ML20212L156

Safety Evaluation Supporting Amends 72 & 72 to Licenses NPF-87 & NPF-89,respectively

ML20212L156
Person / Time
Site:	Comanche Peak
Issue date:	09/30/1999
From:	NRC (Affiliation Not Assigned)
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ML20212L154	List: ML20212L150 ML20212L156 ML20212L159
References
NUDOCS 9910070184
Download: ML20212L156 (45)

Text

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t UNITED STATES g

j NUCLEAR REGULATORY COMMISSION 2

WASHINGTON, D.C. 20666 4001

.....,o SAFETY EVALUATION BY THE CFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 72 TO FACILITY OPERATING LICENSE NO. NPF-87 AND AMENDMENT NO. 72 TO FACILITY OPERATING LICENSE NO NPF-89 TXU ELECTRIC COMPANY COMANCHE PEAK STEAM ELECTRIC STATION. UNITS 1 AND 2 DOCKET NOS. 50-445 AND 50-446

1.0 INTRODUCTION

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By application dated December 21,1998, as supplemented by letters dated April 23, May 14, July 9, August 13 (two letters), August 25, and September 10,1999 (References 1 through 8, respectively), TXU Electric Company (TXU Electric, the licenece) requested changes to the Technical Specifications (TSs) for the Comanche Peak Steam filectric Station (CPSES), Units 1 and 2, and Facility Operating License for CPSES, Unit 2. Speci+ically, the proposed changes would revise (1) FOL No. NPF-89 for Unit 2 to increase rated thermal power (RTP) from 3411 megawatts therrnal(MWt) to 3445 MWt, (2) TS 1.1 to increase the RTP to 3445 MWt for CPSES Unit 2, (3) TS Table 3.3.1-1, Reactor Trip Setpoint for "N 16 Overpower," and " Power Range Neutron Flux - High," Allowable Values for Unit 2, and (4) TS 5.6.5b, " Core Operating Limits Report (COLR)," to reflect appropriate power-dependant, safety analysis assumptions and the updating of these assumptions in NRC staff-approved documents.

2.0 BACKGROUND

CPSES, Unit 2, was originally licensed for a 100 percorit core thermal power rating of i

3411 MWt. As part of the application for license amendment, the licensee evaluated the impact of a 1 percent increase in RTP to 3445 MWt for systems, structures, and components.

By letter dated August 13,1998 (Reference 9), the licensee requested an exemption from certain requirements applicable to emergency core cooling system (ECCS) ovaluation models j

performed in accordance with Appendix K of Part 50 of Title 10 of the Code of Federal Regulations (10 CFR Part 50) for CPSES, Units 1 and 2. This regulation imposes a 2 percent licensed power margin on ECCS evaluation models of light water power reactors licensed in j

accordance with the requirements of Appendix K. Based on the proposed use of the improved Caldon, Inc. (Caldon), instrumentation, referred to as the Leading Edge Flow Meter (LEFM/),

in the determination of core power level, the licensee sought an exemption to reduce the j

9910070184 990930

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>. licensed power uncertainty required by 10 CFR Part 50, Appendix K, for increases of up to 1 percent in the licensed power level using the current NRC-approved methodologies.

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The basis for the exemption was that the Caldon instrumentation provides a more kccurate j

indication of feedwater flow (and correspondingly reactor thermal power) than assumed in tne i

development of Appendix K requirements. Technical support for this conclusion is discussed in

' detail in Caldon Topical Report ER-80P (Reference 10). The improved thermal power measurement accuracy obviates th's need for the full 2 percent power margin assumed in Appendix K, thereby increasing the thermal power available for electrical generation, while improving the certainty that actual reactor thermal power remains at or below the value used to analyze ECCS pedormance during a loss-of-coolant accident (LOCA). The Caldon Topical Report was approved by NRC letter dated March 8,1999 (Reference 11) and the Appendix K exemption was granted by NRC letter dated May 6,1999 (Reference 12).

Along with the propoal to increase the reactor thermal power to 3445 MWt, the licensee also proposed continued use of topical reports identified in CPSES TS 5.6.5b, " Core Operating Limits Report (COLR)." These topical reports describe the NRC-approved methodologies that support the CPSES safety analysis, including the small break and large break LOCAs analyses.

In many of these topical reports, reference is made to the use of a 2 percent uncertainty applied to the reactor power, consistent with Appendix K. The licensee proposed that these topical reports be approved for use consistent with the exemption request and this license amendment request and, further, the acknowledgment that the change in the power uncertainty does not constitute a significar,t change as defined in 10 CFR Part 50, Section 50.46 and Appendix K to 10 CFR Part 50.

3.0 EVALUATION The licensee and the NRC staff evaluated the effect of the proposed increase in RTP on safety

. related components, systems, and structures at CPSES, Unit 2. The effect of the increase in RTP was also evaluated with regard to licensed reactor operator performance and emergency preparedness.

3.1 Plant Svstems Plant systems were reviewed with regard to their inledace with the nuclear supply system and with regard to operation at the increased RTP.

3.1.1 Balance of Plant (BOP) Systems and Nuclear Steam Supolv System Interfaces The licensee performed a detailed evaluation of selected BOP systems that intedace with the nuclear steam supply system (NSSS) with respect to the Westinghouse NSSS/ BOP interface guidelines, regulatory requirements, and design documents. The licensee also evaluated non-NSSS intedacing BOP systems, structures, and components with respect to compliance with the CPSES design bases, applicable industry guidance, and regulatory requirements. The licensee also reviewed the effects of the increase in RTP on a station blackout and the safe shutdcwn fire analysis.

r 3-The licensee evaluated the following systems for the interfacing effects with the NSSS:

e.

Main Steam System

' Steam Dump System Condensate and Feedwater System e

Auxiliary Feedwater System and Condensate Storage Tank The systems were evaluated for three limiting cases of operation at 104.5 percent of the current RTP with varying assumptions concerning steam generator tube plugging, the value of the average reactor temperature (reference T-average), and feedwater temperature.

3.1.1.1 Main Steam System The licensee evaluated the effects resulting from plant operations at 104.5 percent of the current RTP on the main steam system including the main steam isolation valves and main steam bypass valves, steam generator power operated atmospheric relief valves, and main l

steam safety valves. The licensee concluded that the components are adequately sized for the Increase in RTP. The licensee determined that no hardware or operational modifications are required and that the current design basis remains valid. Therefore, the 1 percent increase in j

RTP will have no impact on the operation of the main steam system.

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Based on the NRC staff's review and the experience gained from the review of power uprate applications for similar pressurized-water reactor (PWR) plants, the staff concludes that

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operations at the proposed 1 percent increase in RTP will have an insignificant or no impact on the main steam system and its associated components.

3.1.1.2 Steam Dumo System The licensee evaluated the steam dump system for plant operations at 104.5 percent of the current RTP and concluded that at the higher power level the steam dump system capacity exceeded the Westinghouse,40 percent of the rated steam flow, criterion, at full load steam pressure. The licensee determined that no hardware or operational modifications are required and that the current design basis remains valid. Therefore, the 1 percent increase in RTP will have no impact on the operation of the steam dump system.

Based on the NRC staff's review and the experience gained from the review of power uprate applications for similar PWR plants, the staff concludes that operations at the proposed 1 percent increase in RTP will have an insignificant or no impact on the steam dump system.

3.1.1.3 Auxiliary Feedwater System (AFWS) and Condensate Storaae Tank (CST)

The licensee evaluated the effects of plant operations at 104.5 percent of the current RTP on the AFWS and CST. To fulfill the engineering safety feature design function, sufficient condensate inventory must be available during transient or accident conditions to enable the plant to be placed in a safe shutdown condition. The condensate inventory required for the AFW system was determined to be less than the existing minimum usable inventory of 249,100 gallons. The licensee determined that no hardware or operational modifications are required and that the current design basis remains valid. The licensee concluded that the 1 percent increase in RTP had no impact on the requirements for the AFWS.

. Based on NRC staff's review and the experience gained from the review of power uprate applications for similar PWR plants, the staff concludes that plant operations at the proposed 1 percent power increase in RTP will have an insignificant or no impact on the operation of the

'AFWS and CST.

3.1.1.4' Condensate and Feedwater Systems Thi licensee evaluated the effects of plant operations at 104.5 percent of the current RTP on the condensate and feedwater systems. The condensate and feedwater systems automatically maintain steam generator water levels during steady-state and transient operations. The revised design conditions will impact the feedwater volumetric flow and system pressure drop.

The major components of the systems are the main feedwater line flow restricting orifices, feedwater isolation valves, the feedwater control valves, and the condensate and feedwater pumps. The licensee determined that no hardware or operational modifications are required and that the current design basis remains valid. Therefore, the 1 percent power uprate will have no impact on the operation of the condensate and feedwater systems.

Because these systems do not perform any safety related function and their failure will not affect the performance'of any safety-related system or component, the NRC staff has not reviewed the impact of plant operations at the proposed increase in RTP on the design and perfor'mance of the condensate and feedwater systems.

3.1.2 Balance of Plant Systems - Ooeration The licensee evaluated the following BOP systems for operation at the 1 percent increased power level of 3445 MWt:

e-Main Steam System Steam Dump System e-Condensate and Feedwater Systems

-e Auxiliary Feedwater System Circulating Water System o

e Main Turbine e.

Turbine Plant Cooling System Component Cooling Water System o

Station Service Water System o

o Spent Fuel Storage e-Spent Fuel Pool Cooling System o-

. Heating, Ventilation, and Air Conditioning Systems e

- Radioactive Waste Systems The licensee's evaluation addressed thermal hydraulic parameters (temperature, pressure, and

. flowrate), decay heat, and radioactivity resulting from the 1 percent increase in RTP.

The licensee determined that no hardware or operational modifications are required and in all cases the current design basis remains valid. Only design documentation changes and several instrumentation and control setpoint related changes were necessary.

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. The licensee also evaluated high energy steamline breaks outside of containment. The Levaitstion concluded that the 1 percent power increase will have no effect on either the current licensing basis steamline break mass and energy release analysis or the final safety analysis report conclusions with regard to steamline breaks.

Based on the NRC staff's review and the experience gained from review of power uprate applications for similar PWR plants, the staff concludes that plant operations at the proposed 1 percent increase in RTP will have an insignificant or no impact on the operation of the BOP systems, structures and components.

3.2 Containment Intearity 1

The licensee evaluated the short-and long-term LOCA and steamline break mass and energy releases with respect to the 1 percent increase in RTP and has determined that a calorimetric uncertainty of 2 percent was incorporated into the analysis. The NRC-approved Caldon Report,

' ER 80P, was provided as the basis for the exemption reducing the 2 percent calorimetric u_ncertainty to 1 percent.' In Reference 8, it is proposed that, with the use of the improved instrumentation, the probability that the actual reactor power would exceed 102 percent of the current RTP, when operating at a steady state power level of 101 percent RTP, was less than the probability of exceeding 102 percent of the current RTP, when operating with the traditional instrumentation at 100 percent RTP. Based on this evaluation, there is no margin reduction associated with operation at "101% RTP" with a 1 percent calorimetric uncertainty when using the improved LEFM/ instrumentation.

The change in the uncertainty allowance applied to the core power can affect only the initial power used in the analysis; all other conservative assumptions remain unchanged. For the LOCA mass and energy release calculations, a higher power level of 104.5 percent RTP. (plus a 2 percent power uncertainty) was used; therefore, these analyses remain valid. The mass and energy releases attributed to the steamline break accident were calculated for initial power levels of up to 102 percent RTP, which includes a 2 percent power uncertainty. A spectrum of lower initial power levels was also considered. ' Analyses initiated from lower power levels were found to be limiting for secondary system breaks; thus, these containment analyses remain unaffected. As indicated, through the use of the improved LEFM/ instrumentation, the

.1 percent power uncertainty is used to offset the increase in the operating power level. In all cases, the licensee determined that the mass and energy release calculations remain valid and,

. therefore, the containment integrity analyses are unaffected by the proposed 1 percent increase in RTP.

' Based on the NRC staff's review, operations at the proposed 1 percent increase in RTP through the use of the improved LEFM/ instrumentation and 1 percent power calorime_tric uncertainty will have insignificant or no impact on the containment integrity as the present containment analyses remain valid.-

3.3 Electrical Systems The NRC staff has reviewed information provided by the licensee to determine the impact of the increase in RTP on the emergency electrical power systems. Areas included in the review were the station auxiliary electrical power distribution system, environmental qualification for -

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safety-related electrical equipment, the station blackout analysis, electrical systems associated with the main turtdne auxiliary systems, and the grid stability and reliability analysis.

3.3.1 Station Auxiliarv Electrical Power Distribution System To support unit operation at the core thermal power uprate level, it was initially unclear as to how the station auxiliary electrical power distribution system may be impacted. In this regard, the staff requested the licensee to provide a discussion addressing the impact of the proposed power uprate on the load, voltage, and short circuit values for all levels of the station electrical power distribution system, in response to this request, the licensee notes that no auxiliary load ratings will change and none of these loads will experience demands above their ratings, in addition, the main generator electrical parameters temain the same and the uprate capacity is within the generator rating. Further, the voltage controls and grid source impedance at the CPSES 345 kV grid will not be affected by the increase in RTP and, thus, the evaluated voltages and short circuit current values at different levels of the station auxiliary electrical power distribution system will not change as a result of the increase in RTP. Thus, the increase in RTP has no significant impact on the station auxiliary electrical power distribution system.

3.3.2 Environmental Oualification for Safetv-Related Electrical Eauioment i

The normal environments for the plant buildings were reevaluated by the licensee as a result of j

the increase in RTP. This evaluation determined that the increase in RTP has no significant j

effect on the process fluid temperatures in the auxiliary, safeguards, and electrical and control j

buildings. Except for the main feedwater, the increase in the heat loads is caused by the i

increase in the decay heat load as it is transferred to the component cooling and station service water systems. The increase in temperatures of these systems were determined to be fractions of 1 *F. The increase in temperature of the main feedwater system was determined to be approximately 1 *F. These small changes in fluid temperatures have no significant effect on the area temperatures. The licensee also obtained similar findings for the evaluations performed for normal environmental conditions in the containment and fuel buildings.

