability studies in NEDO-32047-A and NEDO-32164 were based on GE8X8 fuel designs and full-power operating conditions, GENE performed ATWS instability sensitivity studies using the 10X10 GE14 fuel design at a more limiting full-power operating condition than will exist at the CPS EPU/MELLLA condition and with a flatter radial power distribution. On the basis of these studies, GENE reported that the ATWS instability studies show a fully coupled neutronic/thermal-hydraulic reactor power/flow response that is similar to the those reported in previous studies. Furthermore, since the GE14 fuel design has lower heat flux per rod than the GE8X8 and GE 9x9 fuel bundle designs, GENE stated that the GE14 fuel design is less susceptible to extended fuel rod dryout. For an ATWS instability event without mitigation, GENE determined that it expects that at a more limiting condition than the expected CPS EPU/MELLLA condition, with the GE14 fuel design and a flatter radial power distribution, the extent of fuel damage would be bounded by that reported in the NEDO-32047-A ATWS instability analyses.

From its review, the staff determined that the CPS EPU/MELLLA operating conditions are not bounded by the generic ATWS instability analyses in NEDO-32047-A. However, GENEs subsequent sensitivity studies using the GE14 fuel design at a more bounding operating conditions than the CPS EPU (e.g., higher rod line, power level, feedwater flow, power distribution, with GE 14 fuel), indicate that the GE14 fuel design stability performance offsets the impact of the EPU power distribution and the higher bundle power-to-flow conditions. In addition, the ATWS mitigation strategies will still reduce the consequences of oscillations.

The staff has reviewed the information provided and, based on the results of the sensitivity studies reported by GENE for the GE14 equilibrium core, the staff concludes that the consequences of an ATWS instability event for the CPS EPU operation remain bounded by the consequences documented in the generic topical report NEDO-32047-A.

2.6.2 Reactor Safety Performance Evaluations 2.6.2.1 Reactor Transients For CPS, the transient analysis will be performed only during the reload analysis. This exception was discussed during the audit and its resolution is described in Section 9.1 of this SE.

In the proposed TS changes for EPU, there are no changes to the SLMCPR, 1.09 for two recirculation loop operation and 1.12 for single recirculation loop operation. In response to a staff question, the licensee stated that the SLMCPR was calculated for the EPU core using staff approved methodology and the calculated value is 1.08. The present value of 1.09 in the TS is more conservative than the calculated value of 1.08. The staff concludes that the TS are acceptable with regard to SLMCPR.

The insufficient data base issue (test data for upskew power shape) for the GEXL 14 correlation is being addressed by the staff in its review of the following submitted documents:

GEXL 14 Correlation for GE14 Fuel, NEDC-32851P Revision 2 and GEXL Correlation for GE 12 Fuel with Inconel Spacer, NEDC-32464P Revision 2, FLN-2001-018, September 25, 2001." In the interim, the staff concludes that the fuel vendor has taken appropriate actions to account for the lack of data in accordance with its internal quality assurance procedures.

2.6.2.2 Design-Basis Accidents For the CPS EPU, the licensee is taking an exception to the guidelines given in ELTR1.

This issue is discussed in Section 4.3 of this SE.

As part of the EPU review process, the NRC staff audited the CPS LOCA analysis. The staff focused on GENEs use of the LOCA codes and their applicability to the CPS EPU. The staff examined auditing project task reports and DRFs describing analyses for both the pre- and post-EPU LOCA analyses, and interviewed GENE engineering personnel involved in the analyses. The staff have the following observations:

a. The analyses were based on the NRC-approved SAFER/GESTR methodology and GENE followed an NRC-approved process in performing the ECCS-LOCA analysis.

b. CPS was closely involved in the development of the plant-specific information required by GENE in developing the model.

2.6.3 Conclusion All questions were resolved either during the audit or subsequent to the audit.

5($&725&22/$176<67(0$1'&211(&7('6<67(06 The staffs review of the reactor coolant system and connected systems focused on the effects of the power uprate on the operation of the systems, structural and pressure boundary integrity of the piping systems and components, their supports, the reactor vessel and internal components, certain pumps and valves, and balance-of plant (BOP) piping systems.

3.1 Nuclear System Pressure Relief The safety/relief valves (SRVs) provide overpressure protection for the NSSS, preventing failure of the nuclear system pressure boundary and uncontrolled release of fission products.

CPS has 16 SRVs, which are piped to the suppression pool. These SRVs, together with the reactor scram function, provide overpressure protection. The SRV setpoints are established to provide the overpressure protection function while ensuring that there is adequate pressure difference (simmer margin) between the reactor operating pressure and the SRV actuation set points. The setpoints are also selected to be high enough to prevent unnecessary SRV actuations during normal plant maneuvers.

For EPU operation, the licensee will not change the SRV setpoints, because the maximum

operating dome pressure will not change. The licensee evaluated the capabilities of the SRVs to provide overpressure protection based on the current set points and tolerances for operation at the EPU power level and determined that the nuclear boiler pressure relief system has the capability to provide sufficient overpressure protection. The licensee also stated that the EPU evaluation is consistent with the generic evaluations and discussions in Section 5.6.8 of ELTR1 and Section 4.6 of ELTR2.

Since the licensee performed limiting ASME code overpressure analyses (discussed in Section 3.2) based on 102 percent of the EPU power level, and the current SRVs setpoints and upper tolerance limits will not change, the staff finds that the SRVs will have sufficient capacity to handle the increased steam flow associated with the operation at the EPU power level. The ASME overpressure situation is evaluated during each cycle-specific reload analysis.

Therefore, the capability of the SRVs to ensure ASME overpressure protection will be confirmed in each subsequent reload analysis.

3.2 Reactor Overpressure Protection Analysis The design pressure of the reactor vessel and reactor coolant pressure boundary (RCPB) remains at 1250 psig. The ASME Code allowable peak pressure for the reactor vessel and the RCPB is 1375 psig (110 percent of the design pressure of 1250 psig), which is the acceptance limit for pressurization events. The most limiting pressurization transient is analyzed on a cycle specific basis and this approach would be applicable for each EPU reload cycle.

Section 5.5.1.4 and Appendix E of ELTR1 evaluated the ASME overpressure analysis in support of a 20 percent power increase, stating that the limiting pressurization transients events are the main steam isolation valve (MSIV) closure and turbine trip with turbine bypass failure. However, MSIV closure has been determined generically to be the more limiting event.

The licensee analysis of the MSIV closure event assumed an initial dome pressure of 1045 psig with five SRVs out of service, at 102 percent of the EPU rated thermal power and 107 percent core flow, and with a representative GE-14 core. The MSIV position signal scram was assumed to fail and the high-flux signal scram was assumed to shut down the reactor. The MSIV closure event resulted in a maximum reactor dome pressure of 1298 psig, which corresponds to vessel bottom head pressure of 1322 psig. Therefore, the peak calculated vessel pressure (1322 psig) remains below the ASME limit of 1375 psig. The NRC staff-approved evaluation model ODYN was used for the analysis. The licensee determined that there is no decrease in safety margin and the EPU overpressure protection analysis is consistent with the generic analysis in Section 3.8 of ELTR2.

Based on the information submitted, the analysis performed, and that the most limiting pressurization transient is analyzed for each EPU reload cycle, the staff concludes that the licensee analysis of the plant response to overpressure conditions is acceptable.

3.3 Reactor Pressure Vessel and Internals 3.3.1 Reactor Vessel Fracture Toughness On October 2, 2000, the NRC staff approved a proposed set of pressure-temperature (P-T) curves for CPS that would need to be updated within a few years. The licensee stated that they would reevaluate the 32 effective full power years of operation (EFPY) fluence with a staff approved methodology on or before October 15, 2003. The EPU submittal addresses that reevaluation.

The licensee stated that the fracture toughness evaluation process for the reactor pressure vessel follows the guidelines described in the NRC-approved LTRs NEDC-32424P-A, Class III, February 1999, Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate, and that the ASME Code Cases N-588 and N-640 apply to Pressure-Temperature curves.

The neutron fluence for the EPU was recalculated by the licensee using the NRC-approved GE-specific, synthesized two-dimensional transport methodology. The CPS thermal power vessel flux was a conservative upper bound estimate. The EPU fluence, which is bounded by the current RTP fluence, was used to evaluate the vessel material properties against the requirements of 10 CFR Part 50, Appendix G. The decrease in the EPU fluence despite the increase in the core thermal power was the result of more realistic lead factors derived from the above-mentioned methodology. The results of these evaluations indicate that:

(a) The upper shelf energy (USE) remains greater than 50 ft-lb for the design life of the vessel and maintains the margin requirements of 10 CFR Part 50, Appendix G. The minimum end of life upper shelf energy for beltline materials is 74 ft-lb.

(b) The beltline material reference temperature of the nil-ductility transition (RTNDT) remains below 200 degrees Fahrenheit.

(c) The current 32 EFPY P-T curves that are based on ASME Code Cases N-588 and N-640 bound the 38 EFPY P-T curves for the EPU conditions. The hydrotest pressure for EPU is 1105.5 psig.

(d) The current 32 EFPY Adjusted Reference Temperature (ART) bounds the ART for the beltline materials for the EPU conditions, because the fluence for the current ART is larger than the fluence for EPU using the above-mentioned methodology.

(e) The reactor vessel material surveillance program consists of three capsules. The three capsules have been in the reactor vessel since plant startup. Of these three capsules, one is scheduled to be removed after 10 EFPY of operation, the other after 20 EFPY and the third is classified as standby. The EPU has no effect on the existing surveillance schedule; however, there is a separate license amendment request to delay the first capsule removal for one additional cycle.

The maximum operating dome pressure for EPU RTP is unchanged from that for original power operation. Therefore, no change in the hydrostatic and leakage test pressures is required. The licensee concluded that, because the vessel is still in compliance with the regulatory requirements, operation with EPU conditions does not have an adverse effect on the reactor vessel fracture toughness. Based on the information submitted and the responses to the staff RAIs, the staff concludes that the existing fluence and P-T curves are acceptable for 32 EFPY operation.

While the P-T curve does not change, the TS surveillance requirements (SR) 3.4.11.8 and SR 3.4.11.9, which indicate the thermal power in a recirculating loop flow (in single-loop operation during power increase), are changed from: Thermal Power # 30 percent to Thermal Power #

25 percent. The staff concludes that this is acceptable, because in this manner the absolute value of the power remains the same for EPU conditions as for pre-EPU single-loop operation limited by 30 percent of the flow.

3.3.2 Reactor Vessel Integrity The licensee evaluated effects of the CPS power uprate on the reactor vessel and internal components in accordance with its current design-basis. The loads considered in the evaluation include reactor internal pressure difference (RIPD), LOCA loads, flow loads, acoustic loads, thermal loads, seismic, and dead weight. The licensee indicated that the load combinations for normal, upset and faulted conditions were considered consistent with the current design-basis analysis. In its evaluation, the licensee compared the proposed power uprate conditions (pressure, temperature and flow) against those used in the design-basis. For cases where the power uprate conditions are bounded by the design-basis analyses, no further evaluation is performed. If the power uprate conditions are not bounded by the design-basis, new stresses are determined by scaling up the existing design-basis stresses proportionate to the proposed power uprate conditions. The resulting stresses are compared against the applicable allowable values, consistent with the design-basis. Based on the information submitted and the responses to the staff RAIs, the staff concludes that the methodology used by the licensee is consistent with the NRC-approved methodology in ELTR1, Appendix I, and is therefore acceptable.

The stresses and CUFs for the reactor vessel components were evaluated by the licensee in accordance with the ASME Boiler and Pressure Vessel Code,Section III, 1971 Edition with addenda to and including summer 1973, which is the code of record at CPS. However, for certain previously modified components (i.e., recirculation inlet nozzle safe end and thermal sleeve, feedwater nozzle safe end and CRD return nozzle), the ASME 1974 Code Edition with addenda to and including the summer 1976 were used. The CPS reactor internal core support structural components are evaluated in accordance with the ASME Code Section III, Subsection NG 1974 Edition, to and including the summer 1976 addenda, and Code Cases 1618-2, 1682, 1775, N207-1 and N243, which represent the code of record. The licensee indicated that the evaluations supporting the thermal power increase were performed consistent with the design-basis.

The licensee provided the calculated maximum stresses and CUFs for the reactor vessel components in Tables 3-1 and 3-5 of NEDC-32989P. The reactor vessel components that are not listed have maximum stresses and CUFs that are either not affected by the power uprate or already bounded by those listed. The maximum calculated stresses shown in the table are within the allowable limits, and the CUFs are less than the code limit of unity except for the feedwater nozzle safe end. In its amendment request letter dated June 18, 2001, the licensee indicated that the initial calculated CUF at the most critical feedwater nozzle safe end exceeded the code allowable limit of 1.0. By letter dated March 15, 2002, the licensee confirmed the completion of detailed fatigue analysis which was performed for the feedwater nozzles at the reactor vessel. The analysis results in a CUF of 0.87 at the feedwater nozzle safe end based on 14 years of operation at the current rated power and 26 years of operation at the EPU condition. The calculated CUF is less than the allowable limit of 1.0, and therefore, acceptable to the staff. The licensee also indicated that CPS has a fatigue monitoring procedure, Class 1 Component Fatigue Monitoring Program, which monitors CUFs for fatigue critical locations within the plant and their exposure to specified plant transients. Based on the information submitted and the responses to the staff RAIs, the staff concludes that CPS plant operation at the proposed power uprate is acceptable.

3.3.3 Reactor Vessel Internals Structural Evaluation The staff reviewed the information submitted by the licensee to ascertain that the application included provisions for reactor vessel internals inspection so that any degradation as a result of stress corrosion cracking and irradiation assisted stress corrosion cracking will be promptly identified and, thus, failure of reactor vessel internals will be avoided in service. This information was provided in the letter dated December 6, 2001. In its response, the licensee stated that the increase in RIPDs will have some impact on the shroud inspections. However, the impact of the higher RIPDs on the inspection results of other reactor vessel internals is negligible.

The licensee also stated that CPS has been performing all reactor internals inspections in accordance with Boiling Water Reactor Vessel and Internals Project (BWRVIP) inspection and flaw evaluation requirements. Currently, there have been no indications identified in the shroud. Additional core shroud ultrasonic test inspections are planned during the refueling outage scheduled in spring 2002. Indications that may be identified will be evaluated using loading that includes the higher RIPDs due to EPU. Thus, the EPU effects are fully considered in the BWRVIP inspections and evaluations.

Flaw handbooks have been developed for several reactor internals components to evaluate potential flaws that may be discovered as part of the BWRVIP inspections at CPS. The flaw handbooks include and bound the EPU effects including RIPDS changes. Thus, the increased loads resulting from EPU are fully addressed in the BWRVIP inspection and evaluations.

The BWRVIP has been reviewed and approved by the staff as being acceptable to control and manage degradation of BWR safety-related reactor internals. Compliance with the staff-approved BWRVIP inspection program will ensure that degradation of reactor internals is promptly identified and corrected so that the safety-related reactor vessel internals perform in service as designed. Therefore, based on the information submitted and the responses to the staff RAIs, the staff concludes that degradation of CPS safety-related reactor internals will be controlled and managed at EPU conditions.

3.3.4 Flow-Induced Vibration In its assessment of the potential for flow-induced vibration on the components, the licensee indicated that the steam separators and dryers in the upper zone of the reactor are the components that are most affected by the increased steam flow due to the proposed power uprate. The effects of the power uprate on the flow-induced vibration for other components in the reactor annulus and core regions are less significant, because the proposed power uprate conditions do not require any increase in core flow, and very little increase in the drive flow.

For components other than the steam separators and dryers, the evaluation of flow induced vibration for the reactor internal components was performed based on the vibration data recorded during startup testing at the GE prototype BWR/6 plant vibration data. The vibration levels were calculated by extrapolating the recorded vibration data to power uprate conditions and compared to the plant allowable limits. The stresses at critical locations were calculated based on the extrapolated vibration peak response displacements and found to be within the GE allowable design criteria of 10 ksi. Stress values less than 10 ksi for stainless steel are within the endurance limit under which sustained operation is allowed without incurring any cumulative fatigue usage. The licensee concluded that vibration levels of all safety-related reactor internal components are within the acceptance criteria. The staff finds the licensees

specified stress limit of 10 ksi for the reactor internal components to be reasonably conservative in comparison to the ASME code limit of 13.6 ksi for the peak vibration stress, and, therefore, the staff concludes that vibration stress levels are acceptable for the CPS EPU.

3.3.5 Steam Separator and Dryer Performance The licensee stated that the steam separators and dryers are not safety related components; however, their failure may lead to an operational concern. The licensee also indicated that, although the design-basis criteria do not require evaluation of the flow-induced vibration or determination of cumulative fatigue usage for the steam separators and dryers, the maximum vibration level for the shroud separators is small in comparison to the allowable limit. The licensee provided information that the dynamic pressure loads, which may induce vibration for the dryers, are small in comparison to loads from the design-basis faulted condition.

Accordingly, stresses in the dryers due to vibration associated with the proposed uprated condition is estimated less than the allowable limit. In addition, the dryers will be visually inspected during removal in each refueling outage, and any significant cracking can be detected and repaired. The design-basis for the steam dryers specifies that the dryers maintain their structural integrity when subjected to a steam-line break occurring beyond the main steam isolation valves. The current steam dryer analysis remains bounding for the proposed power uprate conditions. Based on the information provided by the licensee by letter dated December 7, 2001, and the staff concludes that the licensee has reasonably demonstrated that the steam dryers and separators will meet their design-basis requirements and maintain their structural integrity following the proposed extended power uprate.

3.4 Reactor Recirculation System The primary function of the recirculation system is to vary the core flow and power during normal operation. However, the recirculation system also forms part of the reactor coolant system (RCS) pressure boundary.

The licensee evaluated the changes in the system operating pressure and temperature at the EPU conditions and determined that changes are small and result in conditions that remain within the current rated conditions. The CPS EPU will not involve any increase in the steady state dome pressure. However, operation at the EPU power level would increase the two-phase core flow resistance, requiring a slight increase in the recirculation system drive flow.

The licensee estimated the required pump head and pump flow at the EPU conditions and determined that the power demand of the recirculation motors will increase slightly. EPU does not require changes to the recirculation flow control system. The setpoint of the interlock for the flow control valve position runback on loss of feedwater pump for EPU was confirmed for EPU conditions. The licensee stated that the CPS recirculation system and its components are capable of providing the core flow required for operation at the EPU conditions. The staff finds that the recirculation system evaluations are consistent with the generic evaluation in Section 4.5 of ELTR2, Supplement 1, and are acceptable. Section 4.5 of Supplement 1 to ELTR2 evaluated the recirculation system performance for a 20 percent power uprate with a 75 psig increase in the normal dome operating pressure and concluded that the recirculation system design can accommodate the operating condition associated with the power uprate.

The licensee also stated that EPU conditions would not significantly increase the net positive suction head (NPSH) required or reduce the NPSH margin for the recirculation pumps or the jet pumps. The licensee will maintain the flow cavitation protection interlock at the current

setpoints of actual feedwater flow rate. The cavitation interlock, shown in the lower portion of the power/flow map, ensures that sufficient subcooling is available to prevent cavitation of the recirculation pumps. This staff finds this consistent with the evaluation in Section F.4.2.6 of ELTR1.

In support of the EPU conditions, the licensee also reanalyzed the anticipated transients without scram(ATWS) with recirculation pump trip. Evaluation of ATWS is in Section 9.3.1 of this SE. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that the impacts on the recirculation system safety functions discussed in Supplement 1 to ELTR2 were adequately considered for the CPS EPU and are acceptable.

3.5 Reactor Coolant Pressure Boundary Piping 3.5.1 Pipe Stresses The licensee evaluated the effects of the power uprate condition, including higher flow rate, temperature, pressure, fluid transients and vibration effects on the RCPB piping and the BOP piping systems and components. The components evaluated included equipment nozzles, anchors, guides, penetrations, pumps, valves, flange connections, and pipe supports (including snubbers, hangers, and struts). The licensee indicated that the original codes of record as referenced in the original and existing design-basis analyses, and analytical techniques were used in the evaluation. No new assumptions were introduced that were not in the original analyses.

The RCPB piping systems evaluated include the reactor recirculation, main steam, main steam drains, reactor core isolation cooling (RCIC), high pressure core spray (HPCS), feedwater, reactor water cleanup (RWCU), low pressure core spray (LPCS), SLC, residual heat removal (RHR), reactor pressure vessel (RPV) head vent line, control rod drive piping and SRV discharge line systems using the present code(s) of record. The licensee indicated that the evaluation follows the process and methodology defined in Appendix K of ELTR1 and in Section 4.8 of Supplement 1 of ELTR2. In general, the licensee compared the increase in pressure, temperature and flow rate due to the power uprate against the same parameters used as input to the original design-basis analyses. The comparison resulted in the bounding percentage increases in stress for affected limiting piping systems. The bounding percentage increases are compared to the design margin between calculated stresses and the code allowable limits. The bounding percentage increases were also applied to the original calculated stresses for the piping to determine the stresses at the proposed power uprate condition. The staff finds the methodology to be acceptable considering the conservatism in the application of the scaling factors for the power uprate stress to loading combinations that include individual loads (i.e., dead weight and seismic) that are not affected by the power uprate.

The licensee stated that the allowable limits from the code of record are used for the power uprate evaluation. For instance, the power uprate evaluation for Class 1 main steam and recirculation piping used the ASME Code,Section III, Subsection NB, 1983 Edition up to and including winter 1984 Addenda, which is the code of record. The evaluation for Class 1 main steam and feedwater branch piping used the ASME Code,Section III, Subsection NB, 1983 Edition up to and including winter 1984 Addenda, which is the code of record. For Class 2 and 3 main steam relief valves branch piping, the evaluation used the ASME Code,Section III, Subsection NB, 1983 Edition up to and including winter 1984 Addenda, which is the code of

record. On the basis of its evaluation, the licensee concluded that for all RCPB piping systems, the original piping design has sufficient design margin to accommodate the slight changes due to the proposed power uprate. Based on its review of the information submitted and the responses to the RAIs, the staff concludes that the RCPB piping systems have sufficient design margin and are acceptable for EPU operation.

The licensee evaluated the stress levels for BOP piping and appropriate components, connections and supports in a manner similar to the evaluation of the RCPB piping and supports. The licensee stated that the original codes of record, as referenced in the appropriate calculations, code allowables and analytical techniques, were used and that no new assumptions were introduced. The evaluated BOP systems include lines that are affected by the power uprate, but not evaluated in Section 3.5 of NEDC-32989P, such as feedwater condensate and heater drain, main steam drain lines, turbine bypass line, and portions of the main steam, feedwater, LPCS, RCIC, HPCS, and RHR systems outside the primary containment. The existing design analyses of the affected BOP piping systems were reviewed against the uprated power conditions. As a result of its evaluation, the licensee indicated that all piping meets the requirements of the ASME Section III 1977 Edition with Addenda through Winter 1978, which is the code of record. There are sufficient margins in the original design analyses to accommodate the changes due to the proposed power uprate. The staff finds that the stresses and CUFs provided for the BOP piping are within the code-allowable limits.

Therefore, based on its review of the information submitted and the responses to the RAIs, the staff concludes that the BOP piping systems have sufficient design margin and are acceptable for EPU operation.

The licensee evaluated pipe supports such as snubbers, hangers, struts, anchorages, equipment nozzles, guides, and penetrations by evaluating the piping interface loads due to the increases in pressure, temperature, and flow for affected limiting piping systems. In its letter dated December 7, 2001, the licensee stated that, for certain main steam and main steam branch piping, and feedwater pipe supports, more detailed evaluations were performed. In these evaluations, the calculations for the support components affected by the power uprate were updated to determine the acceptability of the pipe supports. As a result of these evaluations, there are five feedwater pipe supports that require modifications to meet code allowable stress limits. The modifications will be completed prior to the implementation of the EPU. The licensee reviewed the original postulated pipe break analysis and concluded that the existing pipe break locations were not affected by the power uprate, and that no new pipe break locations were identified. Based on its review of the information submitted and the responses to the RAIs, the staff concludes that the evaluation of the pipe supports and break locations is acceptable for EPU operation.

The licensee indicated that the flow-induced vibration (FIV) levels for the safety-related main steam and feedwater piping systems will increase in proportion to the increase in the fluid density and the square of the fluid velocity following the proposed power uprate. To ensure that the vibration level will be below the acceptable limit, the licensee will perform a piping vibration startup test program, as outlined in Section 10.4.3 of the amendment submittal. The startup testing would include monitoring and evaluating the FIV during the plant start-up for the proposed uprated power operation. Vibration data will be collected at test conditions, which correspond to 100 percent of the original rated thermal power (ORTP), to each 5 percent step increase in power level above 100 percent of ORTP, up to the final proposed uprated power level. The measured vibration levels are compared against the acceptance criteria where the allowable vibration stress levels are set by the design fatigue endurance stress intensity limits

established by the licensee for stainless and carbon steel. The staff finds the licensees methodology in assessing the FIV consistent with the ASME Section III Code and the ASME Operating and Maintenance Standard (OM), Requirements for Preoperational and Initial Startup Vibration Testing of Nuclear Power Piping Systems. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that the methodology to assess FIV at CPS is acceptable.

3.5.2 Flow-Accelerated Corrosion Power uprate will produce changes of several operating plant parameters, some of which will affect flow-accelerated corrosion (FAC). The licensee evaluated the effect of the EPU on FAC in the systems with the expected change of the operating plant parameters. The effect of the EPU on FAC was evaluated in the following systems: recirculation system, main steam and attached piping system and feedwater system, and other RCPB piping.

The licensee stated that the components in the recirculation system are made from stainless steel, which is not susceptible to FAC. No FAC damage will therefore occur in the system.

The licensee stated that the main steam and attached piping system contains components made from carbon steel, which are prone to FAC. Because EPU will produce changes in fluid velocities, temperatures and moisture content, which affect FAC, the licensee evaluated FAC effects on the components in the system. The most significant change in the predicted wall thinning rate caused by EPU conditions is in the steam lines carrying scavenging steam to the high-pressure feedwater heaters. The change is from 38 mils/year to 70 mils/year, which represents over 84 percent increase. This large increase is due to the type of flow in these lines and is consistent with the results obtained at the other plants. Although the wall thinning in other components in the system is smaller, the licensee included the FAC affected systems and components in the scope of the plant monitoring program. The program will monitor wall thinning by FAC using the CHECWORKS predictive code, which will be suitably modified to include the changes in operating parameters caused by the EPU. The results of the prediction will be used to revise the scope and frequency of inspection of the component subjected to FAC in order to ensure that the adequate margin exists before minimum thickness is reached.

The components that are found during the inspections to be degraded beyond the acceptable limits will be repaired or replaced.

The licensee identified that the feedwater system has carbon steel components, which are affected by FAC. The EPU will result in some changes to parameters affecting FAC in the system associated with the turbine cycle. The plant FAC program will be modified to include these changes. Based on the CHECWORKS predictions, appropriate changes to piping inspection frequency will be introduced to ensure adequate margin for those systems with changing process conditions. The program will also ensure timely removal or replacement of the components that do not meet acceptance criteria.

The licensee identified that other RCPB piping is affected by FAC. That piping includes: the RCIC system, RPV head vent and bottom head drain, RWCU system and portions of the RHR system. These systems are included in the licensee FAC program. The EPU does not change any of the operating parameters in any of these systems with the exception of slightly decreasing the inlet temperature to the RWCU. Therefore, FAC potential within any of these systems is not expected to change.

The NRC staff has reviewed and evaluated the licensees analyses of the systems where power uprate may have some effect on FAC. On the basis of this evaluation, the staff concludes that the licensee has adequately demonstrated that the changes in FAC caused by the EPU, will be accounted for by making modifications to its FAC program, so that timely corrective procedures could be implemented.

