ML20217P057

Safety Evaluation Supporting Amends 137 & 129 to Licenses NPF-02 & NPF-08,respectively

ML20217P057
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Site:	Farley
Issue date:	04/29/1998
From:	NRC (Affiliation Not Assigned)
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Download: ML20217P057 (80)

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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO.137 TO FACILITY OPERATING LICENSE NO. NPF-2 AND AMENDMENT NO.129 TO FACILITY OPERATING LICENSE NO. NPF-8 SOUTHERN NUCI PAR OPERATING COMPANY. INC.. ET AL.

JOSEPH M. FARI FY NUCLEAR PLANT. UNITS 1 AND 2 DOCKET NOS. 50-348 AND 50-364

1.0 INTRODUCTION

By letter dated February 14,1997, as supplemented by letters dated June 20, August 5, September 22, November 19, December 9, December 17, and December 31,1997, January 23, February 12, February 26, March 3, March 6, March 16, April 3, April 13, and two i

letters on April 17,1998, the Southem Nuclear Operating Company, Inc. (SNC) et al....

-l submitted a request for changes to the Joseph M. Farlay Nuclear Plant (FNP), Units 1 and 2, i

Technical Specifications (TS) to increase the maximum reactor core power level for facility J

operation from 2652 megawatts-thermal (MWt) to 2775 MWt. The amendments also approve changes to the TS to implement uprated power operation. The results of the uprate evaluations and analyses were documented in Westinghouse WCAP-14723, "Farley Nuclear Plant Units 1 and 2 Power Uprate Project NSSS Licensing Report," dated January 1997 and submitted by

. SNC with the February 14,1997, request.

j The November 19, December 9, December 17, and December 31,1997, January 23, February 12, February 26, March 3, March 6, March 16, April 3, April 13, and two letters on

' April 17,1998, provided clarifying information that did not change the February 14,1997, i

application and the initial proposed no significant hazards consideration determination (October 8,1997,62 FR 52588).

2.0 BACKGROUND

FNP Units 1 and 2 are currently licensed for operation at a reactor core power level of 2652 MWt. SNC undertook a program to uprate the FNP units to a maximum reactor core power level of 2775 MWt, approximately a 4.6 percent increase. At the core uprate power, the generator electrical output for each unit will increase approximately 25 megawatts-electrical (MWe). The engineering studies supporting the core uprate have been performed in accordance with guidance contained in Westinghouse Topical Report WCAP-10263, entitled "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Power Plant,"

dated January 1983. This WCAP methodology, although not formally reviewed and approved by the NRC, was followed by North Anna, Salem, Indian Point 2, Caliaway, Vogtle, and Turkey Point for their core power uprate and these uprates were found acceptable.

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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION L

RELATED TO AMENDMENT NO.137 TO FACILITY OPERATING LICENSE NOf NPF-2 L

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AND AMENDMENT NO.129 TO FACILITY OPERATING LICENSE NO. NPF-8 l

SOUTHERN NUCLEAR OPERATING COMPANY. INC.. ET AL.

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j JOSEPH M. FARI FY NUCI FAR PLANT. UNITS 1 AND 2 l

DOCKET NOS. 50-348 AND 50-364 l

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1.0 INTRODUCTION

L l

By letter dated February 14,1997, as supplemented by letters dated June 20, August 5, L

September 22, November 19, December 9, December 17, and December 31,1997, i

January 23, February 12, February 26, March 3, March 6, March 16, April 3, April 13, and two l

letters on April 17,1998, the Southem Nuclear Operating Company, Inc. (SNC) et al.,

submitted a request for changes to the Joseph M. Farley Nuclear Plant (FNP), Units 1 and 2, Technical Specifications (TS) to increase the maximum reactor core power level for facility operation from 2652 megawatts-thermal (MWt) to 2775 MWt. The amendments also approve changes to the TS to implement uprated power operation. _ The results of the uprate evaluations and analyses were documented in Westinghouse WCAP-14723, "Farley Nuclear Plant Units 1 and 2 Power Uprate Project NSSS Licensing Report," dated January 1997 and submitted by i'

SNC with the February 14,1997, request.

1 The November 19, December 9, December 17, and December 31,1997, January 23, i

l

' February 12, February 26, March 3, March 6, March 16, April 3, April 13, and two letters on j

I April 17,1998, provided clarifying information that did not change the February 14,1997, l

application and the initial proposed no significant hazards consideration determination l

(October 8,1997,62 FR 52588).

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2.0 BACKGROUND

i-i' FNP Units 1 and 2 are currently licensed for operation at a reactor core power level of l

2652 MWt. SNC undertook a program to uprate the FNP units to a maximum reactor core l

power level of 2775 MWt, approximately a 4.6 percent increase. At the core uprate power, the generator electrical output for each unit will increase approximately 25 megawatts-electrical (MWe). The engineering studies supporting the core uprate have been performed in accordance with guidance contained in Westinghouse Topical Report WCAP-10263, entitled "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Power Plant,"

dated January 1983. This WCAP methodology, although not formally reviewed and approved by the NRC, was followed by North Anna, Salem, Indian Point 2,' Caliaway, Vogtle, and Turkey Point for their core power uprate and these uprates were found acceptable.

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. SNC's letter of February 14,1997, submitted Westinghouse WCAP-14723, "Farley Nuclear Plant Units 1 and 2 Power Uprate Project NSSS Licensing Report," dated January 1997, which provided supporting documentation and analyses for the proposed changes. SNC stated that the results of the Nuclear Steam Supply System (NSSS) analyses and evaluations demonstrate that the FNP Units 1 and 2 NSSS is in-compliance with applicable licensing criteria and requirements and can operate acceptably at the power uprate conditions.

f SNC addressed the overall risk associated with the increase in rated thermal power and concluded that there is no impact on the calculated core damage frequency. The conclusion -

was based on the fact that all of the Final Safety Analysis Report (FSAR) transients were analyzed or evaluated at the uprated conditions with acceptable results and because SNC evaluated the success criteria and operator action failure probabilities used in the current FNP probabilistic risk assessment (PRA) model with no adverse impact.

The FNP power uprate amendments were reviewed with consideration given to the recommendations from the Report of the Maine Yankee Lessons Learned Task Group, dated December 5,1996. This report is documented in SECY-97-042, " Response to OlG Event inquiry 96-04S Regarding Maine Yankee,' dated February 18,1997. The Task Group concluded that a power uprate review procedure should be developed in light of the Maine Yankee findings. Although a Maine Yankee lessons leamed power uprate procedure has not been developed, the recommendations of the report were considered in the review of the FNP uprate. The main findings centered around the use and applicability of the code methodologies used to support the uprated power. SNC has made an effort to verify that the code inputs and assumptions are appropriate and applicable to the plant given the uprated conditions and any changes (plant modifications and procedural changes) that have occurrrsd since initial licensing.

SNC indicated that all principal codes were used in accordance with the applicable limitations and restrictions. SNC has also provided a summary list of analysis assumptions and of codes used and their review status (i.e., generically approved and new for FNP, generically approved and approved for FNP) for consideration in the NRC review. The staff considered all of the Maine Yankee Lessons Leamed recommendations and appropriately addressed them in this review. For the few recommendatiens that were not adopted, the staff provided adequate justification and obtained cognizant management approval.

3.0 ACCIDENT ANALYSES EVALUATION in support of this power uprate, the FNP units were reevaluated by SNC for operation at a rated thermal power of 2775 MWt with respect to safety analyses.

The transient analyses presented rely heavily on analysis performed in the past to support other NRC-approved licensing actions (overpressure delta temperature (OPAT) - overtemperature delta temperature (OTAT) review, VANTAGE-5 fuel conversion, and steam generator level tap relocation). SNC stated that these analyses were also used in accordance with the applicable code limitations and restrictions. SNC stated that the principal codes and methodologies used are all part of the FNP design basis with the exception of the methodology used to evaluate the large break loss-of-coolant accident (LOCA). SNC is using the NRC-approved WCAP-12945-P-A, " Code Qualification Document for Best Estimate LOCA Analysis," for the analysis of this accident. This methodology received a rigorous NRC review and approval. Sensitivity studies and comparative analysis were presented to the staff as part of the review effort. As a result,

i. SNC's letter of February 14,1997, submitted Westinghouse WCAP-14723, "Farley Nuclear Plant Units 1 and 2 Power Uprate Project NSSS Ucensing Report," dated January 1997, which j

provided supporting documentation and analyses for the proposed changes. SNC stated that the results of the Nuclear Steam Supply System (NSSS) analyses and evaluations demonstrate L

that the FNP Units 1 and 2 NSSS is in compliance with applicable licensing criteria and '

requirements and can operate acceptably at the power uprate conditions.

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SNC addressed the overall risk associated with the increase in rated thermal power and concluded that there is no impact on the calculated core damage frequency. The conclusion -

was based on the fact that all of the Final Safety Analysis Report (FSAR) transients were analyzed or evaluated at the uprated conditions with acceptable results and because SNC evaluated the success criteria and o;. orator action failure probabilities used in the current FNP probabilistic risk assessment (PRA) model with no adverse impact.

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The FNP power uprate amendments were reviewed with consideration given to the -

recommendations from the Report of the Maine Yankee Lessons Leamed Task Group, dated December 5,1996. This report is documented in SECY-97-042, " Response to OlG Event -

l Inquiry 96-04S Regarding Maine Yankee," dated February 18,1997. The Task Group l

concluded that a power uprate review procedure should be developed in light of the Maine Yankee findings. Although a Maine Yankee lessons leamed power uprate procedure has not been developed, the recommendations of the report were considered in the review of the FNP l

uprate. The main findings centered around the use and applicability of the code methodologies used to support the uprated power. SNC has made an effort to verify that the code inputs and assumptions are appropriate and applicable to the plant given the uprated conditions and any l

changes (plant modifications and procedural changes) that have occurred since initial licensing.

SNC indicated that all principal codes were used in accordance with the applicable limitations L

and restrictions.. SNC has also provided a summary list of analysis assumptions and of codes l

used and their review status (i.e., generically approved and new for FNP, generically approved and approved for FNP) for consideration in the NRC review. The staff considered all of the Maine Yankee Lessons Leamed recommendations and appropriately addressed them in this review. For the few recommendations that were not adopted, the staff provided adequate l

. Justification and obtained cognizant management approval.