The CPSES post-accident thermal environmental parameters are generated from computer models of the building structures that calculate the environment created by mass and energy

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releases during postulated pipe breaks consistent with the CPSES design basis. For the i

increase in RTP, the licensee's evaluations concluded that by use of the reduced power calorimetric uncertainty to offset the increase in reactor core thermal power, the existing mass and energy releases used to establish the resulting environmental conditions for Doth inside and outside containment remained valid. Since the mass and energy releases as well as other factors do not change, the resulting environmental conditions are also unchanged and the increase in RTP has no impact on the CPSES nonradiological environmental qualification program for safety-related electrical equipment.

In general, postulated radiation doses impacting environmental qualification for electrical equipment depend primarily on the post accident contributions. However, normal operating 1

dose rate contributions are also included in the CPSES design basis calculations. These normal operating radiation contributions are, in all cases, based on-Westinghouse source terms, which were originally generated for a reactor core power level of 104.5 percent (i.e.,3565 MWt) and assumed 1 percent fuel defects. The assumption of 1 percent fuel defects is considered to be very conservative inasmuch as operation with this level of fuel leakage is 1

7-not expected. Moreover, TS 3.4.16,"RCS Specific Activity," requires remedial action when RCS activity exceeds the equi"alent of 1 percent failed fuel. Thus, with regard to cases where normal operating equipment qualification dose rate contributions may be significant, it can conservatively be concluded that the increase in RTP would not change dose rates or accumulated doses enough to exceed design basis values.

The licensee. so evaluated the effects of post-accident radiological consequences on electrical equipment qualification. The source term used in the original analysis was generated for operation at a thermal power of 3565 MWt. The licensee performed revised core fission

- product inventory calculations and from these calculations concluded that the original source term remains bounding. Based on the revised core fission product inventory, the post accident gamma source strengths for some energies were found to slightly increase as a result of the increase in RTP. However, when applied in specific dose rate computations, these licensee computations showed that the accumulated doses at all times remain lower than current design basis values and that all doses used for electrical equipment qualification remain within existing design basis values.

Thus, in summary, the increase in RTP has a neg!;gible effect on normal plant operating environmental conditions and has no significant effect on the environmental conditions currently used for the safety related electrical equipment environmental qualification program.

3.3.3 Station Blackout Analvsis The existing calculations used to demonstrate the capability to withstand a station blackout (SBO) event of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> without uncovering the core were reviewed by the licensee for the increase in RTP conditions. The later stages of the existing analysis credit operator action to maintain reactor coolant system temperature and pressure below specified limits by using steam generator atmospheric relief valves. The capacity of these valves was evaluated by the licensee and determined to be sufficient to accommodate the increase in RTP conditions and thus, the time to uncover the core following an SBO event continues to be in excess of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

The existing loss-of-ventilation analysis for the CPSES SBO is a 4-hour transient. For the SBO transient, emergency operating procedures have been developed. Using these procedures, the licensee developed a basic list of equipment items necessary to achieve safe shutdown and restore ac power. The room temperatures identified for the equipment list items were calculated using transient heatup computer models and the peak temperatures were calculated for the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping period. The licensee further evaluated equipment operability at the peak temperatures and concluded that the small temperature changes resulting from the power uprate conditions have no significant effect on the equipment as previously evaluated for the SBO event. This included equipment located in the uninterruptible power supply and battery, control, electrical and switchgear, cable spreading, and diesel generator rooms.

j In summary, the conditions associated with the proposed increase in RTP had no significant effect on the previous evaluation or conclusion for the electrical aspects associated with the SBO event.

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3.3.4[ Electrical Systems Associated With the Main Turbine Auxiliarv Systems The CPSES, Unit 2, steam turbine driven polyphase generator is a four-pole machine rated at 1350 megavolt amps (MVA) with an operating point of 1215 MW at a 0.9 power factor. This rating is based upon 60 psig [ pounds per square inch gauge) hydrogen pressure, which is supplemented with water cooling for the stator and rotor windings. Historically, CPSES, Unit 2, has operated at a peak electrical output of 1167 MW. The anticipated net increase of 20 MW,

.12 from the increase in RTP and 8 from the installation of a new high pressure turbine (not part of the license amendment request), is within the narneplate rating of the generator and there -

are no equipment limitations to prec!ude operation at the core thermal power uprate level. The licensee reviewed applicable electrical calculations and concluded that no changes are required for equipment protection relay settings associated with the generator, although some process alarm setpoints for the generator and exciter may require adjustment.

To deliver electrical power provided by the generator to the transmission system, each CPSES unit is equipped with an isolated phase bus, two main transformers, cabling, and two switchyard circuit breakers. With the exception of the CPSES, Unit 2, main transformers, which are rated

'for 650 MVA each, the remaining components are rated to deliver electrical power at or in excess of the main generator nameplate rating of 1350 MVA. The CPSES, Unit 2, main transformers have a total capacity of 1300 MVA which is slightly less than the output rating of the main generator (1350 MVA). Since the reactive power of the generator must remain below approximately 400 megavolt-amps reactive (MVAR) due to the voltage rating of the primary windings, most of the MVA capacity can be used for real power. With an expected increased power output to 1187 MW from the generator and assuming a maximum reactive power output of 400 MVARs, this results in an apparent power output of 1253 MVA,-which is within all applicable operating limits for the transformers.

The isophase bus main sectio' m sted at 37,000 amperes with each main transformer branch rated at 18,000 amperes. The es conductor will permit a temperature rise of 55 *C, with the enclosure rated at a 30 *C temperature rise. This will permit a total load, assuming a nominal voltage rating of 22 kV and 36,000 amperes, of 1372 MW, which is well in excess of the expected generator power output of 1187 MW. In addition, standard design practice at CPSES requires that switchyard equipment meet the nameplate rating of the main generator;in fact, the equipment often exceeds that rating.

Based on the preceding discussion, the turbine / generator and major electrical components extending from the isophase bus to and including the switchyard have adequate design margin to accept the additional electrical power resulting from the power uprate.

3.3.5 Grid Stability and Reliability Analvsis The capacity of a single CPSES unit is less than 3 percent of the Electric Reliability Council of i

Texas (ERCOT) estimated peak electrical load. The increased electrical output of CPSES, Unit 2, la comparatively negligible and the Unit 2 increased capacity continues to remain less than 3 percent of the ERCOT estimated peak electricalload. Actual grid disturbances on the ERCOT system have occurred where large amounts of capacity were lost, as high as 10 percent, with no integrity degradation of the transmission system observed. The increased power output of CPSES, Unit 2, will not impact grid stability and reliability. In addition, the availability and reliability of electric power from the transmission network to CPSES will not be affected by the power uprate. Thus, CPSES will continue to be in full conformance with General Design Criterion 17 " Electric Power Systems" cf Appendix A to 10 CFR Part 50.

3,4 Structural Evaluation The NRC staff reviewed the CPSES, Unit 2, increase in RTP, as it relates to the effects on the structural and pressure boundary integrity of the NSSS and the BOP system. Affected components in these systems included piping, in-line equipment and pipe supports, the reactor pressure vessel (RPV), core support structures, reactor vessel internals, steam generators (SGs), control rod drive mechanisms (CRDMs), reactor coolant pumps (RCPs), and pressurizer.

3.4.1 Reactor Vessel The licensee reported that the increase in RTP will result in changing the design parameters given in Table IV-1 of Reference 1. Table IV-1 provides three critical cases that were developed to encompass worst conditions for use in the increase in RTP analysis.

The licensee evaluated the reactor vessel for the effects ci the revised design conditions in Table IV-1 on the most limiting vessel locations v 'th regard to ranges of stress intensity and cumulative usage factors (CUFs) in each of the regions, as identified in the reactor vessel stress' reports and addenda. The evaluations considered the worst load sets of operating parameters, which were identified for the increase in RTP condition. The regions of the reactor vessel affected by the increase in RTP include outlet and inlet nozzles, the RPV (main closure head flange, studs, and vessel flange), CRDM housing, bottom head to shell juncture, core

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support pads, and the instrumentation tubes. The licensee evaluated the maximum ranges of

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stresses and CUFs for the critical components at the increase in RTP condition. The evaluation j

was performed in accordance with the American Society of Mechanical Engineers (ASME) i

~ Boiler and Pressure Vessel Code (the Code), Section 111,1971 Edition, with addenda through the Winter 1972 to assure compliance with the Code of record.

The calculated maximum stresses and the maximum CUF for the reactor vessel critical locations are provided in Table 1 of Reference 3. The results indicate that the maximum stresses are within the allowable limits, and the CUFs remain below the allowable ASME Code limit of.1.0. The licensee concluded that the current design of the reactor vessel continues to be in compliance with the licensing basis codes and standards for the increase in RTP

- condition.

The NRC staff concludes that the current design of the reactor vessel continues to be in compliance with the licensing basis codes and standards for the increase in RTP condition.

3.4.2 Reactor Vessel Intearitv/ Neutron Irradiation Several analyses were performed to determine the impact that the neutron irradiation has on the integrity of the reactor vessel. The most critical area is the beltline region of the reactor vessel, since it is predicted to be most susceptible to neutron damage. With regard to the increase in RTP and the reactor vessel integrity, the analyses should include an evaluation of l'

the'(1) pressurized thermal shock (PTS) Miculations, (2) heat up and cooldown pressure-temperature (P-T) limit cu'ves, (3) upper shelf energy, and (4) surveillance capsule withdrawal

_ - - schedule. It should be noted that these evaluations could be affected by changes in the neutron fluences and operating temperatures and pressures that re!. ult from an increase in RTP.

With regard to the PTS evaluation, the licensee atated that the highest current reference temperature - PTS (RTp7s ) end of license value 'or CPSES, Unit 2, RPV, for the intermediate shell plate, remains as 94 *F, which is 176 'F below the screening criteria of the PTS rule. The licensee also indicated that two CPSES, Unit 1, and one CPSES, Unit 2, surveillance capsules had been analyzed, confirming the similarity between the two vessels in irradiated and nonirradiated material properties. The licensee determined that the results of these surveillance capsule evaluations confirmed the conservatism of the early projections.for the CPSES vessel materials and stated that the majority of the irradiation-induced shifts in vessel material properties occur early in life. Therefore, with the substantial margin 10 the RTprs screening criteria and a nominal 1 percent increase in fluence, the licensee determined that the change in the RTp7s value would not be significant and, therefore, a revised PTS report was not required.

The licensee also indicated that the existing fast neutron fluence data, which is used in the reactor vessel design, remains bounding for the uprated power conditions. This was based on a recent fluence evaluation performed in conjunction with the withdrawal of surveillance capsule Y (second capsuje) from the CPSES, Unit 1, reactor. In this evaluation, the inclusion of the impact of low leakage fuel management reduced the CPSES, Unit 1, fluence projections by approximately 33 percent, relative to the values used in the CPSES, Unit 1, reactor vessel design. A similar reduction is anticipated for CPSES, Unit 2, when the upcoming second surveillance capsule evaluation is performed for the Unit 2 reactor. Therefore, the licensee determined that this 33 percent rnargin more than offsets the 1 percent increase in fluence that could be caused by the 1 percent power uprate. Thus, ne licensee found that the fluence values that are used in the design bound the new best mmate fluence projections, including the consideration of a 1 percent increase in RTP.

In addition, the licensee determined that a 4.5 percent or greater increase in RTP would be required to significantly increase the neutron fluence due to the increased power distribution.

Therefore, the licensee stated that, based on the CPSES, Unit 2, operation, the calculated

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fluences that are used in the current reactor vessel design bound the fluences expected to occur with the revised design conditions, since the increase in RTP is only 1 percent.

The licensee found that the revised design conditions showed continued compliance with the existing design and licensing criteria for the RPV. The licensee went on to explain that, with regard to the application of the requirements of 10 CFR Part 50, Appendices G and H, to the CPSES, Unit 2, RPV materials:

(a)

The upper shelf energy (USE) values would still remain well above the 50 foot-pound value throughout the life of the RPV.

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There is no significant change in the 32 effective full p 'wer year (EFPY) shift in adjusted reference temperature and, therefore, the existing P-T curves remain bounding for power operation up to 3445 MWt.

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No changes in the 10 CFR Part 50, Appendix H program (the P.PV surveillance program) are required.

- The staff evaluated the P-T limit curves used for heatup, cooldown, and normal operation of PWRs cased on the following NRC regulations and guidance: 10 CFR Part 50, Appendix G;

' Generic Letter (GL) 8811 (Refersce 13); GL 92-01, Revision 1, Supplement 1 (Reference 14),

Regulatory Guide (RG) 199, Fa ; 4.m. 0; the Standard Review Plan Section 5.3.2; and

- Appendix G to Section XI of the 4SME Code.

Regarding the RPV assessment, the NRC staff has reviewed the information provided by the licensee and determined that the power uprate does not result in any significant charge in the 10 CFR Part 50, Appendix G, USE, or P-T limit curve analysis for CPSES, Unit 2, arid does not

- necessitate any change in the CPSES, Unit 2,10 CFR Part 50, Appendix H, RPV surveillance program. Because the change in fluence resulting from the 1 percent increase in RTP (from

-.the 3411 MWt 1/4 thicknecs (1/4T) fluence values to the 3445 MWt 1/4T fluence values) is nominal, the NRO staff concludes that the lowest CPSES, Unit 2, RPV material USE value at end-of-life (EOL) is still consistent with the results achieved by the NRC staff using the

' RG 1.99, Revis!on 2, methodology The NRC staff independently verified that there was no change in the USE value at EOL, as a result of the 1 percent increase in RTP. The staff also verified that the USE values'of the RPV materials would still remain well above the 50 foot-pound value throughout the life of the vessel and, therefore, still be in accordance with

.10 CFR Part 50, Appendix G.

In evaluating the effect of the power increase in RTP on the shift in the limiting material's adjusted reference temperature (ART) and the need for new P-T limit curves, the NRC staff applied the methodology found in Regulatory Guide 1.99, Revision 2 for the evaluation of radiation embrittlement. The NRC staff identified that the CPSES, Unit 2, intermediate shell plate C5522-2 is still the limiting material based upon its initial reference temperature of 10 'F and its chemical composition (0.06 wt% Cu and 0.64 wt% Ni, resulting with a chemistry factor of 37 *F). ' As noted previously, the change in the fluence paused by the increase in RTP is negligible and, therefore, has no effect on the fluence factor of 1.294. Therefore, the NRC staff calculated the adjusted reference temperature (ART) at EOL for intermediate shell plate C5522-2 to be 91.9 *F. The NRC staff noted that the licensee calculated a more conservative value for the ART (94 PF) at EOL for the CPSES, Unit 2, limiting material. The NRC staff concluded that the 1 percent increase in RTP has a negligible effect on the CPSES, Unit 2, limiting material's ART at EOL, ana that new P-T curves are not required.