3.6 Main Steam Flow Restrictors Regarding the assessment of the main steam flow restrictors, the licensee stated that there is no impact on the structural integrity of the restrictors for the power uprate. In Section 3.2 of the initial submittal, the licensee provided information that a higher peak RPV dome pressure can result from the proposed power uprate, but that this value remains below the ASME code limit of 1375 psig. Also, the restrictors were designed for a maximum differential pressure due to the choke flow condition which is bounding for the uprated power condition. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that the main steam-line flow restrictors will maintain their structural integrity following the power uprate.

3.7 Main Steam Isolation Valves (MSIVs)

The MSIVs are part of the reactor coolant pressure boundary and perform the safety function of steamline isolation. The MSIVs must be able to close within the specified time limits at all design and operating conditions upon receipt of a closure signal. They are designed to satisfy leakage limits set forth in the TS.

The licensee indicated that the MSIVs have been generically evaluated, as discussed in Section 4.7 of ELTR2. This evaluation covers both the effects of the changes to the structural capability of the MSIV to meet pressure boundary requirements, and the potential effects of EPU related changes to the safety functions of the MSIVs. The generic evaluation is based on (1) a 20 percent thermal power increase, (2) an increased operating reactor dome pressure to 1095 psia, (3) a reactor temperature increase to 556 degrees Fahrenheit, and (4) steam and feedwater increase of about 24 percent. The licensee stated that the conditions for CPS are bounded by those in the generic analysis. The increased steam flow will assist the closure of the MSIVs. TS closure timing requirements will continue to be met. Therefore, EPU operation is bounded by the conclusion of the generic evaluation in Section 4.7 of ELTR2.

Based on its review of the information submitted, the responses to the RAIs, and the licensees rationale and evaluation, the staff concludes that the plant operations at the proposed EPU level will not affect the ability of the MSIVs to perform their isolation function.

3.8 Reactor Core Isolation Cooling System The CPS RCIC system provides core cooling in the event of a transient where the RPV is isolated from the main condenser concurrent with the loss-of-feedwater (LOFW), and the RPV pressure is greater than the maximum allowable for the initiation of a low-pressure core cooling system.

Section 5.6.7 of ELTR1 provides the scope of the RCIC system evaluation. The maximum injection pressure for RCIC is conservatively based on the upper analytical set point for the lowest available group of SRVs operating in the relief mode. For the CPS EPU, the reactor

dome pressure and the SRV setpoints are unchanged, and there are no changes to the RCIC high pressure injection parameters. The RCIC injection rate required at EPU conditions is also unchanged from the system design flow rate (600 gpm). The licensee states that the RCIC turbine operation at EPU will not change any startup transient or system reliability. The RCIC system has been modified to include the start up control function concept presented in GE Services Information Letter No 377, RCIC Startup Transient Improvement with Steam Bypass. The licensee further states that EPU operation does not decrease the NPSH available for the RCIC pump, nor does it increase the NPSH required above the system design value. The required EPU surveillance testing and system injection demands would occur at the same reactor operating pressures, so there would be no change to existing system and component reliability. The LOFW transient event was evaluated, and the acceptance criterion, (maintain reactor water level above top of active fuel), continues to be met for EPU conditions.

Based on the information submitted and the responses to the RAIs, the staff concludes that the licensee has analyzed the LOFW transient for EPU operation consistent with ELTR1 guidelines and has conservatively evaluated the pressure performance requirements of the CPS RCIC system.

3.9 Residual Heat Removal System The RHR system is designed to restore and maintain the coolant inventory in the reactor vessel and to remove heat from the primary system and containment following reactor shutdown for both normal and post accident conditions. The RHR system is designed to operate in the low-pressure coolant injection (LPCI) mode (discussed in Section 4.2.2),

shutdown cooling (SDC) mode, suppression pool cooling (SPC) mode, containment spray cooling (CSC) mode, and the fuel pool cooling assist mode (discussed in Section 6.3).

3.9.1 Shutdown Cooling Mode The operational objective of normal shutdown is to reduce the bulk reactor temperature after scram to 125 degrees F within approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> using two SDC heat exchanger loops.

The CPS SDC evaluation at the EPU condition shows that the plant can meet this cooldown time, and is consistent with Section 4.1 of ELTR2. The single loop cooldown target of reaching 212 degrees F within 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> is also met for EPU. Based on the information submitted and the responses to the RAIs, the staff concludes that the CPS SDC is acceptable for EPU operation.

3.9.2 Suppression Pool Cooling Mode The SPC mode of the RHR system is designed to remove heat discharged into the suppression pool to maintain pool temperature below the TS limit during normal plant operation and below the suppression pool design temperature limit after an accident. The power uprate increases the reactor decay heat, which increases the heat input to the suppression pool during a LOCA, which results in a higher peak suppression pool temperature. The EPU effect on suppression pool cooling after a design-basis LOCA is addressed in Section 4.1.1. The effect of higher temperature on NPSH available is addressed in Section 4.2.5.

3.9.3 Containment Spray Cooling Mode The CSC mode is designed to spray water from the suppression pool via spray headers into the containment airspace, to reduce the long-term containment pressure and temperature during post-accident conditions. The power uprate slightly increases the containment spray water temperature. This increase has a negligible effect on the use of the CSC mode to maintain the containment pressure and temperature within their design limits as the peak pressure and temperatures are reached prior to containment spray actuation.

Based on the information submitted and the responses to the RAIs, the staff concludes that plant operations at the proposed EPU level will have an insignificant impact on the CSC mode.

3.10 Reactor Water Cleanup System The RWCU system removes soluble and insoluble impurities from the reactor water, reducing their accumulation in the RCS. The reactor water, after being introduced into the RWCU system, is first cooled in regenerative and nonregenerative heat exchangers and then the insoluble and soluble impurities are removed by the filter-demineralizer. Purified water is then reintroduced to the coolant system through the regenerative heat exchanger. The EPU decreases slightly the temperature within the RWCU, but this change does not affect its performance. Also, a slight increase to the conductivity of reactor water, caused by increased iron input, is expected. However, this increase will be accommodated within the present reactor conductivity limits. The licensees review of functional capability of the RWCU has indicated that the system could perform adequately at its original system flow. The licensee also demonstrated that piping and components will meet all the system safety and design objectives after power uprate.

Based on the information submitted and the responses to the RAIs, the staff concludes that the RWCU will perform acceptably after the power uprate.

4.0 ENGINEERING SAFETY FEATURES 4.1 Containment System Performance The CPS USAR provides the results of analyses of the containment response to various postulated accidents that constitute the design-basis for the containment. Operation with a 20 percent power uprate from 2894 MWt to 3473 MWt would change some of the conditions and assumptions of the containment analyses. ELTR1, Section 5.10.2 requires the power uprate applicant to show the acceptability of the effect of the uprate power on containment capability.

These evaluations will include containment pressures and temperatures, LOCA containment dynamic loads, safety-relief valve containment dynamic loads, and subcompartment pressurization. Appendix G of ELTR1 prescribes the generic approach for this evaluation and outlines the methods and scope of plant-specific containment analyses to be done in support of power uprate. Appendix G states that the applicant will analyze short-term containment pressure and temperature response using the previously applied GE code, M3CPT code. For the recirculation suction line break (RSLB), the CPS EPU analyses uses the LAMB code with Moodys Slip Critical flow model to generate the blowdown flowrates used as inputs to M3CPT.

This approach, using a code with a more detailed reactor pressure vessel model, results in more realistic break flows for input to M3CPT, and differs from the current USAR analyses. Plant-specific use of the LAMB code, which has been previously reviewed by the NRC for Appendix K

LOCA analyses, was addressed in ELTR1 Appendix G.

Appendix G also requires the applicant to perform long-term containment heat-up (suppression pool temperature) analyses for the limiting USAR events to show that pool temperatures will remain within limits for suppression pool design temperature, ECCS NPSH, and equipment qualification temperatures. These analyses can be performed using the GE computer code SHEX. SHEX is partially based on M3CPT and is used to analyze the period from when the break begins until after peak suppression pool heat up (i.e., the long-term response). A comparison of benchmark calculations with the SHEX containment code to USAR calculations shows that the SHEX prediction of the peak suppression temperature with USAR input assumptions is similar to the value reported in the USAR. This computer code has been used by GE on all BWR power uprates and has been found acceptable based on comparison of benchmark calculations, which show that the SHEX prediction of the peak suppression pool temperature with USAR input assumptions is similar to the value reported in the USAR.

The staff has performed confirmatory pressure and temperature analyses for both the short-term and the long-term responses of the CPS containment to a double-ended guillotine break of a RSLB and for the short term response to the main steam-line break (MSLB) event evaluated in the Clinton EPU submittal. The confirmatory analyses were performed with the CONTAIN 2.0 computer program and used mass and energy input values provided by the licensee and plant description values furnished by the licensee and obtained from the CPS USAR. The confirmatory analyses demonstrated that the containment response from the CONTAIN program is similar to that from the GE M3CPT and the GE SHEX computer models. These GE models have been previously accepted for containment analyses and the models are applicable at the EPU power level. The NRC staff conducted CONTAIN analyses confirm the acceptability of the EPU containment pressure and temperature responses as discussed below in Section 4.1.1.

4.1.1 Containment Pressure and Temperature Response Short-term and long-term containment analyses results for the limiting design-basis accident (DBA), a large pipe break LOCA inside the drywell, are documented in the CPS USAR. The short-term analysis was performed to determine the peak drywell and wetwell pressure response during the initial blowdown of the reactor vessel inventory into the containment. The wetwell is defined as the sub-region of the containment between the HCU floor and suppression pool surface. The long-term analysis was performed to determine the peak pool temperature response considering decay heat addition to the suppression pool. In their response dated November 20, 2001, the licensee provided curves showing both short-term and long-term containment response for a DBA-LOCA including temperature and pressure for drywell and wetwell atmosphere, and suppression pool temperature. The licensee also listed the main parameters for the EPU containment pressure and temperature analyses that are different from the USAR values, but are not power-related.

The licensee indicated that the containment analyses were performed in accordance with NRC guidelines using GE codes and models. As noted above, the M3CPT code was used to model the short-term containment pressure and temperature response. The licensee also indicated that the SHEX code was used to model the long-term containment pressure and temperature response for EPU.

4.1.1.1 Long-Term Suppression Pool Temperature Response (a) Bulk Pool Temperature The licensee indicated that the long-term bulk suppression pool temperature response with the EPU was evaluated for the DBA LOCAs, which are the MSLB and RSLB. The bounding analysis was performed at 102 percent of EPU RTP. The analysis was performed using the SHEX code and the more realistic decay heat model. The NRC staff has determined that the model used, the American Nuclear Society/American National Standards Institute (ANS/ANSI) 5.1-1979 decay heat model with an uncertainty adder of two sigma, is acceptable.

The licensee indicated that the USAR analyses assumed thermal equilibrium between the suppression pool and containment airspace. The EPU analyses derived separate conditions for these regions by modeling the expected heat and mass transfer between the airspace and the suppression pool. With the large airspace-to-pool volume ratio found in Mark III type plants, it is reasonable to expect that the temperatures of the two regions will be different. The EPU analyses were also performed with structural heat sinks modeled in the drywell and containment airspaces. This modeling has been used for power uprate evaluations for other BWR plants with Mark III containments and found acceptable.

The peak bulk suppression pool temperature was calculated to be 177.2 degrees Fahrenheit for a RSLB at 102 percent of EPU power level and 167.5 degrees Fahrenheit at 102 percent of current power level, based on revised EPU methodology and input assumptions. In a letter dated November 20, 2001, the licensee indicated that the major cause of the decrease in peak suppression pool temperature between the USAR value of 180.3 degrees Fahrenheit and the now calculated value of 167.5 degrees Fahrenheit at current power level is the change to a more realistic decay heat model (ANS/ANSI 5.1+2-sigma) for the EPU. The calculated peak suppression pool temperature of 177.2 degrees Fahrenheit at 102 percent of EPU power level remains below the wetwell structure design temperature of 185 degrees Fahrenheit.

The licensee also analyzed the bulk pool temperature response for the alternate shutdown cooling event for EPU. The peak bulk temperature was calculated to be 182.6 degrees Fahrenheit at 102 percent of EPU level, which also remains below the structural design temperature of 185 degrees Fahrenheit.

Based on its review of the licensees analyses, and experience gained from its review of power uprate applications for other BWR plants, the staff concludes that the peak bulk suppression pool temperature response remains acceptable for the power uprate.

(b) Local Pool Temperature with SRV Discharge The local pool temperature limit for SRV discharge is specified in NUREG-0783, Suppression Pool Temperature Limits for BWR Containment, because of concerns resulting from unstable condensation observed at high pool temperatures in plants without quenchers. Elimination of this limit for plants with quenchers on the SRV discharge lines is justified in GE report NEDO-30832, Elimination of Limit on Local Suppression Pool Temperature for SRV Discharge with Quenchers. In a SE dated August 29.1994, the staff approved elimination of the maximum local pool temperature limit for plants with quenchers on the SRV discharge lines, provided the ECCS suction strainers are below the quencher elevation. The licensee indicated that at CPS the ECCS suction strainers are located below the SRV quenchers and, therefore, a local pool

temperature analysis is not required.

Based on its review of the licensees rationale and evaluation, the staff concludes that the plant operations at the EPU will have no adverse impact on the local pool temperature with SRV discharge and, therefore, remains acceptable.

4.1.1.2 Short-Term Containment Gas Temperature Response The licensee indicated that the limiting DBA with respect to peak drywell and containment airspace temperatures is a MSLB. The MSLB produces a higher drywell temperature response than the DBA LOCA (liquid line break) because the steam has a higher energy content than liquid at the same pressure. The analyses calculated the peak drywell gas temperature of 339.97 degrees Fahrenheit at EPU level and 339.92 degrees Fahrenheit at current power level using the same methods. The peak drywell airspace temperature calculated for the MSLB does exceed the drywell structural design value of 330 degrees Fahrenheit but only for a short time (less than 0.5 seconds at the beginning of the event). The drywell shell temperature will remain below 330 degrees Fahrenheit because it takes a much longer time for the drywell structural materials to increase to 330 degrees Fahrenheit.

The current licensing basis analysis had calculated a peak drywell temperature of 330 degrees Fahrenheit. The increase in peak drywell temperature is not caused by the increased power because the results at current power are similar to that for EPU. The licensee indicated that the increase in peak drywell temperature is mainly caused by two parameter changes. The EPU evaluation was performed with the initial drywell pressure at the TS lower limit of -0.2 psig; while previously, the nominal pressure of 0 psig was used. The second parameter change was a previously analyzed correction in drywell volume (from 246,500 to 241,699 cubic feet).

The peak calculated containment temperatures remain below the design structural limit of 185 degrees Fahrenheit. Therefore, the wetwell airspace temperature response also remains acceptable.

Based on the information submitted and the responses to the RAIs, the staff concludes that the drywell and wetwell air temperature response will remain acceptable after the EPU.

4.1.1.3 Short-Term Containment Pressure Response The licensee indicated that the short-term containment response analyses were performed for the limiting DBA LOCA, which assumes a double-ended guillotine break of a RSLB and a double-ended guillotine break of a MSLB, to demonstrate that operation at the EPU level does not result in exceeding the drywell and containment design pressure limits. The short-term analysis covers the blowdown period during which the maximum drywell pressures and differential pressures between the drywell and containment occur. These analyses were performed at 102 percent of EPU RTP per Regulatory Guide 1.49, with the break flow calculated by using a more detailed model than used for previous licensing basis analyses. These analyses calculated a peak short-term drywell pressure of 23.2 psig and a wetwell pressure of 9.4 psig for MSLB at EPU, which remains below the drywell design value of 30 psig and the wetwell design value of 15.0 psig.

At the current power level, these analyses calculated a peak drywell pressure of 23.1 psig and a wetwell pressure of 9.4 psig. The current licensing basis analyses had calculated a peak drywell

pressure of 18.9 psig and a wetwell pressure of 7.7 psig. In a letter dated November 20, 2001, the licensee indicated three main factors which cause the increase in peak drywell pressure.

The EPU evaluation was performed with the initial drywell pressure at the TS lower limit of -0.2 psig while previously; the nominal pressure of 0 psig was used. Second parameter change was a previously analyzed correction in drywell volume (from 246,500 to 241,699 cubic feet). The third was the use of more conservative upper design limit of the main steam line safe end used in the EPU evaluation (from 1.8 to 1.87 feet). The licensee indicated that the cause for the increased peak wetwell pressure is mainly due to the increased drywell pressure and decrease in calculated wetwell volume (from 153,043 to 140,478 cubic feet). For EPU, the wetwell volume was conservatively assumed using only the lowest elevation for the HCU floor from the pool surface while the USAR used an average value.

The analyses also calculated a peak long-term containment pressure of 7.0 psig for MSLB at EPU which remains below the containment design value of 15.0 psig. The current licensing basis analyses had calculated a peak long-term containment pressure of 8.7 psig. The USAR value for containment pressure is higher because heat sinks for the long-term analysis were not modeled while the EPU has modeled the heat sinks as indicated in Section 4.1.1.1.

These results show that the maximum drywell, wetwell and containment pressures remain bounded by the structural design pressure values after the EPU.

Based on the information submitted and the responses to the RAIs, the staff concludes that the containment pressure response following a postulated LOCA will remain acceptable after the EPU.

4.1.2 Containment Dynamic Loads 4.1.2.1 LOCA Containment Dynamic Loads The licensee indicated that the LOCA containment dynamic loads analysis for the EPU is based primarily on the short-term MSLB and RSLB DBA LOCA analyses. These analyses were performed similarly to the analysis described above in Section 4.1.1.3 except that break flows for the RSLB were calculated using the more detailed reactor pressure vessel model of NEDE-20566-P-A, GE model for LOCA Analyses in accordance with 10 CFR Part 50 Appendix K.

These analyses provide calculated values for the controlling parameters for the dynamic loads throughout the blowdown. The key parameters are the drywell and containment pressures, vent flow rates, and suppression pool temperature. The LOCA dynamic loads with the EPU include pool swell, condensation oscillation, and chugging.

The licensing bases for CPS LOCA loads are presented in USAR, Section A.3.8.3. The licensee indicated that during the USAR containment design load evaluation, a conservative bounding LOCA bubble pressure of 20.1 psig (USAR, Section A3.8.3.1) was assumed and shown to be greater than the peak calculated drywell pressure (18.9 psig). Since the peak drywell pressure for EPU is now calculated to be 23.2 psig, a more realistic approach is used to justify the existing load definition.

The licensee indicated that the use of the peak drywell pressure as the basis for the peak drywell wall pressure is conservative. The pressure at the time of vent clearing is a valid bounding value because the rapid bubble expansion decreases the bubble pressure. The peak drywell pressure occurs a few tenths of a second after vent clearing. However, the peak drywell

wall pressure will occur immediately after vent clearing when the LOCA bubble first forms.

Based on the LOCA containment analysis results for the EPU, the drywell pressure at vent clearing is determined to be less than 19 psig. This justifies the continued use of 20.1 psig design value as a conservative peak LOCA air bubble pressure load on the drywell wall for the EPU.

The short-term containment response conditions for EPU are within the range of test conditions used to define the pool swell and condensation oscillation loads for the plant. The long-term response conditions for EPU, in which chugging would occur, are within the conditions used to define the chugging loads. Therefore, the pool swell, condensation oscillation, and chugging loads for the EPU remain bounded by the existing load definitions.

Based on the information submitted, the responses to the RAIs, and its review of the licensees rationale and evaluation, the staff concludes that the LOCA containment dynamic loads will remain acceptable after the EPU.

4.1.2.2 Safety/Relief Valve Loads The SRV air-clearing loads include discharge line loads, suppression pool boundary pressure loads, and drag loads on submerged structures. These loads are influenced by the SRV opening setpoint pressure, the initial water leg height in the discharge line, the discharge line geometry, and suppression pool geometry. For the first SRV actuations, the only parameter change which can affect the SRV loads, that could be introduced by the EPU, is an increase in the SRV opening setpoint pressure. This EPU does not include an increase in the SRV opening setpoint pressures; therefore, it has no effect on the loads from the first SRV actuations.

After SRV closure, water refloods the discharge line; condenses steam; creates a low pressure which causes the vacuum breaker to open, allowing water level in the discharge line to decrease. Loads due to subsequent SRV actuations depend primarily on the maximum SRV discharge line reflood height at the time of SRV opening and time intervals between openings.

The time intervals between SRV openings are controlled primarily by the reactor pressure response, which in turn depends on the reactor power level. The licensee indicated that the time between the SRV closure and subsequent re-opening is long enough that the water column height during subsequent actuations has been reduced to its initial condition. The time to the second pop of the Low-Low Set Logic is about 34 seconds. A review of applicable test data shows that the water leg inside the SRV discharge line returns to the initial (pre-actuation) water level or lower level by approximately 5 seconds. In addition, the low-low-set (LLS) interlock continues to perform the function of preventing other non-LLS valves from reopening.

Therefore, SRV loads remain bounded by the existing load definition.

Based on the information submitted, the responses to the RAIs, and its review of the licensees rationale and evaluation, the staff concludes that the EPU will have insignificant or no impact on the SRV containment loads.

4.1.2.3 Subcompartment Pressurization The licensee indicated that the actual asymmetric loads on the vessel, attached piping, and biological shield wall due to a postulated pipe break in the annulus between the reactor vessel and biological shield wall do not increase. The licensing loads are based on the mass and energy releases for a postulated feedwater line break or a recirculation inlet line break in the

annulus at 2894 MWt. The mass and energy releases for the recirculation inlet line break used the methods provided in NEDO-24548 Annulus Pressurization Load Adequacy Evaluation.

However, the subcooled critical mass flux was more conservatively calculated using the Henry-Fauske subcooled critical mass flux model. NEDO-24548 recommends use of the Moody slip flow model for subcooled blowdown. The licensee stated that the evaluation performed for EPU used the recommended Moody slip flow model. The resulting EPU mass and energy releases for the recirculation inlet break remain bounded by the licensing basis mass and energy releases performed at 2894 MWt. The staff finds the use of the Moody slip flow model for subcooled blowdown as recommended in NEDO-24548 acceptable.

The licensee also indicated that the feedwater line break mass and energy releases at EPU remain bounded by the licensing basis mass and energy releases. Therefore, biological shield wall and component designs remain adequate because the original analyzed loads are based on mass and energy releases that bound the EPU conditions. Also, the pressure loadings on the drywell head refueling bulkhead plate due to postulated pipe breaks in the drywell head and the drywell do not increase at EPU. Therefore, the subcompartment pressurization will remain acceptable at EPU.

Based on the information submitted, the responses to the RAIs, and its review of the licensees rationale and evaluation, the staff concludes that plant operation at the EPU will have an insignificant impact on the subcompartment pressurization.

4.1.3 Containment Isolation The licensee indicated that the system designs for containment isolation are not affected by the EPU. The capability of the actuation devices to perform with the higher flow and temperature during normal operations and under post-accident conditions, has been determined to be acceptable.

Based on the information submitted, the responses to the RAIs, and its review of the licensees rationale and evaluation, the staff concludes that the plant operations at EPU will have an insignificant or no impact on the containment isolation system.

4.1.4 Generic Letter 96-06 The licensee indicated that the plants past response to Generic Letter (GL) 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions, was reviewed for the EPU post-accident conditions. The original containment design temperatures and pressures, which are assumed in the current GL 96-06 evaluation, are not exceeded under post-accident conditions for the EPU. The peak drywell airspace temperature calculated for the DBA LOCA exceeds 330 degrees Fahrenheit, but has been determined to be acceptable. Therefore, the current response remains valid for the EPU.

Based on the information submitted and the responses to the RAIs, the staff concludes that the CPS GL 96-06 evaluation is acceptable for EPU operation.

4.2 Emergency Core Cooling Systems The ECCS components are designed to provide protection in the event of a LOCA due to a rupture of the primary system piping. Although DBAs are not expected to occur during the

lifetime of a plant, plants are designed and analyzed to ensure that the radiological dose from a DBA will not exceed the 10 CFR Part 100 limits. For a LOCA, 10 CFR 50.46 specifies design acceptance criteria based on the peak cladding temperature (PCT), local cladding oxidation, total hydrogen generation, coolable core geometry, and the long-term cooling. The LOCA analysis considers a spectrum of break sizes and locations, including a rapid circumferential rupture of the largest recirculation system pipe. Assuming a single-failure of the ECCS, the LOCA analysis identifies the break sizes that most severely challenge the ECCS systems and the primary containment. The MAPLHGR operating limit is based on the most limiting LOCA analysis, and licensees perform LOCA analyses for each new fuel type to demonstrate that the 10 CFR 50.46 acceptance criteria are met.

The ECCS for CPS includes the HPCS system, the LPCI mode of RHR, the LPCS system and the automatic depressurization system (ADS). ECCS performance is discussed in Section 4.3.

4.2.1 High-Pressure Core Spray System.

The HPCS system (with other ECCS systems as backups) is designed to maintain reactor water level inventory during small and intermediate-break LOCAs, isolation transients and LOFW. The HPCS system is designed to pump water into the reactor vessel over a wide range of reactor operating pressures. The HPCS system also serves as a backup to the RCIC system. The system is designed to operate from normal offsite auxiliary power or from its dedicated emergency diesel generator.

The HPCS system is required to start and operate reliably over its design operating range.

During the LOFW event and isolation transients, the RCIC system maintains water level above the top-of-active fuel (TAF). For the MSIV closure, the SRVs open and close as required to control pressure and HPCS eventually restores water level.

The licensee evaluated the capability of the HPCS system during operation at the EPU power level to provide core cooling to the reactor to prevent excessive fuel PCT following small-break and intermediate-break LOCAs, and the systems ability to ensure core coverage up to the TAF in isolation transients and LOFW transients. The licensee stated that the HPCS evaluation is applicable to and is consistent with the evaluation in Section 4.3 of ELTR2. The maximum reactor pressure at which the HPCS system must be capable of injecting into the vessel for the RCIC backup function was selected based on the upper analytical values for the second lowest group of SRVs operating in the low-low set mode of operation. The EPU does not decrease the NPSH available for the HPCS pump or increase the required NPSH.

The generic evaluation in Section 4.3 of the supplement to ELTR2 is based on typical HPCS pump design pressures. The licensee evaluated the capability of the HPCS system to perform as designed and analyzed its performance at the EPU conditions, and concluded that HPCS can start and inject the required amount of coolant into the reactor for the range of reactor pressures associated with LOCAs and isolation transients. The EPU does not change the power required for the pump or the power required from the dedicated HPCS diesel generator. Based on the information submitted, the responses to the RAIs, and its review of the licensees rationale and evaluation, the staff concludes that HPCS is acceptable for EPU operation.

4.2.2 Low Pressure Coolant Injection The LPCI mode of the RHR system is automatically initiated in the event of a LOCA, and in

conjunction with other ECCS systems, the LPCI mode is used to provide adequate core cooling for all LOCA events. The licensee further stated that the existing system has the capability to perform the design injection function of the LPCI mode for operation at the EPU condition and that the generic evaluation in Section 4.1 of ELTR2 bounds the CPS LPCI system performance.

Based on the information submitted, the responses to the RAIs, and the licensees ECCS-LOCA analysis (see Section 4.3 of this SE) demonstrating that the system provides adequate core cooling, the staff concludes that LPCI is acceptable for EPU operation.

4.2.3 Low Pressure Core Spray System The LPCS system initiates automatically in the event of a LOCA, and in conjunction with other ECCS systems, the LPCS system provides adequate core cooling for all LOCA events.