3.0 ACCIDENT ANALYSES EVALUATION I '

In support of this power uprate, the FNP units were reevaluated by SNC for operation at a rated thermal power of 2775 MWt with respect to safety analyses.

l The transient analyses presented rely heavily on analysis performed in the past to support other l

NRC-approved licensing actions (overpressure delta temperature (OPAT) - overtemperature delta temperature (OTAT) review, VANTAGE-5 fuel conversion, and steam generator level tap i

L relocation). SNC stated that these analyses were also used in accordance with the applicable code limitations and restrictions. SNC stated that the principal codes and methodologies used

. are all part of the FNP design basis with the exception of the methodology used to evaluate the large break loss-of-coolant accident (LOCA). SNC is using the NRC-approved WCAP-12945-P-A, " Code Qualification Document for Best Estimate LOCA Analysis," for the analysis of this accident. This methodology received a rigorous NRC review and approval. Sensitivity studies and comparative analysis were presented to the staff as part of the review effort. As a result,

. the staff concludes that a comparative analyses, between the old and new power levels,' is not necessary, as recommended in the Report of the Maine Yankee Lessons Learned Task Group.

3.1 LOCA Analvres 3.1.1 Larae Break LOCA (I RI OCA)

The LBLOCA analysis was performed, at the uprated conditions, using the NRC-approved Westinghouse Best Estimate Methodology or WCOBRA/ TRAC. This methodology is appropriate for use at FNP because Units 1 and 2 are 3 loop Westinghouse designs for which the topical was approved. SNC performed the analysis in accordance with the code limitations -

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and restrictions and as a result, the methodology is acceptable for use in FNP licensing applications, including reference in the technical specifications and core operating limits report (COLR). Use of this methodology is for the time from event initiation to core quench and not for use in evaluating long-term cooling.

The results of the best estimate analysis indicate that the calculated peak clad temperature

. (PCT) is 2064'F, the maximum localized oxidation is 12 percent, the maximum hydrogen generation is 0.6 percent, the core remains coolable, and the core remains cool in the long term. These results are acceptable and meet the acceptance criteria of 10 CFR 50.46 of a PCT less than 2200'F, a maximum localized oxidation less than 17 percent, the maximum hydrogen generation less than 1.0 percent, the core remains coolable, and the core remains cool in the' long term. As a result, the staff finds this acceptable.

3.1.2 Small Break LOCA (SBLOCA)

SNC stated that the NRC-approved NOTRUMP continues to be used for the SBLOCA analysis, at the uprated conditions. In order to determine the limiting set of conditions, a number of cases were e>aluated. The analysis was run at both the high and low average temperatures limits, the Units 1 and 2 flow characteristics (Unit 1 has a barrel /beffic upflow configuration while Unit 2 has a downdow configuration), and for both ZlRLO and zircaloy clad fuel. SNC stated that the analysis assumes the limiting single failure of a loss of one train of the emergency core cooling system (ECCS) with an assumed loss of offsite power (LOOP) at the time of the reector trip. ' SNC stated that the delay from the time of event initiation to the time of the trip in the modeling is inconsequential and is not less limiting than assuming the LOOP occurs at the time of the event. The results indicate that the limitir.2 CT is 1968* F for the Unit 1, low T.,,, ZlRLO P

clad 3-inch break. The highest localized oxidation is 5.84 percent, the total oxidation remains less than i percent, the core remains coolable, and long-term cooling is maintained. As a result, the analysis of the SBLOCA is acceptable.

3.1.3 Hot Leg Switchover SNC stated that a calculation has been performed to determine the new hot leg ewitchover

'(HLSO) time and minimum hot leg recalculation flow based on an uprated core power of 2775 MWt. The new HLSO time is 7.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The new hot leg recalculation minimum flow for the worst break and single failure is 8g.1 lbm/sec. This hot leg recalculation minimum flow has b

h been shown to be available. SNC concluded that with the above HLSO time and flow rate, the core geometry will remain coolable.

1 3.1.4 Post-LOCA Long-Term Coohng SNC stated that an analysis of long-term cooling was performed at the uprated power. SNC has performed an evaluation to determine the effects of power uprating to post-LOCA long-term -

cooling. It is concluded that the new average temperature range has a very small effect on the -

i post-LOCA sump boron concentration. Therefore, the core will remain suberitical post-LOCA and that decay heat can be removed for the extended period of time required by the long lived radioactivity remaining. The revised post-LOCA long-term core cooling boron limit curve is used to qualify the fuel on a cycle-by-cycle basis during the fuel reload process.

1 3.2 Non-LOCA Transient Analyses SNC stated that the non-LOCA analysis was performed using codes that have been approved both generically and for FNP. They were used in accordance with applicable limitations and restrictions. A number of other NRC-approved license amendments were referenced because the previously approved analysis assumed uprated conditions. These include the transition to VANTAGE-5 fuel, the revision of the OPAT and OTAT setpoints with the implementation of the relaxed axial offset control, and the steam generator level tap relocation license amendments.

SNC stated that these analyses were also performed in accordance with the applicable code limitations and restrictions. The analysis associated with the revision of the OPAT and OTAT setpoints included all of the changes associated with this amendment. The analysis associated with the VANTAGE-5 fuel transition included the uprated power, the ZlRLO fuel, and the reduced reactor coolant system (RCS) flow; however, it did not include all other conforming uprated related changes, including the reduction in ECCS flow. The transients that continue to rely on these analyses have been evaluated to verify continued acceptability. The staff finds this acceptable.

SNC stated that where applicable, the NRC-approved revised thermal design procedure (RTDP) was used in the evaluation of the departure from nucleate boiling (DNB). A reduced core flow of 86,000 gpm per loop was employed in the analysis, which is associated with an indicated flow limit of 97,800 gpm and 20 percent steam generator (SG) tube plugging was assumed SNC stated that for each transient, both a stuck rod and the limiting single failure were assumed. The limiting single failure for each transient was selected on an event-specific basis. For the SG tube rupture, however, the single failure of the steam driven auxiliary _

foodwater pump was chosen, even though this is not the most limiting single failure. SNC stated that its design basis does not require the consideration of a single failure in the analysis

- of the SG tube rupture and the original analysis did not assume a single failure. The L

consideration of this single failure is more conservative than was required by the original design basis. As a result, the consideration of the failure of the steam driven auxiliary feedwater pump, a less limiting single failure, is now acceptable. Additionally, SNC stated that where an LOOP was assumed, the timing was chosen consistently with the original design basis assumptions.

These assumptions are acceptable. A brief discussion of each individual transient is presented below.

c 3.2.1 Uncenuolled Rod Cin=*ar Control A===mbiv (RCCA) Bank Withdraw 2' frem a Sd n1 =1 Condition The uncontrolled RCCA bank withdrawal from a suberitical condition is analyzed to ensure that the core and the RCS are not adversely affected. This analysis was performed with acceptable results at the uprated conditions during the VANTAGE-5 fuel conversion. This has been

- demonstrated because the results of the analysis show that the minimum DNB ratio (DNBR) -

remains greater than the safety analysis limit and that the maximum fuel temperatures -

' predicted to occur are much less than those required for clad damage or fuel melting to occur.

The effect of the power uprate on this event is therefore, acceptable.

3.2.2 Uncenb "id Rod Cluster Control A==ambiv Bar k Withdrawal at Power

.The analysis of the uncontrolled RCCA bank withdrawal at power case was analyzed while revising the OPAT and OTAT setpoints, at the uprated conditions, with acceptable results and NRC approval as addressed in Farley License Amendment No.121 for Unit No.1 and License Amendment No.113 for Unit No. 2, issued on September 3,1996.

3.2.3 Rod Cluster Control A==ambiv Mi-wnwn!

The dropped RCCA and the statistically misaligned assembly were analyzed at the uprated conditions while transitioning to VANTAGE-5 fuel. The analysis resulted in the calculated DNB meeting the design basis. Although the rod control system has been modified, affecting the control system response, SNC performed an analysis to demonstrate the acceptability of the rod control parameters since this modification.- These calculations confirmed that the DNB design basis continues to be met. As a result, the staff finds this acceptable.

3.2.4 Uncenhu::ed Boron Dilution The uncontrolled boron dilution was analyzed whi!e revising the OPAT and OTAT setpoints, at the uprated conditions, with acceptable results and NRC approval as addressed in Farley License Amendment No.121 for Unit No.1 and License Amendment No.113 for Unit No. 2, issued on September 3,1996.

3.2.5 Partial Loss of Forced Reactor Caa!=nt Svste n Flow

' The transient was analyzed for the power uprate. The event was analyzed using the RTDP and concluded that the DNBR design basis is met, the pressure of the primary and secondary l remain within the design limits, and fuel centerline melt is not predicted. As a result, the statt finds this acceptable.

3.2.6 Startuo of an inactive Reactor Coolant Loon The FNP TSs do not allow operation with a loop out of service, therefore this is not analyzed and it is acceptable.

1 l

. 3.2.7 Loss of External Electrical Load and/or Turbine T.[jg The loss of load was evaluated for the uprate. The analysis was performed for two cases. The analysis was performed using minimum reactivity feedback with pressurizer pressure control (pressurizer sprays and power-operated relief valves (PORVs)) available using the RTDP to evaluate the DNB transient. The assumptions are established to maximize the DNB transient.

The event was also analyzed using minimum reactivity feedback with no credit of pressurizer pressure control. These assumptions were made to maximize the primary and secondary overpressure transients. For the DNB transient analysis, the primary and secondary code safety relief valves are assumed to open at the low end of the allowable tolerance to maximize the DNB transient, and for the overpressure transient analysis, the valve is assumed to open at the upper tolerarice.' No accumulation in the primary safety relief valves is assumed; however,-

a delay of 1.6 seconds after the setpoint plus tolerance is reached is assumed prior to the valve relieving any steam to clear the loop seals. For the five secondary safety relief valves on each of three steam headers, the first three are modeled with 3 percent accumulation, the fourth 2 percent, and 10 psi accumulation for the last.