. Finally, based on the preceding information, the NRC staff concludes that no modification of the CPSES, Unit 2, RPV surveillance program is necessary, as a result of the increase in RTP.

3.4.3' ' Reactor Core Suooort Structures and Vessel Internals In Reference 3, the licensee provided the additional information requested by the staff for evaluating the RPV core support and internal structures. The limiting reactor internal components evaluated include the lower core plate, core barrel, baffle plate, baffle barrel region bolts,' and the upper core plate.

The licensee evaluated these critical reactor internal components considering the worst case sets of the revised design conditions provided in Table IV-1 of Reference 1. The licensee 1

- indicated that, for the baffle barrel region, the current structural and thermal analyses of record for CPSES, Unit 2, remain bounding for the increase in RTP condition. Table 2 of Reference 1 identifies the maximum calculated CUFs for the upper ano lower core plates. The remaining reactor internal components are less limiting. In addition, the potential for the flow induced vibration does not increase with the increased RTP condition. As a result of its evaluation, the licensee concluded that the reactor internal components at CPSES, Unit 2 will be structurally i

adequate for the proposed power uprate condition.

The NRC staff concludes that the reactor internal components at CPSES, Unit 2, will be structurally adequate for the proposed increase in RTP.

3.4.4 Control Rod Drive Mechanisms The pressure boundary portions of the CRDMs are those portions exposed to the reactor vessel / core inlet fluid. The licensee evaluated the adequacy of the CRDMs by reviewing the CPSES, Unit 2, current CRDM design specifications and stress report to compare the design basis input parameters against the revised design conditions in Table IV-1 of Reference 1 for the increase in RTP. Table 3 of Reference 3 identifies the applicable ASME Code and results of the stress and fatigue evaluation for the CPDM components. The licensee indicated that the Code used for the increase in RTP evaluation is the same as the Code of record. The results indicate that the stresses and CUFs for the proposed conditions remain within the ASME Code limits.

On the basis of its review, the NRC staff concludes that the current design of CRDMs continues to be in compliance with licensing basis codes and standards for the increase in RTP.

3.4.5 Steam Generators (SG_s)

The licensee reviewed the existing structural and fatigue analyses of the SGs at CPSES, Unit 2, and compared the conditions corresponding to the proposed increase in RTP with the design parameters of the Model D5 SGs stress reports. The comparison of key parameters is shown in Table IV-1 of Reference 1. For evaluation of the critical SG components, the licensee incorporated the key input parameters to develop scaling factors that were used to calculate the CPSES, Unit 2, stress and fatigue usage conditions corresponding to the proposed increase in RTP. The evaluation was performed in accordance with the requirements of the ASME Code, Section ill,1971 Edition through the Summer 1972 Addenda, which is the same as the current Code of record for SGs at CPSES, Unit 2.

j The calculated maximum stresses and cumulative fatigue usaae factors for the critical SG components are provided in Table SB of Reference 3. The results indicate that the maximum calculated ctresses are below the Code-allowable limits except for the divider plate and tubes where the licensee performed a plastic analysis considering the actual material stress-strain relation and the stress redistribution. The licensee indicated that the analysis complies with the Code and that the results satisfy the Code requirements. The results provided in Table 58 also show that the calculated CUFs are within the allowable limit of unity for the 40-year service life except for the secondary-side manway studs and/or nuts for which the fatigue usage was calculated based on a 20-year period. The licensee committed to replace the secondary-side manway studs and/or nuts prior to 20 years of service so as to remain within compliance with the fatigue limit requirement.

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f 13-I On'the basis of its review, the NRC staff concludes that the current CPSES, Unit 2, SGs are acceptable for the proposed increase in RTP, up to 13 years following its implementation at CPSES, Unit 2.' The licensee has committed to inform the NRC staff when it completes the

- replacement of the secondary-side manway studs and/or nuts as they reach the fatigue usage limit of 1.0 (Reference 8). The NRC staff finds that reasonable controls for the implementation t

and for subsequent evaluation of proposed changes pertaining to the above regulatory commitment are best provided by the licensee's administrative processes, including its

_. commitment management program. The above regulatory commitment does not warrant the creation of a regulatory requirement (an item requiring prior NRC approval of subsequent changes). The staff notes that pending industry and regulatory guidance pertaining to 10 CFR 50.71(e) may call for some information related to the above commitment to be included in a future update of the CPSES FSAR.

3.4.6 Steam Generator Tube Intearity CPSES, Unit 2, utilizes four Westinghouse model D5 SGs. The tubes are thermally treated alloy 600 with full-depth hydraulically expanded tubesheet joints. The tube support plates are made of stainless. steel. The staff focused its review on the licencee's evaluation of the SG

. tubing degradation mechanisms and structural integrity.

3.4.6.1 Steam Generator Tube Dearadation The prop. aed 1 percent increase in RTP for CPSES, Unit 2, will result in an approximate 0.3 *F

- increase in the primary inlet temperature (T ) of the SGs. The value of T is considered to be w

the most sensitive operating parameter with respect to corrosion. The primary system nominal operating pressure of 2250 psia [ pounds per square inch absolute) will remain unchanged for CPSES, Unit 2 conditions corresponding to the proposed increase in RTP. The steam pressure is expected to decrease by approximately 4 psi.

The licensee evaluated the effect of the increase in RTP on the CPSES, Unit 2, SG tube degradation mechanisms. CPSES, Unit 2, has operat'ed for 5 EFPY without any corrosion related degradation of its SGs. The SG tube material, thermally treated alloy 600, is known to have improved corrosion resistance when compared to mill annealed alloy 600. The SG tube expansion transition geometry and manufacturing processes used in producing the Westinghouse model DS SGs have also improved the corrosion characteristics of the SGs at CPSES, Unit 2, compared to earlier model SGs. Byron Unit 2 has SGs with the same tube

' material as CPSES, Unit 2, and has operated successfully for 13 EFPY under conditions similar to the CPSES, Unit 2, increased RTP conditions with no active corrosion of the SG tubing.

L The licensee evaluated other parameters that may affect corrosion, such as steam temperature and flows for the increased RTP conditions, and determined that they have a negligible impact i

on the SG tube corrosion.

1 Based on the licensee's evaluations and industry experience, the NRC staff concludes that

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. CPSES, Unit 2, SGs will not experience any significant increase in corrosion due to the j

increased RTP. The NRC staff also finds that the increase in RTP is not likely to significantly j

increase any corrosion-related degradation.

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4 3.4.6.2 Anti-Vibration Bar Wear The licensee evaluated anti-vibration bar (AVB) wear potential, caused by flow-induced vibrations and other mechanisms using two methods. The first method was a pre-increased RTP evaluation, using both theoretical considerations and the actual tube wear conditions. The second method was a post increased RTP evaluation using wear projection technology.' The wear projection technology evaluation produces information needed to project wear during operation under the increased RTP condition.

From the evaluations and the licensee's minimal experience with AVB wear, the licensee concluded that the wear rates prior to the increase in RTP and the projected wear rates after the increase in RTP remain negligible.

Based on the licensee's evaluations, the NRC staff finds that the increase in RTP is not likely to significantly affect the tube wear by the AVBs.

3.4.6.3 Preheater Wear The licensee perform d a preliminary assessment to estimate the effects of a bounding 4.5 percent increasr

.4TP at CPSES, Unit 2, with respect to preheater tube wear. A review of eddy current inspec,, results for preheater tubes was also performed. The licensee stated that there were no tubes plugged as a result of wear in the preheater, and that only two tubes had any indication of tube wear in the preheater region. The maximum wear depth of the limiting tube was estimated to be approximately 5 percent through-wall. The licensee concluded from its review of the eddy current data that significant preheater tube wear is not present in the CPSES, Unit 2, SGs.

l The increase in RTP will increase the feedwater flow into the SGs. This increased flow through the main feedwater nozzle could increase tube wear. The licensee performed an evaluation to estimate the level of increase in tube wear that could occur for the bounding, increased RTP, condition. The licensee determined that the rate of wear could increase by a factor of approximately 1.6. Therefore, the wear will remain negligible.

The licensee will continue to monitor the tubes located in the preheater in accordance with the SG integrity program required its technical specifications to determine if significant tube wear is occurring. The licensee stated that, should tube wear be identified, appropriate actions (such j

as wear projection, tube plugging / stabilization, or orifice plate modifications) will be considered.

The NRC staff concludes that the increase in RTP will not significantly affect the tube wear in the preheater region and that in the unlikely event that wear does increase, it will be detected l

by the licensee's periodic tube inspections.

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ASME Paper,"An Empirical Wear Projection Technology with Steam Generator Tube Applications and Relations to Work Rate and Wear Simulations / Tests," T. M. Frick, AD-Vol. 53-2, Fluid-Structure Interaction.

Aercelasticity, Flow-induced Vibration and Noise, Volume !!, Dallas, November 1997.

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- 3.4.6.4 Monitorina Tube Dearadation

-The licensee states that the increase in RTP will not introduce any new degradation -

mechanisms. This is supported by industry experience with similar SGs. Therefore, the licensee concludes that the current SG integrity program is acceptable. In the event that a need should develop for additional surveillance or inspection criteria, the licensee will follow its current SG integrity program to develop and determine what changes will be necessary. The

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licensee concludes that the increase in RTP is not sufficient to require pre-emptive changes to the existing program.-

The NRC staff concludes that the licensee's plans to assess tube degradation are acceptable.

3.4.6.5 Pluaaina Limit The licensee performed a structural analysis to determine whether the tube plugging limit of 40 percent, in CPSES, Unit 2, TS 5.5.9d.1.f would remain conservative to support operation at the increased RTP conditions. The licensee's increased RTP analysis addressed the conditions that were historically found to be limiting in analyses performed for CPSES, Unit 2 and similar plants. The increased RTP analysis determined the minimum required wall 4

thickness to be 0.016 inches (37.2 percent of wall thickness).. The 40 percent plugging limit provides for an allowance of 22.8 percent for growth and eddy current measurement uncertainty.

.The licensee stated that the technical justification for the current 40 percent TS tube plugging

- limit remains conservative and would not be impacted by the proposed increase in RTP.

. The NRC staff concludes that the 40 percent plugging limit, in CPSES, Unit 2, TS 5.5.9d.1.f continues to be appropriate under the proposed, increased RTP conditions.

3.4.7 Steam Generator Blowdown System Intearity j

The SG blowdown system is used for controlling chemistry, and the buildup of particulates, in the SG secondary side water.

The SG blowdown flow comes from two locations: the normal blowdown location (lower nozzle) and the supplemental blowdown location (sampling nozzle). Due to the proposed increase in l

RTP, to maintain velocity limitations at the lower nozzle, the split of blowdown flow between these two locations is altered by decreasing blowdown flow from the lower nozzle by

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approximately 1 percent and by.a corresponding increase of the blowdown flow from the j

sampling nozzle. Since this modification does not change the total blowdown flow from the SG,

. the ability of the system to control the rate of addition of dissolved solids to the secondary i

syst'em from condenser leakage or makeup water will not be impacted by this revised condition.

Also, the reduction of the lower nozzle blowdown rate will not cause any significant buildup of particulates in the secondary system because the blowdown rate still will remain within the

- range needed for particulate control.

The NRC staff concludes that the proposed increase in RTP will not significantly impact j

- operation of the SG blowdown system in that neither the rate of addition of dissolved solids nor the generation of particulates will be affected by the increase in RTP.

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' 16-3.4.8 - Reactor Coolant Pumos (RCPs)

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The licensee reviewed the existing design basis analyses of the CPSES, Unit 2, RCPs to determine the impact of the revised design conditions in Table IV-1 of Reference 1 on the

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RCPs performance and design adequacy. Table 4 of Reference 3 identifies the applicable ASME Code of record used in the evaluation, and results of the stress and fatigue usage evaluation for the RCP and components. The components evaluated included the RCP casing, mair; flange bolts, thermal barrier, casing foot, heat exchanger, discharge and suction nozzles, casing weir plate, seal housing, and auxiliary nozzles.

For the proposed increase in RTP, the reactor coolant system (RCS) pressure remains unchanged. As provided in Table IV-1 of Reference 1, the limiting design parameter (i.e., the SG outlet temperature) would increase from 559.3 to 562.4 *F for the increase in RTP.' There are no significant changes to the design thermal transients. As a result of the evaluation, the licensee indicated that the current stress and fatigue margins in the stress reports for the CPSES, Unit 2, RCPs are sufficient to accommodate this small increase in the SG outlet temperature.

On the basis of its review, the NRC staff concludes that the current RCPs, when operating at the proposed increase in RTP, will remain in compliance with the requirements of the Code of

record for the facility.

3.4.9 Pressurizer.

The licensee evaluated the structural adequacy of the pressurizer and components for operation at conditions corresponding to the proposed increase in RTP. The eveloation was performed for the limiting locations at the pressurizer spray nozzle, the surge ncgia, and upper shell. The Code used in the evaluation is the ASME Code, Section lil,1971 Editiv, through

Summer 1973 Addenda, which is the same as the current Code of record for CPSES, Unit 2, pressurizer. *ihe evaluation was performed by comparing the key parameters in the current CPSES pressurizer stress report against the revised design conditions in Table IV-1 of

. Reference 1, for the proposed ' increase in RTP. The licensee concluded that the existing design-basis analyses remain bounding for the proposed increase in RTP conditions.

The NRC staff concludes that the existing pressurizer and components will remain adequate during plant operation at the increased RTP in that the RCS pressure remains unchanged.'

3.4.10 Nuclear Steam Suoolvina System Pioina and Pioe Suooorts The licensee reviewed the design basis analysis of the NSSS piping and supports against the conditions corresponding to the proposed increase in RTP, with regard to the design transient input parameters shown in Table IV 1 of Reference 1, and the LOCA dynamic loads. The evaluation was performed for the reactor coolant loop piping, primary equipment nozzles, primary equipment supports, and the pressurizer surge line piping. The methods, criteria, and requirements used in the existing design basis analysis for CPSES, Unit 2, piping and supports were used for the increr. sed RTP evaluation. The licensee performed the evaluation to ensure compliance with the Crede of record. No new methods or new computer codes were used other than those used in the original design basis analyses, as described in the CPSES FSAR.