The licensee stated that while the calculated LOCA PCT could increase slightly at the uprated power level, the existing LPCS system combined with other ECCS systems will provide adequate long-term post-LOCA core cooling. The licensee explained that the existing LPCS system hardware has the capability to perform its design injection function at the EPU conditions and that the generic evaluation in Section 4.1 of ELTR2 bounds the CPS LPCS system performance. Based on the information submitted, the responses to the RAIs, and the licensees ECCS-LOCA analysis (see Section 4.3 of this SE) demonstrating that the system provides adequate core cooling, the staff concludes that LPCS is acceptable for EPU operation.

4.2.4. Automatic Depressurization System The ADS uses seven SRVs to reduce reactor pressure after a small-break LOCA, allowing the LPCI and LPCS systems to provide cooling flow to the vessel. The plant design requires the SRVs to have a minimum flow capacity. After a specified delay, the ADS actuates either on low water level plus high drywell pressure or on sustained low water level alone. The licensee stated that the ability of the ADS to initiate on appropriate signals is not affected by the power uprate.

Based on the information submitted, the responses to the RAIs, and the licensees ECCS-LOCA analysis (see Section 4.3 of this SE) demonstrating that the system provides adequate core cooling, the staff concludes that ADS is acceptable for EPU operation.

4.2.5 Net Positive Suction Head The increased heat input to the suppression pool due to EPU could increase the peak suppression pool water temperature. This might affect the operation of ECCS pumps. The licensee indicated that the NPSH requirements for the ECCS pumps are conservatively based on 0 psig containment pressure and a peak suppression pool temperature of 212 degrees Fahrenheit. As discussed in Section 4.1.1.1 Long -Term Suppression Pool Temperature Response, the calculated peak suppression pool temperature for the most limiting case is 182.6 degrees Fahrenheit, which is less than the design value of 185 degrees Fahrenheit. Using a containment pressure equal to the vapor pressure at the specified temperature (14.7 psia at 212 degrees Fahrenheit), the NPSH calculations ensures that no credit is taken for the containment overpressure. Therefore, the EPU does not affect compliance with the ECCS pump NPSH requirements.

Based on the information submitted, the responses to the RAIs, and the licensees rationale and evaluations, the staff concludes that the plant operations at EPU will have an insignificant or no impact on the ECCS pumps NPSH requirements.

4.3 Emergency Core Cooling System Performance Evaluation The ECCS is designed to provide protection against postulated LOCAs caused by ruptures in the primary system piping. The ECCS performance under all LOCA conditions and the analysis models must satisfy the requirements of 10 CFR 50.46 and 10 CFR Part 50, Appendix K.

The NRC staff approved codes SAFER, LAMB, GESTR, and TASC were used for the CPS LOCA analysis.

The SAFER code was used to calculate the long-term-thermal-hydraulic behavior of the coolant in the vessel during a LOCA. Some important parameters calculated by SAFER are vessel pressure, vessel water level, and ECCS flow rates. The SAFER code also calculates PCT and local maximum oxidation.

The LAMB code is used to analyze the short-term thermal-hydraulic behavior of the coolant in the vessel during a postulated LOCA. In particular, LAMB predicts the core flow, core inlet enthalpy, and core pressure during the initial phase of the LOCA event (i.e., the first 5 seconds).

The GESTR code is used to provide best-estimate predictions of the thermal performance of GE nuclear fuel rods experiencing variable power histories. For LOCA analysis, the GESTR code is used to initialize the fuel stored energy and fuel rod fission gas inventory at the onset of a postulated LOCA.

TASC has been accepted for transient analysis and LOCA analysis. TASC is a detailed model of an isolated fuel channel. TASC is an improved version of the NRC-approved SCAT code, with the added capability to model advanced fuel features (partial length rods and new critical power correlation). It is used to predict the time to boiling transition for a large-break LOCA.

This value is used in subsequent codes to turn off nucleate boiling heat transfer models and turn on transition boiling models.

The licensee is taking an exception to the guidelines given in ELTR1. The ELTR1 approach required a plant-specific break spectrum evaluation to be submitted as part of the PUSAR using equilibrium core design parameters.

The staff concludes that this approach is acceptable for the following reasons:

(a) The NRC staff evaluations of several requests for stretch power increase and extended power uprate at BWRs have shown that the change of PCT for power uprates is not significant. The maximum increase in PCT was less than 20 degrees Fahrenheit, and is well within the acceptance criteria of 10 CFR 50.46. Since there is only a small change in PCT, a constant-pressure EPU has a negligible effect on the adders used to determine the licensing basis PCT.

(b) The ECCS performance characteristics and basic break spectrum response are not affected by a constant-pressure EPU.

(c) The limiting break sizes are well known and have been shown not to be a function of reactor power level.

(d) The analyses assume the hot bundle continues to operate at the thermal limits (minimum critical power ratio (MCPR), MAPLHGR, and LHGR) which are not changed by the EPU.

(e) The PCT for the limiting large-break LOCA is determined primarily by the hot bundle power, which is unchanged with power uprate.

(f)

(g) If CPS is limited by MAPLHGR or the LOCA analysis results are at the acceptance limits, a detailed analysis for the licensing basis PCT will be performed.

In addition to the large-break LOCA analysis, the small-recirculation-break LOCA response will be confirmed by the licensee as part of the CPS core reload analyses in order to assure adequate ADS capacity. The increased decay heat associated with EPU will increase the steam generation rate. The higher steam generation rate may result in a longer ADS blowdown and a higher PCT for the small-break LOCA. A spectrum of small-breaks will be analyzed in order to determine the effect of the uprate on the PCT for the small-break LOCA response. A sufficient number of break sizes will be analyzed to establish the worst small-break size at CPS.

The EPU will make a negligible effect on compliance with the other acceptance criteria of 10 CFR 50.46 (local cladding oxidation, core-wide metal-water reaction, coolable geometry). Long-term cooling is assured when the core remains flooded to the jet pump top elevation and when a core spray system is operating.

Based on the information submitted, the responses to the RAIs, and because the licensee will evaluate ECCS-LOCA performance for each fuel reload at the EPU conditions, the staff concludes that the CPS ECCS-LOCA performance complies with 10 CFR 50.46 and Appendix K requirements, and is acceptable.

4.4 Main Control Room Atmosphere Control System The licensee stated that the main control room atmosphere control system (MCRACS) is designed to maintain a habitable environment and to ensure the operability of all the components in the control room under all the station operating and accident conditions. The system is designed to maintain a positive pressure within the control room envelope with respect to the adjacent areas to preclude infiltration of unconditioned air, during all the operating modes except when the system is in recirculation mode or when the system is in the maximum outside air purge mode. The licensee further claimed that the performance of the system is not impacted as a result of the proposed EPU. The makeup air filter trains are capable of removing 99.95 percent of all particulate matter larger than 0.3 microns (through the high efficiency particulate air filtration) and no less than 99 percent of all forms of iodine (methyl and elemental iodides through the charcoal adsorption). As a result of the proposed EPU, the outside air iodine concentration is increased by up to 20 percent. The amount of charcoal in the makeup air train is more than adequate to handle the additional iodine loading and the additional decay heat as a result of radionuclides deposited is insignificant. The revised control room doses are bounded by the current licensing basis.

In a letter dated November 5, 2001, the staff requested additional information concerning the amount of charcoal in the makeup air train to ascertain that it is more than adequate to handle additional iodine loading and the additional decay heat as a result of radionuclides deposited.

The staff also requested information on additional heat loads affecting the MCRACS, as a result of the proposed EPU.

The licensee responded in a letter dated November 20, 2001, that the quantity of charcoal required for pre-EPU plant operation is 160 pounds based on CPS Calculation VC-6, Charcoal Requirements for CR Makeup Air System Filters. The amount of charcoal required will increase linearly with the 20 percent increase in outside air iodine concentration as a result of EPU and the post-EPU quantity of charcoal required will increase to a total of 192 pounds of charcoal, which is bounded by the actual charcoal quantity provided of 1260 pounds. The staff reviewed the licensees analysis, and based on that review, the staff concludes that the charcoal loading is acceptable for EPU.

The pre-EPU heat addition is less than 1 BTU/hour as a result of decay heat based on CPS

Calculation VC-1, Heating Rate in Control Room Air Filter Units. Therefore, the additional heat load due to the 20 percent EPU increase will still be negligible. The EPU increases in heat loads do not impact the MCRACS since these occur outside the control room areas. For the proposed EPU, the controls and indicating devices in the control room remain unchanged. The electrical (electronic) signals transmitted to some control room devices increase slightly due to higher process temperature and electrical loads. The minor associated heat load increases from these signals have an insignificant effect on the pre-EPU design margin of the MCRACS. The staff reviewed the information provided, and concludes that the heat load increases due to the proposed EPU are insignificant and acceptable.

Despite the increase in iodine loading as a result of the EPU, the iodine loading on the control room filters remains a small fraction of the allowable limit of 2.5 mg of total iodine (radioactive plus stable) per gram of activated carbon, identified in Regulatory Guide (RG) 1.52. Therefore, the control room filter efficiency is not affected by the EPU. The staff finds that the CPS continues to conform to the regulatory requirements of 10 CFR Part 50, Appendix A, GDC 19, GL 99-02, and the guidelines of RG 1.52 (Revision 2) and NUREG-0800, Standard Review Plan, Section 6.4.

Based on its review of the licensees rationale, and the experience gained from its review of power uprate applications for other BWR plants, the staff concludes that the EPU does not adversely affect the operation of the MCRACS.

4.5 Standby Gas Treatment System The licensee stated that by limiting the release of airborne particulates and halogens, the standby gas treatment system (SGTS) is designed to control off-site dose rates following a postulated DBA. The design flow capacity of the system was selected to maintain the secondary containment at the required negative pressure (with respect to the adjacent areas) to prevent ex-filtration of air from the reactor building. This capability is unaffected by the proposed EPU.

The licensee further stated that the charcoal filter bed removal efficiency for radioiodine is also not affected by the proposed EPU. The total post-LOCA iodine loading on the filters increases proportionally with the increase in core iodine inventory. Under the EPU conditions, the post-LOCA iodine loading increases from 1.3 to 1.6 mg of total iodine per gram of charcoal, but remains well below the original design capacity of the filter and below that allowed by RG 1.52 (2.5 mg of total iodine (radioactive plus stable) per gram of activated carbon). Therefore, the SGTS is unaffected by the proposed EPU and retains its capability of meeting its design-basis requirement for mitigation of offsite doses following a postulated DBA.

Based on its review of the licensees rationale, and the experience gained from its review of power uprate applications for other BWR plants, the staff concludes that the proposed EPU does not adversely affect operation of the SGTS.

4.6 Post-LOCA Combustible Gas Control System The licensee indicated that the combustible gas control system (CGCS) is designed to maintain the hydrogen concentrations of the drywell and containment atmospheres below the lower flammability limit following a hypothetical LOCA. The CGCS consists of two redundant 100 percent capacity mixing compressors and two 100 percent capacity recombiners. As a backup means of control, containment atmosphere can be purged through the SGTS. Design of the

system is based on the production of hydrogen from 1) metal-water reaction of active fuel cladding, 2) corrosion of zinc and aluminum exposed to water during a postulated LOCA, and 3) radiolysis of water. Only post-LOCA production of hydrogen and oxygen from radiolysis will increase in proportion to the power level. In a letter dated November 20, 2001, in response to the staff request for additional information (RAI), the licensee indicated that the hydrogen contribution from metal-water reaction of fuel cladding is not affected by the EPU, but is affected by fuel design. Hydrogen from metal-water is based on reaction of the cladding in the active fuel region for GE14 fuel, in accordance with RG 1.7, Control of Combustible Gas Concentrations in Containment Following a Loss-of Coolant Accident. Hydrogen from corrosion of aluminum and zinc is assumed not to change from the current licensed thermal power analysis on the basis that post-LOCA containment temperatures used in the original analysis are conservative and bound the maximum temperatures analyzed to occur for EPU. Because aluminum and zinc corrosion rates are pH dependent, analyses are performed at bounding pH values of 5.6 and 8.6 to determine the impact on required mixer start time, recombiner start time, and containment maximum hydrogen concentration.

The licensee indicated that the increase in radiolysis due to the EPU has a minor impact on the time available to start the system before reaching procedurally controlled limits, but does not impact the ability of the system to maintain hydrogen below the lower flammability limit of 4 percent by volume in the drywell and the containment atmosphere. For the EPU, the minimum required start time for the containment mixer decreases from 2.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to 2.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />. The minimum required start time for the recombiner decreases from 28.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 22.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. As a result, the maximum containment hydrogen concentration increases from 3.6 percent to 3.8 percent, occurring 523 hours0.00605 days <br />0.145 hours <br />8.647487e-4 weeks <br />1.990015e-4 months <br /> (21.8 days) following the LOCA. The EPU has no impact on the recombiner maximum operating temperature. The maximum operating temperature of the recombiners is dependent only on the maximum hydrogen concentration when the recombiners are in operation. The containment maximum hydrogen concentration is procedurally controlled to remain below the RG 1.7 flammability limit; and, therefore, is not influenced by the EPU.

Based on the information submitted, the responses to the RAIs, and its review of the licensees rationale and evaluation, the staff concludes that plant operations at the proposed uprate power level, will have a minor impact on the post-LOCA CGCS and the system will remain acceptable at the EPU conditions.

5.0 INSTRUMENTATION AND CONTROL 5.1 Suitability of Existing Instruments In its submittal, the licensee stated that for the proposed power uprate, each existing instrument of the affected NSSS and BOP systems was evaluated to determine its suitability for the revised operating range of the affected process parameters. Where operation at the power-uprated condition impacted safety analysis limits, the evaluation verified that the acceptable safety margin continued to exist under all conditions of the power uprate and, where necessary, setpoint and uncertainty calculations for the affected instruments were revised. Apart from the few devices that needed change, the licensees evaluations found most of the existing instrumentation acceptable for the proposed power uprate operation. The evaluations resulted in the following changes:

C Upgrade electro-hydraulic control system to accommodate turbine control valve stem lift vs. flow characteristic.

C Revise various instrument setpoints.

C Expand the indicating range on various control room and in-plant instrumentation.

These changes will be performed to accommodate the revised process parameters. Based on the fact that these changes are based on system review and analysis reviewed by the NRC staff and documented in other sections of this SE, and power ascension testing confirming the acceptability of these changes, the staff concludes that, when the above-noted modifications and changes are implemented during the next refueling outage, the CPS instrumentation and control systems will accommodate the proposed power uprate without compromising safety.

5.2 Instrumentation Trip Setpoint and Allowable Values The licensee in its submittal dated June 18, 2001, identified that instrument setpoints in the TS are established using GE setpoint methodology. The staff has previously reviewed this instrument setpoint methodology and found it acceptable for establishing new setpoints in power uprate applications. However, the staff was concerned about the use of a different setpoint methodology for BOP instruments. By letter dated November 5, 2001, the staff requested the licensee to discuss the instrument setpoint methodology used for BOP instrumentation. The licensee in its response dated November 8, 2001, stated that they have not revised any BOP instruments to support EPU application. The staff in its letter also requested the licensee to provide the changes in instrument setpoints and allowable values together with the analytical limits provided in Table 5-1 of the GE topical report. In its response, the licensee provided a table containing instrument setpoint, allowable values, and analytical limits for all the instrumentations listed in Table 5-1. Based on the review of this table, the NRC staff has determined that the proposed power uprate will not result in any significant reduction of margin.

The proposed setpoint changes resulting from the power uprate are intended to maintain existing margins between operating conditions and the reactor trip setpoints and do not significantly increase the likelihood of a false trip or failure to trip upon demand. Therefore, based on the information submitted and the responses to RAIs, the staff concludes that the existing licensing basis is not affected by the setpoint changes to accommodate the power uprate.

5.3 TS Changes Related to the Power Uprate The following TS changes have been proposed by the licensee:

1. TS SR 3.3.1.1.2 The licensee has proposed to change the Note preceding TS SR 3.3.1.1.2 and TS SR 3.3.1.1.2 to revise the percent RTP at which the average power range monitors (APRM) are calibrated to reactor power calculated from a heat balance. The percent RTP has been revised from $25 percent RTP to $ 21.6 percent RTP. The 25 percent RTP value in the TS is based on the generic analysis using the highest average bundle power at 100 percent RTP. In order to maintain the same basis with respect to absolute thermal power, the licensee has reduced the percent RTP threshold corresponding to a higher average bundle power for the uprated power level. On this basis, the staff

concludes that the proposed change to the TS is acceptable.

2. TS Section 3.3.1.1 Action E.1, TS SR 3.3.1.1.16, TS Table 3.3.1.1-1 Functions 9 and 10, TS 3.3.4.1 Applicability and Action D.2, and TS SR 3.3.4.1.4 The licensee has proposed to revise the percentage-of-RTP value corresponding to the power level where the reactor protection system (RPS) trip and end-of-cycle recirculation pump trip on turbine stop valve (TSV) closure or on turbine control valve (TCV) fast closure are not automatically bypassed from $ 40 percent to $ 33.3 percent. The licensees justification of this change is that these scram signals and recirculation pump trip functions are automatically bypassed at a low power level when the turbine bypass steam flow capacity is sufficient to mitigate a TSV or TCV closure transient. Because the turbine bypass capacity is not being changed by this EPU, the corresponding percentage of RTP is being revised to maintain the current thermal power value in MWt, corresponding to the existing bypass steam flow capacity. On this basis, the staff concludes that the licensees justification for these TS changes is acceptable.

3. TS Table 3.3.1.1-1 Function 5, and Action F.1 of TS Section 3.3.1.1 The licensee has proposed to reduce from 25 percent to 21.6 percent the percentage-of-RTP value at which the reactor vessel water level - high, Level 8 Function shall be operable. The 25 percent RTP value in the TS is based on the generic analysis using the highest average bundle power at 100 percent RTP. In order to maintain the same basis with respect to absolute thermal power, the licensee has reduced the percent of RTP threshold corresponding to a higher average bundle power for the uprated power level. On this basis, the staff concludes that the proposed changes to the TS are acceptable.

4. TS Table 3.3.1.1-1 Function 2b The licensee has proposed to revise the allowable value (AV) for the two-loop operation APRM flow-biased, high RPS trip from # 0.66W +67 percent RTP and # 113 percent RTP to # 0.55W + 62 percent RTP and # 113 percent RTP. The licensee has also revised the footnote (b) to change the allowable value for single-loop operation from # 0.66 (W-8) + 51 percent RTP to # 0.55 (W - 8) + 42.5 percent RTP. MELLLA has been approved by the staff for use at CPS. Based on that approval and the information provided, the staff concludes that the licensee proposed TS changes are acceptable.

5. TS SR 3.3.2.1.2, SR 3.3.2.1.4, SR 3.3.2.1.5 and TS Table 3.3.2.1-1 notes (b) and (c)

The licensee has proposed to revise the lower bound analytical limit for the low power setpoint (LLSP) from 20 percent to 16.7 percent and upper bound analytical limit for LLSP from 35 percent to 29.2 percent. Both of these values maintain the original absolute thermal power bases and therefore has no effect on the previous analysis. On this basis, the staff concludes that the proposed changes are acceptable.

6. TS Table 3.3.6.1-1, Function 1.c The licensee has proposed to revise the allowable value for the main steam line isolation on main steam flow - high function from # 178 psid to # 284 psid. The current analytical

limit is based on 140 percent rated flow. For the extended power uprate, the analytical limit is based on 130 percent of the rated flow since the main steam line flow restrictors will limit the steam flow to 135 percent of uprated steam flow. The licensee has calculated the allowable value based on the staff-approved GE setpoint methodology. On this basis, the staff concludes that the proposed change is acceptable.

5.4 Conclusion Based on the information submitted, the responses to the RAIs, and the above evaluation, the staff concludes that the licensees instrument setpoint methodology and the resulting TS setpoint changes for the power uprate are consistent with the CPS licensing basis; and, therefore, are acceptable.

6.0 ELECTRICAL POWER AND AUXILIARY SYSTEMS 6.1 Alternating Current (AC) Power 6.1.1 Background The main power system includes the main generator, the main power transformer, the switchyard, the unit auxiliary transformers, the reserve auxiliary transformer, and the emergency reserve auxiliary transformers. The generator is rated at 22 kV, 1100 MVA, 0.9 pf. The generator is hydrogen-cooled and is connected through a forced cooled isolated phase bus to main power transformer that steps up the generator voltage from 22 kV to 345 kV. During normal operation, the class 1E ac power system is supplied from the 345 kV offsite power system via the 345 kV switchyard and the reserve auxiliary transformer. The alternate source of offsite power is the 138 kV Clinton Tap Line, which is supplied via the emergency reserve auxiliary transformer and is physically and electrically separated form the 345 kV switchyard.

The three standby diesel generators are started automatically upon either loss of voltage on the associated standby 4.16 kV bus, or a LOCA signal, or a manual start signal. The transmission lines and the electrical distribution system were evaluated to conform to GDC 17 of Appendix A to 10 CFR Part 50.

For operation at EPU, there is an increase in the non-class 1E electrical load demand on the reserve auxiliary transformer (RAT) and the unit auxiliary transformers (UATs) associated with loads in the main transformer and isolated-phase bus cooling, reactor recirculation, condensate, condensate booster, service water, and feedwater systems. These additional electrical loads affect the original analyzed load, voltage drop and short circuit values. A portion of the non-Class 1E auxiliary power distribution equipment has presently identified undervoltage, overload and short circuit over-duty conditions under certain plant analyzed conditions. These conditions are exacerbated with the additional EPU non-Class 1E loading. Additionally, grid voltage ranges wider than presently analyzed are anticipated, and the modifications will include the effects of anticipated wider grid voltage range as part of modifications for the RAT and the RAT connections to the distribution equipment.

6.1.2 Grid Stability The licensee has performed the grid stability analysis on the 345 kV network for a net output of 1120 MWe (Gross MWe minus auxiliary power usage) for the EPU and determined that they need to implement several modifications and procedure changes to ensure grid stability. The

NRC staff was concerned that, with a 20 percent MWe increase, reactive power (VARs) produced by the generator will be reduced. To compensate for a reduction in VARs, capacitor banks or voltage stabilizers may be installed. By letter dated November 30, 2001, the licensee informed the staff that the main generator VAR capability will not be reduced by the power uprate. Analysis of the generator capability shows that generator gross VARs (lagging) will increase from approximately 489 MVAR at the current licensed power level to approximately 518 MVAR during Cycle 9 and 550 MVAR during Cycle 10 and beyond. Therefore, no capacitor banks or voltage stabilizers will be needed. Based on the information submitted and the responses to the RAIs, the staff concludes that CPS meets the requirements of GDC 17 for grid stability at the EPU condition.

6.1.3 Main Generator The main generator is currently rated for 985 MWe at 0.90 power factor. The turbine generator was originally designed with a maximum flow-passing capability and generator output in excess of rated conditions to ensure that the original steam-passing capability and generator output is achieved. The NRC staff requested more information regarding the modifications to the main generator. By letter dated December 13, 2001, the licensee provided additional information.

The existing generator rating is being increased from 1100 MVA to 1265 MVA by implementing the manufacturers recommendations for hardware modifications. These planned modifications include increasing the generator hydrogen system operating pressure to 75 psig, replacing the hydrogen coolers and increasing the generator stator water cooling system flow-rate. The existing exciter is not capable of maintaining the current 0.9 power factor at the increased 1265 MVA rating. The licensee plans to upgrade the exciter in the refueling outage following the next operating cycle to obtain a generator capability of 1265 MVA at 0.9 power factor. The existing generator and main power transformer protective relaying scheme will be modified to ensure reliable operation before achieving full EPU. Based on the information submitted and the responses to the RAIs, the staff concludes that the main generator can operate safely at the EPU condition.

6.1.4 Power Transformers The main power transformer bank consists of three single-phase units each rated at 310 MVA/347 MVA forced oil and forced air (FOA) at 55 degrees centigrade/65 degrees centigrade over ambient. The licensee has proposed to replace the existing main power transformers to support EPU-related generator output. The new MVA rating of the main power transformers will be 1425 MVA and will support the main generator maximum output 1184 MVA.

The NRC staff concludes that the main power transformer can be operated safely at the EPU condition.

The UATs are rated at 33.3 MVA for 65 degrees centigrade temperature rise. For operation at EPU, there is an increase in the electrical load demand on UAT associated with loads in the main transformer and isolated-phase bus cooling, reactor recirculation, condensate, condensate booster, service water, and feedwater systems. The licensee confirmed that the UATs are sized to supply the additional load demand due to EPU. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that the UATs can operate safely at the EPU condition.

The RAT is rated at 63.4 MVA for 55 degrees centigrade temperature rise. For operation at EPU, there is an increase in the electrical load demand on RAT associated with loads in the

main transformer and isolated-phase bus cooling, reactor recirculation, condensate, condensate booster, service water, and feedwater systems. The RAT feeds both Class 1E and non-Class 1E 4.16 kV buses and non-Class 1E 6.9 kV buses. Portions of the non-Class 1E auxiliary power distribution equipment have presently identified undervoltage, overload and short circuit over-duty conditions under certain plant analyzed conditions. These conditions are exacerbated with the additional EPU non-Class 1E loading. Additionally, grid voltage ranges wider than presently analyzed are anticipated and the modifications will include the effects of anticipated wider grid voltage range as part of modifications for the RAT and the RAT connections to the distribution equipment. The staff was concerned about the addition of the additional loads that would affect GDC 17 compliance. By letter dated November 30, 2001, the licensee responded that, due to anticipated grid conditions and the increased plant auxiliary loading due to power uprate, the RAT will be replaced during the refueling outage concurrent with the second stage of uprate. In the interim, analysis of the generator capability shows that the generator gross MVARs (lagging) will increase from approximately 489 MVAR at the current licensed power level to approximately 518 MVAR. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that the new RAT is sized to handle the increased plant auxiliary loading during the interim and can operate safely at the EPU condition.

The emergency reserve auxiliary transformer (ERAT) is rated at 30 MVA for 65 degrees centigrade temperature rise. The ERAT is adequate to support EPU operation for existing analyzed conditions. However, grid voltage ranges wider than presently analyzed are anticipated, and ERAT control enhancements will be implemented to address the anticipated wider range subsequent to EPU. The staff was concerned about the addition of the additional loads that would affect GDC 17 compliance. By letter dated November 30, 2001, the licensee responded that, due to anticipated grid conditions, the ERAT will be modified to utilize its load tap changer to automatically respond to grid conditions. The licensee stated that the change to ERAT operation is due to anticipated grid conditions and is not EPU related, because there are no class 1E auxiliary power system load changes associated with EPU. The ERAT only feeds Class 1E loads. Based on the information submitted and the responses to the RAIs, the staff concludes that, the ERAT can operate safely at the EPU condition.

6.1.5 Isolated Phase Duct The isolated phase bus duct and associated coolers will be modified before exceeding the current licensed thermal power to handle the additional loads associated with EPU. The associated coolers to the isolated phase bus duct will be modified to increase the cooling flow to support EPU-related generator output. Based on the information submitted and the responses to the RAIs, the staff concludes that upon completion of the above modifications, the isolated phase duct can be operated safely to accept the maximum generator output at the EPU condition.

6.1.6 Emergency Diesel Generators Power required to perform safety-related functions (pump and valve loads) is not increased with the EPU, and the current emergency power system remains adequate. Under emergency conditions, the systems have sufficient capacity to support all required loads for a safe shutdown, and to operate the engineered safety feature equipment following postulated accidents. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that the emergency diesel generators can be operated safely at the EPU condition.

6.2 Direct Current (DC) Power The dc loading requirements were reviewed, and no reactor power dependent loads were identified. Based on the information submitted and the responses to the RAIs, the staff concludes that operation at the EPU condition does not increase dc loads beyond name plate rating.