The analysis results conclude that for the DNB case, the DNB design basis is met. For the overpressure case, both the primary and secondary system pressure remains below 110 percent of the design pressure. The peak calculated pressure for the primary system is 2747 with a limit of 2748.5 psi. The calculated peak secondary pressure is 1199 psi with a limit of 1208.5 psi. Fuel centerfir,e melt is not expected. As a result, the staff finds the analysis acceptable.

3.2.8 Loss of Normal Feedwater The loss of normal feedwater was analyzed for the power uprate. The DNB transient for this -

event is bounded by the loss of electric load event. The peak pressure analysis results demonstrated that the primary and secondary systems do not exceed the safety limits. The pressurizer is not predicted to go water Solid. Additionally, the motor driven auxiliary feedwater pumps to two SGs provide sufficient cooling. As a result, this is acceptable.

3.2.9 Loss of All Offsite Power to the Plant Auxilianes The loss of all offsite power to plant auxiliaries event was analyzed for the power uprate. The DNB transient for this event is bounded by the loss of electric load event. The peak pressure analysis results demonstrated that the primary and secondary systems do not exceed the safety limits. The pressurizer is not predicted to go water solid. As a result, this is acceptable.

3.2.10 Excessive Heat Removal Due to Feedwater System Malfunction This event was analyzed for the VANTAGE-5 transition with acceptable results and NRC

' approval as addressed in Farley License Amendment No. 91 for Unit No.1 and License Amendment No. 84 for Unit No. 2, issued on December 30,1991. As a result, the current FSAR analysis remains valid.

. 3.2.11 Accidental Deoressurization of RCS The accidental depressurization of RCS was analyzed while revising the OPAT and OTAT setpoints, at the uprated conditions, with acceptable results and NRC approval as addressed in Farley License Amendment No.121 for Unit No.1 and License Amendment No.113 for Unit No. 2, issued on September 10,1996.

3.2.12 Inadvertent Oneratian of Emeroency Core CMina Svstem Durina Pcar Ooeratian The inadvertent ECCS is analyzed to assure that the primary and secondary pressure limits are not exceeded, that the DNBR limits are not exceeded, and that the event does. not progress to a more severe event. The event was analyzed and meets this criteria; however, to prevent the

. water solid relief from the primary code safety relief valves and the potential for the valve sticking open creating a more severe transient, SNC credits the opening of the PORVs. The staff has reviewed this and determined that this is acceptable because there is sufficient time for the operators to take action and open the PORV block valve if it is closed. Additionally, although the automatic actuation of the PORV is not considered safety-related, the accumulation circuits are routed separately; there are two separate Class 1E procured transmitters, powered from 1E power supplies, with 1E relays. Therefore, the PORV is considered highly reliable and its use is acceptable.

3.2.13 Inadvartent Loadino of a Fuel Assembly into an imq,.per Position SNC performed an analysis to verify that operation at the uprated power does not affect the ability of the instrumentation to detect the incorrect loading of an assembly. The evaluation concluded that the current analysis is still applicable and the conclusions remain valid. If a pin or rod were to be incorrectly loaded, the damage would be limited to that pin, if an assembly were incorrectly loaded, it would be detected by the incore detectors. The staff finds this acceptable.

3.2.14 Comolete Loss of Forced Reactor Coolant Flow TFs complete loss of flow was analyzed for the power uprate using the RTDP. For the limiting case run, the reactor is assumed to trip on the loss of RCS flow. The results indicate that tM DNBR does not decrease below the limit, fuel centerline melt is not predicted, and the primary and secondary pressure also remain below the limit. As a result, the acceptance criteria are -

met.

3.2.15 Sinole Rod Cluster Control Assembiv Withdrawal at Full Power The single rod withdraw transient was analyzed during the VANTAGE-5 fuel conversion with NRC approval as addressed in Farley License Amendment No. 91 for Unit No.1 and License Amendment No. 84 for Unit No. 2, issued on December 30,1991. An evaluation was

. performed to confirm this analysis continues to be conservative with respect all the uprated conditions. The staff finds this acceptable.

3.2.16 ' Excessive Load increase incident. Accidenta' Depressunzation of Main Steam System.

Minor Secondary System Pipe Breaks. and Repture of a Main Steamline The main steamline rupture is considered a limiting fault; however, it was analyzed to more limiting criteria so that more frequent events do not need to be analyzed. The staff finds this

' acceptable. As a result, no DNB or fuel failures are predicted.

~ The event was analyzed using the NRC-approved Topical Report, WCAP-g226-P-A, Rev',sion 1, " Reactor Core Response To Excessive Secondary Steam Releases," which is applicable to FNP. The excessive cooldown associated with the steamline rupture and a negative moderator temperature coefficient causes an increase in the core reactivity.' The positive reactivity associated with the cooldown, and assuming the most reactive rod is stuck in -

! the fully withdrawn position causes a retum to criticality. The limiting case for the plant is in hot standby, end-of-life, O percent tube plugging, and minimum ECCS conditions. Both cases where offske power is lost and offsite power is not lost were analyzed to determine which is.

more limiting. The case where power remains available is more limiting and no DNB and no fuel failure was predicted. As a result, it is appropriate to use this event to bound the more frequent excessive load increase and accidental depressurization of main steam events. The staff finds the results acceptable.-

3.2.17 Rupture of a Main Feedwater Pipe The feedwater pipe rupture was analyzed at the uprated power to support the relocation of the SG level tap license amendment. Although the analysis was performed at the uprated power, a sensitivity study was performed to quantify the effects of some of the other plant parameters being modified with this amendment. The sensitivity study concluded that there was no significant change to the peak primary and secondary pressure. analysis and that there continues to be margin with regard to bulk boiling in the core and DNB. The auxiiiary feedwater continues to provide sufficient capacity to remove the decay heat. As a result, the current FSAR analysis remains valid.

3.2.18 Sinale Reactor Coolant Pumo Locked Rotor The event was analyzed for the power uprate amendment. The results concluded that ttm peak primary and secondary pressure remain within the design limit of 110 percent of the design pressure. Although DNB occurs, less than 20 percent of the core is calculated to experience DNB and the maximum clad temperature was 2165 *F. As a result, the staff finds the analysis and results acceptable.

)

3.2.1g Ruoture of a Control Rod Drive Mechanism Housina IRod Cluster Control As==mbly E$ction]

The rod ejection accident was analyzed based on the NRC-approved Topical Report WCAP-7588, Revision 1 A, "An Evaluation of the Rod Ejection Accident in Westinghouse

. Pressurized Water Reactors Using Spatial Kinetics Methods." The results conclude that the average fuel enthalpy at the hot spot remains well below 280 kcal/gm (actually below 225 kcal/gm) and therefore there is no danger of sudden fuel dispersal into the coolant. DNB is predicted to occur in less than 10 percent of the core and the peak RCS pressure does not exceed that which would cause reactor pressure vessel stress to exceed the faulted condition stress limits. As a result, the an& lysis is acceptable.

3.2.20 Steam System Pioina Failure at Full Power The steam system piping failure at full power was analyzed while revising the OPAT and OTAT.

setpoints, at the uprated conditions, with acceptable results and NRC approval as addressed in.

Farley License Amendment No.121 for Unit No.1 and License Amendment No.113 for Unit No. 2, issued on September 3,1996.

3.2.21 Steam Generator Tube Ruoture (SGTR)

The SGTR analysis is used to verify that the postulated offsite dose consequences are acceptable. SNC performed mass and energy balance analyses, consistent with the original design basis, to determine the quantity of primary-to-secondary leak 1ge from both the intact and faulted steam generators and the quantity of steam released to tue environment.

3.3 cent.;nment intearity Analyses SNC performed containment integrity analyses at uprated power to ensure that the maximum pressure inside the containment will remain below the containment building design pressure of 54 psig if a design bases LOCA or main steamline break (MSLB) inside containment should i

occur dug plant operation. The analyses also established the pressure and temperature conditions for environmental qualification and operation of safety-related equipment located inside the containment. The LOCA peak pressure is also used as a basis for the containment

. leak rate test pressure to ensure that dose limits will be met in the event of a release of

. radioactive material to containment.

SNC indicated that the containment functional analyses included the assumption of the most limiting single active failure and the availability or unavailability of offsite power, depending on which resulted in the highest containn ent temperature and pressure. Bounding initial temperatures and pressures for analyses were selected to envelope the limiting conditions for operation.

. 3.3.1 LOCA Containment Integnty Analyses SNC performed analyses to determine the containment pressure and temperature response during postulated LOCAs using mass and energy (M&E) releases, which incorporate revised j

design parametem corresponding to 2775 MWt with updated computer modeling. As in the

. current licensing basis FSAR, the postulated LOCA analyses were performed for the double

- ended hot leg (CEHL) guillotine break of reactor coolant pipe and the double ended pump

suction (DEPS) break. It has been determined that the DEHL break results in the most hmiting

1 pressure during the blowdown phase and that the DEPS break yields the highest energy flow rates during the post-blowdown period.

I SNC indicated that the M&E releases in the containment were calculated for power uprate using Westinghouse Topical Report WCAP-10325-P-A, " Westinghouse LOCA Mass and Energy Release Model for Containment Design - March 1979 Version," May 1983, which is applicable to FNP. In these analyses, the 1979 ANS 5.1 decay heat model with 2 a sigma uncertainty factor was used. Westinghouse Topical Report WCAP-8264-P-A, Revision 1,

" Westinghouse Mass and Energy Release Data for Containment Design," August 1975 for M&E -

release calculations was used in the original / current design basis analyses. The M&E release analyses were presented in attachment 5 of WCAP-14723 of the February 14,1997, submittal.

The up0.ed Westinghouse Topical Report WCAP-10325-P-A computer code with the same methodology and assumptions (except the FNP specific data) have been utilized and approved on many plant-specific dockets for Westinghouse pressurized water reactors such as Turkey Point, Catawba, McGuire, Sequoyah, Watts Bar, Surry Units 1 and 2. Millstone 3, Beaver Vallsy 2, and indian Point 2. The staff finds the use of Topical Report WCAP-10325 for LOCA M&E release calculations acceptable for FNP.