.e

! ' The RCS pressure remains unchanged for the proposed increase in RTP. The actual hot leg

'and cold leg temperatures for the increase in RTP are projected to vary about 4 'F from the corresponding temperatures at the current RTP. The licensee indicated that there is sufficient margin in the existing analysis to envelop the thermal forces and stresses associated with the temperature changes defined in Table IV-1 of Reference 1. In addition, the licensee reviewed the fatigue analysis and the stratification loadings of the pressurizer surge lines for the power

. uprate condition in Table IV-1. The licensee concluded that the current analyses that were performed using the envelope of thermal cases remain bounding for the increase in RTP condition.

The NRC staff concludes that the current analyses that were performed using the envelope of thermal cases remain bounding for conditions corresponding to the proposed increase in RTP.

The licensee also indicated that the design transients used in the evaluation of the RCS piping systems and equipment nozzles are unchanged for the increase in RTP with regards to the type and number of occurrences during the 40-year plant operation. The loop hydraulic forces will increase slightly due to the dacrease in the cold leg temperature and the increase in water density at conditions corresponding to the proposed increase in RTP. The licensee indicated that the small increase (about 3 percent) in LOCA loads for the increase in RTP is offset by the model improvement and the application of leak-before-break technology, which reduces the

- LOCA loads about 30 percent. Therefore, the current LOCA hydraulic forcing functions are bounding conditions corresponding to the proposed increase in RTP. The licensee concluded

- that the existing stresses and loads for the piping and supports remain bounding conditions corresponding to the proposed increase in RTP..The licensee also reviewed the existing fatigue analyses for the reactor coolant piping, nozzles, and auxiliary lines, and concluded that there are sufficient margins to accommodate the slight increase in CUFs due to changes in the

- range of temperatures associated with cooldown and heatup events following the power uprate.

' On the basis of its review, the staff concludes that the existirig NSSS piping and supports, the primary equipment nozzles, the primary equipment supports, and the auxiliary lines connecting

. to the primary loop piping will remain in compliance with the requirements of the design basis criteria, as defined in the.FSAR, and are acceptable for the proposed increase in RTP.

3.4.11 BOP Systems and Motor-Ooerated Valves (MOVs)

The licensee evaluated the adequacy of the BOP piping systems based on comparing the existing design basis parameters with the core power uprate condition shown in Table IV-1 of l Reference 1, with regard to the RCS temperatures, steam temperature, and steam flow rate.

The following BOP piping systems were evaluated for increased RTP: main steam, extraction steam, feedwater, SG blowdown, auxiliary feedwater, extraction steam, heater drains, condensate, circulating water, turbine plant cooling, secondary sampling, spent fuel pool cooling, residual heat removal, component cooling, station service water, and combustible gas control. As a result, the licensee concluded that the existing CPSES, Unit 2, BOP systems, structures,' and components ecMinue to remain in compliance with all CPSES, Unit 2, design basis requirements at condit' ors corresponding to the proposed increase in RTP.

In Reference 3, the licensee stated that the BOP safety-related valves were found not to be impacted by the proposed increase in RTP. This determination was further confirmed by verifying that changes in system operating temperature, pressure, and flow rate were bounded I

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by the requirements of the associated equipmen't specification. As such, the increased thrust required to (perate the MOVs due to expected differential pressure conditions is within the

capabilities of the existing valve actuators.

' On the basis of its review, the NRC staff concludes that the increase in RTP will have no adverse effects ' n the safety related valves and the CPSES, Unit 2, MOV program.

o j The licensee assessed auxiliary equipment (including the heat exchangers, pumps, valves, and

- tanks) for the Teoto increase from 560 to 563 'F. The evaluation indicated that the fatigue usage values for each component remain below the allowable limit and that the components continue to comply with the current design criteria.- On the basis'of its analysis, the licensee concluded that the BOP piping, pipe supports and equipment nozzles, heating, ventilation, and air conditioning systems, and valves remain acceptable and continue to satisfy the design basis requirements for conditions corresponding to the proposed increase in RTP.

On the basis of its review, the NRC staff concludes that the increase in RTP has no significant impact on the design basis for components within affected BOP systems.

3.5 Instrumentation and Controls

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The LEFM/ system is an updated version of the original LEFM developed by Westinghouse and is used in the determination of feedwater flow. The LEFM/ consists of a common control i

unit in the control room with a spool piece installed in the main feedwater system (or line.) The LEFM/ manufactured by Caldon and installed at CPSES, Unit 2 is an ultrasonic flow meter utilizing time-of-flight (transit time or counter propagating) technology. An additional feature of the LEFM/ is the use of multiple chordal paths with the transducers mounted within a spool piece. This arrangement, as stated in Topical Report ER-80P, provides better definition of the flow profile and more accurately defines dimensional parameters such as path length, path angle, and pipe diameter, therefore improving the accumcy of the spool piece mounted LEFM/

f with respect to its clamp-on version.

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in the review of Topical Report ER 80P, the staff found that chordal, spool piece mounted, transit time ultrasonic meters can achieve accuracies of.5 percent of indicated flow. A key element in achieving installed high accuracy with an ultrasonic flow meter (or flow meters overa!!) is an accurate representation of the profile factor, including extrapolation to higher Reynolds numbers. One method of achieving high installed accuracy is to calibrate the flow meter in a piping arrangement representative of the plant-specific installation. For the LEFM/,

accurate fluid temperature correlation is also a factor since the speed of sound in the fluid (as a function of feedwater temperature) is used in the calculation of reactor thermal power. A calibration of a flow meter in piping modeled after the plant arrangement at Reynolds numbers encountered in service can help maintain instrument calibration once installed.

Several differences are associated with the installation of the LEFM/ as opposed to the installation of a flow venturi for a stated accuracy. For example, Caldon installs an LEFM/ in one to four feedwater lines, whereas venturi flow elements are installed in each feedwater line.

NRC staff review of plant thermal power measurement using venturiinstrumentation shows a range of uncertainty between 1.3 and 2.0 percent. In these installations, instruments are installed on each feedwater line, whereas a single LEFM/ will be installed at CPSES, Unit 2.

Additionally, the LEFM/ hydraulic model and calibration include the plant piping arrangement, unlike a venturi, which is generally calibrated in straight pipe.

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! An examination of the uncertainties attributable to each type of flow meter provides an insight into the feedwater measurement uncertainty attributable to the LEFM/ system. As stated by the licensee, flow uncertainties for the LEFM/ are grouped into the following categories:

, hydraulic, geometric, tirne measurement, and correlation uncertainties (temperature, density, and pressure). As stated by the licensee, the dominant measurement uncertainty is for system hydraulics. A venturi-based system includes similar categories of uncertaintles: hydraulics, geometry, instrumentation, and feedwater density. A venturi flow element installation uses instrumentation for pressure and differential pressure measurement to obtain an appropriate output from the venturi flow element and also requires separate fluid temperature measurement instrumentation. This additional instrumentation can be a significant contributor to the overall flow measurement uncertainty. Additionally, most licensees do not calibrate venturi flow elements to a plant specific installation. Because the plant installation may not be free of

' velocity effects, most venturi installations provide for additional systematic uncertainty to account for any flow-induced bias that may be present (typically.25 percent for CPSES, Unit 2).

This bias is added on the basis of susceptibility of flow nozzles to rotational flow components.

~ To improve measurement uncertainty, venturi-based systems may take credit for multiple

. venturi elements (each feedwater line, errors assumed uncorrelated) in the determination of feedwater flow and thermal power measurement. This treatment can affett the uncertainty magnitudes of venturi-based measurement systems by reducing the measurement uncertainty by In (n= number of loops). Topical Report ER-80P also takes credit for multiple LEFM/ flow elements when employed. However, the NRC staff noted that the CPSES, Unit 2, thermal power measurement uncertainty methodology does not credit the multiple elements in the CPSES, Unit 2 calculation since the LEFM/ installation at CPSES, Unit 2, is only a single flow element installation.

The improvements in flow measurement uncertainty attributed to the LEFM/ over a venturi-based system exist in several areas. The LEFM/ shows a reduction in instrument uncertainties for plant-specific installations, although Caldon includes an additional modeling uncertainty The bias penalty taken for flow nozzles is not required, based on the operating characteristics of the LEFM/ and assumed LEFM/ calibration in a piping arrangement modeled after the plant-specific installation. The measurement uncertainty for ancillary instrumentation is reduced substantially as well with the LEFM/. Correlation and hydraulic uncertainties are reduced. In contrast to a venturi flow element, fouling of the LEFM/ spool piece is not a significant concern (no flow restriction) and is essentially eliminated.

The LEFM/ also improves the measurement uncertainty of venturi-based systems by quantifying velocity profiles and correcting them through LEFM/ calibration, modeling for installation effects (elbows, drain lines, reducers, orientation, pipe diameters, etc.), and LEFM/

operational data.

Time-of flight meters, including the Caldon LEFM/, determine fluid velocity by establishing the speed of sound through the fluid. Because the speed of sound in relation to fluid temperature i

. and pressure is also known, the LEFM/ system can determine fluid temperature. The LEFM/

shows improved uncertainty for thermal power measurement when resistance temperature detector (RTD) feedwater temperature measurement is replaced with the LEFM/ system. The licensee' replaced the RTD inputs only for thermal power measurement. The improvement in measurement uncertainty is based on accurate temperature / pressure / sound velocity correlation used in the LEFM/ system and comparative testing with plant temperature instrumentation.

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e On the basis of the preceding information, the _LEFM/ can improve on the accuracy of a venturi-based system by (1) the elimhation of significant time-dependent effects, (2) the l

analysis of transducer inaccuracies (including system clock) through system diagnostics, (3) the

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reduction in ancillary instrumentation uncertainties, and (4) the operating and performance characteristics of the LEFM/ itself. An evaluation of the LEFM/ uncertainty budget, including performance data, shows that the LEFM/ can reduce the feedwater flow and thermal power measurement uncertainty.

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However, the failure / degradation of the LEFM transducers (coupling to the fluid) may provide a time-dependent effect if there is no corresponding method to detect the degradation.

Additionally, the LEFM/ system clock may experience drift as well. In the LEFM/ system, online diagnostics and surveillance are designed to maintain clock accuracy and detect degradation in LEFM/ signal characteristics to limit the time dependencies of these uncertainties.

I Topical Report ER-80P states that the LEFM/ spool pieces are calibrated in a calibration laboratory to standards traceable to the National Institute of Standards and Technology (NIST).

Caldon also stated that calibration is performed in a piping arrangement that represents

. (models) the plant-specific installation. Caldon then applies a meter factor to the instrument

< that represents the installation model. However, the flow rates and/or temperature range of most calibration facilities are limited compared with the flow rates / temperatures of a plant feedwater system. Because the test facility used by Caldon cannot approach the Reynolds numbers of the plant-specific application (because of temperature constraints), Caldon must project the profile factor for the LEFM/ to higher Reynolds numbers encountered in plant feedwater systems. The licensee stated that testing has shown upstream hydraulic features, such as bends and tees, cause axial and transverse velocity distortions but have minimal effect on the established profile factor and corresponding meter calibration. Although a chordal ultrasonic flow meter can be shown to be resistant to velocity profile effects, the NRC staff notes that there are piping arrangements that can affect the profile factor and calibration. This situation may repire additional installation / calibration criteria to avoid this effect. The installation at CPStiS, Unit 2,~ as stated by the licensee, is not subject to additional installafon effects from those seen in previous spool piece calibrations. The licensee also provided additional data and procedures for the extrapolation of profile factors to higher Reynolds numbers.

The original LEFM installation at CPSES, although typical of Westinghouse installations, does not comply with all of the installation criteria as outlined in Topical Report ER 80P. The installation assumptions and criteria outlined in Topical Report ER 80P are intended to ensure that the uncertainty and accuracy of the updated LEFM/ will support an uprate in thermal power. The original LEFM installation accuracy requirements were not as critical, and original testing and uncertainty allowances reflect this fact. The licensee used the original CPSES LEFM installation to quantify any fouling in the venturi and provide a means to quantify this phenomenon when it occurred. With respect to Topical Report ER 80P, the differences in the 1

CPSES installation include an uncalibrated original LEFM spool piece, with no modeling of the

,J CPSES piping arrangement. The LEFM installation and, subsequently, the updated LEFM/

1 installation are different from the installation generally assumed in Topical Report ER-80P in

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that the spool piece was not calibrated at a calibration facility traceable to a standard nor was i

the piping arrangement at CPSES, Unit 2, modeled during calibration. Because of these installation differences, the uncertainty of the updated LEFM/ may not account for the

installation and calibration differences of the original LEFM spool piece installation. To comply with Topical Report ER-80P, and the correspondir g NRC staff Safety Evaluation (SE) contained in Reference 10, the licensee provided additional information concerning CPSES, Unit 2, piping geometry, calibration uncertainties, and test results to quantify and bound the measurement uncertainties (calibration / installation effects) of the updated LEFM/ installation.

This step makes the installation at CPSES consistent with Topical Report ER-80P The sample certification included in Topical Report ER 80P states that a complete hydraulic test report for site-specific model(s) will be included in the documentation. Topical Report ER 80P also states that for spool pieces for which the profile factor was not measured for a unit installed in a plant, the installed spool piece uncertainties due to dimensions will be bounding and included in the uncertainty for thermal power measurement. The licensee has submitted data to show that by analysis and testing the installation at CPSES is comparable to previous installations, test configurations, and LEFM/ profile factor assumptions. The licensee stated that, on the basis

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- of production tolerances and previous laboratory calibrations to known piping arrangements, the accuracy of the LEFM/ feedwater flow measurement at CPSES, Unit 2, is capable of improved thermal power measurement uncertainty (less than 1 percent).

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- With regard to the NRC staff SE for Caldon Topical Report ER 80P, the SE includes four additional criteria that a licensee incorporating Topical Report ER-80P in its licensing basis

~ hould address:

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a.

The licensee should discuss the maintenance and calibration procedures that it will

' implement with the incorporation of the LEFM/. These procedures should include processes and contingencies for inoperable LEFM/ instrumentation and the effect on thermal power measurement and plant operation.

> The licensee responded that an earlier LEFM system is currently installed at CPSES.

The licensee states that it will update the existing procedures for the LEFM (calibration / maintenance) to incorporate vendor requirements necessary for the installation and operation of the new LEFM/ system.

The licensee provided information on the maintenance and surveillance requirements of the LEFM/. The designated surveillance includes on-line diagnostics and limited periodic tests.

The licensee has also stated that procedures,used to pedorm a unit calorimetric measurement to adjust the Power Range Nuclear instrumentation System (NIS) and

- N-16 channels will be revised to incorporate the installation of the updated LEFM/

system. The revised procedures will provide for a contingency plan and instructions for those occasions when the LEFM/ system is unavailable.