6.3 Fuel Pool Cooling The spent fuel pool cooling and cleanup (SFPCC) system is designed to remove the decay heat from the spent fuel assemblies stored in the spent fuel pool (SFP), and to clarify and purify the water in the SFP. The SFP cooling portion of the SFPCC system consists of two 100 percent capacity cooling trains each primarily equipped with one pump, one heat exchanger, and its associated valves, piping, instrumentation and controls. Heat is removed from the SFP heat exchanger by the component cooling water (CCW) system. In addition, the RHR system, which has a higher heat removal capacity, serves as a back-up system to the SFPCC system and provides supplemental cooling to maintain the SFP below the temperature limit of 150 degrees Fahrenheit in the event that the SFP heat load exceeds the heat removal capability of the SFPCC cooling system. The reactor will not be started up when the SFP water temperature exceeds 150 degrees Fahrenheit or when portions of the RHR system are being used for SFP cooling.

As a result of plant operations at the proposed uprate power level, the decay heat load for any specific fuel discharge scenario will increase slightly. The licensee performed evaluations which demonstrate that the combination of the SFPCC system heat exchangers and the availability of the RHR system is sufficient to remove the maximum SFP heat load resulting from plant operations at the proposed uprate power level during a planned refueling outage or an unplanned full core offload event.

In the response, dated November 8, 2001, the licensee stated that under normal (planned) refueling conditions, the maximum SFP heat load is 19.9 x 106 Btu/hr at 61 hours7.060185e-4 days <br />0.0169 hours <br />1.008598e-4 weeks <br />2.32105e-5 months <br /> after shutdown. With one SFPCC train and an ultimate heat sink temperature of 95 degrees Fahrenheit, the SFP temperature will be maintained at or below 120 degrees Fahrenheit. Under abnormal (unplanned) heat load conditions, the maximum SFP heat load is 46.2 x 106 Btu/hr at 134 hours0.00155 days <br />0.0372 hours <br />2.215608e-4 weeks <br />5.0987e-5 months <br /> after shutdown. With both SFPCC trains, and ultimate heat sink temperature of 95 degrees Fahrenheit, the SFP temperature will be 140 degrees Fahrenheit. In any event, the SFP temperature under planned refueling outage or unplanned full-core offload does not exceed the SFP temperature limit of 150 degrees Fahrenheit.

In addition, the SFP has a water temperature monitor system which alarms locally and in the control room. In the event that the alarm goes off due to high SFP temperature, plant procedure, Fuel Pool Cooling and Cleanup, lists the probable causes and corrective actions to be taken. Corrective actions include increasing cooling water flow, placing additional cooling trains in service, shifting cooling water sources, or aligning RHR to provide supplemental cooling. This will provide additional assurance that the above limitation of 150 degrees Fahrenheit during planned refueling outages or unplanned full-core offloads is not exceeded.

Based on its review of the licensee's rationale and evaluations, and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that plant operations at the proposed uprate power level do not change the design aspects and operations

of the SFP cooling system and the RHR system in the fuel pool cooling assist mode, and, therefore, are acceptable.

6.4 Water Systems 6.4.1 Service Water Systems The service water systems are designed to provide cooling water to various components/systems (both safety-related and nonsafety-related).

6.4.1.1 Safety-Related Loads The safety-related shutdown service water (SSW) system is designed to provide a reliable supply of cooling water during and following a LOCA for the following components/systems:

RHR heat exchangers, RHR pump seal coolers, emergency diesel generator heat exchangers, SFPCC heat exchangers, control room air conditioning water chillers, and various components and auxiliary unit coolers. The licensee performed evaluations and stated that plant operations at the proposed uprate power level will have an insignificant impact on the safety-related performance of the SSW system.

Following a LOCA, a majority of the increases in heat loads resulting from plant operations at the proposed uprate power level is from the RHR heat exchangers, as they provide the suppression pool cooling and the containment spray cooling. In the containment pressure and temperature response analyses, the licensee assumed the post-LOCA SSW flow rate and temperature to be unchanged for power uprated conditions. Results of these analyses demonstrate that, during and following a LOCA, the SSW system has sufficient capacity to remove the increased heat loads due to plant operations at the proposed uprate power level. The staffs evaluation of the containment system performance for plant operations at the proposed uprate power level is addressed in Section 4.1.

Based on its review of the licensee's rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff finds that the safety-related performance of the SSW system during and following the DBA is not significantly dependent on the reactor rated power. Therefore, the staff concludes that plant operations at the proposed uprate power level will have an insignificant effect on the service water system regarding the safety-related loads.

6.4.1.2 Non-Safety-Related Loads The non-safety-related service water systems are designed to provide cooling water to various plant equipment during normal plant operations and shutdown periods. The increase in heat loads on these systems due to uprated operation is approximately proportional to the power uprate. The licensee performed evaluations which demonstrate that the increase in heat loads on these systems is insignificant and that these systems have sufficient cooling capacities for plant operations at the proposed power uprate level.

Based on its review of the licensee's rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that plant operations at the proposed uprated power level have little or no impact on the non-safety-related service water systems. Therefore, the CPS EPU does not require modification of the non-safety-related

service water systems.

6.4.2 Main Condenser, Circulating Water, and Normal Heat Sink System Performance The main condenser, circulating, and normal heat sink systems are designed to remove the heat rejected to the condenser thereby maintaining low condenser pressure as recommended by the turbine vendor. The licensee stated that the performance of the main condenser, circulating water, and normal heat sink systems was evaluated and found adequate for plant operations at the proposed uprate power level.

Since the main condenser, circulating water, and normal heat sink systems do not perform any safety-related function, the impact of the proposed uprate power operations on the designs and performances of these systems was not reviewed.

6.4.3 Component Cooling Water System The CCW system is designed to remove heat from the SFPCC system and various auxiliary plant equipment housed in the reactor building during normal plant operations. As a result of plant operations at the proposed uprate power level, only the heat loads from the reactor recirculation pumps and the SFP will increase slightly. The operation of the remaining equipment cooled by the CCW system is not power-dependent, and is not affected by plant operations at the proposed uprated power level. The licensee performed evaluations and stated that the increase in heat loads on the CCW system due to plant operations at the proposed uprated power level is insignificant. The CCW heat exchangers were conservatively designed for heat loads which bound those anticipated for plant operations at the proposed uprate power level.

Based on its review of the licensees rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that plant operations at the proposed uprate power level do not change the design aspects and operations of the CCW system, and, therefore, the impact of EPU operation on the CCW system is insignificant.

6.4.4 Turbine Building Closed Cooling Water System The turbine building closed cooling water system (TBCCW) system supplies cooling water to auxiliary plant equipment in the turbine building. The licensee stated that the TBCCW system heat-load increases due to power uprate are those related to the operation of the turbine-generator; however, the TBCCW system has adequate heat removal capability for plant operations at the proposed uprate power level.

Since the TBCCW system does not perform any safety-related function, the impact of plant operations at the proposed uprate power level on the designs and performances of this system was not reviewed.

6.4.5 Ultimate Heat Sink The ultimate heat sink (UHS) for CPS consists of a submerged pond within Lake Clinton which is formed by the submerged dam across the North Fork of Salt Creek channel approximately one mile from the circulating water screen house. The licensee stated that the UHS was originally designed for two 991 MWe units. Therefore, the UHS remains to provide sufficient cooling water

at a temperature of 95 degrees Fahrenheit to remove the increased heat loads due to plant operations at the proposed uprate power level, following a DBA.

Based on its review of the licensees rationale and the experience gained from their review of power uprate applications for similar BWR plants, the staff concludes that EPU operation will have no impact on the UHS.

6.5 Standby Liquid Control System The licensee evaluated the effect of the EPU on the SLC system injection and shutdown capability. The CPS SLC is a manually operated system that pumps concentrated sodium pentaborate solution into the vessel through the HPCS sparger in order to provide neutron absorption and is capable of bringing the reactor to a subcritical shutdown condition from rated thermal power.

The licensee stated that an increase in the core thermal power does not by itself directly affect the ability of the SLC boron solution to bring the reactor subcritical and to maintain the reactor in a safe-shutdown condition. A higher fuel batch fraction, a change in fuel enrichment, or a new fuel design might affect the shutdown concentration, but operating at the EPU condition does not affect the required boron solution. The SLC system shutdown capability is reevaluated for each reload core. Neither the new fuel design nor a planned extension in the fuel cycle operating time requires an increase in the minimum reactor boron concentration of 660 ppm.

The licensee states that the SLC system is designed to inject at a maximum reactor pressure equal to the upper analytical setpoints for the second lowest group of SRVs operating in the relief mode. Additionally, the licensee states that, since the reactor dome operating pressure and the SRV setpoints will not change, the current SLC system process parameters are acceptable.

The SLC pumps are positive displacement pumps, and small changes in the SRVs setpoint would have no effect on the SLC system capability to inject the required flow rate.

The licensee states that there is sufficient margin (60 psi) to lifting the SLC system relief valves.

The calculated maximum required pump discharge pressure, based on the peak reactor pressure during the limiting ATWS event, is below the lowest calculated nominal opening pressure for the SLC pump relief valves. Consequently, the SLC relief valves do not lift during the ATWS events. The operation of the SLC system was also analyzed to confirm that the pump discharge relief valves will reclose in the event that the system is initiated before the time the reactor pressure recovers from the first transient peak. The evaluation compared the calculated maximum reactor pressure needed for the pump discharge relief valves to reclose with the lower reactor pressure expected during the time SRVs are cycling open and closed.

Considerations were also given to system flow, head losses for full injection, and cyclic pressure pulsations due to the positive displacement pump operation in determining the setpoint for the relief valves. The relief valves are periodically tested to maintain this tolerance.

The SLC ATWS performance is addressed in Section 9.3.1 of the PUSAR, and the licensee has stated that the evaluation is based on a representative core design at the EPU condition. The minimum allowable solution concentration used in the ATWS analysis was increased from the current value of 10.3 wt percent up to 10.8 wt percent. This was done to minimize the risk of having the ATWS analysis for EPU generate a peak suppression pool temperature that exceeds current design limits.

Based on the information submitted and the responses to the RAIs, the staff concludes that the

SLC system will be able to inject boron into the reactor coolant system as required by 10 CFR 50.62.

6.6 Power-Dependent Heating, Ventilation, and Air Conditioning Systems The licensee stated that the heating ventilation and air conditioning (HVAC) systems consists mainly of heating, cooling supply, exhaust and recirculation units in the turbine building, containment building and the drywell, auxiliary building, fuel handling building, control building, and the radwaste building. EPU results in a small increase in the heat load caused by slightly higher process temperatures and higher electrical currents in some motors and cables. The affected areas are the steam tunnel in the containment and the auxiliary buildings, the drywell in the containment building, the feedwater heater bay, condenser, steam driven feedwater pumps, condensate/condensate booster pump areas of the turbine building, and the fuel pool cooling areas in the fuel handling building. The licensee further stated that the heat load in the containment and auxiliary building steam tunnels increases due to the increase in the feedwater process temperature. The increased heat load is within the margin of the steam tunnel area coolers. In the drywell, the increase in feedwater process temperature and the slight increase in the recirculation pump motor horsepower are within the margins in the system capacity. In the turbine building, the maximum temperature increase in the feedwater heater bay and condenser areas is less than 2 degrees Fahrenheit due to the increase in the feedwater process temperatures. The increased heat load due to increased power requirements of the condensate and condensate booster pump motors is within the margin of the pump area coolers. The increase in temperature of the steam supplying the steam driven feedwater pumps increases the heat load on the area coolers, but the heat load remains within the area cooler margins. In the fuel building, the increase in heat load due to a slight fuel pool cooling process temperature increase is within the margin of the area coolers.

The licensee concluded that, based on a review of design-basis calculations and environmental qualification design temperatures, the design of the HVAC is adequate for the EPU. The only areas where EPU is expected to cause a temperature increase is the feedwater heater bay and condenser areas of the turbine building where the expected increase is less than 2 degrees Fahrenheit.

In a letter dated November 5, 2001, the staff requested additional information concerning the specific design capability and expected increase in heat loads due to the proposed EPU for the systems, structures or components served by the HVAC in the turbine building, containment building and the drywell, auxiliary building, fuel handling building, control building, and the radwaste building. The licensee responded in a letter dated November 20, 2001, stating that the increase in heat loads due to EPU impacted the HVAC system serving the following areas, but did not adversely affect the design area temperatures:

1 Drywell area - The feedwater temperature increases by 10 degrees Fahrenheit and the reactor recirculation pump horsepower increases by 0.9 percent due to EPU. The feedwater temperature increase adds 6,752 BTU/hour. The pumps are water-cooled. The 0.9 percent increase in horsepower translates to an increase in heat load of 196 BTU/hour from the pump casing. These increases are well within the approximate 2,140,000 BTU/hour (178 tons of refrigeration) pre-EPU design margin of the drywell cooling system.

2. Containment building steam tunnel - The feedwater temperature increase adds 2,506 BTU/hour of heat to the tunnel pre-EPU total load of 667,700 BTU/hour. The area cooler

cooling capacity is 1,400,000 BTU/hour.

3. Turbine building feedwater heater and condenser areas - The increase in feedwater process temperatures increases the total area heat load by 3.4 percent. Conservatively assuming that there is no margin in the area coolers, the corresponding maximum increase in temperature in these areas is less than 2 degrees Fahrenheit as shown below:

Mass flow of cooling air to the area is unchanged by EPU.

Thus, the area temperature increase = 0.034 x (Tarea - Tcooling air)

= 0.034 x (122 °F - 85 °F)= 1.3 °F.

4. Condensate booster pump room - The pre-EPU cooling requirement is 1,913,339 BTU/hour. The EPU cooling requirement is 2,295,479 BTU/hour. The room cooler cooling capacity is 2,800,000 BTU/hour.

5. Condensate pump room - The pre-EPU cooling requirement is 840,528 BTU/hour. The EPU cooling requirement is 994,128 BTU/hour. The room cooler cooling capacity is 1,400,000 BTU/hour.

6. Feedwater pump area - The increase in supply steam temperature to the turbine driven pump adds 2,603 BTU/hour to the area pre-EPU total load of 3,567,147 BTU/hour. The area cooler cooling capacity is 5,538,460 BTU/hour.

7. Auxiliary building main steam tunnel - The increase in feedwater temperature adds 9,776 BTU/hour to the total heat load of 482,688 BTU/hour. The cooler capacity is 1,400,000 BTU/hour.

8. Spent fuel pool cooling areas - The slight increase in fuel pool cooling process temperature adds 8,600 BTU/hour. The area cooler cooling margin is approximately 129,000 BTU/hour.

Based on its review of the information submitted, the responses to the RAIs, and the experience gained from its review of power uprate applications for other BWR plants, the staff concludes that the EPU does not adversely affect the operation of the CPS HVAC systems.

6.7 Fire Protection Program The staff finds that the operation of the plant at the EPU RTP will have no impact on the existing fire detection or suppression systems, the existing fire barriers provided to protect safe shutdown capability, or the administrative controls that are specified in the plants fire protection plan required by 10 CFR 50.48(a). The NRC requirements for achieving and maintaining safe shutdown following a fire require that: (1) one train of systems necessary to achieve and maintain hot shutdown be maintained free of fire damage, and (2) that the systems necessary to achieve and maintain cold shutdown can either be repaired within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if using redundant systems, or that the systems can be repaired, and that cold shutdown can be achieved within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if using alternative or dedicated shutdown capability. While Section 6.7, Fire Protection, of the submittal only addresses cold shutdown capability and is silent concerning hot shutdown capability, Table 6-3 indicates that the limits for important reactor process variables (peak cladding temperature, primary systems pressure, primary containment pressure, and suppression pool bulk temperature) are not exceeded following a fire event. Section 3.8, RCIC,

states that for certain beyond-design-basis events (Appendix R or ATWS), operation of the RCIC System at suppression pool temperatures greater than the operation limit may be accomplished by using the dedicated condensate storage tank (CST) volume source of water.

Section 4.2.1, HPCS, states that for certain beyond-design-basis events (Appendix R or ATWS),

operation of the HPCS System at suppression pool temperatures greater than the operation limit may be accomplished by using the dedicated CST volume source of water. While the staff does not consider an Appendix R fire a beyond-design-basis event as stated in the report, the staff has accepted the use of either HPCS or RCIC with suction from either the suppression pool or the CST for providing reactor coolant makeup to achieve hot shutdown when those systems are protected in accordance with the requirements specified in Section III.G of Appendix R to 10 CFR Part 50. While the higher decay heat associated with the EPU may reduce the time available for the operators to achieve cold shutdown, it should not impact the time required to repair those systems necessary to achieve and maintain cold shutdown, and would therefore only affect those fire areas in the plant where alternative or dedicated shutdown systems are relied upon to satisfy NRC requirements (i.e., those plant areas that must achieve cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a fire). The licensee has stated that the safe shutdown systems and equipment used to achieve and maintain cold shutdown conditions do not change, and are adequate for the EPU conditions. The staff finds this acceptable. The EPU may also reduce the time available for the operators to stabilize the plant in hot shutdown, and may affect the systems necessary to achieve and maintain hot shutdown for those plant areas that rely upon the use of safety relief valves in conjunction with the use of low pressure systems, such as core spray and LPCI, to provide reactor coolant makeup. The licensee has stated that the operator actions required to mitigate the consequences of a fire are not affected by the EPU and that sufficient time is available for the operator to perform the necessary actions.

Therefore, based on its review of the information submitted and the responses to the RAIs, the staff concludes that the EPU will not adversely affect the safe shutdown capability.

6.8 Systems Not Impacted or Insignificantly Impacted by EPU The licensee identified systems that are not affected or insignificantly affected by plant operations at the proposed uprate power level (e.g., auxiliary steam, service air, diesel fuel oil and diesel generator ventilation systems, etc.).

The staff reviewed these systems and, based on the information submitted, the staff concludes that EPU operation has insignificant or no impact on the systems.

7.0 POWER CONVERSION SYSTEMS 7.1 Turbine-Generator The turbine-generator was originally designed to have the capability to operate continuously at 105 percent of rated steam flow conditions with a degree of margin to allow control of important variables such as steam inlet pressure. The licensee stated that, as a result of plant operations at the proposed uprate power level, the high pressure turbine will be modified (based on a GE advanced steam flow path technology to improve steam path efficiency) to operate continuously at approximately 105 percent of the proposed power uprate steam flow conditions.

The licensee stated that it is expected, during the final modification design and implementation process, the mechanical governor may have to be changed or replaced and the overspeed trip

settings may have to be changed due to the large increase in flow.

Based on the information submitted, the responses to the RAIs, and the licensees rationale and evaluation, the staff concludes that operation of the turbine-generator at the proposed uprate power level is acceptable.

7.2 Miscellaneous Power Conversion Systems The licensee evaluated the miscellaneous steam and power conversion systems and their associated components (including the condenser and steam jet air ejectors, turbine steam bypass, and feedwater and condensate systems) for plant operations at the proposed uprate power level. The licensee stated that the existing equipment for these systems are acceptable for plant operations at the proposed uprate power level.

Since these systems do not perform any safety related function, the impact of plant operations at the proposed uprate power level on the design and performance of these systems was not reviewed.

8.0 RADWASTE SYSTEMS AND RADIATION SOURCES 8.1 Liquid Waste Management The single largest source of liquid and wet solid waste is from the backwash of the condensate demineralizer pre-filters, cleaning of demineralizer polish resins, and replacement of condensate demineralizer resins. The licensee stated that, with plant operations at the proposed uprate power level, the average time between pre-filter backwashes and deep bed resin cleaning will be reduced slightly. This reduction does not affect plant safety. Similarly, the RWCU filter-demineralizer requires more frequent backwashes due to slightly higher levels of activation and fission products.

The licensee further stated that the activated corrosion products in liquid wastes are expected to increase proportionally to the power uprate. However, the total volume of processed waste is not expected to increase appreciably, since the only significant increase in processed waste is due to the more frequent backwash of the condensate demineralizers. The licensee performed evaluations of plant operations and effluent reports, and concluded that the requirements of 10 CFR Part 20 and 10 CFR Part 50, Appendix I, will continue to be satisfied.

Based on its review of the licensee's rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that the liquid radwaste system is acceptable for EPU operation.

8.2 Gaseous Waste Management Gaseous wastes generated during normal and abnormal operation are collected, controlled, processed, stored, and disposed utilizing the gaseous waste processing treatment systems.

These systems, which are designed to meet the requirements of 10 CFR Part 20 and 10 CFR Part 50, Appendix I, include the offgas system and SGTS, as well as other building ventilation systems. Various devices and processes, such as radiation monitors, filters, isolation dampers, and fans, are used to control airborne radioactive gases. Results of the licensees analyses demonstrate that airborne effluent activity released through building vents will not increase

significantly due to plant operations at the proposed uprate power level. The release limit is an administratively controlled variable, and is not a function of core power.

Based on its review of the licensees rationale and evaluation, and the experience gained from its review of power uprate applications for BWR plants, the staff concludes that plant operations at the proposed uprate power level will have an insignificant impact on the above systems.

8.2.1 Offgas System Core radiolysis (i.e., formation of H2 and O2) increases linearly with core power, thus increasing the heat load on the offgas recombiner and related components. The licensee evaluated the impact of the increases of these offgases resulting from plant operation at the proposed EPU on the offgas system. The licensee stated these operational increases in offgas due to EPU remain well within the design capacity of the system. The system radiological release rate is administratively controlled, and does not change with operating power. Therefore, EPU does not affect the offgas system design or operation.

Based on its review of the licensees rationale and evaluation, and the experience gained from its review of power uprate applications for other BWR plants, the staff concludes that plant operations at the proposed EPU will have an insignificant impact on the offgas systems.

8.3 Radiation Sources in the Core The NRC staff has reviewed the licensees plan for power uprate with respect to its effect on the facility radiation levels and on the radiation sources in the core. During power operation, the radiation sources in the core include radiation from the fission process, accumulated fission products, and neutron reactions as a secondary result of reactor power. The radiation sources in the core are expected to increase in proportion to the increase in power. This increase, however, is bounded by the existing safety margins of the design-basis sources. Since the reactor vessel is inaccessible during operation, a 20 percent increase in the radiation sources in the reactor core will have no effect on occupational worker personnel doses during power operations. Due to design shielding and containment surrounding the reactor vessel, worker occupational doses are largely unaffected, and doses to the public from radiation shine from the reactor vessel remain essentially zero as a result of the EPU.

The post-operational radiation sources in the core are the result of accumulated fission products.

Two forms of post-operational source data are used for shielding analysis purposes. The first of these is the core gamma-ray source. The total short-term gamma energy source increases in proportion to reactor power. The shielding at CPS was conservatively designed so that the proposed increase in radiation sources in the core will not affect radiation zoning in the plant.

The second set of post-operation source data consists of tabulated isotopic activity inventories for fission products in the fuel. These are used for post-accident evaluations. Most fission product inventories reach equilibrium within a three-year period. The inventories of these fission products, as well as the inventories of the longer-lived fission products, can be expected to increase in proportion to the thermal power increase. On the basis of experience gained from our review of EPU applications for other BWR plants and for the reasons described above, the NRC staff concludes that the level of the radiation sources in the reactor core following EPU will be acceptable.

8.4 Radiation Sources in the Reactor Coolant During operations, the reactor coolant passing through the reactor core region becomes radioactive as a result of nuclear reactions. The activation products in the reactor water will increase in approximate proportion to the increase in thermal power. The installed shielding at CPS was conservatively designed so that the increase in activation products in the reactor water resulting from the proposed power uprate will not affect radiation zoning in the plant. However, the licensee will monitor radiation levels throughout the plant and restrict access to areas when necessary to maintain occupational doses as low as reasonably achievable (ALARA).

Activated corrosion products (ACP) are the result of the activation of metallic wear materials in the reactor coolant. Under the EPU conditions at CPS, the feedwater flow rate will increase by nearly 22 percent, but the reactor water cleanup system flow will remain at the pre-EPU value.

This will result in an increase in the concentration of metallic materials in the reactor water. In addition, the filter efficiency of the condensate demineralizers may decrease as a result of the feedwater flow increase. The licensee estimates that the combination of these increases in concentration of metallic materials in the reactor water with the increase in neutron flux could result in an increase in the production of ACP by as much as 34 percent. However, the expected ACP increase should not exceed the design-basis concentrations. The areas that would likely see higher radiation levels due to increases in activated corrosion products are inside the drywell adjacent to the recirculation and RWCU piping, in the auxiliary building in the cubicles containing the RWCU pumps, and in containment areas containing the RWCU heat exchangers and filter/demineralizers. These areas are already identified as radiologically controlled areas and are not normally occupied. Access to these areas is already controlled under current plant radiation protection procedures. The licensee will identify any significant changes to radiation levels that may result from the EPU by special radiation surveys that will be conducted as part of the EPU startup test program. Increases in radiation levels are not expected to be large enough to restrict operations or affect occupancy levels in these areas.

Fission products in the reactor coolant result from the escape of minute fractions of the fission products which are contained in the fuel rods. Fission products in the primary coolant are separable into the products in the steam and the products in the reactor water. The activity in the steam consists of noble gases released from the core plus carryover activity from the reactor water. Since the current fuel thermal limits (which affect the rate of release of fission products from the fuel rods) will be maintained for the proposed power uprate, there will be no change in the amounts of fission products released to the reactor coolant from the fuel. Therefore, the fission product activity levels in the steam and reactor water are expected to be approximately equal to current measured data. The current measured fission product activity levels in the reactor coolant are a small fraction of the design-basis levels. Offgas rates for the current operations are also well below the original design-basis. Even if the fission product activity in the reactor coolant were to increase in proportion to the thermal power increase, the resulting fission product activity levels in the reactor coolant would still be a small fraction of the design-basis levels.

The licensee has stated that the various radiation sources in the reactor coolant will either remain relatively unchanged or will increase in approximate proportion to the increase in thermal power as a consequence of EPU. In all cases however, the increased level of radiation sources following EPU will be well below the design-basis data levels. Based on the information submitted and the responses to the RAIs, the staff concludesthat the increased level of radiation sources in the reactor coolant will be acceptable.

8.5 Radiation Levels Radiation sources in the reactor coolant contribute to the plant radiation levels. As discussed previously, the overall proposed 20 percent power uprate will result in a proportional increase in certain radiation sources in the reactor coolant. This increase in reactor coolant activity will result in some increases (up to 20 percent) in plant radiation levels in many areas of the plant.

The increase in plant radiation levels may be higher in certain areas of the plant. The small potential increase in radiation levels resulting from the proposed power uprate, however, will not affect radiation zoning or shielding in the various areas of the plant that may experience higher radiation levels.

Post-operational radiation levels in most areas of the plant are expected to increase by no more than the percentage increase in thermal power level. This increase in post-operational radiation levels could be slightly higher in a few areas near the reactor water piping and liquid radwaste equipment. As stated in the section above, the increased concentration of corrosion products in the reactor water may lead to increased crud buildup in systems handling reactor water, which will increase the post-operation radiation levels in the vicinity of the affected equipment. The licensee has estimated that the combined effect of the increase in concentration of corrosion products and the increase in neutron flux as a result of the EPU will result in a maximum increase of 34 percent in the post-operational dose rates in limited areas of the plant. The plant areas likely to see increases in the post-operational doses greater than the increase in power following EPU are inside the drywell adjacent to the recirculation and RWCU piping, in the auxiliary building cubicles containing the RWCU pumps, and in containment areas containing the RWCU heat exchangers and filter/demineralizers. Many of these areas are normally locked and controlled in accordance with high radiation area requirements, and require infrequent access.

The increased radiation levels described above will not necessitate the changing of any radiation zoning levels.

During the initial power accession steps of the EPU, the licensee will conduct a startup test program. This startup program will include radiation monitoring to verify, change, or establish proper radiological controls within the plant to ensure that personnel exposures are maintained ALARA. The licensee also stated that many portions of the plant were originally designed for higher-than-expected radiation sources. Therefore, the small potential increase in radiation levels resulting from the proposed power uprate will not affect radiation zoning or shielding in the various areas of the plant that may experience higher radiation levels. The doses to individual workers will be maintained within acceptable limits by controlling access to radiation areas. The licensee will use procedural controls to compensate for any increased radiation levels and to maintain occupational doses ALARA.