SNC stated that the uprated containment pressure and temperature response analyses were performed using the GOTHIC computer code developed under an EPRI contract from the older NRC code, FATHOMS. GOTHIC was developed under a fully qualified quality assurance program and has undergone extensive peer review. The original containment temperature and pressure analyses were performed using the Copatta computer code. Later analyses were -

performed using the Compact code. Previous blowdown model data were used with the GOTHIC modeling and compared to the previous analyses with consistent results with differences on the order of 1 psi and 10'F at peak conditions. SNC explained the reasons for slight differences in pressure and temperature for FNP in a letter dated December 17,1997.

The staff has reviewed the December 17 letter and finds the ressons for slight differences acceptable. Therefore, based on the comparison with previous modeling with consistent resuits, the staff finds the use of the GOTHIC computer code for FNP containment temperature and pressure analyses accep'able.

SNC stated that uprate analyses made maximum use of the previous analyses for input anumptions. Other than changes in M&E release input due to power uprate and updated codes, other key model/ inputs were: (a) residual heat removal (RHR) beat exchanger properties (heat transfer coefficient and component cooling water flow) were modified to represent actual plant design data; (b) containment cooler performance model was modified for degraded cooler service conditions (The model uses a single degraded cooler in service); (c) initial containment temperature assumption was 127'F, which corresponds to the containment design operating bulk average temperature plus margin; (d) initial containment pressure assumptien was 14.7 psia be :ause the containment mini-purge fans are normally running and maintaining pressure at essentially atmospheric. Additionally, limiting cases for LOCA and MSLB were analyzed at the TSs initial containment pressures of +3 psig and -1.5 psig for maximum pressure and temperature evaluations.

For the DEHL break, the FNP uprate analyses calculated a containment peak pressure of 43.0 psig and peak temperature of 263*F. For the DEPS breaks, the uprate analyses

. calculated a containment peak pressure of 41.5 psig and a peak temperature of 261*F. The uprate calculated LOCA peak pressure and temperature of 43.0 psig and 263'F remain below the containment design pressure of 54 psig and design temperature of 280*F. The proposed power uprate will not affect the Net Positive Suction Head (NPSH) requireraents of ECCS pumps as the peak LOCA temperature of 263'F remains below the preuprate LOCA temperature of 268'F.

3.3.2 Main Steamline Break Containment Intearity Analysis SNC performed analyses to determine the containment pressure and temperature responses during postulated steamline breaks inside containment for limiting conditions for operation at uprated power. The uprate analyses were evaluated for initial power levels of 102 percent, 70 percent,30 percent, and 0 percent and spectrum of break sizes similar to that in the current FSAR. The MSLB mass and snergy release and the pressure and temperature analyses have included the effects of various single failures. The MSLB M&E releases were calculated using the LOFTRAN computer code. The staff has found the use of this code acceptable. A discussion of LOFTRAN is provided in a staff Safety Evaluation issued on May 27,1986.

Containment temperature and pressure responses were calculated using the GOTHIC computer code. As indicated earlier for LOCA containment analysis, the staff has found the use of the GOTHIC computer code acceptable for FNP.

For the MSLB, the uprate analyses calculated a peak containment pressure of 52.4 psig and a

_ peak air temperature of 383*F. The peak containment pressure at uprated conditions remains below the containment design pressure of 54 psig. SNC indicated that peak air temperature, which is 5'F more than the preuprate temperature of 378'F, will be for a very short duration anri that the containment structure temperature will remain below the containment design temperature of 280*F at all times. Also, updated calculated pressure and temperatura curves for LOCA and MSLB cases will remain bounded by the curves used for equipment.

qualifications.

Based on the preceding discussion, the staff finds the proposed change for power uprate will not affect the containment integrity as the calculated peak containment pressure and temperature remains below the containmert design pressure and temperature, and therefore, is acceptable.

3.3.3 Short-term Subcomssa.ent Analvsis

' SNC indicated that an evaluation was conducted to determine the effect of a powe uprate on the short-term LOCA-related M&E releases that support subcompartment analyses discussed in Chapter 6.2 of the FNP FSAR. In the FSAR, a double-ended circumferential rupture of the RCS cold leg forms the basis for the steam generator compartments; a 100 in* reactor vessel inlet break forms the basis for the reactor cavity region, and both spray line break and surge line break were considered for the pressurizer compartment. The magnitude of the pressure differential across the walls is a function of several parameters, wh'ch include the blowdown M&E release rates, the subcompartment volume, vent areas, and vent flow behavior. The

[

blowdown M&E release rates are affected by the initial RCS temperature conditions. Any l

, changes in RCS volume, steam generator liquid / steam mass and volume, and differences in units, such as upflow verses downflow, have no effect on releases because of the short

- duration of postulated accident. Any volumetric changes are small and have no impact on the subcompartment model. Therefore, the only change that needs to be addressed for this program is the decrease in the RCS coolant temperatures Based upon the results of the evaluation, the current design basis LOCA-related M&E releases, including the spray line and the surge line releases, could increase by a factor of 1.18 due to RCS temperature effects.

SNC stated that the subcompartment anriysis was performed for the pressurizer compartment with the increased releases of 18 percent due to RCS temperature effects. Results of the analysis showed that the subcompartment wall differential pressure and uplift forces remain bounded by the previous design basis analysis.' FNP is approved for leak-before-break (LBB) ~

as per WCAP-12825, " Technical Justification for Eliminating Large Primary Loop Rupture as a -

Structural Design Basis for the Joseph M. Farley Ln.sts 1 and 2 Nuclear Power Plants," January 1991. This means that the current breaks (a double-ended circumferential rupture of the reactor coolant cold leg break for the steam generator compartments, and a reactor vessel inlet break for the reactor cavity region) no longer have to be considered for the short-term effects Since the RCS piping has been eliminated from consideration, the large branch nozzles must be considered for design verification. This includes the surge line, accumulator line, and the RHR line. These smaller breaks, which are outside the cavity region, would result in minimum asymmetric pressurization in the reactor cavity. Additionally, compared to the large RCS double-ended ruptures, the differential loadings are significantly reduced. The decrease in M&E releases associated with the smaller RCS nozzle breaks, as compared to the larger RCS pipe breaks, more than offsets the increased releases associated with decreased RCS initial coolant temperature. Therefore, the current licensing basis subcompartment analyses that consider breaks in the primary loop RCS piping (steam generator subcompartment and reactor cavity region), therefore remain bounding.

Based on the preceding review, the staff concludes that the uprating is acceptable as the subcompartment pressure loading analysis from high-energy-line ruptures remain bounded by the current FSAR analysis.

3.4 Additional Design Basis and Programmatic Evaluations 3.4.1 Containment Post-LOCA Hydronen Generation SNC indicated that the effect of power uprate was reviewed for the Zirconium (Zr)-water reaction, corrosion of construction materials in the containment, radiolytic decomposition of core

' and sump solution modes of post-LOCA hydrogen production, and for the capability of the combustible gas control system to maintain acceptable hydrogen concentratum inside the containmentJ SNC stated that the hydrogen generation due to Zr-water reaction is not affected by the power-i uprate since total quantity of Zr (in the fuel cladding) remains unchanged Also, the post-LOCA

)

containment temperature profiles to determine the corrosion rate for aluminum and zinc for power uprate remains bounded by that used in previous design basis analyses, and therefore, hydrogen generation due to corrosion rates will not be affected by power uprate. The hydrogen

e Ceneration post-LOCA due to radiolytic decomposition of core and sump solution will increase by approximately 5 percent proportional to the increase in reactor power level.

SNC indicated that the increase in hydrogen generation rate due to power uprate is determined to have a negligible effect on the post-accident hydrogen mixing system. The analysis performed for uprated power showed that with no recombiner in service, the hydrogen concentration will not exceed 4 percent by volume for 17 days following a LOCA. Placing a hydrogen recombiner in service prior to the 18th day following a LOCA will maintain containment hydrogen levels below the lower flammability limit of 4 percent. Based on the above review, the staff finds that the power uprate will not impact the post-LOCA hydrogen control system.

3.4.2 Comoliance with 10 CFR Part 50 Anoendir R SNC stated that the power uprate evaluation did not identify changes to design or operating conditions that adversely impact the post-fire safe shutdown capability in accordance with Appendix R. SNC also stated that there were no physical plant configuration changes or combustible load changes. The staff finds this acceptable. The staff may review, during a future onsite inspection, the supporting information for SNC's letter of March 6,1998.

3.4.3 Station Blackout (SBO)

SNC performed evaluations of the impact resulting from plant operations at the proposed uprated power level on system response and coping capabilities for SBO events. SNC stated that current design basis temperature profiles in areas housing SBO-required equipment remain bounded for an SBO in an uprated plant.

With this evaluation, the staff has also reviewed whether this power uprate would affect current General Design Criterion (GDC)-17 and SBO requirements. Although the power uprate resulted in a small electricalload increase of the reactr coolant pumps and' charging pumps on non-Class 1E 4160 V buses, SNC's assessment has not iMicated that power uprate would

. affect bus loadings and voltages to such a degree that the electrical onsite or offsite power system configuration would need to be modified. Therefore, the staff finds that the power uprate continues to satisfy the current GDC-17 requirement. SNC has also reviewed the SBO coping analysis, which is a function of offsite power design, emergency power configuration, and emergency diesel generator target reliability per Regulatory Guide 1.155, " Station

- Blackout." SNC finds that none of the SBO coping criteria are affected by power uprate. On

. this basis, the staff concludes that power uprate at FNP would not affect current SBO coping duration and would continue to meet the GDC-17 requirements.

Based on its review and the experience gained from the review of power uprate applications for similar PWR plants, the staff finds that the impact on system response and coping capabilities for an SBO event resulting from plant operations at the proposed uprated power level is insignificant.

1 1

3.4.4 Safetv-Related Motor-Operated Valves (MOV)

I In its response to the staff's request for additional information dated January 23,1998, SNC stated that the FNP NSSS and Balance of Plant safety-related valves were demonstrated to be acceptable for the power uprate. This determination was confirmed by verifying that changes in system operating temperature and pressure were bounded by the requirements of the associated equipment specification. As a result, SNC concluded that the power uprate has no impact on FNP's Generic Letter 89-10 (Safety-Related " Motor-Operated Valve (MOV) Testing and Surveillance") program and that the increased thrust required to operate the MOVs due to expected differential pressure conditions is within the capabilities of the existing valve actuators.