Guidance on LEFM/ unavailability will be included in the plant Technical Requirements Manual. The guidance proposed by the licensee directs the operators to operate the plant consistent with the accident analysis and the uncertainties associated with each method of determining plant thermal power (LEFM/ or venturi-based feedwater flow instrumentation).

If ths LEFM/ becorr.es unavailable during the intervals between performance of the TS surveillance requirements, plant operation al a thermal power of 3445 MWt may

e continue. However, to remain in compliance with the bases for operation at an RTP of 3445 MWt, the LEFM/ must be retumed to service bvfore the performance of Surveillance Requirement (SR) 3.3.1.2, which requires comparison of calorimetric heat balance, to NIS and N-16 Power Monitor channel output, and adjustment based on results, every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Procedural guidance would require that reactor power be reduced or maintained at a power level less than or equal to 99 percent RTP (3411 MWt). This reduction in power is intended to be performed before performing SR 3.3.1.2 in order to remain within the plant's design basis immediately upon performance of SR 3.3.1.2 with an inoperative LEFM/. In order to maintain compliance with the safety analysis, it is necessary to operate the plant at a maximum core thermal power of 3411 MWt, on the basis of a venturi-based power measurement uncertainty of 2 percent RTP when using feedwater venturiinstrumentation. Core power would be maintained at a value less than or equal to 3411 MWt until the LEFM/ is returned to service and SR 3.3.1.2 has been performed using LEFM/

instrumentation. Once the LEFM/ is returned to service, the plant can be operated at 3445 MWt. The staff notes that the licensee has mritained the 2 percent margin in the basis for the N-16 and power range neutron flux setpoints to accommodate a failed LEFM/.

The licensee will also revise the CPSES FSAR to reflect both methods of thermal power measurement and the associated instrument uncertainty terms, which is acceptable to the NRC staff.

b.

For plants that currently have LEFM/ s installed, the licensee should provide an evaluation of the operational and maintenance history of the installation and confirm that the instrumentation is representative of the LEFM/ system and bounds the analysis and assumptions set forth in Topical Report ER-80P.

The licensee currently has an earlier version of the LEFM installed at CPSES and stated that the only problems encountered to date involved the LEFM transducers.

The licensee stated that this failure is occasional and that is identified by loss of a transducer signal, and that it does not cause a reduction in LEFM accuracy that is not readily apparent. The NRC staff's reviews identified licensee event reports attributable to LEFM failures as well. The vendor and the licensee provided additionalinformation to address these concerns and to show that current LEFM/ systems have been updated to prevent the recurrence of problems. The licensee will update the CPSES, Unit 2, LEFM system such that the LEFM will conform to the LEFM/ system presented in Topical Repcrt ER-80P. The updated LEFM/ system includes the updated hardware / electronics and software to conform to the requirements of Topical Report ER-80P. The licensee's factory acceptance testing will document that the LEFM/ installed at CPSES, Unit 2, complies with the system presented in Topical Report ER-80P. The NRC staff finds that the licensee has satisfied the previously mentioned criteria and this change is therefore acceptable.

c.

The licensee should confirm that the methodology used to calculate the uncertainty of the LEFM/ in comparison with the current feedwater instrumentation is based on accepted plant setpoint methodology (as for the development of instrument uncertainty). If an altemative methodology is used, the application should be justified and applied to both venturi and ultrasonic flow measurement instrumentation for comparison.

-- The staff notes that the Appendix K rule assumes that the 2 percent margin accounts a.

for uncertainties associated with the measurement of thermal power. Contributars to the uncertainty were not identified and the magnitude of the uncertainty was not demonstrated by experiment or analysis. The rule does not require quantification of actual uncertainties nor did the background documentation for the rule discuss any detailed technical basis for the choice of a 2 percent margin. However, for a power uprate, such as proposed for CPSES, Unit 2, the NRC staff determined that an evaluation of the uncertainty methodology employed for the power uprate reque.t should be documented.

The licensee stated that the methodo!ogy used to calculate the power calorimetric uncertainty for CPSF.S, Unit 2, is the same as that referenced in Topical Report ER-80P and follows the standard of ANSl/ASME Performance Test Code (PTC) 19.1 - 1985, " Measurement Uncertainty." The methodology is the same as that of Topical Report ER-80P except that CPSES, Unit 2, does not credit the venturi coefficient errors as a systematic error or take credit for multiple venturi flow elements.

ANSI /ASME PTC 19.1 defines and describes methods used to estimate measurement uncertainty. This methodology is used for the development of an uncertainty model for analysis, the reporting of test results and validation (acceptance testing, for example). This standard serves as a reference to other PTC 19 series standards and to ASME performance test codes.

The NRC staff has not reviewed ANSI /ASME PTC 19.1 or endorsed its use in a regulatory guide. The NRC staff did not review ANSI /ASME PTC 19.1 regarding its acceptability or applicability in the determination of safety-related setpoints, limiting safety system settings, or allowable values. The NRC staff did not evaluate the standard regarding uncertainty methodologies that a licensee may have implemented in the development of TS parameters representing safety analysis assumptions (for which thermal power may be included); however, the NRC staff evaluated the attemative approach as discussed below.

The NRC staff has endorsed Instrument Society of America (ISA) standard ISA 67.04, 1982," Safety-Related Instrumentation Used in Nuclear Power Plants," for the establishment of safety-related setpoints through RG 1.105, Revision 2," Instrument Setpoints for Safety Related Systems." The NRC staff notes that the techniques used by ANSI /ASMS PTC 19.1 provide an alternate approach to the square root sum-of-the squares (SRSS) techniques presented by ISA 67.04 with regard to bias error and differ in the application of uncertainty " coverage" when compared with ISA 67.04.

The NRC staff also recognizes that ANSI /ASME PTC 19.1 is intended for applications different from those of ISA 67.04 and may be appropriate for the determination of measurement uncertainty for thermal power measurement acceptance testing. Still, for TS values related to safety analysis assumptions, the applications of ISA 67.04, PTC 19.1, or a plant specific methodology, should be consistent with current plant practice when implementing methodologies for thermal power uprate based on improved measurement uncertainty. On the basis of this information, the NRC staff found that the methodology used by the licensee was consistent for thermal power measuremer,t, inc:uding the 1 percent power uprate request and satisfies the NRC staff SE criteria contained in Reference 10.

-24 d.

Licensees for plant installations in which the ultrasonic meter (including the LEFM/) was not installed with flow elements calibrated to a specific piping arrangement (flow profiles and meter factors not representative of the plant-specific installation) should provide additional justification for use. This justification should show that the meter installation either is independent of the plant-specific piping arrangement for the stated accuracy or can be shown to be equivalent to known calibrations and plant arrangements for the specific installation, including the propagation of flow profile effects at higher Reynolds numbers. Additionally, for previously installed calibrated elements, the licensee should confirm that the piping arrangement remains bounding for the original installation and calibratio,1 assumptions.

The installation of the LEFM/ at CPSES, Unit 2 uses an in-line spool piece installed in the e

main feedwater header. This installation is an alternative to the installation of LEFM/

spool pieces in each feedwater line and is an acceptable alternative according to Topical j

Report ER-80P for thermal power measurement. T he licensee performed a plant-specific evaluation, including test results, and calculations, to develop a plant-specific profile factor for the LEFM/ system at CPSES, Unit 2. The licensee stated that there has been no change in the feedwater system arrangement that would affect the assumptions, analysis, j

or the calculations used to determine the plant-specific profile factor. The installation of the j

LEFM/ electronics / hardware and software does not affect the LEFM/ spool piece l

installation with respect to profile (no changes to the spool piece itself are made). The j

licensee stated that on the basis of the preceding information, the piping arrangement remains bounding for the original LEFM installation and calibra?!on assumptions. No revisions to piping hydraulics have been made since the original LEFM installation.

The use of the LEFM/ will be limited to calorimetric power determination. Through the use of the updated LEFM/, the power calorimetric uncertainty is less than 1 percent RTP.

However, this uncertainty is not applicable when the RTP is based on venturi-based feedwater instrumentation, even if the updated LEFM/ is used to correct the venturi-based flow indications for effects such as fouling.

An additional point required by the NRC staff's SE on Topical Report ER 80P was that licensees should confirm that no additional uncertainties beyond those included in Topical Report ER-80P are included in the 10 CFR Part 50, Appendix K,2 percent uncertainty allowance. The licensee stated that the uncertainties assumed in Topical Report ER-80P are considered complete and that no additional uncertainties were assumed in the 10 CFR Part 50, Appendix K,102 percent thermal power margin requirement for CPSES, Unit 2.

The NRC staff notes that the LEFM/ is not considered safety related (for thermal power determination) but that the system software was developed and will be maintained under a verification and validation (V&V) program consistent with Institute of Electrical and Electronic Engineers (IEEE) standard 7-4.3.2 - 1990, "lEEE Standard Criteria for Digital Computers in Safety Systems of Nuclear Power Plants" and ASME standard NOA-2a -1990," Quality Assurance Requirements of Computer Software for Nuclear Facility Applications," Subpart 2.7.

The licensee stated that the V&V program was applied to all system software and firmware.

On the basis of tne NRC staff's review of Topical Report ER-80P, industry experience with ultrasonic flow meter technology, information provided by the licensee, and the evaluation of the plant-specific installation at CPSES, Unit 2, the NRC staff finds that the capability exists such

f i

-25 that feedwater flow and f,emperature measurement uncertainties cari be quantified such that thermal power measurement uncertainty can be limited to 1 percent and can support a proposed 1 percent power uprate for CPSES, Unit 2. The licensee provided additional information to resolve plant-specific criteria outlined in the NRC staff's SE on Topical Report L

ER-80P, including maintenance / calibration, maintenance history, hydraulic arrangement, methodology, and site-specific criteria.

u 3.6 Safety Analysis and Chances to the License and the T.Rs -

The NRC staff's safety evaluations approving the CPSES, Unit 2, exemption to Appenalix K (Reference 12) and the Caldon topical report on the LEFM/ (Reference 11) raised issues that the staff intended to address in the proposed power uprate review. The staff's approval of the Appendix K exemption did not midress overall risk impact and safety margin of the proposed

- change, leaving these issues for consideration during the power uprate' review. The evaluation of the Caldon topical report (Reference 10) highlighted concerns related to plant-specific LEFM/ performance information, maintenance and calibration, and appropriate application of setpoint methodology. The staff's review of the exemption request (Reference 9) also emphasized the need for incorporating the Caldon topical report and related plant-specific information into the plant licensing basis.

3.6.1'. LOCA' Analysis i

CPSES, Unit 2, conforms to the Appendix K power level requirement since the analyses of ECCS performance for the plant were condu:ted assuming that the reactor had been operated at a power level of 102 percent of licensed power. The licensing-basis analysis for the LOCA is discussed in Sections 4 and 15 of the CPSES FSAR, which references topical reports that describe the analysis methods and assumptions. NRC approved methodologies are also listed in TS 5.6.5. The FSAR cites a licensee topical report (Reference 15) and FSAR Section 15.6, both of which state that the assumption used for reactor analysis during the large-break LOCA is.102 percent of licensed power. The licensing basis for small-break LOCA analysis appears In another licensee topical report (Reference 16), which uses the analysis assumption of 1'02 percent of licensed power. The peak cladding temperatures (PCTs) given in the FSAR are listed below for each unit.

1 Peak Cladding Temperature Results From LOCA Analyses LOCA Type Unit 1 Unit 2 Small Brea{

1695'F 1781*F Large Break 2013*F 2119'F The results of the CPSES, Unit 2, LOCA analyses meet the requirements of 10 CFR Part 50,

. Section 50.46.'

e 3.6.2 Non-LOCA Safety Analyses Most safety analyses for CPSES, Unit 2, were conducted assuming 102 percent of RTP, For

. maay of these analyses, the licensee conforrned to Standard Review Plan (SRP) guidance in ch60 sing an assumed initial power level of 102 percent on the basis of riccuunting for power measurement error. Other safety analyses (for example, SG tube rupture) kssumed an initial power level below 102 percent of RTP. Although the licensee has conducted NSSS component analyses for affected primary, secondary, and BOP systems at 104.5 percent power, corresponding safety artalyses were not included in the submittal.

The following table summarizes the power level assumptions under the current CPSES, Unit 2, licensing basis:

1 i

7: Initial Power Levels Currently Used in Comanche Peak Unit 2 Licensing Analyses FSAR Section*

Event Maximum Assumed initial Power Level (% of 3411 MW) 15.1.1 Decrease in Feedwater Temperature 102 15.1.2 increase in Feedwater Flow 102 15.1.3 Excessive increase in Steam Flow 102 15.1.4 Inadvertent Opening of a Steam Generator Relief or Safety Valve 102 15.1.5 Main Steamline Break 102

~

15.2.2 Loss of External Electric Load

_._ _ Turbine Trip

, _.. _ _ _. _ _. _ _. Bounded by turbine trip

. ~... _ _..- _ _ _. _ _ _... _ _. _. _. _. _

15.2.3 102 15.2.4 Inadvertent Main Stearn Isolation Valve Closure Bounded by turbine trip 15.2.5 Loss of Condenser Vacuum Bounded by turbine trip l

15.2.6 Loss of Offsite Power 102 15.2.7 Loss of Normal 5eedwater 152 15.2.8 Feedline Break 102 15.3.1 Partial Loss of Reactor Coolant System Coolant Flow 102 15.3.2 Complete Loss of Reactor Coolant System Coolant Flow 102 15.3.3 Reactor Coolant Pump Shaft Seizure (Locked Rotor) 102 15.3.4 Reactor Coolant Pump Shaft Break Analyzed with locked rotor 15.4.1 Uncontrolled Rod Cluster Control Assembly (RCCA) 0 W thdrawal From Subentical 15.4.2 Uncontrolled RCCA Withdrawal From Power 102 15.4.3 RCCA Misalignments 102 Dropped RCCA/ Dropped Bank 100 7 2 uncertainty 15.4.6 Inadvertent Boron Dilution 100 15.4.7 Mistoaded Fuel Assembly 102 15.4.8 Rod Ejection 102

~

15.5.1 lnadvertent ECCS Actuation 1b2 15.5.2 Chemical and Volume Control System Malfunctions Bounded by inadvertent ECCS actuation 15.6.1 lnadvertent Opening of a Pressurizer Safety or Relief Valve 102

. Letdown Line Rupture Dose calculation only 15.6.2

_ _ _...SG Tube Rupture 101 15.6.3 15.6.5 LOCA 102 LOCA Mass & Energy Releases for Containment Integrity 104.5 Steamline Break Mass & Energy Releases 102

• FSAR section numbers corresponding to non-applicable SRP sections are omitted The NRC staff noted that SG tube rupture is evaluated at 101-percent power and, boron dilution at nominal power, and that power measurement uncertainty is statistically considered in the dropped rod control cluster assembly (RCCA) event, rather than by the direct addition of 2 percent to the RTP.