In December 2000, CPS implemented a zinc injection program. Zinc addition has become an established tool for controlling shutdown dose rates in BWRs. The use of zinc addition also suppresses the release of soluble Co-60 from the fuel deposits so that the concentration of Co-60 in the reactor water is decreased. The use of zinc addition also forms a protective oxide film on stainless steel so the corrosion on the RCS piping is suppressed. In the long run, the licensee expects zinc addition to have a significant effect on the reduction in dose rates in the plant. The licensee is also planning to initiate a program of noble metal injection during the refueling outage in the spring of 2002. The use of noble metal injection increases the efficiency of hydrogen injection, thereby allowing the licensee to achieve low electrochemical corrosion potentials on the BWR components (which in turn, minimize intergranular stress corrosion cracking) while maintaining low hydrogen addition rates. The maintenance of low hydrogen

addition rates minimizes N-16 effects on operating dose rates.

The licensee states that post-accident radiation levels are expected to increase by no more than the proposed percentage increase in power level. Item II.B.2 of NUREG-0737 states that the occupational worker dose guidelines of 10 CFR Part 50, Appendix A, GDC 19 shall not be exceeded during the course of an accident. Compliance with Item II.B.2 ensures that operators can access and perform required duties and actions in designated vital areas. GDC 19 requires that adequate radiation protection be provided such that the dose to personnel shall not exceed five rem whole body, or its equivalent to any part of the body for the duration of the accident.

The CPS USAR lists the following vital areas at CPS: main control room, technical support center, sampling station, and sample analysis areas. The main control room and technical support center are adjacent to each other and share the same habitability envelope. The licensee calculates that the total post-LOCA operator dose from external sources will increase from 0.46 person-rem under pre-EPU conditions to 0.59 person-rem under EPU conditions. The sampling station and the sample analysis areas are in the same vicinity. Neither of these vital areas will be continuously occupied following an accident. The licensee has estimated that the mission dose to obtain a sample, transport the sample to the sample analysis area, and perform the sample analysis will increase from 0.61 person-rem to approximately 1 person-rem under EPU conditions. These mission doses are below the dose limit of 5 rem whole body contained in GDC 19. Therefore, personnel access to, and work in, designated vital areas for accident mitigation following a LOCA can still be accomplished without exceeding the dose requirements of GDC 19.

Several physical plant modifications will need to be completed prior to full implementation of the power rate increase. These modifications will be planned and conducted in accordance with the station ALARA program. These modifications will be implemented during the spring 2002 refueling outage. The licensee estimates that the total collective dose accrued to implement these modifications will be approximately 5 person-rem. The principal contributors to this dose are expected to be the main turbine replacements and the installation of test equipment for vibration monitoring. This expected one-time occupational dose to make these modifications is a small fraction of the average yearly worker collective dose at CPS.

Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that radiation levels during EPU operation will be acceptable.

8.6 Normal Operation Off-Site Doses For the EPU, normal operation gaseous activity levels are expected to increase in proportion to the percentage increase in core thermal power. The TS limits for CPS implement the guidelines of 10 CFR Part 50, Appendix I. At the original rated power, the radiation effluent doses were a small fraction of the doses allowed by TS limits. The EPU will not involve significant increases in the offsite doses from noble gases, airborne particulates, iodine, or tritium. Doses from liquid effluents are currently zero and are expected to remain zero under EPU conditions. The licensee has calculated the estimated annual dose at the site boundary from skyshine and gaseous effluents for continuous occupancy at pre-EPU conditions. The total annual whole body dose at the site boundary is estimated to be 2.2 mrem, which is less than 10 percent of the 40 CFR Part 190 limit of 25 mrem. The skyshine dose is approximately 40 percent of this estimated dose. These estimated doses were calculated using design basis activities. Actual measured offsite doses at CPS are well below the calculated doses. Therefore, the NRC staff concludes that any increase in offsite doses due to EPU will be bounded by the calculated

design basis doses, will be well within the TS dose limits, will be below the limits of 10 CFR Part 20 and 10 CFR Part 50, Appendix I, and is acceptable.

Additionally, on the basis of its review of the information provided, the NRC staff concludes that the proposed EPU will have little effect on personnel occupational doses and that these doses will be maintained ALARA in accordance with the requirements of 10 CFR 20.1101. Also, the operator calculated doses from external exposures from a DBA will be less than the allowable GDC 19 criteria, and will allow operators access into vital areas for needed emergency activities.

Therefore, the staff concludes that the proposed power uprate at CPS is acceptable from a normal operations occupational and GDC 19 accident dose perspective.

9.0 REACTOR SAFETY PERFORMANCE EVALUATION 9.1 Reactor Transients AOOs are abnormal transients which are expected to occur one or more times in the life of a plant and are initiated by a malfunction, a single-failure of equipment, or a personnel error. The applicable acceptance criteria for the AOOs are based on 10 CFR Part 50, Appendix A, GDC 10, 15, and 20. GDC 10 requires that the reactor core and associated control and instrumentation systems be designed with sufficient margin to ensure that the SAFDL are not exceeded during normal operation and during AOOs. GDC 15 stipulates that sufficient margin be included to ensure that the design conditions of the reactor coolant pressure boundary are not exceeded during normal operating conditions and AOOs. GDC 20 specifies that a protection system be provided that automatically initiates appropriate systems to ensure that the specified fuel design limits are not exceeded during normal operating conditions and AOOs.

The SRP (NUREG-0800) provides further guidelines that: (1) pressure in the reactor coolant and main steam system should be maintained below 110 percent of the design values according to the ASME Code,Section III, Article NB-7000, Overpressure Protection; (2) fuel cladding integrity should be maintained by ensuring that the reactor core is designed to operate with appropriate margin to specified limits during normal operating conditions and AOOs; (3) an incident of moderate frequency should not generate a more serious plant condition unless other faults occur independently; and (4) an incident of moderate frequency, in combination with any single active component failure or single operator error, should not result in the loss of function of any fission product barrier other than the fuel cladding. A limited number of fuel cladding perforations are acceptable.

The CPS USAR evaluates a wide range of potential transients. Chapter 15 of the USAR contains the design-basis analyses that evaluate the effects of an AOO resulting from changes in system parameters such as: (1) a decrease in core coolant temperature, (2) an increase in reactor pressure, (3) a decrease in reactor core coolant flow rate, (4) reactivity and power distribution anomalies, (5) an increase in reactor coolant inventory, and (6) a decrease in reactor coolant inventory. The plants responses to the most limiting transients are analyzed in each reload cycle and are used to establish the thermal limits. A potentially limiting event is an event or an accident that has the potential to affect the core operating and safety limits.

The generic guidelines for EPU evaluation (Appendix E of ELTR1) identified the set of limiting transients to be considered in each event category. The staff SE for ELTR1 states that: - - -the staff agrees with the minimum set of limiting transients to be analyzed, which is contained in Appendix E of ELTR1."

The following transients in Appendix E of ELTR1 will be analyzed as part of the reload analysis:

loss of feedwater heating feedwater controller failure load rejection no bypass turbine trip no bypass main steam isolation valve closure with flux scram rod withdrawal error Pressure regulator downscale failure (PRDS), main steam isolation valve closure-direct scram (MSIVD), and turbine trip no bypass with flux scram (TTNBPF), which are listed in Appendix A of ELTR1, will not be analyzed in the reload analysis.

(a) Pressure Regulator Downscale Failure Based on the review and approval of the maximum extended operating domain (MEOD) flexibility options for BWR/6 plants, the staff agrees that the PRDS is not an AOO for a BWR/6 plant such as CPS. Therefore, the staff concludes that this event need not be analyzed for CPS.

(b) Main steam isolation valve closure direct scram The MSIVD is mitigated by the direct scram signal on valve position.

The staff concludes that the MSIVD analysis need not be performed for CPS.

(c) Turbine Trip, Bypass failure, with Scram on High Flux TTNBPF was included in Table E-1 of ELTR1 to confirm that the MSIV closure with flux scram event is the worst case. The staff concludes that the MSIV closure event is more limiting, and, therefore, the TTNBPF event need not be performed for CPS.

The licensee performed a computer calculation of only two transients with an equilibrium core, the MSIV closure event with flux scram (discussed in Section 3.2) and the LOFW event.

The LOFW transient was analyzed for EPU using the methods in Section 5.3.2 of ELTR1.

During a LOFW transient, assuming an additional single-failure (loss of RCIC or HPCS), reactor vessel level is automatically maintained above the TAF by the RCIC or HPCS system without any operator action. Increased decay heat from the EPU results in a lower reactor water level for loss of water level events. Also, slightly more time is required for the automatic systems to restore water level. Operator action time is needed only for long-term plant shutdown. After water level is restored, the operator manually controls the reactor water level, reduces reactor pressure, and initiates RHR shutdown cooling. These sequences do not require any new

operator actions. Therefore, the operator actions for a LOFW transient do not significantly change for EPU. The analysis was performed using the NRC-approved SAFER code and the licensee verified the capability of RCIC and HPCS systems. Based on the information submitted and the responses to the RAIs, the staff concludes that the LOFW transient analysis result is acceptable for EPU operation.

All of the transients listed in Table E-1 of ELTR1 were considered. The limiting overpressure transient was analyzed as defined by NEDE-24011P-A General Electric Standard Application for Reactor Fuel, GESTAR dated August 13, 1999, and supplemented October 22, 1999, and by ELTR1.

The limiting events are defined in GESTAR and the core reload analysis will be based on GESTAR. The other events listed in Table E-1 of ELTR1 do not establish the OLMCPR, based on experience and the characteristics of these events, and therefore are not analyzed to establish this limit.

As described above, most of the transients listed in Appendix E of ELTR1 will be analyzed as part of the reload analysis before the EPU operation.

Based on the information submitted and the staff audit, the staff finds this approach acceptable for CPS.

9.2 Design-Basis Accidents 9.2.1 Background ELTR1 provides generic guidelines for justifying operation at up to a 20 percent increase in core thermal powerThe guidelines for the performance of radiological evaluations are contained in Section 5.4 and Appendix H of ELTR1. Section 5.4 provides that the magnitude of the potential radiological consequences of a DBA is proportional to the quantity of fission products released to the environment. This release is a product of the activity released from the core and the transport mechanisms between the core and the effluent release point. In general, the inventory of fission products in the fuel rods, the creation of radioactive materials outside of the fuel by irradiation, and the concentration of radioactive material in the RCS is directly proportional to the RTP. Thus, an increase in the RTP can be expected to increase the inventory of radioactive material that is available for release. The previously analyzed transport mechanisms could be affected by plant modifications associated with the power uprate, potentially resulting in a larger release rate. The ELTR1 provides that the EPU application will provide justification that current radiological consequences are still bounding and within applicable criteria, or will provide reanalysis of any areas adversely affected by the proposed uprate.

Appendix H of the ELTR1 describes the generic bases to be used in the generic radiological evaluations or in reanalysis of any areas adversely affected by the EPU.

Appendix H of the ELTR1 provides that existing calculations as shown in the current USAR is valid and that, with few exceptions, the postulated results are changed by the magnitude of the change in radiation source inventory. The increased consequences can be resolved on a ratio of the sources basis. Exceptions are associated with changes in radioactive material transport assumptions and methods caused by modifications to the plant pursuant to the uprate. The appendix provides that new calculations will be carried out only as necessary. There are some design-basis events, such as a main steam-line break, which release the radioactive materials in reactor coolant to the environment. Since the evaluations for these events utilize the reactor coolant concentrations established by the TSs, the consequences of these events will not change unless the mass of coolant lost changes.

Staff positions on ELTR1 provides that the existing calculations found in the safety analysis report should remain valid as a result of the EPU and that the doses will be increased by the magnitude of the change in the source term. The staff noted that the increased doses must meet the dose acceptance criteria in the plants licensing basis and that the licensee will demonstrate assumptions and conditions stated in the ELTR1 are met. If these assumptions are not met, applicants will be expected to recalculate the affected radiological analyses.

ELTR2 presents specific evaluations of areas of licensing review that are generically applicable to some or all of the BWR product lines. Section 5.3.2.2.3 of the ELTR2 addresses the EPU impact on radiological consequences of DBAs and provides information comparable in scope and detail to that provided in Section 5.4 and Appendix H in ELTR1.

9.2.1.1 Plant-Specific Evaluation Section 9.3 in the PUSAR addresses the impact of the EPU on the previously analyzed radiological consequences of DBAs for CPS. This section is based on the guidelines in Section 5.4 of ELTR1. The plant-specific radiological assessments were evaluated at 102 percent of the proposed rated thermal power, consistent with the guidance of RG 1.49, Power Levels of Nuclear Power Plants. Based on the information submitted and the responses to the RAIs, the staff concludes that the power level used for plant-specific evaluations is acceptable.

9.2.1.2 Development of Plant-Specific Scaling Factors The core fission product inventory used in performing the existing, pre-EPU, radiological consequence analyses was generated by the reactor vendor. The licensee had a recalculation performed of the core fission product inventory for the post-EPU core using the ORIGEN2 code.

In recalculating the fission product inventory, AmerGen has addressed the ELTR1 guidelines regarding the assessment of the impacts of the EPU and higher burnup fuel impact on

radionuclide composition and inventory. The NRC staff compared the pre- and post-EPU inventories, normalized in units of Ci/MWt, and noted only a slight change in the values for those radionuclides that are the predominant contributors to dose. The staff also compared the post-EPU values against Ci/MWt values developed by the staff and observed excellent agreement.

In support of Amendment No. 127, the licensee at the time, Illinois Power Company, reanalyzed the radiological consequences of a DBA LOCA. The staff performed a review of the assumptions used and found them acceptable. This was documented in a SE dated April 25, 2000. For the present action, AmerGen re-performed the analysis changing only the core inventory to reflect the increased power level. AmerGen then used the ratio between the before-and-after whole body and thyroid doses to adjust the pre-EPU doses for the control rod drop accident (CRDA) and the fuel handling accident (FHA). The transport of radioactive materials within the plant systems and in the environment differs from accident to accident, suggesting that scaling factors determined for the LOCA may be inappropriate for other accidents. However, since the parameters that affect the transport are unchanged pre- and post-accident, the relative change in the LOCA dose results represents only the change in core inventory. Since the transport parameters are also unchanged pre- and post-accident for the FHA and CRDA, the scaling factor for the LOCA is appropriate for use in these cases as well.

Based on the information submitted, the responses to the RAIs, and the staff audit, the staff concludes that the method used to determine the scaling factors is appropriate and consistent with the staff-approved ELTR1 and ELTR2 and the conditions identified in the associated staff SE.

9.2.1.3 Application of Scaling Factors to Pre-EPU Analyses The licensee considered the plant-specific EPU impact on the following DBA accidents: LOCA, CRDA, FHA, and MSLB outside containment. For the first three accidents, the EPU does impact the fission product inventory available for release. As such, the radiological consequences postulated in prior analyses were multiplied by the plant-specific scaling factors described above.

As there were no plant modifications that would impact the transport of radioactive material to the environment so no further adjustments or reanalyses were necessary. The results of these analyses are tabulated in Table 1.

For the MSLB accident, the analyses assume that the reactor coolant specific activity is at the design basis value identified in the USAR. Since the design basis reactor coolant activity is considered bounding for EPU, these analyses are not affected by the EPU. The EPU does not affect transport assumptions used in the MSLB analyses. Specifically, the licensee has proposed to operate at the same reactor dome pressure used pre-EPU for post-EPU operations.

While the post-EPU normal operational steam flow will be greater, the flow restrictors in the steam lines establish the maximum flow rate at which steam will flow during MSLB conditions.

The pre-EPU analyses were based on the maximum flow rate, which is unaffected by the EPU.

As a result of these considerations, the EPU has no impact on previously analyzed consequences of the MSLB event.

The CPS USAR Chapter 15 addresses a larger spectrum of accidents with regard to radiological consequences than were addressed in this submittal. Many of these accidents were dispositioned with reference to the bounding MSIV closure analysis (USAR 15.2.4.5). However, there were also analyses addressing the feedwater line break (USAR 15.6.6.5) and the main condenser offgas treatment system failure (USAR 15.7.1.1). The staff requested additional

information regarding these accidents. In its response, the licensee noted that the feedwater line break was not considered to be a DBA and that the analysis in USAR 15.6.6.5 was a realistic case analysis that was based on an arbitrary source term that is independent of the RTP. The analysis results would not be impacted by the EPU.

With regard to the MSIV analysis, it is assumed that the MSIVs go shut and the plant is cooled down by blowing down steam to the suppression pool. The source term assumed to be equivalent to the TS value for RCS specific activity is unaffected by the EPU. However, the amount of heat to be rejected increases for this event. The licensee assumed that the increase in heat will correspond to the 20 percent increase in RTP and has increased the pre-EPU doses for an MSIV closure event by 20 percent. The results of this calculation are within the 10 CFR Part 20 limits for the general public for routine releases.

With regard to the main condenser offgas system failure, the analysis assumes that the system is operated at 100,000 uCi/sec noble gas after 30 minute decay for a period of 11 months, and one month of operation at 350,000 uCi/sec after 30 minutes of decay. The 350,000 uCi/sec value bounds the TS Section 3.7.5 value of 289,000 uCi/sec after 30 minutes of decay. The 100,000 uCi/sec value is the original design-basis value used for normal operation releases.

Section 8.4 of the PUSAR indicates that the offgas rates for current operations are well below the original design-basis. Although an increase in activity could be experienced due to the EPU, the magnitude of the activity is controlled by the TS. Therefore, there is no change postulated due to the EPU. The results of this calculation are shown on Table 1.

Based on the information submitted and the responses to the RAIs, the staff concludes that dose consequences are acceptable for EPU impact on the accidents discussed above.

9.2.2 Control Room Doses The licensee evaluated the consequences of the EPU on control room habitability for the DBA LOCA as part of its recalculation of the accident. The EPU impact on control room doses for the other accidents was not provided in the initial submittal. Although the amount of fission products available for release is greater for an LOCA than for the remaining DBAs, there are other accident parameters that could cause the dose from a lesser DBA to be limiting with regard to control room habitability. Therefore, the staff requested additional information on the EPU impact for the remaining accidents. In its response, the licensee noted that all releases at CPS are assumed to be ground level releases and that the control room ventilation emergency filtration system is initiated on high radiation readings at the control room intake for all accidents.

The licensee used the activity released to the environment for each accident as benchmarks, eliminating the need to evaluate differences in release path filtration and other mitigation. The atmospheric dispersion for the different release points is the only remaining significant difference between the DBAs. For each DBA, the magnitude of the differences in activity released to the environment by each DBA and that from the LOCA were sufficient to compensate for differences in atmospheric dispersion for the release points applicable to each DBA. Although the staff believes it is preferable that the control room doses are calculated directly for each DBA, the staff concludes that the LOCA is the limiting DBA with regard to control room habitability.

The NRC staff is currently evaluating, on a generic basis, deficiencies in the design, operation, and maintenance of control room habitability systems and is pursuing appropriate regulatory action. The staff expects to issue a GL and regulatory guidance on these issues in early 2002.

One of the primary concerns identified by the staff involves unsubstantiated assumptions at

many plants regarding the amount of unfiltered inleakage to the control room envelope during accident conditions. Due to the magnitude of the potential increases in post-EPU doses, the staff reviewed the CPS EPU submittal to determine whether there was reasonable assurance that the CPS control room habitability systems could perform their design function to provide plant operators a habitable environment in which to take actions necessary to operate the plant in a safe manner.

Integrated unfiltered inleakage testing has not been reported for CPS. In response to staff RAIs, the licensee provided extensive information concerning the validity of the assumed inleakage at CPS. When the CPS control room ventilation is in the emergency mode, an air makeup flow of 3000 cfm is passed through the 99 percent efficient charcoal filter unit and the 70 percent efficient supply filter before being exhausted into the control room. The return fan recirculates 61,000 cfm which mixes with the filtered 3000 cfm makeup flow at the suction of the supply filter prior to being exhausted into the control room. The return fan suction duct is located outside of the control room envelope and operates at the negative pressure relative to its exterior environment. The licensee assumes that contaminated air leaks into this duct at a rate of 650 cfm. TS surveillance requirement 3.7.3.5 confirms this assumption every 18 months. TS SR 3.7.3.6 confirms the ability of the ventilation system to maintain a positive pressure of 0.125 inch water gauge with a makeup flow rate less than or equal to 3000 cfm. The licensee also assumes a 10-cfm unfiltered infiltration into the control room.

While the staff resolution of the generic control room habitability issue may result in integrated boundary integrity testing, based on the information submitted and the responses to the RAIs, the staff concludes that the ongoing CPS surveillance program for positive pressurization in conjunction with the surveillance test program for the negative pressure duct work outside the control room boundary provide reasonable assurance that the EPU will not have an adverse impact on control room habitability. The staffs acceptance of the licensees unfiltered inleakage conclusions does not foreclose any future generic regulatory actions that may become applicable to CPS in this regard.

9.2.3 Conclusion The NRC staff reviewed the assumptions, inputs, and methods used to assess the radiological impacts of the proposed EPU at CPS. In doing this review, the staff relied upon information placed on the docket, staff experience in doing similar reviews, the staff SE for CPS Amendment 127, and the staff-accepted ELTR1 and ELTR2 topical reports. The staff finds that the licensee used analysis methods and assumptions consistent with the conservative guidance of ELTR1 and ELTR2. The staff compared the dose estimates to the applicable criteria. The staff concludes, with reasonable assurance, that the licensees estimates of the exclusion area boundary, low population zone, and control room doses will continue to comply with 10 CFR Part 100 and 10 CFR Part 50, Appendix A, GDC-19, as clarified in NUREG-0800 Sections 6.4 and

15. Therefore, the staff concludes that operation at the proposed EPU RTP is acceptable with regard to the radiological consequences of postulated DBAs.

9.3 Special Events 9.3.1 Anticipated Transient Without Scram An ATWS is defined as an AOO with failure of the reactor protection system to initiate a reactor scram to terminate the event. The requirements for ATWS are specified in 10 CFR Part 62.

The regulation requires BWR facilities to have the following mitigating features for an ATWS event:

(1) A SLC system with the capability of injecting a borated water solution with reactivity control equivalent to the control obtained by injecting 86 gpm of a 13 weight percent sodium pentaborate decahydrate solution at the natural boron-10 isotope abundance into a 251 inch inside diameter reactor vessel; (2) an alternate rod insertion (ARI) system that is designed to perform its function in a reliable manner and that is independent from sensor output to the final actuation device; and (3) equipment to trip the reactor coolant recirculation pumps automatically under conditions indicative of an ATWS.

BWR performance during an ATWS is also compared to the criteria used in the development of the ATWS safety analyses described in NEDO-24222, Assessment of BWR Mitigation of ATWS, Volume II (Ref. 13). The criteria include (a) limiting the peak vessel bottom pressure to less than the ASME Service Level C limit of 1500 psig, (b) ensuring that the peak cladding temperature remains below the 10 CFR 50.46 limit of 2200 degrees Fahrenheit, (c) ensuring that the cladding oxidation remains below the limit in 10 CFR 50.46, (d) limiting peak suppression pool temperature to less than 185 degrees Fahrenheit (the containment design temperature),

and (e) limiting the peak containment pressure to a maximum of 15 psig (containment design pressure).

The ATWS analyses assume that the SLC system will inject within a specified time to bring the reactor subcritical from the hot full power and maintain the reactor subcritical after the reactor has cooled to the cold-shutdown condition. For every core reload, the licensee evaluates how plant modifications, reload core designs, changes in fuel design, and other reactor operating changes affect the applicability of the ATWS analysis of record.

The licensee stated that CPS meets the ATWS mitigation requirements defined in 10 CFR 50.62, because (a) an ARI system is installed, (b) the boron injection capability is equivalent to 86 gpm, and (c) an automatic ATWS-recirculation pump trip (RPT) has been installed. Section L.3 of ELTR1 discusses the ATWS analyses and provides a generic evaluation of the following limiting ATWS events in terms of overpressure and suppression pool cooling: (a) MSIV closure, (b) pressure regulator failure to open (PRFO), (c) loss of offsite power (LOOP), and (4) inadvertent opening of a relief valve (IORV). The licensee performed the ATWS analyses for a representative core design at the EPU operating condition to demonstrate that CPS meets the ATWS acceptance criteria. To benchmark the plant response to limiting ATWS events at EPU conditions, the licensee also performed the ATWS analyses for the current RTP.

An ATWS event under EPU conditions, has the same symptoms and requires the same operator actions as under pre-EPU conditions. The plant operating staff will be able to identify and respond to an ATWS event as under the current power level. The CPS ATWS analysis assumed the same timing of operator actions. Boron injection was assumed to start at the boron initiation temperature (BIIT) or 2 minutes after the ATWS trip point (i.e, low reactor water level or high reactor pressure), whichever is later. In both current power conditions and EPU conditions, the SLC pumps are started at 2 minutes after the trip point. The times to reach hot shutdown are similar in both cases.

Table 9-6 of the PUSAR lists the key input parameters used in the ATWS analyses and the corresponding results (peak vessel bottom pressure, PCT, peak suppression pool temperature, and peak containment pressure). The licensee stated that the results of the ATWS analyses meet the ATWS acceptance criteria.

Based on the information submitted and the responses to the RAIs, the staff concludes that CPS meets the ATWS rule stipulated in 10 CR 50.62 and that the results of the ATWS analyses for EPU operation meet the ATWS acceptance criteria. Future reload evaluations will confirm that the plant response to an ATWS event, based on the cycle-specific conditions, will continue to meet the ATWS acceptance criteria. Therefore, the staff concludes that the licensees response concerning an ATWS event for EPU operation is acceptable.

9.3.2 Station Blackout The licensee re-evaluated Station blackout (SBO) using the guidelines of NUMARC 87-00. The plant responses to and coping capabilities for an SBO event are affected slightly by operation at the EPU level, due to the increase in the decay heat. There are no changes to the systems and equipment used to respond to an SBO, nor is the required coping time changed. The licensee evaluated the following areas containing equipment necessary to mitigate the SBO event:

1. main control room

2. battery and inverter rooms

3. MCC 1A and 1B areas (125 Vdc distribution panels)

4. HPCS room

5. RCIC pump room

6. 1A EDG room

7. main steam tunnel

8. drywell and suppression pool The increase in the calculated suppression pool temperature due to the EPU may result in a small temperature increase in areas such as the RCIC room. The HPCS room is unaffected because the Division III emergency diesel generator powers the room cooling. The temperatures in the control room, motor-control-center areas, battery rooms and inverter rooms are not affected by the EPU. SBO containment conditions are enveloped by the peak temperatures and pressures analyzed for the DBA LOCA. The electrical power requirements during a SBO are not affected by the EPU. The battery loading is bounded due to conservatism in the existing SBO calculations. Analysis shows that the suppression pool temperature may exceed the EPU-based heat capacity temperature limit (HCTL) approximately three hours into the SBO event, but remains below the pool design temperature. The suppression pool temperature is brought below the HCTL upon initiation of RHR suppression pool cooling with the restoration of divisional ac power at four hours. Based on the information submitted and the responses to the RAIs, the staff concludes that CPS continues to meet the requirements of 10 CFR 50.63 and maintains sufficient coping capability and coping time at the EPU condition under SBO.

10.0 ADDITIONAL ASPECTS OF EXTENDED POWER UPRATE 10.1 High-Energy Line Breaks The increase in the steam and feedwater flows resulting from a slight increase in downcomer

subcooling due to plant operations at the proposed uprate power level will cause a small increase in the mass and energy release rates following certain high energy line breaks (HELB).

This results in a small increase in the subcompartment pressure and temperature profiles. The licensee stated that the HELB analysis evaluation was made for all systems (e.g., main steam system, feedwater system, reactor core isolation cooling system, etc.) evaluated in the USAR.