On the basis of its review, the staff concurs.with SNC's conclusion that the power uprate will.

have no adverse effects on the safety-related valves and FNP's MOV program. The staff may review, in a future onsite inspection, the supporting information for SNC's letter of January 23, 1998.

3.5 Radiological Analysis SNC performed reanalyses of a select number of the FNP FSAR Chapter 15 accidents. Such reanalyses were required because of SNC's proposal to increase core power and to change various operating parameters as part of the power uprate. These changes would alter the releases from these postulated accidents.

The accidents for which SNC performed such reanalyses and the NRC guideline dose limits for these accidents are as follows:

1.

Loss of AC Power - 2.5 rem whole body,30 rem thyroid 2.

Waste Gas Decay Tank Rupture

- 500 mrom whole body 3.

Large Break LOCA

- 25 rem whole body,300 rem thyroid

-4.

Main Steamline Break

- preexisting spike case - 25 rem whole body, 300 rem thyroid

- accident-initiated spike case - 2.5 rem whole body,30 rem thyroid -

5.

Steam Generator Tube Rupture

- preexisting spike case - 25 rem whole body, 300 rem thyroid.

- accident-initiated spike case - 2.5 rem whole body, 30 rem thyroid 6.

Locked Rotor

- 2.5 rem whole body,30 rem thyroid 7.

Fuel Handling

- 6 rem whole body,75 rem thyroid 8.

Rod Ejection

- 6 rem whole body,75 rem thyroid

- 9. ~

Small Break LOCA

- 25 rem whole body,300 thyroid

~

-O Consistent with the guidance in the Standard Review Plan (SRP) for some accidents, the reanalysis was performed at a core power rating of 102 percent (2831 MWt) of the proposed power uprate value (2775 MWt).

SNC impsemented attemate repair criteria (ARC) for the steam generator tubes. Because of this, in the event of an MSLB accident, there may be additional primary-to-secondary leakage over and above that which would otherwise occur. For FNP, the value for accident-induced.

leakage is presently at 23.8 gpm and the TS for normal operating leakage is 150 gpd/SG (0.1 gpm/SG).- At the accident-induced leakage rate of 23.8 gpm, it became necessary to reduce the TS values for maximum instantaneous and the 48-hour values for dose equivalent

l to the current values of 9 pCi/g and 0.15 pCi/g, respectively. The staff anticipates ' hat, upon' replacement of the SGs, SNC will request that the TS values for dose equivalent '8'l in primary coolant be restored to their previous values of 60 pCi/g for the maximum instantaneous value and to 1 pCi/g for the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value. Therefore, with the exception of the MSLB, wherever possible, the staff performed its accident analyses involving the TS values with primary _ coolant levels of dose equivalent '8'l at the usual levels of 60 pCi/g and 1 pCi/g.

. The staff reviewed SNC's calculations and performed confirmatory calculations of the doses associated with these accidents for individuals located offsite at the exclusion area boundary (EAB) and at the low population zone (LPZ) and onsite for the control room operators.. The F.NP control room is designed to isolate and the control room emergency ventilation system automatically starts on a containment isolation signal. If the control room receives a high radiation signal, the control room is automatically isolated but it requires manual action on the part of an operator to initiate operation of the control room emergency ventilation system.

. Based on these assumptions, the staff found the control room operator doses acceptable.

The following sections provide the staffs assessment of the potential consequences of the above postulated accidents.

3.5.1 Accidents Analyzed 3.5.1.1 Loss of ac Power SNC indicated that a loss of ac power would not result in the release of. radioactivity unless there was radioectivity in the primary coolant and a primary-to-secondary leak existed. The analysis performed by SNC assumed a reactor coolant activity level based upon 1 percent failed fuel for noble gases, the TS values for dose equivalent l in primary coolant and a 150 gpd/SG primary-to-secondary leak rate.

I.

The staff assessed the potential consequences of a loss of ac power. The staffs assumptions -

are presented in Table 3.5.1-1. Thyroid and whole body doses were calculated at the exclusion area boundry, low population zone, and in the control room. The thyroid, whole body and control room operator doses are presented in Tables 3.5.2-1 through 3.5.2-3, respectively. The doses were found acceptable.

J

, 3.5.1.2 Waste Gas Decay Tank RJpture SNC reevaluated the consequences of the release of the contents of a waste gas decay tank as a result of the power uprate. SNC indicated that its evaluation " conforms to the guidelines of Regulatory Guide 1.24. The releases result in offsite doses (which) are a small fraction of the 10 CFR guidelines, which meets the acceptance criteria."

The staff did not perform such a reassessment of the consequences of this accident Decause FNP is limited by TS 3.11.2.6 as to the quantity of radioactivity that each tank may contain.

- This limit is 70,500 Ci of SXe equivalent. Since SNC did not propose to change the limit for this TS; the previoue TS amendrnent, which approved the 70,500 Cl, was still deemed to be limiting.

It should be noted that the guideline dose criterion for the curie contents of a waste gas decay tank is 500 mrem to the whole body. This r/as detailed in Section 5.6 of NUREG-0133,

" Preparation of Radiological Effluent Technical Specifications for Nuclear Power Plants." The guideline is not a small fraction of Part 100 (2.5 rem to the whole body) as stated by SNC in its submittal.

3.5.1.3 Large Break LOCA (LBLQCA)

SNC calculated the potential consequences of a postulated LBLOCA to the control room operators and to individuals located offsite at the exclusion area boundry and low population zone. SNC postulated that the pathways for releases in the event of a LOCA were containment leakage and ECCS recircu!ation loop leakage discharged via the penetration room filter system.

SNC also assumed that at the time that the LOCA occurred, the containment was being purged. The purge was assumed to be isolated within 6 seconds following the accident. As part of the effort to demonstrate the capability of the plant to meet Part 100 and GDC-19 doses, SNC also performed a calculation that assumed that it was necessary to purge the containment 18 days after the LOCA due to the H recombiners being inoperable.

2 In SNC's analysis, it was assumed that the containment source term for elemental and particulate forms of iodine was reduced by sprays. In addition, it was assumed that the elemental fo m of iodine was also subject to removal via plateout. SNC assumed that the sprayed and unsprayed regions were mixed by the containment cooling fans at a rate of 40,500 cim. However, the staff did not incorporate this assumption because the TS associated with the containment cooling fans places no requirements for fan flow. Consequently, there is no basis for assuming that mechanical mixing will occur at the above stated rate.

Condequently, the staff assumed that the flow rate between the sprayed and unsprayed regions was due to natural convection and was equal to two of the unsprayed regions volume per hour.

SNC also assumed that the elemental forms of iodine were removed from the containment due to plateout. SNC assumed that the removal rate was a function of the elemental iodine, which had been removed. Until a decontamination factor (DF) of 100 was achieved, the removal rate was 2.7/hr. Between a DF of 100 and 1000, the removal rate was 0.27/hr. After a DF of 1000 was achieved, no removal was assumed to o. cur due to plateout. The staff reviewed this assumption and determined that it was acceptable.

. WCAP-14723, Attachment 6, Tables 2.16-1 and 2.16-2 contain revised values for the post-accident iodine removal coemcients. Evaluation of these tables is presented bebw:

In calculating the coefficient for plateout of elemental iodine activity released to containment (A.), SNC used wall deposition velocities for elementaliodine from NUREG/CR-0009. Using these deposition velocities, SNC calculated A,=12.5 hr 4 However, NUREG-0009 specifically recommends that, in determining plateout coefficients, the mass transfer coefficient through gas film be used instead of wall deposition velocities. The same recommendation is made in Section 6.2.5, Revision 2 of the Standard Review Plan. Using this coefficient, the staff calculated A,=2.7 hr.

4 In its letter of March 3,1998, SNC changed the coefficient for plateout of elemental iodine to a A, value of 2.7 hr, which is an acceptable value.

4 When the concentration of iodine in the containment atmosphere is reduced and the DF for containment iodine reaches certain limiting value, iodine removal becomes less efficient, and the calculated coefficient for the removal of particulate iodine Dy containment sprays (A,) should be reduced by a factor of 10. In Section 6.5.2, Revision 2 of the Standard Review Plan, this limit is specified as DF=50 and was utilized

. in the staff's calculation. However, the value of DF=100 as specified in NUREG/CR-l 0009 is a conservative number. In SNC's submittal, it is given as DF=100. The value of DF=100 will have an insignificant effect on radiation doses and therefore is i

acceptable.

The staff did note some inconsistency in the manner in which SNC stated that it had performed the calculation of releases from ECCS leakage and the actual manner in which it was 4

performed. In Table 2 of a December 9,1997, letter to the staff, SNC indicated that it had assumed that the leakage associated with ECCS operation would be 20 times the value in I

FSAR Table 6.3-8. However, calculations provided in a March 3,1998, transmittal to the staff, j

showed that the value actually used was 10 times the rate in FSAR Table 6.3-8. The staff i

chose a value of 20 times the flow rate in FSAR Table 6.3-8 for this isssessment.

SNC stated that the results of its analyses demonstrated that in all cases, Part 100 doses and GDC-19 doses were met.

Additional details on the assumptions for this evaluation are presented in Table 3.5.1.3-1. The staff assessed the potential consequences of a LOCA based upon the assumptions in this Table. The thyroid, whole body and control room operator doses are presented in Tables 3.5.2-1 through 3.5.2-3, respectively. The doses were found to be acceptable in that they were less thari 25 rem whole body (or 300 rem to the thyroid) at the exclusion area boundary and control room doses were less than 5 rem whole body during an accident.

3.5.1.4 Main Steamline Break FNP has applied the ARC to its SG tubes. Application of this criteria permits SNC to make the decision to allow tubes to remain in service when previously SNC would have been required to plug or sleeve the tubes due to the degradation that has occurred. However, allowing these tubes to remain in service necessitates that SNC 'take into account, in its analysis, the potential,

, which exists, that an MSLB may induce leakage in the tubes that have been allowed to remain in service due to application of ARC. Consequently, when an analysis is performed of the consequences of an MSLB accident concurrent with a loss of offsite power, SNC assumes that the accident induces leakage in those tubes of the affected SG which has experienced the pressures associated with a steamline break and to which ARC has been applied.