3.6.3 ' Safety System Setooints The licensee's application, and supplements, propeses changes to the setpoints and associated values of the N-16 overpower and power rango neutron flux functions. The N-16 overpower trip ensures fuel integrity for possible overpower conditions and the power range neutron flux-high trip provides protection during reactivity excursions.

Activity from radioactive decay of _N-16 in the primary coolant water is used for continuous measurement of reactor power level. N-16 is formed by high energy neutron activation of oxygen 16 that is present in the reactor coolant. N-16 activity is directly proportional to the integrated fast neutron flux in the core and thus serves to measure core power. The N-16

activity is monitored outside each of the four RCS hot-leg pipes.

Two reactor protection functions rely on the power indication provided by the N-16 monitoring system. These functions are the overtemperature N-16 and overpower N-16, and they are discussed in a licensee topical report (Reference 17). Along with the overtemperature N-16 trip, the overpower N-16 trip is designed to protect against fuel centerline melting, departure

. from nucleate boiling (DNB), and hot-leg saturation during postulated events, ensuring that the allowable heat generation rate of the fuelis not exceeded. It provides protection equivehnt to the overpower AT function employed at other plants. The overpower N-16 trip function also limits the required range of the overtemperature N-16 trip function and serves as a backup to the power range neutron flux-high trip. This is because overpower N-16 is insensitive to variations in reactor vessel downcomer fluid density that affect power range neutron flux readings. The overpower N-16 trip is credited in the analysis of the decrease in feedwater temperature event, uncontrolled RCCA withdrawal at power, and excessive steam demand events.

The power range neutron flux-high trip is credited in the analysis of uncontrolled RCCA withdrawal at low power and at full power, inactive reactor coolant pump startup at incorrect temperature, and other events. A complete list of the analyses that credit the power range neutron flux-high trip is presented in the CPSES FSAR Table 7.2-4, " Reactor Trip Correlation."

3.6.4 Eleview Scooe in its application, as supplemented, the licensee proposed using a 1-percent power uncertainty

)

allowance in place of the 2 percent currently used in most safety analyses. The proposalis made on the same basis used to support the exemption from the Appendix K requirement to conduct ECCS evaluations at 102 percent of RTP. Therefore, the NRC staff began its review of the accident analyses by assessing (1) the possible effect on safety analyses of the reduced analysis margin and (2) the proposed higher power condition. The NRC staff also reviewed the suitability of proposed safety system setpoints for the higher power level, the applicability of

. existing safety analysis topical reports used by the licensee, and the cignificance of the change l

ns defined in 10 CFR Part 50, Section 50.46.

]

The licensee's application, as supplemented, was not presented as a risk-informed licensing action. However, the NRC staff sought to confirm that plant risk and safety margins would not be materially affected by the proposed change. Generally, a low risk impact is attributed to j

O l

i small power uprates, and the NRC staff sought to confirm that point for this application, as supple lnented."

in addition to the material su~umitted in the application, as supplemented, the NRC staff based its review on the CPSES FSAR and other topical reports.

3.6.5 ' Acceptance Criteria in its application, as supplemented, the licensee stated that it had conducted the eva'uations and analyses used to support the proposed power uprate consistent with WCAP-10263 (Reference 18). The Westinghouse report describes safety evaluations and component design reviews needed to support a power level increase for Westinghouse PWRs. Revised safety analyses were not included in the licensee's application, as supplemented, but the licensee did conduct component analysis under the new conditions.

As discussed earlier, most of the existing licensing-basis analyses were conducted assuming 102 percent of rsted power. In addition to appearing in the Appendix K rule for ECCS evaluations, the 102-percent power specification is used in a number of SRP sections. The tables that follow show SRP sections that (1) incorporate the 102-percent value but offer the option to justify a smaller value and (2) give the 102-pc cent value without an alternative.

SRP Sections Containing the 102 Percent Power Margin With an Option SRP Section Title 15.2.6 Loos of Non-emergency AC Power to the Station Auxiliaries 15.2.7 Loss of Normal Feedwater Flow 15.3.1-15.3.2 Loss of Forced Reactor Coolant Flow, including Trip of Pump and Flow Controller Malfunctions

'15.3.3-15.3.4 Reactor Coolant Pump Rotor Seizure and Reactor Coolant Pump Shaft Break 16.4.3 Control Rod Misoperation (System Malfunction or Operator Error) 15.5.1-15.5.2 Inadvertent Operation of ECCS and Chemical and Volume Control System Malfunction That increases Reactor Coolant Inventory 15.6.1 Inadvertent Opening of a PWR Pressurizer Relief Valve or a BWR Relief Valve 15.6.5 Loss-of-Coolant Accidents Resulting From Spectrum of Postulated Piping Breaks Within the Reactor Coolant Pressure Boundary 2

NRC staff reviews of extended power uprates for two boiling-water reactors (much greater than 1 percent increases) did not identify significant risk increases. The NRC staff has taken the position that risk evaluations are not expected to accompany applications for marginalincreases in licensed power. See NRC letter from the Executive Director for Operations to the Advisory Committee on Reactor Safeguards,

' Staff Response to ACRS Letter of July 24,1998, on General Electric Nuclear Energy Extended Power Uprate Program and Monticello Nuclear Generating Plant Extended Power Levelincrease Request,"

September 14,1998.

! - SRP Sections Specifying the 102 Percent Power Requirement f

SRP Section Title 6.2.1.3 Mass and Energy Release Analysis for Postulated Loss-of-Coolant Accidents 6.2.1.4 Mass and Energy Release Anaysir, for Postulated Secondary System Pipe Ruptures 15.1.1-15.1.4 Decrease in Fedwater Temperature, increase in Feedwater Flow, increase in Steam Flow, anJ Inadvertent Opening of a Steam Generator Relief or Safety Valve 15.2.1-15.2.5 Loss of External Load, Turbine Trip, Loss of Condenser Vacuum, Closure of Main Steam Isolation Valve (BWR), and Steam Pressure Regulatory Failure (Closed) 15.4.6 Chemical and Volume Control System Malfunction That Results in a Decrease in Boron Concentra' ion in the Reactor Coolant (PWR)

The licensee often used an assumption of 102 parcent of rated power in analyses of events not previously listed. The licasee linked the assumption to uncertainties in power measurement in the same way that it is linked in the analyses listed and for the LOCA.

To determine the acceptability of the proposed changes to protection system setpoints, the NRC staff referred to WCAP 12123 (Reference 19). The staff consulted SRP Chapter 19 (Reference 20) cnd previously stated NRC staff positions on power uprates for guidance in evaluating the risk impact of the proposed change.

3.6.6 Safety Analyses The licensee's application, as supplemented, stated that the existing safety analyses that apply a 2-percent allowance for power measurer.:ent uncertainly could be used to support the proposed higher rated thermal power with an allowance of 1 percent. This appears reasonable because ant. lyses conducted at 102 percent of the current RTP and those conducted at 101 percent of the RTP are initiated at essentially the same RTP. Therefore, the primary consideration is whether the margin included in the assumed initial power for safety analyses accounts only for power measurement uncertainties, as the NRC staff has concluded is the case for LOCA analyses.

i in considering the exemption to Appendix K, the NRC staff understood that there is a j

considerable margin between ECCS performance requirements and the results of existing LOCA analysis. The considerable margin gave the NRC staff confidence that the marginal increase in RTP would not introduce unexpected effects that might change the course of current analyses nor the acceptability of analysis methods. The staff sought to determine if this confidence could be extended to other analyses.

l The margin for assumed initial power for safety analyses is intended to account for i

uncertainties in measuring reactor power. The assumption does not, by itself, ensure safety I

margins, and its proposed reduction does not necessarily result in reduction in margins of safety, SRP Chapter 19,"Use of Probabilistic Risk Assessment in Plant-Specific, Risk informed Decisionmaking: General Guidance" (Reference 20) directs that any reduction in margin should appropriately reflect understanding of the uncertainties involved and the potential impact of the proposed change. The NRC staff used the SRP Chapter 19 guidance although it does not appear that a safety margin was being reduced in the licensce's proposal.

A safety margin represents an allowance for uncertainty in pedormance of structures, systems, and coniponents (SSCs). Guidance in SRP Chapter 19 states that proposed revisions to the u-licensing basis should provide sufficient margin to account for uncertainty in analysis and data.

In this case, the licensee has presented information showing the uncertainties associated with the LEFM/ for feedwater flow measurement. The licensee has also demonstrated that, when

using the LEFM/ rather than venturi flow measurement, there is less likelihood that power level at the onset of a LOCA or other event would exceed the proposed power level of 101 percent

assumed for analysis.' The NRC staff accepted the licensee's arguments in approving the request for exemption from the power level requirement in Appendix K.

The margin of safety' for a particular event is most directly determined by comparing the predicted results of the event to an appropriate safety limit, such as a fuel or core performance limit (e.g., departure from nucleate boiling ratio - DNBR). The licensee submitted information in the Caldon, Inc., topical report (Reference 10) and in responses to stati questions (References 2,5, and 6) regarding the expected effect on various safety margins of employing the LEFM/ and reducing the analysis margin for initial assumed power. These specific cases are discussed below.

The NRC staff generally accepts the licensee's suggestion that the use of a smaller power

- margin for safety analyses in non-LOCA analyses does not erode margins of safety and should be acceptable on the same basis that it is for LOCA analyses. To reach the same level of confidence regarding non-LOCA safety analyses as it did for LOCA analyses, the NRC staff compared the analytical results of selected safety analyses with the associated acceptance criteria.

The NRC staff noted that there were two analyses, for the SG tube rupture and boron dilution events', that were not conducted at 102 percent of the existing RTP. Also, for the dropped RCCA event (commonly referred to as the dropped rod event), the analysis is performed using a statistical combination of uncertainties method described in a licensee topical report (Reference 21). Rather than taking a purely deterministic approach and assuming a power level higher than licensed power in the analysis, the licensee evaluated the event from nominal full power conditions. The uncertainties in initial conditions are statistically combined and then included in the DNBR limit. This is the only event analyzed in this fashion for CPSES, Unit 2.

The NRC staff also chose to evaluate the uncontrolled RCCA withdrawal event because it is an example of the SRP guidance not explicitly assigned an initial pcwer level to account for power measurement uncertainty.'

3.6.6.1 Steam Generator Tube Ruoture The licensee's topical report describing the SG tube rupture (SGTR) methodology (Reference 22) states that the analysis is conducted at 101 percent of RTP. The acceptance criterion for SGTR is that the SG does not overfill before operator action terminates the break flow into the secondary system. Then, the event is evaluated against the dose consequence

. guidelines of 10 CFR Part 100. The dose assessment is performed based on operation at 104.5 percent of RTP.

F The licensee stated that the dose consequences are dominated by the blowdown of secondary fluid from the affected steam generator through the failed-open atmospheric relief valve. As steam generator blowdown is very rapid, the licensee contends that the mass release is insensitive to small power level chariges. The insensitivity was identified in analyses for a

g licensee topical report (Reference 22) and additional calculations that were performed at the proposed higher power level. The recent calgulations confirmed that the mass release, and hence the dose consequences, are insensitive to small changes in the assumed initial power.

3.6.6.2 Boron Dilution

- Boron dilution is conducted at various plant operating states, including nominal full-power conditions as discussed in the licensee topical report (Reference 21) and Section 15.4 of the CPSES FSAR. The acceptance criterion for an uncontrolled boron dilution event at power is that at least 15 minutes must be available between the time an alarm announces the event until shutdown margin is lost to allow operator corrective actions to be taken. Following reactor trip, the fluid conditions will resemble hot zero-power conditions. The initial boron concentrations at hot zero-power conditions (Mode 3) are greater than at full power. A larger initial boron concentration results in a quicker reduction in the boron concentration during the dilution, leading to a faster erosion of shutdown margin. Therefore., the analysis at hot zero-power is more limiting than at full power. The licensee concluded that the boron dilution transient is not

sensitive to the initial power level, but only to the boron concentrations at specified conditions.

3.6.6.3 Drocoed RCCA The dropped rod event is analyzed to demonstrate compliance with the DNBR acceptance limit.

The CPSES, Unit 2, Cycle 5 analysis was conducted using the statistical combination of uncertainties (SCU) method described in a licensee topical report (Reference 21). The system analyses assume nominal full-power conditions at event initiation. Uncertainties in the initial conditions of core power,' reactor coolant system pressure, core inlet temperature, and hot channel peaking factors are statistically combined and included in the DNBR limit. This approach differs from a deterministic calculation, which assumes that all applicable parameter uncertainties occur simultaneously in the most adverse manner. The SCU methodology uses a

" square root sum of the squares" approach along with sensitivity coefficients to combine the

- uncertainties of individual parameters into a single uncertainty factor. In this calculation, nominal values of system parameters are used to obtain a result for the transient analysis, and then the uncertainty factor obtained through the statistical combination method is applied to the result. The NRC staff previously approved use of the SCU methodology for rod drop accident calculations for CPSES, Unit 2 (Reference 23).

For the dropped rod analyses performed to support CPSES, Unit 2, Cycle 5 operation, the licensee stated that analyses were performed at 3411 MW plus 2-percent power uncertainty and at 3445 MW plus 1-percent power uncertainty with the results of the latter being slightly more restrictive. Several bounding assomptions used in analyses from previous cycles were

. retained for the CPSES Cycle 5 analysis, making the analysis more conservative than is required. The analysis result met the DNBR acceptance criterion.