The evaluation shows that the affected buildings and cubicles that support the safety-related functions are designed to withstand the resulting pressure and thermal loading following a HELB. The equipment and systems that support a safety-related function are also qualified for the environmental conditions imposed upon them.

Based on its review of the licensees rationale and evaluation, and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that the existing analysis for HELB remains bounding and is acceptable for plant operations at the proposed uprate power level.

10.2 Moderate Energy Line Breaks The licensee performed an evaluation and concluded that the original moderate energy line break analysis is not affected by plant operations at uprate power level.

Based on its review of the licensees rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that the existing analysis for moderate energy line breaks remains bounding and is acceptable for plant operations at the proposed uprate power level.

10.3 Equipment Qualification 10.3.1 Electrical Equipment The licensee evaluated the equipment environmental qualification (EQ) for safety-related electrical equipment located inside the containment for the expected EPU normal plant operation environment, and for a DBA, MSLB and LOCA conditions and their resultant temperature, pressure, humidity, and radiation consequences. The current accident conditions for temperature and pressure are modified for the EPU conditions. The current radiation levels under normal plant conditions do not increase except in the vicinity of the reactor. The licensees EQ review for the EPU conditions identified some equipment located within the containment, which could potentially be affected by the higher temperature and radiation levels (accident conditions). The qualification of this equipment will be resolved by reanalysis, by refined radiation calculations, by reducing qualified life, by adding new equipment, or by replacing the existing equipment with qualified equipment. The staff requested the licensee provide additional information on the program addressing EQ. By letter dated December 13, 2001, the licensee stated that the program ensures that they perform EQ impact assessments for all the impacted EQ calculations to ensure that the EPU parameters have no impact on the safety-related function of equipment before operation at uprated conditions.

The licensee evaluated EQ for safety-related electrical equipment located outside the containment based on a MSLB in the pipe tunnel, or other HELB, whichever is limiting for each plant area. The accident temperature, pressure and humidity conditions resulting from a LOCA or HELB do not change with the uprated power level, but some HELB pressure profiles increase by a small amount. The licensees EQ review for the EPU conditions identified some equipment

located outside the containment that could be affected by the EPU conditions. The qualification of this equipment will be resolved by reanalysis, by refined radiation calculations, by reducing qualified life, by adding new equipment, or by replacing the existing equipment with qualified equipment. The staff was concerned about the addition of the additional loads that would affect GDC 17 compliance. By letter dated November 30, 2001, the licensee responded that due to anticipated grid conditions and the increased plant auxiliary loading due to power uprate, the RAT will be replaced during refueling outage C1R09, concurrent with the second stage of uprate.

The staff finds that completion of the above modifications in accordance with the licensees EQ program will result in the qualification of the safety-related electrical equipment conforming to 10 CFR 50.49. Therefore, based on its review of the licensee's rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that the licensee's approach to qualification of safety-related electrical equipment for EPU operation is acceptable.

10.3.2 Mechanical Equipment With Non-Metallic Components Plant operations at the proposed uprate power level increases the normal process temperature.

The normal and accident radiation levels also increase slightly. The licensee performed an evaluation of the effects of plant operations at the proposed uprate power level on the non-metallic components of safety-related mechanical equipment and identified some equipment potentially affected by the slight increases in temperature and radiation levels. The licensee stated that the qualification of such equipment is resolved: by reanalysis; by refined radiation calculations (location specific); by slightly reducing qualified life; or by performing additional tests/analyses to support qualification.

Based on its review of the licensee's rationale and the experience gained from its review of power uprate applications for similar BWR plants, the staff concludes that the licensee's approach to qualification of mechanical equipment with non-metallic components for EPU operation is acceptable.

10.3.3 Mechanical Components Design Qualification 10.3.3.1 Equipment Seismic and Dynamic Qualification The licensee evaluated equipment qualification for the power uprate condition. The plant-specific dynamic loads such as SRV discharge and LOCA loads (including pool swell, condensation oscillation, and chugging loads) that were used in the equipment design will remain unchanged as discussed in Section 4.1.2 of NEDC-32989P, since these loads are based on the range of test conditions for the design-basis analysis at CPS, which are bounding for the power uprate condition.

Based on its review of the information submitted and the responses to the RAIs, the staff concludes that the original seismic and dynamic qualification of safety-related mechanical and electrical equipment is not affected by EPU conditions for the following reasons:

1. The seismic loads are unaffected by the power uprate;

2. No new pipe break locations or pipe whip and jet impingement targets are postulated as a result of the uprated condition;

3. Pipe whip and jet impingement loads do not increase for the power uprate; and

4. SRV and LOCA dynamic loads used in the original design-basis analyses are bounding for the power uprate.

Therefore, based on the above, the staff concludes that the licensees approach to seismic and dynamic qualification of equipment for EPU operation is acceptable.

10.3.3.2 Safety-Related SRV and Power-Operated Valves The licensee performed the over-pressure protection analysis at the uprated power condition using the upper tolerance limits of the valve set points. The peak RPV dome pressure was calculated at 1298 psig. This peak steam pressure remains below the ASME allowable of 1375 psig (110 percent of design pressure) and safety-related SRV operability is not affected by the proposed power uprate. Furthermore, the maximum operating reactor dome pressure remains unchanged for the CPS power uprate. Consequently, the licensee concluded that the SRV setpoints and analytical limits are not affected by the proposed power uprate, and that the SRV loads for the SRV discharge line piping will remain unchanged. The staff agrees with the licensees conclusion that the SRVs and the SRV discharge piping will continue to maintain their structural integrity and provide sufficient over-pressure protection to accommodate the proposed power uprate.

The licensee evaluated the effect of the power uprate on the capability of plant mechanical systems, including safety-related pumps and valves, to perform their safety functions at CPS.

For example, safety-related pumps were determined to be adequately designed for operation at power uprate conditions, because of the minor impact to system parameters for safety-related equipment, including ECCS. The licensee also evaluated the safety-related motor-operated valves (MOVs) within the scope of the program established in response to GL 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance. The NRC staff completed a detailed review of the GL 89-10 program at CPS through a series of plant inspections. The staff also accepted the licensees MOV program in response to GL 96-05, Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves, through review of information submitted by the licensee. In evaluating the impact of the power uprate on the MOV program at CPS, the licensee reviewed fluid temperatures and pressures resulting from the power uprate, and plant calculations for MOV setpoints to address any changes in system and environmental conditions. The licensee determined reduced capability margin for MOVs that apply the post-accident transient pressure curve, MOVs that operate against the maximum differential pressure between the drywell and containment, and MOVs that operate in certain high ambient temperature areas. However, all MOVs were found to have sufficient operability margin. The licensee reported that the valve factors used to predict the operating thrust requirements in the MOV calculations were not adjusted, because fluid differential pressures and temperatures are not significantly affected by the power uprate. The licensee evaluated the impact of the power uprate on air-operated valves and safety and relief valves through its review of plant systems.

No modifications were identified to be necessary for the performance of these valves under EPU conditions. The licensee evaluated the impact of the power uprate on its response to GL 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves. The licensee determined that the gate valves evaluated in response to GL 95-07 would not be adversely affected by potential pressure locking or thermal binding, because the pressures assumed in the GL 95-07 calculations bound the power uprate conditions. Based on the staffs previous review of the licensees programs in response to GLs 89-10, 95-07, and 96-05, and the current review of the information submitted by the licensee describing the scope, extent, and

results of the evaluation of safety-related pumps and valves at CPS, the staff concludes that the effect of EPU operation on the capability of safety-related pumps and valves is acceptable.

The licensee stated in the letter dated December 7, 2001, that the containment design temperature used for the evaluation of GL 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Condition, was not affected by the proposed power uprate. Therefore, based on the information submitted and the responses to the RAIs, the staff concludes that EPU operation is acceptable with regard to potential over-pressurization of isolated piping segments.

10.4 Testing 10.4.1 Generic Test Guidelines for GE BWR EPU Section 5.11.9 of ELTR1 provides the general guidelines for EPU testing and has been accepted by the NRC as the review basis for EPU amendment requests. Per the report, a testing plan will be included in the EPU licensing application which will include the pre-operational tests for systems or components which have revised performance requirements. Guidelines to be applied during the approach to and demonstration of uprated operating conditions are provided in Section L.2 Guidelines for Uprate Testing.

10.4.2 CPS Testing Plan The licensee stated that they will conduct a limited subset of the original startup tests at the time of implementation of the EPU. The tests will be conducted in accordance with the NRC-approved generic EPU guidelines of ELTR1 to demonstrate the capability of plant systems to perform their designed functions under uprated conditions.

The tests will be similar to some of the original startup tests described in the CPS USAR and will be conducted using established controls and procedures which have been revised to reflect the uprated conditions. The licensee provided the following power increase test plan in Section 10.4 of NEDO-32989:

a. Surveillance testing will be performed on the instrumentation that requires re-calibration for the EPU in addition to the testing performed according to the plant TSs schedule.

b. Steady-state data will be taken during power ascension beginning at 90 percent original licensed thermal power and continuing at each EPU power increase increment so that system performance parameters can be projected through the EPU power ascension.

c. Power increases beyond the previous rating will be made along an established flow control/rod line in increments of less than or equal to 5 percent power.

Steady-state operating data including fuel thermal margin will be taken and evaluated at each step. Routine measurements of reactor and system pressures, flows and vibration will be evaluated from each measurement point, prior to next power increment.

d. Control system tests will be performed for the feedwater/reactor water level controls and pressure controls. These operational tests will be made at the

appropriate plant conditions for that test and at each power increment above the previous rated power condition, to show acceptable adjustments and operational capability.

The EPU tests are identified in a test specification containing the associated acceptance criteria and the appropriate test conditions. All testing will be performed in accordance with written procedures. Original performance criteria and modified performance criteria updated since the initial test program are utilized for supporting EPU power ascension testing. An exception to ELTR1 Is that CPS does not intend to perform the recommended large transient tests. The staffs evaluation of this exception follows in Section 10.4.3.

10.4.3 Large Transient Tests 10.4.3.1 Background To achieve an EPU, a licensee makes several major modifications to the plant. However, most of the major modifications are made to nonsafety-related secondary plant systems such as the main turbine, generator, and feedwater system. Testing is done in accordance with technical specification (TS) surveillance requirements on instrumentation that is re-calibrated for EPU conditions. A licensees power ascension test plan includes hold points for testing and data collection. Steady-state data will be taken at points from 90% up to100% of the pre-uprated thermal power, so that system performance parameters can be projected for uprate power before the pre-uprated power rating is exceeded. Power increases will be made along an established flow control/rod line in increments of 5% power or less. Steady-state operating data, including fuel thermal margin, will be taken and evaluated at each step. Routine measurements of reactor and system pressures, flows and vibration will be evaluated from each measurement point, prior to the next power increment. Radiation measurements will be made at selected power levels to ensure the protection of personnel.

The proposed CPS EPU results in approximately a 20 percent increase in steam and feedwater flow rates with no increase in reactor dome pressure. It also results in a small operating pressure/temperature decrease at the turbine inlet and increased loading of certain electrical equipment.

In the application submitted to the NRC, the licensee proposed not to perform the large transient tests (MSIV closure and generator load rejection tests similar to those conducted during initial plant startup) included in the ELTR1. ELTR1 includes the MSIV closure test for power uprates greater than 10 percent above any previously recorded MSIV closure transient data and the generator load rejection test for power uprates greater than 15 percent above any previously recorded generator load rejection transient data. In a letter to the staff dated January 15, 2002, the licensee provided justification for not performing these tests and concluded that they are not needed to demonstrate the safety of BWRs implementing EPU with no change in operating reactor dome pressure.

10.4.3.2 Evaluation In evaluating the licensees justification not to perform the two large transient tests, the staff considered: (1) the modifications, if any, made to the plant for an EPU that are related to the two tests, (2) component and system level testing that will be performed either as part of the licensees power ascension and test plan or to meet TS surveillance requirements, (3) past

experience at other plants and (4) the importance of the additional information that could be obtained from performing the two tests with respect to plant analyses.

Large transient testing is normally performed on new plants because experience does not exist to confirm a plants operation and response to events. However, these tests are not normally performed for plant modifications following initial startup because of well established quality assurance and maintenance programs including component and system level post modification testing and extensive experience with general behavior of unmodified equipment. When major modifications are made to the plant, large transient testing may be needed to confirm that the modifications were correctly implemented. However, such testing should only be imposed if it is deemed necessary to demonstrate safe operation of the plant.

The licensee stated that the risk posed by intentionally initiating these transients, although small, should not be incurred unnecessarily and that conducting these tests would cause additional thermal cycles on the unit. Also, the licensee stated that, as part of the EPU, there are no new systems, features or significant additional components being installed to support the increased power level.

The licensee provided information on testing and on events that occurred at previously uprated BWR plants. Tests were performed at a foreign plant to demonstrate modifications made to its system to enable it to successfully avoid a scram during a turbine trip or generator load rejection transient from full power. These tests involved turbine trips at 110.5% ORTP and 113.5% ORTP and a generator load rejection test at 104.2% ORTP. The testing demonstrated the performance of equipment that was modified in preparation for higher power levels. Equipment that was not modified performed as before. The reactor vessel pressure was controlled at the same operating point for all the tests. No unexpected performance was observed except in the fine-tuning of the turbine bypass opening that was done as the series of tests progressed.

These large transient tests at the foreign plant demonstrated the response of the equipment and the reactor response. The observed response closely matched the predicted response from which the licensee concluded that the uprate licensing analyses reflected the behavior of the plant.

The three unplanned transients at BWR plants included two load rejections and a turbine trip subsequent to power uprate. In each case the licensee concluded that no anomalies were seen in the plants response to these events, and the behavior of the primary mitigation systems was as expected. No new plant behavior was observed. Thus, the licensee concluded that large transients, either planned or unplanned, have not provided any significant new information about transient modeling or actual plant response.

The staff agrees that transient tests only challenge a limited set of systems and components and other testing can demonstrate adequate performance for the equipment modified as part of the EPU. Specifically, the staff has reviewed the list of testing of systems/components required by TS and concludes that these tests are sufficient to demonstrate the system and/or component initiation setpoint and performance characteristics.

The staff also considered the importance of the information that could be gained from the transient tests in light of experience to date with EPUs at BWRs. Although the BWR designs are not all identical, the staff considers the experience with EPUs at these plants useful because it provides a measure of how well the analyses can predict the impact of the power uprate and

hardware modifications on equipment response during events. The staff previously reviewed information provided by Exelon Generation Company, LLC, for the Dresden and Quad Cities Nuclear Power Stations EPUs and identified no significant anomalies related to plant safety from tests or events.

The results of the tests under consideration would not be directly comparable to the results of the safety analyses used for licensing plants or granting amendments. In performing safety analyses, licensees use bounding assumptions such as assuming the failure of the most limiting component (e.g., single failure). In addition, when performing licensing analyses, licensees do not rely on non-safety related equipment or anticipatory trips for mitigation. In performing the tests under consideration, the licensee would not be expected to disable the limiting component, non-safety equipment, or anticipatory trips to mimic the safety analysis cases. Therefore, the results of the tests would be much less limiting than those of the safety analyses. Furthermore, because of the availability of the additional equipment (e.g., non-safety related equipment and anticipatory trips), the test case scenarios would be significantly different (e.g., follow different success paths) from the corresponding safety analyses. Therefore, successful large transient testing would not confirm the adequacy of the existing analyses.

The NRC staff also does not consider the information that could be obtained from the large transient tests to be necessary for validation of analytical codes, such as the NRC staff approved ODYN transient modeling code used for the CPS EPU analyses. The basis for this conclusion is that these codes have been validated using test data obtained from numerous test facilities and operational experience in BWRs. The staff agrees that large transient testing is unnecessary for purposes of code validation and that no new information about transient modeling is expected to be gained from performance of the tests.

The guidelines of ELTR1 have been accepted by the NRC staff as the generic review basis for EPU amendment requests. GE LTR NEDC-33004P, Constant Pressure Power Uprate, Revision 1 (Proprietary), dated July 2001, submitted to the staff for review also includes generic guidelines for testing, but has eliminated the recommendation in ELTR1 to perform large transient tests. The staff has previously accepted not performing the large transient tests on a plant-specific basis for Dresden and Quad Cities. Information obtained from the MSIV closure and generator load rejection tests could be useful to confirm plant performance, adjust plant control systems, and enhance training material. However, the staff does not consider the benefits to be sufficient to justify the challenges to the plant and its equipment; the potential risk, although small, associated with performing these tests (i.e., the risk due to potential random equipment failures during the test); and the additional burden that would be imposed on the licensee. The staff also concludes that these tests would not provide new and significant information regarding the adequacy of the safety analyses nor are they required for code validation. Therefore, based on the information submitted, the response to RAIs, and a response from GE associated with the ongoing staff review of NEDC-33004P, the staff concludes that large transient tests need not be performed at CPS.

10.4.4 Conclusion The licensees test plan follows the guidelines of ELTR1 and the staff position regarding individual EPU amendment requests, except for the issue of large transient tests. The staff concludes that the performance of numerous component, system, and other testing in combination with the evaluation of the systems and components and operating experience

discussed above, are sufficient to satisfactorily demonstrate successful plant modifications and performance. Based on the information submitted and the responses to the RAIs, the staff concludes that there is reasonable assurance that the applicants EPU testing program is consistent with the requirements of 10 CFR 50, Appendix B, Criterion XI, Test Control and the recommendations of ELTR1 with the approved deviation of not performing large transient testing, and therefore, is acceptable.

10.5 Risk Implications 10.5.1 Background The staff reviewed the information provided in the licensees original submittal, specifically the probabilistic risk assessment (PRA) section of Attachment E, as supplemented. The staff used the guidance provided in RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, to focus the review of this non-risk-informed submittal. The staffs evaluation of the licensees submittal focused on the capability of the licensees PRA and other risk evaluations (e.g., for external events) to analyze the risks stemming from both the current, pre-EPU plant operations and the proposed post-EPU conditions. The staffs evaluation did not involve an in-depth review of the licensees PRA. This evaluation included a review of the licensees discussions of EPU impacts on core damage frequency (CDF) and large early release frequency (LERF) due to internal events, external events, and shutdown operations. The evaluation also addressed the quality of the CPS PRA, commensurate with its use in the licensees and staffs decision-making processes.

10.5.2 Internal Events The NRC SE on the CPS individual plant examination (IPE) was issued in November 1996 and concluded, based on the staffs Step 1" review, that the licensee had met the intent of GL 88-20, Individual Plant Examination for Severe Accident Vulnerabilities. The CPS internal events PRA has been updated by the licensee several times since the staff review relative to GL 88-20 to reflect the current plant configuration and to reflect the accumulation of additional plant operating history and component failure data.

The licensee evaluated the changes due to EPU implementation for its potential impact on the CPS internal events PRA in the following key areas: initiating event frequency, component reliability, system success criteria, and operator response. Each of these areas are specifically addressed in the following subsections, with the staffs evaluation findings, followed by a description of the overall impacts due to the EPU on the internal events CDF and LERF.

10.5.2.1 Initiating Event Frequency The licensee concluded in their supplemental submittal that the EPU would not significantly impact the initiating event frequencies of their CPS internal events PRA. This conclusion is supported by the fact that no equipment is expected to be operated beyond its design limits or operating ranges as a result of the EPU. In addition, the licensee stated that there have been no modifications to actuation or plant scram logic as a part of the EPU process that could affect the CPS scram frequency and that the instrument setpoint adjustments identified in their original submittal would continue to preserve the existing operating margin from the trip setpoints and therefore, would not be expected to impact the frequency of reactor scrams.

However, the licensee will be making a number of changes to the BOP equipment in support of the EPU. The licensee stated that they performed extensive evaluations of the capabilities of the systems and components that will need to run at higher capacities and that, as needed, components were being replaced or modified to improve their capability and/or reliability.

Examples of the systems and components that were identified as being replaced or modified include:

 Replacement of the main power transformers with transformers that can accommodate the stations increased power output.

 Modification of the isophase bus duct cooling system to provide additional cooling for the bus ducts.

 Upgrading the main generator hydrogen cooling system to accommodate higher power output.

 Replacement of the main turbine rotors and blades to reliably accommodate the increased power output.

 Modification of the last stage buckets of the turbines for the turbine-driven reactor feedwater pumps (TDRFPs) to improve the reliability of the TDRFPs for continuous operation at increased flow.

Due to the numerous BOP modifications, there is the potential in the near-term for burn-in failures (the licensee used the phrase infant mortality to describe the potential short-term increase in failure probability of newly installed equipment). The licensee performed a sensitivity calculation (Sensitivity #1) in which the frequency of the transient without isolation initiating event was increased by 10 percent. This increase in the frequency of reactor trips/transients was used to represent the short-term impact from the burn-in failure stage that might be associated with the numerous BOP changes, especially in those systems related to the power conversion system, that would be implemented in support of the EPU. This sensitivity case indicated that a 10 percent increase in the transient without isolation initiating event frequency would result in a 5.1 percent increase in the base CDF, from a pre-EPU CDF of 1.38E-5/year to a post-EPU CDF of 1.45E-5/year, an increase of 7.0E-7/year. This increased initiating event frequency also resulted in a 7.6 percent increase in the base LERF, from a pre-EPU LERF of 1.45E-7/year to a post-EPU LERF of 1.56E-7/year, an increase of 1.1E-8/year.

The licensee also stated that, independent of the EPU, there has been an effort to reduce the CPS scram frequency by identifying scram-likely situations and equipment configurations and reducing or eliminating these scram potentials. The effects of these scram reduction efforts will be reflected in future updates of the CPS PRA as the transient initiating event frequencies are adjusted based on actual plant operating experience. A reduction in the transient scram frequencies would result in a reduction in plant risk both in the pre-EPU and post-EPU cases, and in the change in risk as well. The licensee did not account for these potential risk reductions.

The staff finds that it is reasonable to conclude that the initiating event frequencies will not change, as long as the operating ranges or limits of the equipment are not exceeded. This is based on the licensee properly implementing the equipment modifications and replacements it

identified in its license amendment submittal. Further, based on the licensees sensitivity calculation, any short-term risk impact from burn-in failures due to the numerous BOP equipment changes is expected to be very small. Finally, the staff notes that, if there are any changes observed in the future in initiating event frequencies, these changes will be identified and tracked under the plants existing performance monitoring programs and processes and will be reflected in future updates of the PRA based on plant actual operating experience.

The staff has not identified any issues associated with the licensees evaluation of initiating event frequencies that would significantly alter the overall results or conclusions for this license amendment. Therefore, the staff concludes that there are no issues with the initiating event frequencies associated with the CPS internal events PRA that would rebut the presumption of adequate protection or warrant denial of this license amendment and that the expectation is that there will be no change in initiating event frequencies as a result of the EPU.

10.5.2.2 Component Reliability The licensee concluded in their supplemental submittal that the EPU would not significantly impact the reliability of equipment and stated in their response to a staff RAI that the long-term reliability of the systems and components is anticipated to be comparable to the existing reliability. These conclusions are supported by the fact that no equipment is expected to be operated beyond its design limits or operating ranges as a result of the EPU. The licensee also stated that they performed extensive evaluations of the capabilities of the systems and components that will need to run at higher capacities and that, as needed, components were being replaced or modified to improve their capability and/or reliability. Further, the licensee stated that the reliability of components used to provide core cooling during post-scram conditions should be unaffected because the systems credited for core cooling were largely unchanged. However, the licensee will be making a number of changes to the BOP equipment in support of the EPU. As previously described in Section 3.1.1, the licensee performed a sensitivity calculation (Sensitivity #1) to represent the short-term impacts from the burn-in failure stage that might be associated with the numerous BOP changes and determined that the risk impact of these BOP changes would be very small.

In their evaluation of the impacts of the EPU, the licensee did change the probability of a stuck-open relief valve (SORV) for ATWS scenarios. This modeling change was not due to a reduction in the reliability of the SRVs, but rather reflects the potential increase in SRV demands (i.e., cycles) during an ATWS at EPU conditions. The probability of a SORV during an ATWS event was increased by approximately 20 percent, from 1.6E-2 to 1.9E-2. The licensee indicated that this increased probability of a SORV during an ATWS event had a negligible impact on CDF.

The staff finds that it is reasonable to conclude that equipment reliability will not change, as long as the operating ranges or limits of the equipment are not exceeded, and that it is reasonable to postulate that the only change in failure probability is the probability of a SORV due to the increased number of cycles that may be demanded of a SRV during an ATWS event. These staff findings are based on the licensee properly implementing the equipment modifications and replacements it identified in its license amendment submittal. Further, based on the licensees sensitivity calculation, any short-term risk impact of the numerous BOP equipment changes due to burn-in failures is expected to be very small. Finally, the staff notes that the licensees component monitoring programs should detect any significant degradation in performance, and

the staff expects these programs to maintain the current reliability of the equipment.

The staff has not identified any issues associated with licensees evaluation of component reliability that would significantly alter the overall results or conclusions for this license amendment. Therefore, the staff concludes that there are no issues with the component reliabilities/failure rates modeled in the CPS internal events PRA that would rebut the presumption of adequate protection or warrant denial of this license amendment and that the expectation is that there will be no change in component reliability as a result of the EPU.

10.5.2.3 Success Criteria The licensee stated in their supplemental submittal that the severe accident scenarios identified in the CPS internal events PRA were reviewed and that the relatively small perturbations due to the EPU would not affect the scenario development or their qualitative engineering insights regarding the adequacy of procedures and systems to accomplish their safety missions associated with preventing core damage. The licensee indicated that they performed thermal-hydraulic calculations using the modular accident analysis program (MAAP) computer code and that they considered the increased heat inputs resulting from implementing the proposed EPU.

Based on the CPS EPU analyses and MAAP runs performed in support of these analyses, the licensee concluded that no changes were identified in the system success criteria for the CPS internal events PRA.

The staff finds that it is reasonable to expect that the system success criteria will not change.

The staff has not identified any issues associated with licensees evaluation of success criteria that would significantly alter the overall results or conclusions for this license amendment.

Therefore, the staff concludes that there are no issues with the success criteria associated with the CPS internal events PRA that would rebut the presumption of adequate protection or warrant denial of this license amendment and that the expectation is that there will be no change in system success criteria as a result of the EPU.

10.5.2.4 Operator Response In a supplemental submittal, the licensee stated that the proposed EPU would reduce the time available for some operator actions, but that these reductions in the available operator response time were generally determined to be small when compared with the total time required to detect, diagnose, and perform the actions.

The licensee identified and reviewed operator actions that had a Fussell-Vesely (F-V) importance measure that was greater than 5.0E-3 or that had an available operator response time that was less than 30 minutes. The licensee stated that they identified 28 operator actions having a high F-V importance measure and an additional 17 operator actions having a short available response time. However, of the operator actions identified using the above criteria, only eight operator actions were determined to warrant re-calculation of their human error probabilities (HEPs). These operator actions include: manually initiating rapid RPV depressurization, starting the SLC system to avoid hotwell depletion or containment overpressure, manually starting a diesel generator (DG) following a failure of the DG to automatically start, bypassing the MSIV isolation to maintain a steam path, and placing a TDRFP back into service after a failure of the motor-driven feedwater pump (MDFWP) to automatically start. Even though the HEPs were changed for these operator actions to reflect the reduction in

the time available to perform these actions, the impact on the PRA results were mostly negligible. The increased HEPs result in only about a 2.9 percent increase in the base CDF, from a pre-EPU CDF of 1.38E-5/year to a post-EPU CDF of 1.42E-5/year, an increase of 4.0E-7/year. Likewise, the increased HEPs result in only a 5.5 percent increase in the base LERF, from a pre-EPU LERF of 1.45E-7/year to a post-EPU LERF of 1.53E-7/year, an increase of 8.0E-9/year.