On October 29,1997, Amendments 132 and 124 were issued to FNP Units 1 and 2, respectively, which implemented the most recent ARC criteria. This amendment approved a primary-to-secondary leak rate of 23.8 gpm and primary cociant activity levels of dose equivalent '8'l of 9 pCi/g for the maximum instantaneous value and 0.15 pCi/g for the 48-hour

{

value. _On March 16,1998, SNC submitted a revised MSLB analysis that utilized the assumptions of Amendments 132 and 124 but modified the assumptions to incorporate changes associated with the power uprate such as steam released from the intact SGs.

For the power uprate amendment, the reevaluation of.the MSLB involved two cases. One case assumed the accident occurred following an iodine spike, referred to as the oreexisting spike case. The second case assumed that the MSLB resulted in the initiation of :.n iodine spike, referred to as the accident-initiated spike. In both cases, a 150 gpd/SG, primary-to-secondary leak was assumed for the intact SGs. For case one, it was assumed that a preexisting iodine spike had occurred prior to the steamline break. Reactor coolant concentration was assumed to be at the TS Figure 3.4-1 full power limit of 9 pCi/g of dose equivalent '8'l.

The second case assumed the steamline break initiated a concurrent iodine so!ke. The reactor coolant concentration was assumed to be at the existing TS 48-hour limit of 0.15 pCi/g dose equivalent is'l. The secondary system activity was assumed to be at the TS limit of 0.1 pCi/g dose equivalent '8'l. Concurrent with the MSLB, an iodine spike was ast umed to occur that releases iodine from the fuel gap to the reactor coolant at a rate that is 600 times the normal iodine release rate. No failed fuel was assumed to occur as a result of the MSLB.

For both analyses, it was assumed that the 23.8 gpm of primary-tassecondary tube leak occurred in the faulted SG until it was isolated. After isolation of the faulted SG, it was assumed that primary-to-secondary leakage to the intact SGs would continue at a rate of 150 gpd/SG. Because offsite power is assumed to be lost, tra main condenser was unavailable for steam dump and cooling of the reactor core must occur through the use of the safety valves. After 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, no further steam release or activity release was assumed to occur due to the steamline break.

The power uprate amendment request presented a new value for the quantity of steam released from the intact SGs during an MSLB. The quantity presented in the power uprate amendment was approximately 25 percent less than the value which was presented in support of the latest ARC amendments. This decrease in steaming rate for the intact SGs incorporated a plant-specific value for Farley whereas the previous value had been a generic Westinghouse value. A rigorous calculation of the dose consequences of an MSLB would include the contribution from the steaming of the intact SGs. However, the dose contribution from this source is minimal. The staffs analysis, which assessed the latest ARC amendment request, assumed, in the calculation of doses, that any primary-to-secondary leakage to the intact SGs was released to the environment without a partition factor. This is a conservative assumption.

i

1

.o-, Since the primary-to-secondary leakage rates remained unaffected by the power uprate, the doses, which were calculated by the staff, remain unchanged. Based upon the manner in which the staff calculated the doses for the MSLB in the ARC amendments, these doses remain

. relevant and acceptable and are incorporated into this safety evaluation.

SNC was also asked to determine if the MSLB remained the limiting accident with respect to radiological consequences when the effects of ARC and the power uprate are considered or if the locked rotor or the rod ejection accidents resu!ted in accident-induced leakage which, when coupled with the increase in source term, became more limiting. The staff's concem was that the pressure transient associated with the locked rotor and rod ejection accidents might induce leakage during the event, When this, accident-induced leakage is combined with the normal operating primary-to-secondary leakage and the failed and melted fuel associated with the transient, the potential exists that one of these accidents may b6come more limiting, from a radiological standpoint, even though the partition factor for the faulted SG is 1 for the MSLB and j

100 for the other transients, provided the tubes are covered. SNC indicated that for the power uprate, even with the inclusion of ARC, the MSLB is the more limiting accident. SNC stated that the basis for this statement was contained in WCAP-12871, Rev. 2, "J. M. Farley Units 1 and 2 Steam Generator Tube Plugging Criteria for ODSCC at Tube Support Plates," February 1992. Section 11.3 of WCAP-12871 had concluded that the increased source terms associated with the locked rotor and rod ejection accidents were offset by reduced primary-to-secondary differential pressure; decreased flashing and increased mixing in the SG; and continued coverage of the SG tubes at the tube sheet and the tube support plate interfaces. The issue of partial SG tube uncovery was addressed generically by the Westinghouse Owners Group and documented in WCAP-13247, " Report of the Methodology for the Resolution of the Steam

{

Generator Tube Uncover issue," in March of 1992. SNC stated that the conclusions drawn in the study, that the current design basis methodologies remain valid, is still applicable to Farley given the power uprate and the implementation of ARC.

j SNC also presented a qualitative assessment to demonstrate that the MSLB was still limiting, with respect to radiological consequences. An assessment of the expected primary-to-secondary differential pressure associated with the locked rotor and rod ejection accidents determined that the locked rotor pressure transient was more challenging with regard to' primary

' to secondary differential pressure. For the locked rotor accident, the primary pressure peaks in approximately 3 seconds for Farley and levels off after about 25 seconds. Farley estimated the accident-induced leakage for a locked rotor event. This scoping assessment relied on leakage data obtained previously for iive pulled tube specimens from the Farley SGs. Leakage data for i

these specimens was collected for differential pressure loadings representative of normal operating conditions and of MSLB. This data was adjusted to reflect the pressure, temperature, J

and hydraulic conditions associated with the postulated locked rotor event. The adjustment

- procedure was adapted from an adjustment methodology included and documented in the industry ARC database for 7/8-inch tubing. This data base has been accepted by the NRC as documented in GL g5-05 and plant-specific SERs approving implementation of the ARC.

Application of the adjustment procedure yielded a factor of 3.7 reduction in leakage rate for the first 25 seconds of a postulated locked rotor event when compared to leakage under postulated MSLB conditions and a factor of 8.4 reduction after 25 seconds.

, SNC's estimates are based on limited data that required significant adjustment to reflect postulated conditions during the. locked rotor event. Nevenheless, SNC's estimates incorporate a number of conservatisms such that it is the staff's judgement that actual leakage under postulated locked rotor and rod ejection events would be less than that indicated by SNC's assessment. In particular, SNC took no credit for the constraint against leakage provided by the corrosion product in the tube-to-tube support plate (TSP) crevices. Such constraint has

_ typically not been assumed in assessing leakage from MSLB due to potential axial displacement of the TSP during the event. TSP displacement would not be expected to occur during locked rotor and rod ejection events.

SNC presented the resuits of offsite dose assessments based on the leak rate ratios above and a limiting MSLB leak rate of 24 gpm. The locked rotor estimate for leakage ~was utilized for the rod ejection accdent since its value bounded both assessments. For the locked rotor, accident-induced leakage was estimated at 6.5 gpm per SG for 0-25 seconds and 2.9 gpm per SG for the remainder of the accident. These leakage rates were assumed to exist for all three SGs and long-term leakage was assumed to last until the RCS ar.d SG pressures equalize.

It was assumed for the locked rotor that the leakage remained constant until residual heat removal cut in at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after that accident. For this qualitative assessment, SNC determined that a fuel failure value of 6.3 percent is sufficiently cor.cervative; 20 percent was assumed in the licensing basis calculations. The staff found the value of 6.3 percent acceptable. Based upon these assumptions, SNC, calculated a thyroid dose of approximately 22 rem.

For the control rod ejection, the duration of the accident, as described in the Farley Nuclear Plant Units 1 and 2 Power Uprate Project NSSS Licensing Report (WCAP-14723) was 2500 seconds. Using the rod ejection source term for the power uprate with the above noted primary-to-secondary leak rates, SNC calculated at offsite thyroid dose of approximately 46 rem.

Based upon the results for the locked rotor and rod ejection accidents noted above, since the consequences of the MSLB is at the existing dose limit of 30 rem, SNC concluded that the MSLB remains the limiting accident.. SNC concluded this because the MSLB is at 100 percent of the dose guideline value whereas the locked rotor and rod ejection accidents doses were determined to be 60-70 percent of their guideline values. SNC also concluded that the offsite consequences would be more limiting than the control room operator doses (GDC-19).

The staff has evaluated SNC's assessment of whether the MSLB remains the limiting accident.

The staff reviewed SNC's discussion of the pressure transients associated with the locked rotor and rod ejection accident, SNC's estimate of the accdent-induced leakage, which may be initiated by such events, the estimated fuel failures associated with the locked rotor and rod ejection events and the radiological consequences postulated for these events. The staff concluded that the postulated offsite doses by SNC were reasonable. In addition, the staff concluded that it would be the offsite consequences rather than GDC-19, which would be limiting for this assessment. Based upon its review, the staff has concluded that the MSLB remains the limiting accdent, with respect to radiological consequences, even when both ARC and the power uprate are considered.

=

c The details of the stafs asserament of the doses of an MSLB were presented in Amendments 132 and 124. The doses, which were presented in that assessment, are presented in Tables 3.5.2-1 through 3.5.2-3 for the sake of comp'eteness.

3.5.1.5 Steam GeneratorTube Ruoture SNC reevaluated the consequences o' a postulated SGTR accdent. For this evaluation, SNC assessed two cases. One case inv:,ived a preexisting spike. The other case involved an

. accident-initiated spike. In both cases, in the intact SGs, it was assumed that primary-to-secondary leakage existed at the present TS value of 150 gpd/SG prior to and following the SGTRc In the preexisting iodine spike case it was assumed that the iodine spike occurred prior to the SGTR. At the time that SNC performed its assessment of this accident for the power uprate, the existing technical specification value for the max.imum instantaneous value of dose equivalent '8'l in the reactor coolant was 30 pCi/g. It was at this value that SNC performed its dose assessment and submitted it to the staff for review and approval. Subsequently, in Unit 1

' Amendment 132 and Unit 2 Amendment 124, SNC reduced this value of dose equiv* lent 58 I to 9 pCi/g.