]

. 3.6.6.4 Uncontrolled RCCA Withdrawal The acceptance criterion for the uncontrolled RCC withdrawal event is compliance with the DNBR limit. For the CPSES, Unit 2, Cycle 5 analysis, the licensee analyzed full-pewer cases at 102 percent of the proposed power level of 3445 MWt. This exceeds the proposed analysis i

assumption of 101 percent. The resulting minimum DNBR was greater than the limiting DNBR.

g

, Comparison of the previously discussed results of the safety analyses to the appropriate safety

~ limits for the events gives the NRC staff confidence that s;fficient safety margins will be maintained at the proposed higher power level. The NRC staff examined events in which the existing analyses assumed initial power below 102 percent and one case in which NRC staff guidance did not expressly attribute power margin to power measurement uncertainty. For those events not specifically addressed in detail above, the NRC staff accepts the licensee

- position that the 2-percent allowance for initial power used in those analyses is intended only for power measurement uncertainty, and that margins of safety criteria are not affected.

3.6.7 ' Licensee Toolcal Reoorts The safety analysis methods for many non-LOCA events are described in topical reports identified in CPSES TS 5.6.5. In many of these topical reports, the assumed power level of 102

- percent is used, consistent with Appendix K. In addition to the exemption to the Appendix K power level requirement, the licensee has requested that the methodologies for non-LOCA analyses that use a 2-percent uncertainty be approved for use with a 1-percent power margin, consistent with the Appendix K exemption.

- The licensee proposes the same justification for this change that was used for the exemption:

use of the LEFM/ reduces the probability that actual reactor power would exceed the power level assumed for analysis, even if the uncertainty margin were only 1 percent. The licensee further contends that other conservative assumptions in accident analyses are unaffected by the change in assumed power margin. The licensee gave examples of other conservative analysis requirements, and then concluded that the power level assumption is only one of several conservative assumptions applied in each safety analysis. Based on the use of LEFM/, the licensee contends that a smaller power measurement uncertainty does not reduce the analytical margin in safety analyses.

The NRC staff concludes that a 1-percent allowance for power measurement uncertainty can be applied to safety analyses and the NRC staff concludes that the use of the licensee's topical reports for analyses using 101 percent power is acceptable. However, the licensee should change the stated initial power levelin the topical reports in future revisions of the documents and incorporate this requirement in TS 5.6.5b. Further, TS 5.6.5b should be modified to clearly state when 101 percent or 102 percent of rated power is to be used in safety analyses, based on the availability of LEFM/ feedwater flow measurements for reactor thermal power determination. These changes to TS 5.6.5 were proposed in Reference 8 and are acceptable.

Shouki the LEFM/become inoperable, therefore invalidating the uncertainty analysis supporting the 1 percent margin, the currently accepted margin of 2 percent would again apply, as proposed in Reference 8. Unless the safety analyses were revised, the licensee would face the prospect of operating outside an analyzed condition unth plant power was reduced. This commitment is addressed in Section 3.6.11, herein.

3.6.8 10 CFR 50.46 Criteria in the application, as supplemented, the licensee requested the NRC to confirm that the proposed change in ECCS analyses is not considered significant under 10 CFR Part 50, Section 50.46. A significant change is defined in 10 CFR Part 50, Section 50.46(a)(3)(i) as one that results in a calculated change to peak cladding temperature of 50 *F or more. The change

I proposed by the licensee uses the existir g ECCS analysis results, but revises the uncertainty basis for an input parameter (i.e., initial power). Therefore, the changt is not considered significant since the peak cladding temperature does not change. However, the proposal is a change in methodology that should be reflected in annual ECCS reports submitted in accordance with 10 CFR Part 50, Section 50.46, as proposed in Reference 8. Also, the Caldon topical report (Reference 10) should be included as a COLR reference in CPSES, TS 5.6.5b.

This change to TS 5.6.5b was proposed in Reference 8 and is acceptable. These issues are addressed in Section 3.6.11, herein.

3.6.9 Reactor Protection Setooints The licensee proposed changing the overpower N-16 trip setpoint and allowable values. The trip setpoint would change from less than or equal to 112 percent of RTP to less than or equal to 110 percent of RTP, and the allowable value would change from less than or equal to 114.5 percent of RTP to less than or equal to 113.4 percent of RTP, The power range neutron flux-high trip setpoint would remain unchanged at less than or equal to 109 percent of RTP, but the allowable value would be reduced from less than or equal to 111.7 percent of RTP to less than or equal to 111.1 percent of RTP. The licensee also proposed changing the safety analysis limit for both the overpower N-16 trip function and the neutron power range reactor trip function to 116.8 percent. These values are summarized in the table that follows.

Summary of Proposed Reactor Protection Setpoint Changes Protection System Value Current Proposed

% RTP*

MWt

% RTP*

MWt Safety Analysis Limit 118 4025 116.8 4024 Power Range Neutron Flux-High Trip 109 3718 109 3755 Power Range Neutron Flux-High Allowable 111.7 3810 111.1 3827 Overpower N-16 Trip 112 3820 110 3790 Overpower N 16 Allowable 114.5 3906 113.4 3907

• Note: Current rated power = 3411 MWt; proposed rated power = 3445 MWt The licensee stated that the trips and allowable values for the N-16 overpower function and power range neutron flux-high were determined using WCAP-12123 methods (Reference 19).

The licensee did not propose a change to the N-16 overtemperature trip setpoint because the current setpoint approved in a previous license amendment is based on operation at the proposed higher power level.

The trip value is the nominal setpoint at which the instrument will trip the reactor. To accommodate instrument drift assumed to occur between operational tests and the accuracy to which the setpoints can be measured and calibrated, allowable values for the trip setpoints are specified in TS Table 3.3.1-1," Reactor Trip System Instrumentation." Operation is permitted with setpoints less conservative than the trip value, but within the allowable value.

o I The safety analysis limitis the value of the setpoint used in safety analyses. The allowaNe and the trip setpoint values are based on the safety analysis limit and contain offsets to account for

-inaccuracles in measurement of plant parameters as well as sensor and instrumentation rack inaccuracies.

1 As shown in the table, there is a notable increase in the thermal power corresponding to the setpoint for the power range neutron flux-high trip and allowable values. The NRC staff followed the setpoint methodology in WCAP-12123 (Reference 19) to confirm the validity of the values and to ensure that setpoint margin was available. The setpoint margin is defined in Section 3 of WCAP-12123 and is used to determine the acceptability of the parameters combined to assess the accuracy of a protection system channel. The setpoint margin is basically a comparison of the combined uncertainties associated with the protection function to the difference between the safety analysis limit and the nominal trip value. Tab'e 3-10 of

' WCAP-12123 lists the margins associated with the various protection system functions. The values vary among the functions, but are always positive. In the case of the power range neutron flux high function, the margin is smaller under the revised allowable value, but remains positive. For the overpower N-16 function, the revisions to the trip setpoint and allowable values yield a greater margin. On the basis of the NRC staff's assessment using the setpoint methodology, the changes to the protection system setpoints are acceptable and the proposed Allowable Values in TS Table 3.3.1-1, for " Power Range Neutron Flux - High" and " Overpower N-16,* are acceptable.

e The staff noted that the plant TSs contain a daily surveillance requirement (SR 3.3.1.2) to compare reactor power indications from the nuclear instrumentation system and the N-16 monitoring system to the reactor theimal power determined by calorimetric heat balance. The calorimetric measurement can dih-bv no more than 2 percent of RTP from the nuclear instrumentation or N-16 indications. This surveillance ensures the validity of the 2 percent value for power measurement error used in the setpoint calculations for the overpower N-16 trip and the power range neutron flux reactor trio setpoints.

The licensee has maintained the 2-percent margin in this SR and applied it in setpoint methodology as the basis for the revised N-16 and power range neutron flux setpoints. A 1-percent margin could have been used for the surveillance and in the setpoint determination,

- resulting in some additional reduction in setpoints. Maintaining the 2-percent value could serve as a contingency should t% 1.EFM/ become inoperable and should the licensee have to rely on feedwater flow measurement using the venturi system in the calorimetric calculation.

Resorting to venturi flow measurement would render invalid the uncertainty basis for using a

'1-percent power margin and would dictate that the 2-percent allowance be included in the

- setpoint calculation. Maintaining a 2-percent margin in the basis for the protection system setpoints avoids the need to revise setpoints in the event that the LEFM/ input were not available.

Maintaining the 2-percent margin for the SR while reducing the safety analysis margin to 1 percent introduces an inconsistency between the TSs and safety analyses. This

~ inconsistency does not raise a safety concern and is acceptable given the licensee requirement to maintain plant power at or below licensed power.

. The licensee stated that, even if the nuclear instrument and N-16 indications are less than the calorimetric measurement but within the 2-percent tolerance of the TS, procedural guidance L,-

R, provides for operating the plant consistent with the calorimetric measurement. The procedural guidance is intended to ensure that the plant operates'within the bounds of the operating

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license.~ Calorimetric power may be monitored continuously, but it is only required to be checked for the daily comparison to nuclear instrument and N-16 power readings. Operation with nuclear instrumentation or N-16 indications above 100 percent is generally not permitted.8 Therefore, the plant is not expected to be operated above its licensed power for any appreciable' period. The longest period that the plant could conceivably operate above rated

' power is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the surveillance interval.

LThe objective of the SR is not to prevent reactor thermal power.from exceeding the value used in the safety analysis, but to maintain the nuclear instrumentation and N-16 indications consistent with the measured thermal output of the reactor. Whenever the plant operator discovers that reactor power exceeds licensed power, either by indication or calorimetric measurement, power level must be reduced. Even with the current TS requirement, there is i

potential for the surveillance to reveal that reactor power actually exceeds 102 percent of rated power, a condition beyond safety analysis assumptions. Such an occurrence would be I

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reportable to the NRC, as would any discovery of operation above rated power. Under the existing TS requirement and the proposed changes, adjustment of the power indications may not be required even if the difference from the calorimetric exceeds the margin used in the

. safety analysis. The safety analysis assumption is not directly related to the input used for

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setpoint calculation. With the proposed change, plant operation above rated power or above i

the power level assumed for safety analysis will not be permitted for any longer period than is possible under current TS requirements. Therefore, the existing SR, in light of the licensee's j

proposed changes, is acceptable, j

3.6.10 Risk Considerations in the exemption granted in Reference 12, the NRC staff stated that during the power uprate review, it would consider the overall risk impact of the proposed power increne. The NRC staff sought to confirm that plant risk and safety margins would not be materially diected by the proposed change.

A principal effect of increased power would be an increase in fission product inventory, primarily the inventory of short-lived isotopes. Although fission product inventories can be predicted with reasonable accuracy, analysis of fission product transport from the fuel to the environment involves uncertainties that are considered large with respect to the change in source term anticipated from a small increase in power level. However, the licensee included revised post accident dose evaluations under the proposed conditions to confirm that radiological consequences would continue to be acceptable.

On the basis of previous staff evaluations of requests to increase licensed power, the NRC staff did not expect a significant impact on plant risk from the proposed power increase. However, to confirm this conclusion, the NRC staff questioned the licensee in the areas of impact on results of individual plant examinations (! pes), the progression of anticipated transients without scram (ATWS), and containment integrity analyses, I

3.

NRC Inspection Procedure 61706 indicates that operation above rated thermal power for short periods is permissible to accommodate conditions that may cause small power excursions above rated power.

The CPSES, Unit 2, IPE reviewed by the NRC staff in 1997 (Reference 24) attributed 17 percent of the core damage frequency (CDF) to LOCA events, with loss of offsite power and internal flooding dominating CDF. The NRC staff concluded that the nature of the reactor coolant pump seal model used in plant evaluations and pessimistic modeling assumptions i

contributed to this result. Marginally increasing core power is not expected to significantly change the outcomes of these events, and the IPE results would not materially change.

The licensee stated that the analysis of ATWS progression included sensitivity studies assuming power levels above the proposed new power level with acceptable results.

Therefore, the proposed higher power level will not interfere with expected ATWS progression.

Defense in depth is a primary consideration for proposed changes to reduce the analysis margin. The NRC staff considers defense in depth in terms of maintaining a balance among core damage prevention, contcinment failure, and consequence mitigation. As already discussed in this evaluation, the NRC staff has concluded that the license amendment

. proposed by the licensee does not materially affect the margins of safety, that expected

. radiological consequences are acceptable, and that the potential for core damage is essentially unchanged. The licensee conducted revised containment integrity analyses to complete the examination of defense-in-depth considerations.

Mass and energy release calculations used to evaluated containment integrity were performed at power levels up to 102 percent of RTP. The containment mass and energy release calculation for a LOCA was conducted at 104.5 percent of RTP. For those analyses based on 102 percent of current rated power, the results are applicable to the proposed higher power level using the 1-percent uncertainty margin attributed to use of the LEFM. The contribution of the slightly greater heat load from operation at a marginally higher power is smaller than the conservatisms included in mass and energy release calculations. Therefore, plant risk attributed to the containment challenge of a LOCA or steamline break events is not expected to be significantly affected by operation at the proposed higher power level.

The NRC staff agrees that plant operation at the proposed higher power level is not likely to materially affect plant risk. The NRC staff examined several areas associated with plant risk evaluation at CPSES, Unit 2, to support this conclusion. The NRC staff's conclusion is consistent with previous staff positions regarding the risk impact of marginalincreases in licensed power.

3.6.11 Safety Analysis Conclusions and Licensee Commitments In summary, the NRC staff accepts the proposed changes in the license amendment request to permit operation of CPSES, Unit 2, at 3445 MWt with the commitments stated below. This conclusion is made on the same basis used to approve the exemption to the power level requirement for LOCA analysis in Appendix K as well as evaluation of the results of selected safety analyses. By approving the Appendix K exemption, the NRC staff agreed that the margin above rated power assumed in LOCA analysis accounts for power measurement i

uncertainty. Therefore, those existing safety analyses conducted at 102 percent of rated power are acceptable at 101 percent of the proposed higher power level without affecting associated margins of safety. The NRC staff also considered selected safety analyses that had not been conducted at 102 percent of the current rated power level. The licensee provided sufficient information to allow comparison of the results of these analyses to appropriate safety limits.

p, 38-The comparison gives the staff confidence that sufficient safety margins for these events will be maintained at the proposed higher power level. Accordingly, the proposed change to the RTP in paragraph 2.C.(1) of FOL NPF-89, and in TS 1.1 is acceptable.

The NRC staff also accepts the proposed changes to reactor protection system allowable values in TS Table 3.3.1-1 and setpoint values because the changes were made following the procedures given in the Wsstinghouse setpoint methodology, as described in WCAP 12123

-(Reference 19), and because sufficient setpoint margin was maintained.