Since the supplemental submittal did not explicitly identify all 45 operator actions that were determined to exceed the above criteria, the staff requested additional information about specific operator actions that were not identified by the licensee, but that have typically been identified as being impacted by power uprates. Specifically, the licensee was requested to provide additional information regarding operator actions associated with ATWS events in which the operators must perform power/level control, and in which the operators must inhibit the ADS. The ATWS power/level control operator actions were determined not to be affected by the EPU, because the time-dependent diagnosis portion of the HEP for these actions is actually already modeled as part of the SLC initiation operator actions, which were identified and evaluated above. The remaining execution portion of the HEP is not impacted by the decrease in time available due to the EPU. The ATWS operator action to inhibit ADS was identified by the licensee as being impacted slightly by the EPU. The licensee stated that, even though they had inadvertently not discussed this operator action in their supplemental submittal, the HEP change associated with this operator action had been incorporated into the above risk evaluation.

In addition, the staff requested the licensee to provide additional information about the operator action of manually initiating rapid RPV depressurization. The licensee had identified this operator action as being impacted by the EPU, but had represented the action with a single basic event. The staff had expected to see different basic events, with different HEPs, to reflect the differences in the available response times associated with different initiating events. In previously reviewed power uprates, the available response times for this action for ATWS events and some LOCAs were substantially shorter than for transients such as a turbine trip event. The licensee performed a specific sensitivity study to address the impact of using different HEPs for this operator action to reflect different accident conditions. The licensee used the original CPS HEP value for transients, but substituted the HEP values identified in the Quad Cities Nuclear Power Station EPU submittal for the ATWS and LOCA initiating events. Though using the substituted HEPs resulted in an increase in these basic events, their contributions were still sufficiently small to make no difference to the pre-EPU and post-EPU CDFs or to the change in CDF.

To ensure that all potentially risk-important operator actions were identified and evaluated, the staff requested additional information about operator actions that, if assumed failed, would increase the CDF by more than 1E-6/year or the LERF by more than 1E-7/year. The licensee responded that any operator action that was not identified by their criteria (i.e., F-V importance measure greater than 5.0E-3 and available operator response time less than 30 minutes) would result in a negligible risk increase because these actions would represent less than 0.5 percent of the CDF and would be longer-term actions that would not be significantly impacted by the increase in decay heat load that results from implementing the EPU. Even still, the licensee provided a list of those operator actions that, if assumed failed, would increase the CDF by more than 1E-6/year or the LERF by more than 1E-7/year. The licensee indicated that these frequencies translated into a CDF risk achievement worth (RAW) value of 1.06 and a LERF RAW value of 1.7. Applying these additional screening criteria resulted in the identification of

seven additional operator actions, which the licensee evaluated. These operator actions include:

starting the SLC system to avoid suppression pool depletion, venting containment, providing alternate boron injection, lining up vacuum pumps, initiating SPC, and initiating service water injection through the RHR discharge line B. The licensee determined that there were no increases in the HEPs used in the CPS internal events PRA for these operator actions because these actions were determined not to be sensitive to the slight reductions in the time available to perform the actions. For nearly every one of these operator actions there is well over an hour available to diagnose and to perform them, with some having more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> available. For the operator action to line up vacuum pumps, which is the only action identified as having less than one hour available, there is actually more time available under EPU conditions than for the pre-EPU case.

The staff finds that the licensees human reliability analysis application derives HEP values for the identified operator actions that reasonably reflect the reductions in the times available for the operators to perform the necessary actions under the EPU conditions. This staff finding is based on the licensees submitted information, including the related sensitivity studies, that indicate the risk impact resulting from the reductions in the available operator response time due to the EPU for selected operator actions is expected to be very small.

The staff has not identified any issues associated with licensees evaluation of operator actions that would significantly alter the overall results or conclusions for this license amendment.

Therefore, the staff concludes that there are no issues with the licensees human reliability analysis application associated with the CPS internal events PRA that would rebut the presumption of adequate protection or warrant denial of this license amendment.

10.5.2.5 Summary of Internal Events Evaluation Results As stated in the preceding subsections, the licensee indicated that no impacts are expected due to the EPU for initiating event frequencies, component reliability, or success criteria, but potential impacts of the EPU were identified for selected operator actions due to the decrease in available operator response times.

Based on the licensees evaluation, implementing the EPU increases the CPS internal events PRA CDF from the pre-EPU base value of 1.38E-5/year to the post-EPU base value of 1.42E-5/year, an increase of 4.0E-7/year or 2.9 percent. The majority of the change in risk is stated as coming from the loss of coolant inventory control accident scenarios due to the increase in the HEP for the operator action to perform RPV emergency depressurization. The remainder of the change in risk is stated to be due primarily to ATWS scenarios due to the increase in the HEPs associated with the operator actions to initiate the SLC system.

The Level 2 analysis calculates the containment response under postulated severe accident conditions and provides an assessment of the containment adequacy. The slight changes in accident progression timing and decay heat load are stated by the licensee to have negligible or only minor impacts on the containment safety functions, such as containment isolation, ex-vessel debris coolability, and ultimate containment strength. The licensee states that the systems that perform these functions continue to maintain their capability and that the event times for associated operator actions remain long even with an increase in decay heat because of the Mark III containment design. The EPU change in power represents a relatively small change to the containment failure frequency under severe accident conditions. Carrying the

changes to the Level 1 analysis (i.e., core damage scenarios) as an input to the Level 2 analysis, the licensee states that the EPU increases the CPS internal events PRA LERF from the pre-EPU base value of 1.45E-7/year to the post-EPU base value of 1.53E-7/year, an increase of 8.0E-9/year or 5.5 percent.

In response to a staff RAI, the licensee provided lists of the contributors, by initiating event, to CDF and LERF for both the pre-EPU and post-EPU evaluations. The dominant contributors to CDF are identified by initiating event as: loss of the reserve auxiliary transformer (about 30 percent), transient without isolation (about 17 percent pre-EPU and 19 percent post-EPU), loss of offsite power (about 17 percent pre-EPU and 16 percent post-EPU), transient with isolation (about 8 percent pre-EPU and 7 percent post-EPU), and loss of instrument air (about 7 percent).

The dominant contributors to LERF are identified by initiating event as: interfacing systems LOCA (ISLOCA) in the SDC system (about 45 percent pre-EPU and 43 percent post-EPU),

ISLOCA in the feedwater system (about 38 percent pre-EPU and 36 percent post-EPU),

transient without isolation (about 5 percent pre-EPU and 11 percent post-EPU), and loss of the RAT (about 7 percent pre-EPU and 6 percent post-EPU). Although some fractional/percentage contributions are slightly reduced, their absolute values remain the same or may even increase slightly. The reduced fractional/percentage contributions occur to offset the larger increases of other contributors, such as the transient without isolation initiating event, which is the only initiating event that has an increased contribution to both CDF and LERF. These lists show that the dominant contributors do not change as a result of the EPU, even though their individual contributions may change slightly.

In addition to their base evaluation, the licensee performed a number of sensitivity calculations using different assumed conditions to support their decision-making process. Sensitivity #1 addressed the potential for the near-term burn-in failures resulting from the numerous changes being made as part of the EPU to various BOP equipment. This calculation, which was previously discussed in Sections 3.1.1 and 3.1.2, increased the transient without isolation initiating event frequency by 10 percent. Sensitivity #2 addressed the potential for further reductions in the available time for time-critical operator actions. This calculation reduced the available time for selected operator actions by 20 percent, which is equal to the increase in power level, and then recalculated the associated HEPs for these operator actions. Sensitivity

1. 3 addressed the fact that the CPS internal events PRA models a number of repair and recovery actions (e.g., repair or recovery of pumps or valves), which was identified in the CPS IPE staff SE as an area for which the licensee needed to provide a more sound technical basis. For this calculation, selected repair and recovery actions were set to guaranteed failure and also included the HEP modeling changes identified above for Sensitivity #2. Sensitivity #4 addressed the combined impacts from the three previously described sensitivity cases (i.e., Sensitivity #1,

1. 2, and #3). Sensitivity #5 addressed the potential impact of not adding an automatic start feature to the standby MDFWP, following a trip of an operating TDRFP, as this modification may not be necessary to support EPU.

Sensitivity #4 (i.e., the combined sensitivity case) results indicate that the assumed conditions would result in about a 23 percent increase in the base CDF, from a pre-EPU CDF of 1.38E-5/year to a post-EPU CDF of 1.70E-5/year, an increase of 3.2E-6/year, and also result in a 7.6 percent increase in the base LERF, from a pre-EPU LERF of 1.45E-7/year to a post-EPU LERF of 1.56E-7/year, an increase of 1.1E-8/year. The increase in CDF is primarily due to the removal of operator recovery actions (Sensitivity #3) while the increase in LERF is primarily due to the increase in the transient without isolation initiating event frequency (Sensitivity # 1).

Sensitivity #5 (i.e., not adding the MDFWP automatic start feature) results indicate a modest increase over the base CDF EPU evaluation and no change in the base LERF EPU evaluation.

The results indicate a 6.5 percent increase in the base CDF, from a pre-EPU CDF of 1.38E-5/year to a post-EPU CDF of 1.47E-5/year, an increase of 9.0E-7/year, and also a 5.5 percent increase in the base LERF, from a pre-EPU LERF of 1.45E-7/year to a post-EPU LERF of 1.53E-7/year, an increase of 8.0E-9/year.

After submitting the license application, the licensee decided to not implement the MDFWP automatic start feature. To properly reflect the worst-case conditions, the staff requested that the licensee re-perform Sensitivity #4 without crediting the MDFWP automatic start feature (i.e.,

combining Sensitivity #4 with Sensitivity #5). The results of this evaluation indicate a slight increase in CDF and no change in LERF from that provided above for Sensitivity #4. The results indicate almost a 29 percent increase in the base CDF, from a pre-EPU CDF of 1.38E-5/year to an EPU CDF of 1.78E-5/year, an increase of 4.0E-6/year, and also a 7.6 percent increase in the base LERF, from a pre-EPU LERF of 1.45E-7/year to an EPU LERF of 1.56E-7/year, an increase of 1.1E-8/year.

Even when considering the sensitivity cases, the staff finds that the changes in CDF and LERF from internal events due to the proposed EPU are small and very small, respectively. Therefore, based on the reported analyses and results, the staff concludes that the changes in CDF and LERF from internal events due to the proposed EPU are both well within the acceptance guidelines provided in RG 1.174 and the expectation is that these risk increases will be very small.

10.5.3 External Events The NRC SE on the CPS individual plant examination of external events (IPEEE) was completed in November 2000 and concluded, based on the staffs screening review, that the licensees process was capable of identifying the most likely severe accidents and severe accident vulnerabilities and, therefore, that the licensee had met the intent of Supplement 4 to GL 88-20.

The licensee evaluated the changes due to EPU implementation for its potential impact on the external events analyses, specifically seismic events, fires, and high winds, floods, and other (HFO) external events. Each of these external events is individually addressed in the following subsections, followed by the staffs findings regarding the impact of EPU on external events.

10.5.3.1 Seismic Events For the IPEEE seismic analysis, CPS is categorized as a 0.3g focused-scope plant, per NUREG-1407, Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities. The licensee performed the CPS seismic evaluation in their IPEEE using the Electric Power Research Institute (EPRI) seismic margins assessment (SMA) methodology described in EPRI NP-6041-SL, A Methodology for Assessment of Nuclear Power Plant Seismic Margin. Because the SMA is a deterministic evaluation process, the licensee did not quantify a seismic contribution to plant CDF.

The licensee did not identify any vulnerabilities in the safe shutdown components, systems, and structures in the two shutdown paths selected as part of their IPEEE SMA and the licensee stated that the SMA indicated that the overall high confidence of a low probability of failure

(HCLPF) plant capacity was equal to, or greater than, the review level earthquake (RLE) value of 0.3g. In the staffs SE on the IPEEE SMA, it was noted that the licensee had indicated that there were no immediate operator actions required for the success paths since the systems needed early in response to a RLE are designed for automatic operation and that subsequent operator actions could be performed in the main control room. These subsequent actions are stated as not being time-critical and are proceduralized and trained upon.

Based on their review of the CPS IPEEE, the licensee determined that the SMA results are unaffected by the EPU and that the EPU has little or no impact on the seismic qualifications of the systems, structures, and components. Therefore, the licensee concluded that the EPU has no significant impact on the plant risk profile associated with seismic events.

10.5.3.2 Fires The licensee used the screening approaches and data from the EPRI fire-induced vulnerability evaluation (FIVE) methodology, as described in EPRI technical report TR-100370, and the EPRI fire risk analysis implementation guide, as described in EPRI report 3385-01, to perform the CPS IPEEE fire PRA study. The licensee estimated that the contribution to plant CDF from internal fires was 3.2E-6/year. The staff notes that the plant CDF from internal fires was increased to 3.64E-6/year in response to an IPEEE RAI that resulted in the increase in the heat release rate assumed for electrical cabinet fires, which increased the CDF contribution from the dc/UPS equipment area, fire zone CB3a. The main contributors to the fire-related CDF include fires in the switchgear rooms (about 50 percent), the control room (about 34 percent), and the circulating water screenhouse (about 10 percent). For the EPU PRA impact assessment, the licensee stated that the IPEEE documentation for the fire-induced core damage scenarios and the associated frequency results were reviewed. Based on the results of the internal events PRA evaluation for EPU, which identifies that the predominant contributor to the increase in risk is from operator actions, and a review of the CPS IPEEE, the licensee concluded that the increase in risk contribution associated with fire-induced sequences would be minimal, which is indicated to be less than a 3 percent increase in CDF.

In the IPEEE SE, the staff stated that cables that were previously routed from the Division 2 invertor through the Division 1 cable spreading room and then through the Division 3 switchgear room were to be rerouted. The licensee took credit for these cable routing changes in their IPEEE fire PRA. The effect of this change was reported to result in a 76 percent decrease in plant CDF from internal fires. As part of the staffs review for this license amendment request, the staff sought additional information regarding the status of this cable rerouting effort to confirm the appropriateness of the CPS IPEEE fire analysis. The licensee responded that the cable rerouting was completed per CPS modification FP-091and that the rerouting satisfied the assumptions credited in the IPEEE fire PRA (i.e., these cables no longer pass through the Division 1 cable spreading room or the Division 3 switchgear area). Further, the licensee stated that the rerouted cable does not pass through any new fire zones with the exception that some cabling now passes through the main control room envelope. The risk contributions from the new cable routings are expected to be much less than the original installation and the licensee notes that the main control room has adequate fire suppression features. The main control room fire contribution to plant CDF was given in the IPEEE SE as 1.2E-6/year, which could be increased slightly by considering this additional cabling. However, the licensee stated that this increase would not change the conclusions or overall results associated with the fire analysis:

primarily that the main control room is one of the dominant contributors to the fire risk.

Based on the licensees evaluation, an increase of about 3 percent, which is similar to the increase in the internal events PRA results, would increase the fire CDF by about 1.1E-7/year, to an EPU fire CDF of about 3.75E-6/year. This base CDF and change in CDF are both well within the RG 1.174 acceptance guidelines. Even using the worst case sensitivity results from the internal events PRA (i.e., Sensitivity #4), which estimated an increase in the CDF of about 29 percent, the fire CDF results would still be well within the RG 1.174 acceptance guidelines, with a base EPU fire CDF of about 4.7E-6/year and a change in fire CDF of about 1.1E-6/year.

These results indicate at most only a small increase in risk due to the EPU.

10.5.3.3 High Winds, Floods, and Other External Events For the IPEEE evaluation of HFO external events, the licensee used the progressive screening approach described in NUREG-1407 and GL 88-20, Supplement 4. Since CPS was designed in accordance with the 1975 SRP, the focus of the HFO external events review in the IPEEE was to show conformance with the SRP criteria. For the IPEEE, the licensee performed walkdowns to confirm that no plant changes had occurred since the plant was licensed that would impact the IPEEE review. The licensee did not quantitatively estimate the contribution to CDF from HFO external events since these events were screened out using the NUREG-1407 progressive screening approach. Based on their review of the CPS IPEEE, the licensee concluded that the EPU has no significant impact on the plant risk profile associated with these HFO external events.

10.5.3.4 Conclusion For seismic events, the licensee previously showed in their IPEEE SMA that the CPS plant HCLPF capacity is equal to, or greater than, the RLE value of 0.3g. Based on the fact that the EPU does not impact the IPEEE SMA, the staff concludes that the increase in risk from seismic events due to the proposed EPU is expected to be negligibly small and within the acceptance guidelines provided in RG 1.174.

For the HFO external events, the licensee previously showed in their IPEEE that the CPS plant design conforms to the criteria provided in the 1975 SRP. Based on the fact that the EPU does not impact these HFO external events evaluations, the staff concludes that the increase in risk from HFO external events due to the proposed EPU is expected to be negligibly small and within the acceptance guidelines provided in RG 1.174.

For fires, the staff finds that, even using the worst case sensitivity results from the internal events PRA, the base fire CDF and the change in fire CDF due to the EPU are well within the RG 1.174 acceptance guidelines, which indicate that there is at most only a small increase in risk due to the EPU. The licensee did not update their fire PRA using the most recent CPS internal events PRA model (i.e., instead of the IPE model). However, given that the fire analysis results are well within the RG 1.174 acceptance guidelines, even when using the worst-case sensitivity results, the staff believes that further resolution would not significantly alter the results or overall conclusions of this specific license application.

Therefore, the staff concludes that there are no external events issues that would rebut the presumption of adequate protection provided by the licensee meeting the deterministic requirements and regulations or warrant denial of this license amendment and that the expectation is that there will be negligible impacts from seismic events and HFO external events

and only a small increase in the risks associated with fires as a result of the EPU.

10.5.4 Shutdown Risk The licensee does not have a shutdown PRA model. Instead, the licensee uses the standard safety function based, defense-in-depth approach to shutdown risk. The licensee qualitatively evaluated the potential impacts on shutdown risk due to the EPU, including: initiating events, success criteria, and human reliability analysis. The following qualitative discussion applies to the shutdown conditions of Hot Shutdown (Mode 3), Cold Shutdown (Mode 4), and Refueling (Mode 5). The EPU risk impact during the transitional periods such as from at-power (Mode 1) to Hot Shutdown and from Startup (Mode 2) to at-power are considered subsumed by the at-power CPS internal events PRA.

The impact of the EPU on shutdown risk is similar to the impact on the at-power CPS internal events PRA in that shutdown risk is affected by the increase in decay heat at EPU conditions.

However, the lower power operating conditions during shutdown, such as lower decay heat level and lower RPV pressure, allow for additional margin for mitigation systems and operator actions.

The shutdown risk contributors include the loss of SDC, RPV water makeup/injection failures, and reactivity control failures. The first two functional challenges are similar in nature to the at-power evaluation. The reactivity control functional impact at shutdown is related to mis-loaded fuel or mis-located fuel, as opposed to the failure to scram issues for the at-power evaluation.

The shutdown reactivity control issues are not a function of the EPU and, therefore, their contribution to changes in CDF or LERF was assessed by the licensee to be zero.

Important initiating events for shutdown include RPV draindown and loss of SDC. However, no new initiating events or increased potential for initiating events during shutdown, such as a loss of a decay heat removal (DHR) train, were identified by the licensee for the EPU configuration.

The impact of the EPU on the success criteria during shutdown is similar to the CPS internal events PRA. The increased power level decreases the time to boildown. However, because the reactor is already shut down, the boildown times are relatively long compared to the at-power PRA. The boildown time is approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after shutdown (e.g., time of Hot Shutdown) and approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> at 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after shutdown (e.g.,

time of Cold Shutdown). The changes in the boildown time when comparing the pre-EPU case with the post-EPU case are small fractions of the total boildown time. These small changes in timing have a negligible impact on the calculated HEPs, which are predominately diagnosis errors rather than errors related to completing tasks.

The increased decay heat levels associated with the EPU do not affect the success criteria for the systems normally used to remove decay heat. A single train of SDC is still capable of bringing the reactor to cold shutdown and a single train of fuel pool cooling and cleanup (FPCC) is capable of accommodating the DHR needs of the spent fuel pool, even when considering a full core offload. The increased decay heat loads associated with the EPU impacts the time when low-capacity DHR systems, such as SFPCC and RWCU, can be considered successful alternate reactor DHR systems. At CPS, the time in each outage when various DHR systems are viable is assessed. The RWCU and SFPCC systems would not be included in the defense-in-depth evaluation until the EPU decay heat level was sufficiently low for these systems to be successful alternatives to SDC. The EPU condition delays the time after shutdown when

SFPCC or RWCU may be used as an alternative. However, shutdown risk is dominated during the early time frame soon after shutdown, when the decay heat level is high and both the SFPCC and the RWCU would not be viable reactor DHR systems for either the pre-EPU or the post-EPU conditions. Therefore, the impact of the EPU on the success criteria for the use of the SFPCC and RWCU as alternative reactor DHR systems is negligible.

However, it is recognized that the SDC equipment will be operating continuously for a significant portion of the outage. Therefore, for the post-EPU condition, the SDC would be required to run for a longer time than in the pre-EPU case before other systems with lower heat removal capacity are adequate for reactor DHR. These later times are generally very low risk periods during the outage. Therefore, for these low risk situations when SFPCC or RWCU could provide a backup in the pre-EPU case, they would become marginal in the post-EPU case for some additional period of time. Because the shutdown risk profile is dominated by the risk at the early times in the outage (e.g., 0 days to 10 days), increasing the time when SDC is the only adequate reactor DHR system, during which the risk is low due to low decay heat, has a minor impact on the overall shutdown risk. With the CPS outages moving towards lasting less than 20 days, this change in success criteria has essentially no impact on the integrated shutdown risk.

Other success criteria are marginally impacted by the EPU. The EPU has a minor impact on shutdown RPV inventory makeup requirements because of the low makeup requirements associated with the low decay heat level. The heat load to the suppression pool is also lower than at-power because of the low decay heat level, such that the margins for the SPC capacity are adequate for the EPU condition. The EPU impact on the success criteria for blowdown loads, RPV overpressure margin, and SRV actuation is estimated by the licensee to be minor because of the low RPV pressure and low decay heat level during shutdown.

Similar to the at-power CPS internal events PRA, the decreased boildown time decreases the time available for operator actions. The risk-significant operator actions during shutdown conditions include recovering a failed DHR system or initiating alternate DHR systems.

However, the longer boildown times during shutdown (e.g., hours as opposed to minutes) results in the EPU having only a minor impact on the shutdown HEPs associated with recovering or initiating DHR systems. Because the available time is relatively long and the HEPs are dominated by diagnosis errors, the increased decay heat levels during shutdown for the EPU conditions will not appreciably impact the HEPs.

In addition to the above evaluation of EPU impacts on shutdown risk, the licensee stated that shutdown risk is evaluated on an ongoing basis during an outage using the deterministic outage risk assessment and management (ORAM) software. The ORAM model is based on defense-in-depth for key shutdown safety functions and is not affected by the equipment unavailability values used in the CPS internal events PRA. The ORAM software evaluates the planned plant shutdown configuration, including: systems available, RPV water level, RPV and containment status, and decay heat level. In addition, the ORAM software evaluates the planned outage schedule to ensure that adequate defense-in-depth is maintained throughout the outage. With respect to the EPU, based on the increased decay heat level, ORAM will be able to identify how much longer SDC needs to operate before alternative DHR systems (e.g., SFPCC or RWCU) could be placed in service.

Based upon the above shutdown risk management evaluations, the licensee concluded that the

EPU will have little or no effect on the process controls for shutdown risk management and a negligible impact on the overall ability of the licensee to adequately manage shutdown risk.

Based on a review of the potential impacts on initiating events, success criteria, and the HRA, the licensee concluded that the EPU configuration will have only a minor impact on shutdown risk.

The licensee identified areas associated with shutdown operations that are potentially affected by the implementation of the EPU. However, these impacts are considered minor and do not change the licensees shutdown risk management approach.

The staff has not identified any issues associated with the licensees evaluation of shutdown risks that would significantly alter the overall results or conclusions for this license amendment.

Therefore, the staff concludes that there are no issues with the shutdown operations risk evaluation that would rebut the presumption of adequate protection or warrant denial of this license amendment and the expectation is that the impact on shutdown risk due to the proposed EPU will be negligible, based on the licensees current shutdown risk management process.

10.5.5 Quality of PRA The licensee stated in their supplemental submittal that the quality of the CPS PRA models used in performing the risk assessment for the CPS EPU is manifest in the scope and level of detail of the PRA, the active maintenance of the PRA models and inputs, and comprehensive critical reviews.

The CPS PRA model and documentation has been routinely updated to reflect the current plant configuration following refueling outages and to reflect the accumulation of additional plant operating history and component failure data. The last update was Revision 3a, which was performed in December 2000. This version builds off Revision 3, which was updated in June 2000 prior to the licensees and independent technical reviews.

The licensee stated that the CPS PRA model has benefitted from comprehensive technical reviews. A comprehensive self-assessment of the CPS PRA was performed in July 2000 using the Nuclear Energy Institute (NEI) checklists of the 11 main technical elements that were also used during the peer review certification. Additionally, a peer review of the CPS PRA was performed in August 2000 using the NEI peer review process guidance, Revision A-3, as part of the BWROG peer review/certification program. This peer review covered the eleven main technical elements and sub-elements and provided comments and recommendations to the licensee on specific enhancements (i.e., certification facts and observations) for the CPS PRA.

The licensee stated that they evaluated the impact on the EPU evaluation from the prominent peer review results. The licensee determined that the majority of the significant findings and observations had no impact or only minor impacts on the EPU evaluation results, because they either did not affect the PRA models (e.g., documentation findings) or affected aspects of the PRA model that were not strongly impacted by the EPU. In addition, the sensitivity calculations discussed in Section 3.1 were performed to address the findings that could have a potentially significant impact on the EPU results. The certification findings and observations that were evaluated by the licensee included: the evaluation of dependent HEPs that had not been updated since the previous revision of the PRA, the inclusion of several hardware repair recoveries, and the failure of the CPS PRA to converge quickly to a set CDF value with lowered

truncation levels. In each of these cases, the licensee performed sensitivity calculations to show that there were no significant impacts on the change in CDF due to the EPU. Therefore, the licensee concluded, based on the results of their reviews, that each of the outstanding potential enhancements had no impact on the EPU evaluation.

The quality of the licensees PRA used to support a license application should be commensurate with the role that the PRA results play in the utilitys and staffs decision-making process and should be commensurate with the degree of rigor needed to provide a valid technical basis for the staffs decision. In this case, the licensee is not requesting relaxation of any deterministic requirements for the proposed EPU and the staffs approval is primarily based on the licensee meeting the current deterministic requirements, with the risk assessment providing confirmatory insights. The staffs evaluation of the licensees submittal focused on the capability of the licensees PRA and other risk evaluations (e.g., for external events) to analyze the risks stemming from both the current, pre-EPU plant operations and the post-EPU conditions. The staffs evaluation did not involve an in-depth review of the licensees PRA.

Therefore, to determine whether the PRA used in support of the license application is of sufficient quality, scope, and detail, the staff evaluated the information provided by the licensee in their submittal and considered the review findings on the original CPS IPE and IPEEE, as well as the fact that the CPS PRA has been through an independent peer review.

The NRC SE on the CPS IPEEE was completed in November 2000 and concluded, based on the staffs screening review, that the licensees process was capable of identifying the most likely severe accidents and severe accident vulnerabilities and, therefore, that the licensee had met the intent of Supplement 4 to GL 88-20. Based on the staff review, as discussed in Section 10.5.3 of this SE, the IPEEE appears to be applicable for the EPU conditions.