For the accident-initiated spike case, it is assumed that the SGTR initiates a concurrent iodine.

spike. For this assessment SNC assumed that the reactor coolant was at the 48-hour TS for dose equivalent '8'l. As for the preexisting spike case, SNC performed the analysis at the SNC

)

value (0.5 pCi/g) which was in existence at the time the power uprate amendment request was filed. The secondary system activity was assumed to be at the TS normal operation limit of i

0.1 pCi/g of dose equivalent '8'I. Concurrent with the SGTR, an iodine spike was assumed to occur that results in the release of iodine from the fuel gap to the reactor coolant at a rate that is 500 times the iodine release rate associated with the 48-hour TS value. SNC's analysis of the SGTR concluded that this accident resulted in no failed fuel.

For both analyses, it was assumed that offsite power was lost and the main condenser was i

unavailable for steam dump. SNC assumed that it took 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to cool the reactor down to a

{

point where no further release of steam or radioactivity to the environment would occur.

The staff has performed its assessment of the potential consequences of an SGTR event. The stars assessment assumed that the reactor coolant activity level for dose equivalent '8'l was at 60 pCi/g for the preexisting spike case and at 1 pCi/g for the accident-initiated spike case. The

. staff performed its assessment at this value because the staff anticipates that SNC will restore these values to the pre-ARC TS values upon replacement of the FNP SGs.

There were certain issues associated with SG operation that the staff believed needed to be l addressed in connection with the power uprate. These issues were SG overfill, SG flashing fractions, and tube uncovery. SNC addressed these issues following the stafs requests for additionalinformation SNC addressed the issue of SG overfillin the event of an SGTR by examining analyses g

performed for plants licensed with the methodology developed in WCAP-10698-P-A, "SGTR

O e Analysis Methodology to Determine the Margin to Steam Generator Overfill," and Supplement 1 to WCAP-10698-P-A, " Evaluation of Offsite Radiation Doses for a Steam Generator Tube Rupture Accident." SNC concluded that the power uprate and its associated changes should not result in an increase in either the possibility or the probability of SG overfill re, curring as a result of an SGTR. The staff finds this consistent with the conc!usions drawn in the approved WCAP-10698-P-A methodology on SG overfill.

With respect to flashing fractions in the event of an SGTR, the analysis performed by SNC assumed no flashing fraction for the leakage occurring from the ruptured tube. SNC indicated that some flashing of break flow from the ruptured tube would be expected. However, SNC indicated that they did not cons.ider flashing as.part of the FNP licensing basis analysis. SNC did provide figures with examples of break flow flashing fractions as a function of time for facilities that have performed detteiled transient analyses and have included flashing as a part of their licensing basis calculation.' These transient analyses modeled the expected operator action to terminate primary-to-secondary break flow, including isolation of the faulted SG, cooldown with the intact SGs, and depressurization with the pressurizer PORV.-

As provided by SNC, the results in both figures assumed that a loss of offsite power had occurred. One figure assumed that a PORV on an intact SG failed closed while the other figure assumed that the PORV on the faulted SG failed open and required operator action to close the associated PORV block valve. However, SNC did not include in its calculations any assumption for the flashing fraction.

The staff concluded that flashing is real phenomenon and should be included in the assessment of the consequences of the power uprate. Absent detailed flashing information, the staff utilized flashing fractions from a recently reviewed SGTR analysis for an SG replacement. The flashing fractions, which were utilized, would be considered conservative to a degree that the staff believes such values would envelope the flashing that might occur at FNP. With the utilization of these values, doses were found to be acceptable. Nevertheless, as a condition to this amendment, the staff has concluded that SNC should provide an SGTR analysis that incorporates a flashing fraction that is appropriate to the Farley design.

J SNC was asked to address the question of tube uncovery during certain transients. SNC indicated that the Westinghouse Owners Group (WOG) had confirmed, on a generic basis, and the staff had concurred in a March 10,1993, letter that the effects of partial SG tube uncovery has a negligible effect on iodine releases from SGTR and non-SGTR transients. A March 31, 1992, letter from the WOG documented information on the SG tube uncovery issue which had been previously discussed with the staff. This letter stated the following with respect to non-SGTR transients. "For those accidents for which some fuel rods are calctilated to be in DNB, the probability of the event and the set of conditions leading to significant offsite releases 1

is considered to be very low (less than_5 x 104 per reactor year) for a representative plant. It is possible that plant-specific considerations may modify the transient behavior and change the probability value." In its April 13,1998, letter, SNC concluded that the assessments done to support the March 31,1992, WOG conclusion are still applicable considering the effects of the power uprate and the use of ARC. The staff has reviewed SNC's April 13,1998, letter, and is in agreement with the SNC conclusion.

J

, Table 3.5.1.5-1 presents the assumptions utilized by the staff in its assessment. The potential consequences of an SGTR accident are presented in Tables 3.5.2 ' through 3.5.2-3. The staff concluded that even with the inclusion of the fisshing fractions and the assumption that the reactor coolant activity levels were at 60 pCi/g for the preexisting spike and 1 pCi/g for the accident-initiated spike case, doses were found to be acceptable.

4 3.5.1.6 Locked Rotor SNC assumed a postulated reactor coolant pump locked rotor event and subsequent leakage of steam from the secondary system due to the leakage of reactor coolant to the secondary -

system. Leakage from the primary side to the secondary side was assumed to exist at the TS -

value. SNC assumed that the contribution of activity from the initial reactor coolant activity levels, even when it is assumed that the reactor coolant activity levels are at the TS values for.

dose equivalent '8'l and an iodine spike is considered, is small relative to the contribution of activity from the release of the gap inventory from 20 percent of the fuel rods in the core. SNC indicated that its analysis results showed that fuel melting would not occur during a locked rotor event.

. The staff performed independent calculations of the consequences of the locked rotor accident.

Table 3.5.1.6-1 presents the assumptions utilized by the staff in its assessment. The staff's assessment of the potential dose consequences of a locked rotor accident are presented in

' Tables 3.5.2-1 through 3.5.2-3. The doses were found to be acceptable.

It should be noted that the staff performed its assessment of the consequences of this accident based upon primary coolant TS values of dose equivalent"'I of 60 pCilg and 1 pCilg. As noted for the SGTR assessment, the calculations were performed at these activity levels based upon the assumption that in the future, upon replacement of the SGs, SNC may wish to restore the TS limits for dose equivalent. Such an assumption will not require the staff to reanalyze this accident in the event that SNC wishes to increase the activity levels of dose equivalent *l in the reactor coolant at a later date provided that there are no future changes to the various arameters, operator actions, and operator and/or system or reactor responses that would alter the doses calculated for this assessment.

3.5.1.7 Fuel Handhng Accident SNC evaluated two fuel handling accident scenarios. The first assumed the refueling accident occurred within containment. In this scenario, a spent fuel assembly was assumed to be dropped onto the core. This was assumed to result in damage to an entire fuel assembly.

Following the drop, the activity released to the containment atmosphere was assumed to be released instantaneously to the environment via the containment purge exhaust filter. SNC assumed that the release via this pathway would have a removal efficiency of 90 percent for the.

elemental form of iodine and 30 percent for the organic form of iodine. SNC assumed no credit

- for decay resuting from holdup in the containment.

The second scenario assumed the refueling accident occurred outside containment in the area

'of the spent fuel pool which is located in the auxiliary building As in the previous scenario it was assumed that the dropping of a spent fuel assembly into the spent fuel pool would result in

. damage to one entire fuel assembly and the release of the volatile gaseous fission products to the spent feel pool with subsequent release to the environment through the penetration room filtration system. SNC assumed credit for mixing of activity in the open area just above the spent fuel pool. SNC took no credit for decay due to holdup in the auxiliary building nor credit

for decay due to transit time after release to the environment. The penetration room filtration system was assumed to remove iodine with an efficiency of 90 percent when it was in the

' elemental form and 70 percent when it was in the crganic form.

The staff has performed an independent calculation of a fuel handling accdont. The staff also evaluated two scenarios. The staff's assessment did not include credit for mixing in the buildings in which the fuel handling acedent occurred because the staff concluded that SNC did not provide adequate justification for the assumption of building mixing.

Table 3.5.1.7-1 contains details of the assumptions utilized by the staff in its assessment. The

. offsite doses are presented in Tables 3.5.2-1 and 3.5.2-2. The control room operator doses are presented in Table 3.5.2-3. The doses were found to meet Part 100 and GDC-19 criteria.

3.5.1.8 Rod Eiection SNC performed an analysis of a postulated rod ejection accident. It was assumed that the reactor was operating with equilibrium activity levels in the primary and secondary systems based upon 1 percent failed fuel and a primary-to-secondary leak rate of 150 gpd/SG. The

. analysis was performed with the assumption that there are two potential release pathways following a rod ejection accident. The first pathway is via containment leakage. It la assumed that the rod ejection accdent results in the release of activity from the fuel rods to primary coolant. A certain fraction of the activity released to primary coolant is assumed to be released to the containment and available for release from the containment at the TS value for containment leakage.

The second pathway is via the secondary side. For this pathway, the assumption is made that reactor coolant leaks from the primary side to the secondary side and then radioactivity is released to the environment via the relief valves since it is assumed that when offsite power is lost, the accident occurs.

For both release pathways, the assumption is made that all of the gap activity of the fuel that has its cladding degraded aa a result of the accident and all of the activity of the fuel that has experienced melting, is released to the primary coolant. SNC's analysis assumed that the rod ejection resulted in 0.25 percent of the fuel in the core melting and 10 percent of the fuel experiencing degradation of cladding.-

The staff has performed a cdiculation of the dose consequences of a rod ejection accdent.

Table 3.5.1.8-1 presents the assumptions utilized by the staff in its assessment. The doses,

which were calculated for this accident, are presented in Tables 3.5.2-1 through 3.5.2-3.

SNC performed the analysis of the consequences of releases occurring from both the secondary side release pathway and the containment pathway. The staff has presented separately the results of the assessment for each path. The thyroid dose at the low population

. zone exceeded the acceptance criterion of Appendix A to SRP 15.4.8. The staff finds this departure from the acceptance criterion acceptable because:

1.

The doses are below the guideline values of 10 CFR Part 100; 2.

The consequences were calculated on the basis of fuel failures that are predicted by -

conservative models; and 3.