The NRC ' staff concludes that there is not a material change to the risk of plant operation for 1 CPSES, Unit 2, under the proposed changes. Information provided by the licensee regarding safety margin impact due to the proposed change met criteria in SRP Chapter 19 (Reference 20). Other information provided by the licensee regarding the expected effect of the proposed changes on the risk profile of the facility is consistent with previous staff positions that little, if any, risk impact is associated with marginalincreases in licensed power.

The NRC staff further concludes that the continued use of associated topical reports listed in

.TS 5.6.5b, as proposed in Reference 8, is acceptable with the commitments stated below:

LEFM/ operation and the associated quantification of power measurement uncertainty will a

apply wl.enever the facility operates at the new, higher rated power. This follows the premise of the NRC approval of the exemption to Appendix K, which allowed the reduction in the assumed power for the LOCA analysis "when the quantification of power measurement uncertainty can be justified by the use of the Caldon LEFM/ System instrumentation." Thersfore, the LEFM/ will be operating and the uncertainty analysis discussed in the staff approval of the exemption to Appendix K (Reference 12) will remain valid for operation at the now rated power level.

The modification to LOCA analysis methods to incorporate the power measurement uncertainty based on use of LEFM/ will be included in the next annual ECCS report prepared in accordance with 10 CFR Part 50, Section 50.46.

These commitments were proposed by the licensee (Reference 8). The NRC staff finds that reasonable controls for the implementation and for subsequent evaluation of proposed changes pertaining to the above regulatory commitments are best provided by the licensee's administrative processes, including its commitment management program. The above regulatory commitments do not warrant the creation of regulatory requirements (items requiring prior NRC approval of subsequent changes). The staff notes that pending industry and regulatory guidance pertaining to 10 CFR 50.71(e) may call for some information related to tne above commitments to be included in a future update of the CPSES FSAR.

3.7 Dose Assessment The licensee performed an assessment of the radiological dose consequences for the proposed incre'ase in RTP. This analysis, contained in Reference 1, describes a review of the effects of the change on post-accident equipment qualification, vital area accessibility, control room and offsite doses, and normal-operating effluent releases. To assess the potentialimpact of the proposed increase in RTP, the licensee reviewed the potential changes in fission product inventory at core EOL. The impact of these changes on dose rates or integrated dose

1 computations was performei The licensee stated that, in general, the current CPSES FSAR i

analyses were performed assuming a design power which is 4.5 percent above the RTP.

Therefore, the current analyses would encompass a proposed increase of 1 percent RTP. The licensee concluded that for all areas reviewed, except for normal plant effluent releases, the

, new doses due to the proposed changes will bound or do not increase currently approved values. The licensee also stated that the normal plant effluent releases would remain below M CFR Part 50, Appendix I limits.

The NRC staff reviewed the CPSES FSAR and the licensee's amendment request describing the proposed increase in RTP. The decrease in reactor power measurement uncertainty (from 2 to 1. percent of the RTP) due to the installation of the LEFM.' equipment, effectively offsets the increase of 1 percent in power level. Furthermore, a review of the tables in Chapter 15 of the CPSES FSAR, which describe dose consequence analyses, indicates that the analyzed power level is 3565 MWt or approximately 1.045 percent of the current RTP of 3411 MWt.

Also, the licensee states that the analyses performed to assess the effects of mass and energy

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releases remain valid under the proposed change.

With the proposed increase in RTP, the measurement uncertainty on reactor power is decreased. This effectively offsets the increase in power. Current reactor power uncertainty ie taken to be 2 percent of the RTP. The minimum upper design limit for power is approximately 3479 MWt (3411 MWt x 1.02). The requested power increase is to 3445 MWt with 1 percent of

- RTP measurement uncertainty. The minimum upper design limit for power associated with the

- proposed change is approximately 3479 MWt (3445 MWt x 1.01). Since these values are equivalent, the proposed change in power is effectively offset by the decrease in measured I

- power uncertainty. In addition to this offset, the Chapter 15 analyses include additional conservatism with respect to assumed pcwer.

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' The current Chapter 15 radiological analyses are calculated with a power that bounds the

- power level plus the 1 percent RTP uncertainty of the proposed change. A review of the tables

' in the CPSES FSAR, Chapter 15, which describe the dose consequences of design basis

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accidents, shows that these analyses assume a power level of 3565 MWt. Therefore, the j

source terms utilized in these analyses bound those associated with the proposed power level of 3445 MWt.

The releases of mass and energy after an accident remain bounding for the proposed change.

Therefore, the current primary and secondary side postulated releases to the environment are

. bounding.- Since the source terms and release rates used in the current analyses remain bounding, the dose consequences will remain bounding.

The'results of the NRC staff's assessment previously described were used to confirm the acceptability of the licensee's analysis methodology and conclusions. Based on considerations above, the NRC staff concludes that the licensee's analyses remain acceptable in that reasonable assurance exists, that the dose consequences, with the proposed increase in RTP, will remain the same or bounded by the current values.

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i 3.8 Emeraency Preparedness and Licensed Operator Performance Topics The NRC staff reviewed References 1 and 2 relative to emergency preparedness and licensed operator performance issues. The NRC staff's evaluation of the licensee's responses relative to five revie v topics is provided below.

Topic 1 - Discuss whether the increase in RTP will change the type and scope of plant emergency and abnormal operating procedures. Will the increase in RTP change the type, scope, and nature of operator actions needed for accident mitigation and will new operator

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actions be required?

The licensee stated in Reference 2 that the increase in RTP would not require any material modifications to pl ant procedures. Further, the responses of the reactor to any event will be unaffected by the change. The NRC staff finds that the licensee's response to be acceptable.

Topic 2 - Provide examples of operator actions that are particularly sensitive to the proposed increase in RTP and discuss how the increase in RTP will affect operator reliability or performance. Identify all operator actions that will have their response times changed because of the increase in RTP. Specify the expected response times before the increase in RTP and the new (reduced / increased) response times. Discuss why any reduced operator response times are needed. Discuss whether any reduction in time available for operator actions, due to the power uprate, will significantly affect the operator's ability to complete the required manual actions in the times allowed. Discuss results of simulator observations regarding operator response times for operator actions that are potentially sensitive to power uprate.

In Reference 2, the licensee stated that the increase in RTP would not change the response of the reactor operators to any event and, tnerefore, would not require any modifications. The NRC staff finds that the licensee's response is acceptable.

- Topic 3 - Discuss all changes that the increase in RTP will have on control room alarms, i

controls, and displays. For example, will zone markings on meters change (e.g., normal range, marginal range, and out-or-tolerance range)? If changes will occur, discuss how they will be addressed.

The licensee stated in Reference 2 that no changes to control room alarms, controls, and displays are required as a direct result of the increase in RTP. When the increase in RTP is i

implemented, the Nuclear Instrumentation System will simply be adjusted to indicate the new 100 percent RTP in accordance with TS requirements and plant administrative controls. The reactor operators will be trained on the changes in a manner consistent with any other design modification. The NRC staff finds that the licensee's responses are acceptable.

TS c 4 - Discuss all changes the increase in RTP will have on the Safety Parameter Display System (SPDS) and how they will be addressed.

The SPDS is unaffected by the proposed increase in RTP and therefore is acceptable to the NRC staff.

Topic 5 - Describe all changes that the increase in RTP will have on the operator training program and the plant simulator. Provide a copy of the post-modification test report (or test abstracts) to document and support the effectiveness of simulator changes as required by ANSI /ANS 3.5-1985, Section 5.4.1.

i. Specifically, please propose a license condition and/or commitment that stipulates the following:

-(a) Provide classroom and simulator training on all changes that affect operator -

performance caused by the power uprate modification.

(b) Complete simulator changes that are consistent with ANSI /ANS 3.5-1985. Simulator fidelity will be re-validated in accordance with ANSI /ANS 3.5-1985, Section 5.4.1,

" Simulator Performance Testing." Simulator revalidation willinclude comparison of individual simulated systems and components and simulated integrated plant steady state and transient performance with reference plant responses using similar startup test procedures.

(c) Complete all control room and plant process computer system changes as a result of

. the power uprate.

(d) Modify operator training and_the plant simulator, as required, to address all related issues and discrepancies that are identified during the startup testing program.

The licensee stated in Reference 2 that the simulation facility is referenced to Unit 1; therefore, simulator modifications are not required for the Unit 2 increase in RTP. The licensee further stated that reactor operators will be trained on the unit differences in the same manner as is currently used. The licensee stated that the increase in RTP is not expected to have any significant effect on the manner in which the operators control the plant. The staff finds that the licensee's responses are acceptable and consistent with the existing simulation facility certification.

1 The NRC staff concludes that the previously discussed review topics associated with the proposed CPSES, Unit 2, increase in RTP have been or will be satisfactorily addressed. The NRC staff further concludes that the increase in RTP should not adversely affect simulation facility fidelity, operator performance, or operator reliability.

4.0 STATE CONSULTATION

in accordance with the Commission's regulations, the Texas State official was notified of the proposed issuance of the amendments. The State official had no comments.

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5.0 ENVIRONMENTAL CONSIDERATION

Pursuant to 10 CFR 51.21,51.32, and 51.35, an Environmental Assessment and Finding of No Significant impact was published in the FederalRegisteron August 11,1999 (64 FR 23762).

Accordingly, based upon the Environmental Assessment, the Commission has determined that the issuance of the amendments will not have a significant effect on the quality of the human environment.

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6.0 CONCLUSION

The Commission has concluded, based on the censiderations 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 Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors:

D. Jackson R. Goel C.Wu M. Blumberg C. Goodman F. Collins C. Doutt F. Ash D. Jaffe J.Donoghue A. Keim M.Khanna K. Parczewski Date: September 30, 1999 1

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REFERENCES 1.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric, to the -

U.S. Nuclear Regulatory Commission (USNRC) Document Control Desk, " Submittal of License Amendment Request 98-010, increase in Unit 2 Reactor Power to 3445 MWt.,"

-TXX-98265, December 21,1998 2.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric, to the USNRC Document Control Desk, " Response to NRC Request for Additional Information on License Amendment Request 98-010," TXX-99105, April 23,1999 3.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric, to the USNRC Document Control Desk, " Response to NRC Request for Additional information on License Amendment Request 98-010," TXX-99115, May 14,1999 4.

Letter from C. L. Terry, Sr, Vice President & Principal Nuclear Officer, TU Electric,

" Response to NRC Request for AdditionalInformation on License Amendment Request 98-010," TXX-99164, July 9,1999 5.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric,

" Response to NRC Request for AdditionalInformation on License Amendment Request 98-010," TXX 99195, August 13,1999 6.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric,

" Supplement to License Amendment Request 98-010", TXX-99198, August 13,1999 7.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TXU Electric,

" Response to NRC Request for Additional Information on License Amendment Request 98-010," TXX-99203, August 25,1999 8.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TXU Electric,

" Response to NRC Request for AdditionalInformation on License Amendment i

Request 98-010," TXX-99212, September 10,1999 9.

Letter from C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric, to the USNRC Document Control Desk, " Request for Exemption from Appendix K to 10 CFR Part 50 ECCS Evaluation Models" TXX-98183, August 13,1998 J

i 10.

Caldon, Inc. Engineering Report - 80, " Improving Thermal Power Accuracy and Plant

]

~ Safety While Increasing Operating Power Level Using the LEFM/ System", ER-80P, 1

Rev. O, March 1997 j

l 11.

Letter from John N. Hannon, NRC, to C. L. Terry, Sr. Vice President & Principal Nuclear l

Officer, TU Electric, " Comanche Peak Steam Electric Station, Units 1 and 2 - Review of Caldon Engineering Topical Report ER 80P, " Improving Thermal Power Accuracy and 4

Plant Safety While increasing Power Level Using the LEFM System (TAC NOS.

MA2298 and MA2299)," March 8,1999

2-12.

Letter from David H. Jaffe, NRC,' to C. L. Terry, Sr. Vice President & Principal Nuclear Officer, TU Electric," Appendix K Exemption Request for Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 (TAC NOS. MA2268 and MA2269)," May 6, 1999 13.

NRC Generic Letter 88-11,"NRC Position on Radiation Embrittlement of Reactor Vessel Materials and its impact on Plant Operations (Generic Letter 88-11)," July 12,1988 14.

NRC Generic Letter 92-01, Revision 1, Supplement 1, " Reactor Vessel Structural Integrity," May 19,1995 15.

Texas Utilities Electric, Topical Report, "Large Break Loss of Coolant Accident Analysis Methodology," Report No. RXE-90-007-A, April 2,1993 16.

Texas Utilities Electric, Topical Report, "Small Break Loss of Coolant Accident Analysis Methodology," Report No. RXE-95-001-P-A, September,1996 (proprietary information; not publicly available) 17.

Texas Utilities Electric, Topical Report, " Power Distribution Control Analysis and Overtemperature N-16 and Overpower N-16 Trip Setpoint Methodology," Report No.

RXE 90-006-P-A, June 1994 (proprietary information; not publicly available) 18.

Westinghouse Electric Corporation, "A Review Plan for Uprating the Licensed Pcwer of a Pressurized Water Reactor Power Plant." WCAP-10263, January 1983 19.

Westinghouse Electric Corporation, " Westinghouse Setpoint Methodology for Protection Systems-Comanche Peak Unit 1," Revision 1, WCAP-12123, April 1989 (proprietary information; not publicly available) 20.

U.S. Nuclear Regulatory Commission, NUREG-0800, " Standard Review Plan, Section 19.0, 'Use of Probabilistic Risk Assessment in Plant-Specific, Risk Informed Decisionmaking: General Guidance'," Revision 0, July 1998 21.

Texas Utilities Electric, Topical Report, " Reactivity Anomaly Events Methodology for Comanche Peak Steam Electric Station Licensing Applications," Report No.

RXE 91-002-A, October 1993 22.

Texas Utilities Electric, Topical Report, " Design Basis Analysis of a Postulated Steam Generator Tube Rupture Event for Comanche Peak Steam Electric Station, Unit 1,"

Report No. RXE-88-101-P, March 1988 (proprietary information; not publicly available) 23.

U.S. Nuclear Regulatory Commission, Letter from Thomas A. Bergman (NRC) to William J. Cahill (TU Electric), " Comanche Peak Steam Electric Station Units 1 and 2, Topical Report RXE 91-002, ' Reactivity Anomaly Events Methodology'," March 10,1993 24.

U.S. Nuclear Regulatory Commission, Letter from Timothy J. Polich (NRC) to C. Lance

- Terry (TXU Electric), " Review of Comanche Peak Steam Electric Station Individual Plant Examination Submittal-Internal Events," March 10,1997 i