The NRC SE on the CPS IPE was issued in November 1996 and concluded, based on the staffs Step 1" review, that the licensee had met the intent of GL 88-20. The licensee has updated the PRA several times since the staff review relative to GL 88-20 to reflect the current plant configuration and to reflect the accumulation of additional plant operating history and component failure data. However, based on the industry peer review of the CPS PRA, high grades were not received in all technical areas. The peer review grades each technical element on a scale of 1 to 4, with a 1 indicating that the PRA can be used in assessing severe accident vulnerabilities and general prioritization of issues (the lowest use) and a 4 indicating that the PRA can be used as a primary basis for decision-making (the highest use). A grade of 3 is suggested for use in a risk-informed licensing submittal to the NRC, which indicates that the PRA can be used to support positions regarding absolute levels of safety significance, if supported by deterministic evaluations. The CPS PRA received a grade of 3 in six of the technical elements. A grade of 2 was received in the remaining five technical elements, covering: initiating events, human reliability analysis, dependency analysis, structural response, and quantification and results interpretation. A grade of 2 indicates that the PRA can be used for applications that involve risk ranking.

In response to a staff RAI, the licensee provided a table that included the peer review certification facts and observations and the licensees evaluation of how these areas impact the EPU evaluation. The licensees evaluation indicated that there were some findings and observations that could have a minor impact on the EPU evaluation, but they determined that there were no significant impacts. To address some of these findings, the licensee performed

sensitivity calculations.

The staff finds that the CPS internal events PRA appears to be controlled and documented to ensure that it reflects the as-built, as-operated plant. The staff also finds that the CPS IPEEE appears to be applicable to the current, pre-EPU and post-EPU conditions. This finding is based on the fact that the IPEEE appears to still be applicable for the seismic and HFO external events and that the licensee has completed the rerouting of some cables in accordance with the assumptions credited in the IPEEE fire analysis.

The licensees internal events PRA did not receive high grades in a number of areas that are impacted by the EPU, as identified by the industry peer review. However, the staff recognizes that this submittal is not a risk-informed license application, sensitivity calculations have been performed to address findings regarding the PRA, and the analyses are only being used to provide confirmatory insights. The staff believes that further refinement of the licensees PRA would not significantly alter the overall conclusions of this specific license application and would not rebut the presumption of adequate protection provided by the licensee meeting the deterministic requirements and regulations or warrant denial of this license amendment.

Therefore, the staff concludes that the CPS internal and external events analyses are acceptable for this license application.

10.5.6 Risk Evaluation Conclusions The staff concludes that, for internal events, no new impacts are expected for initiating event frequencies, component reliability, or success criteria, but impacts are expected for selected operator actions due to the decrease in available operator response times. The staff concludes that the risk increases due to these impacts under the EPU conditions are very small and within the acceptance guidelines of RG 1.174.

The staff finds that the licensee has a process for managing plant risk during shutdown operations and that the risk impact due to the EPU during these operations is expected to be negligible. Also, the staff concludes that the risk impacts from external events under EPU conditions are expected to be negligibly small and within the acceptance guidelines of RG 1.174.

In conclusion, during the course of its review, the staff identified two issues associated with the EPU supporting risk analysis: (1) the EPU fire analysis has not used the most recent CPS internal events PRA and (2) the overall quality of the PRA as identified by the industry peer review may limit its use in license applications. However, the staff believes the identified issues will not rebut the presumption of adequate protection provided by the licensee meeting the deterministic requirements and regulations. This conclusion is based on the fact that the analyses are only being used to provide confirmatory insights and are not being relied upon to make staff decisions. The staff believes that further resolution of these analyses would not significantly alter the findings and current practices of the licensee under EPU conditions.

Therefore, the NRC staff concludes that the identified issues do not warrant denial of this license application.

10.6 Human Performance 10.6.1 Scope of Evaluation This evaluation is limited to the operator performance aspects resulting from the increased allowable maximum power level. It includes required changes to operator actions, human-system interface changes, and changes to procedures and training resulting from the change in maximum power level. The evaluation is based on the licensees response to five broad questions regarding human performance.

The staffs guidance for this review includes Information Notice 97-78, Crediting of Operator Actions in Place of Automatic Actions and Modifications of Operator Actions, Including Response Times, and NUREG-0800, Standard Review Plan, Chapter 18 (draft), Human Factors Engineering. In addition, ANSI/ANS 58.8, Time Response Design Criteria for Safety Related Operator Actions, was used as an initial screening device for the significance of changes in time available for operator actions.

10.6.2 Evaluation The NRC staffs evaluation of the licensees responses to the five questions is provided below.

Question 1 - Changes in Emergency and Abnormal Operating Procedures Describe how the proposed power uprate will change plant emergency and abnormal procedures.

In their letter of October 17, 2001, the licensee stated that because the Emergency Operating Procedures (EOPs) are symptom-based, operator actions remain unchanged. The effect of the EPU on EOPs is limited to revisions to numerical values or inputs to EOP guideline calculations which are expected to result in minor changes to EOP figures and limitations.

No significant Abnormal Operating Procedure (AOP) revisions are expected. However, the licensee has stated that all AOPs will be reviewed for EPU conditions and necessary revisions will be completed prior to EPU implementation.

The licensee further stated that emergency and abnormal procedure changes will be addressed during operator training sessions prior to operation at EPU conditions. Based on the information submitted, the responses to the RAIs, and since there are no changes to operator actions related to the procedures, the staff concludes that the EOPs and AOPs are acceptable for EPU operation.

Question 2 - Changes to Risk-Important Operator Actions Sensitive to Power Uprate Describe any new risk-important operator actions required as a result of the proposed power uprate. Describe changes to any current risk-important operator actions that will occur as a result of the power uprate. Explain any changes in plant risk that result from changes in risk-important operator actions.

(i.e., Identify and describe operator actions that will require additional response time or

will have reduced time available. Your response should address any operator workarounds that might affect these response times. Identify any operator actions that are being automated as a result of the power uprate. Provide justification for the acceptability of these changes.)

As stated in the response to changes in operating procedures, there are no new operator tasks being introduced as a result of the EPU. By letters dated September 28, and December 5, 2001, the licensee described several current operator tasks in which the available time to accomplish each task was reduced as a consequence of the power uprate. The time reduction assumed by the licensee was a conservative 20 percent, the amount of the power uprate. The staff screened these tasks using the time criteria of ANSI/ANS 58.8. Only one task (initiating SLC with one pump to avoid hotwell depletion with 20 percent steam flow to suppression pool) was questionable. However, the licensee stated that nearly doubling the already conservative human error probability for this action based on the increased time available (from 3.1E-01 to 5.2E-01) had very little effect on core damage frequency. Based on the information submitted and the responses to the RAIs, the staff concludes that operator actions can be accomplished during EPU operation.

Question 3 - Changes to Control Room Controls, Displays and Alarms Describe any changes the proposed power uprate will have on the operator interfaces for the control room controls, displays and alarms. For example, what zone markings (e.g.,

normal, marginal and out-of-tolerance ranges) on meters will change? What set points will change? How will the operators know of the change? Describe any controls, displays and alarms that will be upgraded from analog to digital instruments as a result of the proposed power uprate and how operators will be tested to determine that they can use the instruments reliably.

In their letter of October 17, 2001, the licensee stated that there are no major changes to the controls, displays, or alarms as a result of this EPU. Some changes are required to indicator spans, alarm settings, and automatic actuation setpoints. In addition, zone banding on control board indications are being reviewed for acceptability and will be revised as necessary prior to EPU operation. The licensee indicated that the turbine generator control panel will require replacement of several meters that have revised scales representative of new limits associated with the EPU. The licensee provided a list of setpoints to be revised and identified several other minor changes to controls, displays, and alarms. These changes will be implemented as design changes in accordance with approved change control procedures. As such, training and implementation requirements are identified and tracked, including simulator impact. Verification of training is required as part of the design change closure process.

The licensee stated that there are no planned analog-to-digital upgrades to controls, displays, or alarms planned as a result of this EPU.

The purpose of this question is to ensure the staff that the licensee adequately considered the necessary equipment changes resulting from the EPU that affect the operators ability to perform their required functions. Based on the information submitted and the responses to the RAIs, the staff concludes that the licensee has considered the necessary equipment changes resulting from the EPU that affect the operators ability to perform their required functions.

Question 4 - Changes to the Safety Parameter Display System Describe any changes the proposed power uprate will have on the Safety Parameter Display System. How will the operators know of the changes?

The licensee in their letter of October 17, 2001, stated that the analog and digital inputs to the Safety Parameter Display System (SPDS) are not affected by the EPU, and that this change will not affect human factors because the display and function of the system are unchanged.

The staff accepts this statement, but would expect the licensee to make any necessary changes to the SPDS if they are identified in the future.

Question 5 - Changes to the Operator Training Program and Control Room Simulator Describe any changes the proposed power uprate will have on the operator training program and the plant reference control room simulator, and provide the implementation schedule for making the changes.

In their letter of October 17, 2001, the licensee stated that an operator lesson plan will be developed to teach plant changes resulting from the EPU and existing lesson plans will be revised to reflect the changes. The EPU lesson plan will be presented to licensed/certified operations personnel before startup is initiated for operating at EPU conditions. The EPU changes will be incorporated in continuing training lesson plans, as applicable.

Operator training for EPU conditions will be performed on the simulator prior to operating at uprated conditions. This training will consist of a comparison of plant conditions between the current maximum power level and the uprated power level, the normal operating procedural actions to achieve the uprated power level, and selected transients and accidents that present the greatest change from previous power levels.

The plant simulator will contain a software module that reflects the major plant systems and reactor changes as a result of the EPU. This module will be used for test preparation and operator training conducted prior to EPU implementation. These simulator changes will be implemented prior to the licensed operator requalification training session before the power uprate is initiated. The simulator performance validation for the EPU will be performed in accordance with ANSI/ANS 3.5-1993.

Based on the information submitted and the responses to the RAIs, the staff concludes that the licensee will develop and implement a satisfactory training program, including simulator training, for the proposed EPU.

10.6.3 Conclusion Based on the information submitted and the responses to the RAIs, the staff concludes that the review topics associated with the operators integration into the proposed EPU have been satisfactorily addressed by the licensee. The staff further concludes that the proposed EPU should not adversely affect operator performance considering the reduced time available on several risk-important operator actions.

11.0 CHANGES TO FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATIONS 11.1 Changes to Facility Operating License The licensee proposed the following conforming change to the Operating License to reflect the EPU.

1. NPF-62, Section 2.C.(1): The maximum power level is revised to be 3473 MWt.

Justification for Change: The new maximum power level is 3473 MWt as evaluated in this SE.

11.2 Changes to Technical Specifications The licensee proposed conforming changes to the TS to reflect the EPU. Some of these changes are discussed in Sections 3.3.1 and 5.3. The remaining changes are discussed below.

1. TS Section 1.1, Page 1.0-5: The definition of RTP would be revised to be the proposed EPU maximum licensed power level of 3473 MWt.

Justification for Change: This is the new maximum licensed power level as evaluated in this SE.

2. TS Section 2.1.1.1, Page 2.0-1: The safety limit would be revised for fuel cladding integrity at low core flow and reactor pressure from the current 25 percent RTP to 21.6 percent RTP.

Justification for Change: The basis for the proposed safety limit is the transition to the SLMCPR which is based on the GE GEXL correlation. This correlation ensures that above the SLMCPR, 99.9 percent of the fuel rods will avoid boiling transition during plant transients. Therefore, based on the above, the staff concludes that the proposed safety limit is acceptable for EPU operation.

3. TS Section 3.1.3, Page 3.1-8: The proposed change is to the Note in the TS Condition D revising the percent RTP at which two or more inoperable control rods not in compliance with the banked position withdrawal sequence (BPWS) and not separated by two or more operable control rods, are required to be restored to operable status. The percent RTP has been revised from >20 percent RTP to > 16.7 RTP.

Justification for Change: The new percent RTP is required to maintain the existing thermal power level under power uprate conditions for which the BPWS requirements are applicable. This is acceptable based on the information provided and the evaluation in Section 2 of this SE.

4. TS Section 3.1.6, Page 3.1-18: The proposed changes to the applicability section revise the RTP at which operable control rods shall comply with the requirements of BPWS.

The percent RTP has been revised from 20 percent RTP to 16.7 percent RTP.

Justification for Change: The new percent RTP is required to maintain the existing

thermal power level under power uprate conditions for which the BPWS requirements are applicable. This is acceptable based on the information provided and the evaluation in Section 2 of this SE.

5. TS Section 3.1.7, Page 3.1-23: The proposed changes in Figure 3.1.7-1 revise the SLC system weight percent sodium pentaborate solution concentration requirements. The figure has been revised from a 10.3 percent to a 10.8 percent minimum allowable concentration.

Justification for Change: The concentration was increased to comply with the ATWS rule 10 CFR 50.61. This is acceptable based on the information provided and the evaluation in Sections 6.5 and 9.3.1 of this SE.

6. TS Section 3.2.1, Page 3.2-1: The proposed changes to the Applicability, Required Action, and SR revises the RTP at which all average planar linear heat generation rates shall be less than or equal to the limits specified in the COLR. This RTP has been revised from 25 percent to 21.6 percent.

Justification for Change: The new percent RTP is required to maintain the same basis of absolute bundle thermal power level under power uprate conditions for when the requirements are applicable. This is acceptable to the staff based on the information provided and the evaluation in Sections 2 and 9 of this SE.

7. TS Section 3.2.2, Page 3.2-2: The proposed changes to the Applicability, Required Action, and SR revises the RTP at which all MCPRs shall be greater than or equal to the MCPR operating limits specified in the COLR. This RTP has been revised from 25 percent to 21.6 percent.

Justification for Change: The new percent RTP is required to maintain the same basis of absolute bundle thermal power level under power uprate conditions for when the requirements are applicable. This is acceptable to the staff based on the information provided and the evaluation in Sections 2 and 9 of this SE.

8. TS Section 3.2.3,Page 3.2-3: The proposed changes to the Applicability, Required Action, and SR revises the RTP at which all LHGRs shall be less than or equal to the operating limits specified in the COLR. This RTP has been revised from 25 percent to 21.6 percent.

Justification for Change: The new percent RTP is required to maintain the same basis of absolute bundle thermal power level under power uprate conditions for when the requirements are applicable. This is acceptable to the staff based on the information provided and the evaluation in Sections 2 and 9 of this SE.

9. TS Section 3.4.1, Pages 3.4-1, 2, and 5: The proposed changes to the LCO, required action and Figure 3.4.1-1 revise the percent RTP and corresponding operating region at which recirculation loops (i.e., single or both) shall be in operation. The percent RTP for the TS LCO has been revised from less than or equal to 70 percent RTP to less than or equal to 58 percent RTP. Similarly, the percent thermal power axis on Figure 3.4.1-1 has been rescaled corresponding to the percent increase in power.

Justification for Change: The new percent RTP and stability limits are required to maintain the existing thermal power level under power uprate conditions. This is acceptable to the staff based on the information provided and the evaluation in Sections 2 and 9 of this SE.

10. TS Section 3.4.3, Page 3.4-9: The proposed change revises the percent RTP at which jet pump operability shall be verified. The percent has been revised from >25 percent RTP to >21.6 percent RTP.

Justification for Change: The new percent RTP is required to maintain the same basis of absolute bundle thermal power level under power uprate conditions for when the requirements are met. This is acceptable to the staff based on the information provided and the evaluation in Sections 2 and 9 of this SE.

 TS Section 3.7.6, Page 3.7-13: The proposed change revises the percent RTP at which the main turbine bypass system shall be operable. The percent has been revised from

$ 25 percent to $ 21.6 percent.

Justification for Change: The new percent RTP is required to maintain the same basis of absolute bundle thermal power level under power uprate conditions for when the requirements are met. This is acceptable to the staff based on the information provided and the evaluation in Sections 2 and 9 of this SE.

12.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Illinois State official was notified of the proposed issuance of the amendment. The State official had no comments.

13.0 ENVIRONMENTAL CONSIDERATION

Pursuant to 10 CFR 51.21, 51.32, 51.33, and 51.35, a draft environmental assessment and finding of no significant impact was prepared and published in the Federal Register on February 13, 2002 (67 FR 6758). The draft environmental assessment provided a 30-day opportunity for public comment. Comments from a member of the public were received on the environmental assessment. The comments were reviewed and are addressed in the final environmental assessment published in the Federal Register on April 5, 2002 (67 FR 16459). Accordingly, based upon the Environmental Assessment, the Commission has determined that the issuance of this amendment will not have a significant effect on the quality of the human environment.

14.0 CONCLUSION

The staff has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

15.0 REFERENCES

1. Letter from AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Clinton Power Station, Unit 1: Request for License Amendment for Extended Power Uprate Operation," June 18, 2001, with attachments, U-603489.

2. GE Report NEDC-32989P, Safety Analysis Report for &OLQWRQ3RZHU6WDWLRQ Extended Power Uprate, June 2001(Proprietary).

3. GE Report NEDC-32989P, Safety Analysis Report for &OLQWRQ3RZHU6WDWLRQ Extended Power Uprate - Errata and Addenda, E&A Number 1, September 24, 2001 (Proprietary).

4. GE Nuclear Energy, Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate, (ELTR1), Licensing Topical Report NEDC-32424P-A (Proprietary), dated February 1999, and NEDC-32424 (Nonproprietary), April 1995.

5. Nuclear Regulatory Commission, letter to General Electric Company, "Staff Position Concerning General Electric Boiling Water Reactor Extended Power Uprate Program,"

February 8, 1996.

6. GE Nuclear Energy, "Generic Evaluation of General Electric Boiling Water Reactor Extended Power Uprate, (ELTR2), Licensing Topical Report NEDC-32523P-A (Proprietary), February 2000, NEDC-32523P-A Supplement 1, Volume 1 (Proprietary),

February 1999, and NEDC-32523P-A Supplement 1, Volume II (Proprietary), April 1999.

7. Nuclear Regulatory Commission, letter to General Electric Company, "Safety Evaluation by the Office of Nuclear Reactor Regulation Related to General Electric Licensing Topical Report NEDC-32523P," September 14, 1998.

8. Nuclear Regulatory Commission, Standard Review Plan, NUREG-0800, April 1996.

9. Letter from J. B. Hopkins, Nuclear Regulatory Commission, to O. D. Kingsley, Exelon Generation Company, LLC, Clinton Power Station, Unit 1 - Extended Power Uprate, July 30, 2001.

10. Letter from K. A. Ainger, Exelon Generation Company, LLC, to Nuclear Regulatory Commission, Additional Environmental Information Supporting the License Amendment Request to Permit Extended Power Uprate Operation at Clinton Power Station, September 7, 2001, RS-01-189.

11. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Supplemental Information Supporting the License Amendment Request to Permit Extended Power Uprate Operation at Clinton Power Station, September 28, 2001, RS-01-207.

12. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Supplemental Information Supporting the License Amendment Request to Permit Extended Power Uprate Operation at Clinton Power Station, September 28,

2001, RS-01-207.

13. Letter from J. B. Hopkins, Nuclear Regulatory Commission, to O. D. Kingsley, Exelon Generation Company, LLC, Clinton Power Station, Unit 1 - Request For Additional Information, October 3, 2001.

14. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Information Supporting the License Amendment Request to Permit Extended Power Uprate Operation at Clinton Power Station, October 17, 2001, RS-01-225.

15. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Non-Proprietary Safety Analysis Report Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, October 23, 2001, RS-01-241.

16. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Supplemental Safety Analysis Report Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, October 26, 2001, RS-01-246.

17. Letter from P. R. Simpson, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Reactor Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, October 31, 2001, RS-01-247.

18. Letter from J. B. Hopkins, Nuclear Regulatory Commission, to O. D. Kingsley, Exelon Generation Company, LLC, Clinton Power Station, Unit 1 - Request For Additional Information, November 5, 2001.

19. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, November 8, 2001, RS-01-255.

20. Letter from K. A. Ainger, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Electrical Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, November 8, 2001, RS-01-261.

21. Letter from J. B. Hopkins, Nuclear Regulatory Commission, to O. D. Kingsley, Exelon Generation Company, LLC, Clinton Power Station, Unit 1 - Request For Additional Information, November 14, 2001.

22. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Plant Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, November 20, 2001, RS-01-273.

23. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Health Physics Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, November 21, 2001, RS-01-271.

24. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Environmental Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, November 29, 2001, RS-01-277.

25. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, November 30, 2001, RS-01-279.

26. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Risk Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 5, 2001, RS-01-282.

27. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Materials Engineering Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 6, 2001, RS-01-278.

28. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Mechanical Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 7, 2001, RS-01-281.

29. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Reactor Pressure Vessel Fluence Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 13, 2001, RS-01-297.

30. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Electrical Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 13, 2001, RS-01-302.

31. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Reactor Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 20, 2001, RS-01-305.

32. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Reactor Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 21, 2001, RS-01-311.

33. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Reactor Pressure Vessel Fluence Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, December 26, 2001, RS-01-312.

34. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Mechanical Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, January 8, 2002, RS-02-005.

35. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Testing Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, January 15, 2002, RS-02-011.

36. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Additional Mechanical Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, January 16, 2002, RS-02-014.

37. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Supplemental Reactor Systems Information Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, January 24, 2002, RS-02-019.

38. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Feedwater Nozzle Safe End Fatigue Evaluation Supporting the License Amendment Request to Permit Uprated Power Operation at Clinton Power Station, March 15, 2002, RS-02-057.

39. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Revised Risk Analysis Sensitivity Case Supporting the License Amendment Request to Permit Extended Power Uprate Operation at Clinton Power Station, March 22, 2002, RS-02-062.

40. Letter from K. R. Jury, AmerGen Energy Company, LLC, to Nuclear Regulatory Commission, Response to Request for Additional Information, March 29, 2002, RS-02-068.

Principal Contributors: J. Hopkins R. Goel B. Pettis G. Thomas J. Wu R. Eckenrode N. Trehan H. Garg S. La Vie C. Hinson G. Georgiev L. Lois A. Roecklein G. Carpenter T. Scarbrough D. Shum J. Raval Date: April 5, 2002

TABLE 1 CPS RADIOLOGICAL ANALYSIS RESULTS, REM 0-2 hr EAB 30-day LPZ 30-day CR Whole Whole Whole Event Body Thyroid Body Thyroid Body Thyroid Loss-of-Coolant Accident Pre-EPU 11.0 225.0 3.5 86.0 3 25.0 Post EPU 13.5 267.0 4.5 102.0 3.5 29.0 Criterion 25.0 300.0 25.0 300.0 5.0 30.0 Control Rod Drop Accident Pre-EPU 0.018 0.16 0.0056 0.18 <3 <25.0 Post EPU 0.023 0.19 0.0073 0.22 <3.5 <29.0 Criterion 6.25 75.0 6.25 75.0 5.0 30.0 Fuel Handling Accident Pre-EPU 0.24 0.27 0.051 0.058 <3 <25.0 Post EPU 0.31 0.32 0.066 0.070 <3.5 <29.0 Criterion 6.25 75.0 6.25 75.0 5.0 30.0 Main Steam-Line Break Pre-EPU 0.008 0.45 0.0019 0.11 <3 <25.0 Post EPU 0.008 0.45 0.0019 0.11 <3.5 <29.0 Criterion 2.5 30.0 2.5 30.0 5.0 30.0 Offgas System Failure Pre-EPU 0.19 --- 0.045 --- <3 ---

Post EPU 0.19 --- 0.045 --- <3.5 ---

Criterion 0.5 --- 0.5 --- 5.0 ---

LIST OF ACRONYMS AC - alternating current ACP - activated corrosion products ADS - automatic depressurization system ALARA - as low as reasonably achievable ANSI - American National Standards Institute AOO - anticipated operational occurrence AOP - abnormal operating procedure APRM - average power range monitor ART - adjusted reference temperature ASME - American Society of Mechanical Engineers ATWS - anticipated transient without scram AV - allowable value BOP - balance-of-plant BPWS - banked position withdrawal sequence BWR - boiling water reactor BWROG - Boiling Water Reactor Owners Group BWRVIP - Boiling Water Reactor Vessel and Internals Project CCW - component cooling water CDF - core damage frequency CGCS - combustible gas control system COLR - Core Operating Limits Report CPS - Clinton Power Station CRD - control rod drive CRDA - control rod drop accident CRDM - control rod drive mechanism CRP - current rated power CSC - containment spray cooling CST - condensate storage tank CUF - cumulative usage factor DBA - design-basis accident DC - direct current DG - diesel generator DHR - decay heat removal DIVOM - delta critical power ratio over initial critical power ration versus oscillation magnitude DRF - design record file ECCS - emergency core cooling system EFPY - effective full power years EOP - emergency operating procedure EPRI - Electric Power Research Institute EPU - extended power uprate EQ - equipment environmental qualification ERAT - emergency reserve auxiliary transformer FAC - flow-accelerated corrosion FHA - fuel handling accident FIV - flow-induced vibration FIVE - fire-induced vulnerability evaluation ATTACHMENT 2

FPCCS - fuel pool cooling and cleanup system F-V - Fussell-Vesely GDC - general design criteria GE - General Electric Company GENE - General Electric Nuclear Energy GNF - Global Nuclear Fuel GL - generic letter HCLPF - high confidence of a low probability of failure HCTL - heat capacity temperature limit HCU - hydraulic control unit HELB - high-energy line break HEP - human error probability HFO - high winds, floods, and other HPCS - high-pressure core spray HVAC - heating, ventilation, and air conditioning ICA - interim corrective action IPE - individual plant examination IPEEE - individual plant examination of external events ISLOCA - interfacing systems loss-of-coolant accident LERF - large early release frequency LOCA - loss-of-coolant accident LHGR - linear heat generation rate LLS - low-low-set LLSP - low power setpoint LOFW - loss-of-feedwater LPCS - low pressure core spray LTR - licensing topical report MAAP - modular accident analysis program MAPLHGR - maximum average planar linear heat generation rate MCPR - minimum critical power ratio MCRACS - main control room atmosphere control system MDFWP - motor driven feedwater pump MELLLA - maximum extended load limit line analysis MEOD - maximum extended operating domain MOV - motor-operated valves MSIV - main steam isolation valve MSIVD - main steam isolation valve closure-direct MSLB - main steam-line break MWe - megawatts electric MWt - megawatts thermal NEI - Nuclear Energy Institute NPSH - net positive suction head NRC - U.S. Nuclear Regulatory Commission NSSS - nuclear steam supply system OLMCPR - operating limit minimum critical power ratio OPRM - oscillation power range monitor ORAM - outage risk assessment and management ORTP - original rated thermal power

PCT - peak cladding temperature PP&L - Pennsylvania Power and Light Company PRA - probabilistic risk assessment PRDS - pressure regulator downscale failure RAI - request for additional information RAT - reserve auxiliary transformer RAW - risk achievement worth RCIC - reactor core isolation cooling RCPB - reactor coolant pressure boundary RCS - reactor coolant system RG - regulatory guide RHR - residual heat removal RIPD - reactor internal pressure differences RLE - review level earthquake RPS - reactor protection system RPV - reactor pressure vessel RSLB - recirculation suction line break RTP - rated thermal power RWCU - reactor water cleanup SAFDL - specified acceptable fuel design limit SBO - station blackout SDC - shutdown cooling SE - safety evaluation SER - safety evaluation report SFP - spent fuel pool SFPCC - spent fuel pool cooling and cleanup SGTS - standby gas treatment system SLC - standby liquid control SLMCPR-safety limit minimum critical power ratio SMA - seismic margins assessment SORV - stuck-open relief valve SPC - suppression pool cooling SPDS - safety parameter display system SSW - shutdown service water SR - surveillance requirement SRP - Standard Review Plan SRV - safety/relief valve TAF - top-of-active fuel TBCCW - turbine building closed cooling water TCV - turbine control valve TDRFP - turbine driven reactor feedwater pump TS - technical specification TSV - turbine stop valve TTNBPF - turbine trip no bypass with flux scram UAT - unit auxiliary transformer USAR - updated safety analysis report UHS - ultimate heat sink

USE - upper shelf energy VAR - reactive power (volt-ampere reactive)