The SRP acceptance criterion itself is conservative.

All other doses were found to meet the acceptance criterion of SRP 6.4 and SRP 15.4.8.

3.5.1.9 Small Break LOCA SNC calculated the potential consequences of an SBLOCA. In this assessment, SNP assumed the very same assumptions as those for an LBLOCA with two exceptions. The first exception was the source term that was assumed to consist of 100 percent failure of the fuel cladding that results in release of 100 percent of the gap activity. The second exception assumed that the sprays were not activated.- The resultant doses were assumed to occur only from containment leakage with no inclusion of the potential consequences of either a mini-purge or H, venting.

The staff performed a similar calculation. The staffs assessment assumed that the particulate form of iodine would undergo removal via plateout. The doses are presented in Tables 3.5.2-1 through 3.5.2-3. The doses were found acceptable.

3.5.2 Conclusions The staff has assessed those accidents for which the power uprate would have an impact upon the offsite and control room operator doses. These doses are presented in Tables 3.5.2-1 l-through 3.5.2-3. The staff's results demonstrated that, for those accidents that are impacted by

the power uprate, the doses would not exceed the dose guidelines presently contained in the Standard Review Plan,10 CFR Part.100, or GDC-19 of 10 CFR Part 50, Appendix A, for either j

offsite locations or control room operators. Therefore, the staff finds the proposed power uprate acceptable.

4.0 SYSTEMS. STRUCTURES. AND COMPONENTS EVALUATION i

' In its evaluation, the staff refers to several terms in the submittal. These terms are defined below:

ASME Code - editions of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code, Sections til or XI, as appropriate, through the 1988 Addenda

. and the 1989 Edition.'

ASTM Standard Procedures or Practices - procedures or practices for testing or analysis developed by the American Society for Testing and Materials.

e

. Charov-V notch test or Charov-V test - a fracture toughness test that involves impacting a small notched impact specimen (usually in bar form) with an impact pendulum and measuring the fracture energy of the specimen.

Charov transition curve or Charov-V curve - a graphic presentation of Charpy-V test

' data, including absorbed energy, and fracture appearance. The curve includes the lower shelf energy (< 5 percent shear), the transition region, and the upper shelf energy

(> 95 percent shear).

EQL *end of life," the scheduled date of expiration of the operating license for a licensed nuclear power generation facility.

EOL fluence - the best-estimate neutron fluence projected for a specific reactor pressure

- vessel (RPV) beltline material at the clad-base-metal interface on the inside surface of the RPV at the location where the material receives the highest fluence on the expiration date of the operating license.

Pressurized thermal shock (PTS) event - an event or transient in pressurized water reactors (PWRs) causing severe overcooling (thermal shock) concurrent with or followed by significant pressure in the reactor vessel.

Reactor oressure vessel (RPV) beltline - the region of the RPV (shell material including welds, heat-affected zone, and plates or forging materials) that directly surrounds the effective height of the active core and adjacent regions of the RPV that are predicted to experience significant neutron irradiation damage (a consideration in selecting materials).

RT,r,- the reference temperature, RT,er, evaluated for the EOL fluence for each of the RPV beltline material, using tne procedures of Paragraph (c) of the revised PTS rule, 10 CFR 50.61 (Ref. g). For materials in the RPV beltline, the RTers must account for changes in the reference temperature as a result of neutron irradiation damage.

ART,er - the transition temperature shift, or change in RT,er, due to neutron irradiation effects, which is evaluated as the difference in the 30 ft-lb (41 J) index temperatures from the average Charpy-V curves measured before and after irradiation.

UppetsheffinargyluSEl-the average value for all Charpy-V test specimens (normally three) whose test temperature is above the upper end of the transition region of the Charpy-V curve; for specimens tested in sets of three at each test temperature, the set having the highest average may be regarded as defining the USE of the material.

4.1 ReactorVesselIntegnty To determine the acceptability of the power uprate on the integrity of the reactor vessel, the staff evaluated the following-l 1

e

4 H

L Effect on the EOL USE Values for the Beltline Materials Effect on SNC's Revised Pressure / Temperature (P-T) Limit Curves and SNC's Assessment for Prevention Against Pressurized Thermal Shock Effect on the Material Surveillance Programs l

4.1.1 Effect on the EOL USE Va!L== for the FNP Units 1 and 2 RPV Beltline Materials Appendix G,

• Fracture Toughness Requirements," to Part 50 of Title 10 of the Code of Federal Regulations (10 CFR Part 50, Appendix G), requires, in part, that the Charpy-V USEs for RPV beltline materials be no less than 75 ft-Ib (102 J) in the unirradiated condition, and no less than 50 ft-lb (68 J) throughout the life of the RPV, unless it can be demonstrated in a manner approved by the Director, Office of Nuclear Reactor Regulation, that lower values of USE (as l

determined from the results of Charpy-V tests and Charpy-V curves) will provide margins of l

safety against fracture equivalent to those required by Appendix G of Section XI of the ASME l

Code.

l The staff performed an independent review of the Charpy-V test data for Surveillance Capsule Nos. Y, X, U, and W from Unit 1 and for Surveillance Capsules U, W, and X from Unit 2.

. These capsules have been removed from the FNP RPVs and tested in accordance with the respective FNP Unit 1 and Unit 2 surveillance withdrawal program requirements set forth in 10 CFR Part 50, Appendix H.

l Tables 4.1.1-1 and 4.1.1-2 (Attachment 1) compare the projected EOL USE values determined l

by the staff and by SNC. SNC's EOL USE values for the FNP Units 1 and 2 beltline materials were revised and submitted to the staff in SNC's submittal of February 12,1998. Both the staffs and SNC's calculation of the EOL USE values are based on the neutron fluence values for the RPV 1/4T locations as determined from the latest neutron transport calculations for the vessels. These fluences are'slightly more conservative than those which would be projected using RPV neutron dosimeter measurements. Tables 4.1.1-1 and 4.1.1-2 show the uprated, limiting EOL USE values for the FNP beltline materials in bolded print. SNC's projected EOL USE values for the FNP units under uprated conditions were within -4 ft-lbs to +2 ft-lbs of the USE values calculated by the staff and therefore were in agreement. The tables indicate that the beltline materials in the FNP Units 1 and 2 RPVs will continue to satisfy the EOL USE criteria specified in 10 CFR Part 50, Appendix G, if the request to increase the rated thermal l

power of the plants is approved by the staff. Conservative neutron-transport-calculation-based fluences were used to project the EOL USE values for the FNP beltline materials.

l I

'412 Effect on SNC's Revised P-T Limit Curves for FNP Unit 1 and Unit 2 and SNC's 6===== ment for Prevention Aaminst Pra==urizad Thermal Shock l

Section 50.61 to Part 50 of Title 10 of the Code of feders/ Regulations, requires, in part, that

"[f)or each pressurized water reactor for which an operating license has been issued.... the licensee shall have projected values of RTns, accepted by the NRC, for each reactor vessel beltline material for the EOL fluence of the material...For each pressurized water nuclear reactor for which the value of RTn for any materialin the beltline is projected to exceed the l

, PTS screening criterion using the EOL fluence, the, licensee shall implement those flux reduction programs that are reasonably practicable to avoid exceeding the screening criterion...." '

in its review, the sta# performed its own calculations of the effect of the uprated EOL fluences on the projected EOL RTm values for the Units 1 and 2 RPV beltline materials. The staff used the methodology in 10 CFR 50.61 to calculate projected RTm values. The reviewis documented in the staffs SE dated March 31,1998 (Reference 21).

In that SE, the staff determined that the RTm values will continue to satisfy the criteria of 10 CFR 50.61 under the uprated conditio s for the plants. Therefore, the sta# concludes that after the power uprate, FNP Units 1 and 2 will remain in complianco with the criteria of the revised PTS rule,10 CFR 50.61.

The staff also assessed SNC's requests for approval of the uprated P-T limit curves (PTLRs) for the RCSs, and of SNC's proposed PTLRs for the FNP facilities. Appendix G to 10 CFR Part 50 states the requirements for generating P-T limit curves; Generic Letter (GL) 96-03, " Relocation of the Pressure Temperature Limit Curves and Low Temperature Overpressure Protection '

System Limits," provides the staffs position on removing the P-T limit curves from the limiting conditions for operation in the TS. In its SE (Reference 21), the staff determined the proposed, uprated P-T limit curves and PTLRs for the FNP RPVs were acceptable for implementation.

Therefore, the staff concludes that the power uprate will not a#ect SNC's compliance with the criteria of Appendix G to 10 CFR Part 50 or conformance with the staffs position stated in GL 96-03.

4.1.3 Effect on the Material Surveillance Prow ms for the FNP Units 1 and 2 Appendix H to 10 CFR Part 50 provides the NRC's requirements regarding licensee-implemented RPV material surveillance programs. SNC has provided the surveillance capule withdrawal schedules for the FNP units in Table 3-1 of the respective PTLRs for the units. In its submittal of July 13,1997, as amended by its submittal of December 18,1997, SNC requested a number of changes to the FNP Units 1 and 2 material surveillance programs among its PTLR license amendment requests. The proposed changes are based on the uprated neutron fluence values for the beltline materials and surveillance capsules. SNC has informed the NRC that it is currently using the criteria of ASTM Standard Practice E185-82 as the current basis for its material surveillance programs for the FNP units. 2 This is consistent with the criteria of 10 CFR Part 50, Appendix H. The staffs evaluation of the proposed changes to the surveillance programs is provided in an SE (Reference 21). In this SE, the staff reviewed the proposed changes to the materials surveillance programs as proposed in Table 3-1 of the j

proposed PTLRs for the units. The staff determined that the changes to limiting neutron fluence levels for the surveillance capsules under the power uprate will not affect the ability of the materials surveillance programs to comply with the requirements of 10 CFR Part 50 1 According to the revised rule,10 CFR 50.61, the PTS screening criteria are 270'F for plate materials, forging matenals, and axial wold materials, and 300*F for circumferential wold matonals.

2 Henceforth ASTM Standard Prachce E18582 will be sbbreviated as E18%82.

E

. Appendix H. Therefore, the staff concludes that SNC's proposed changes to the material surveillance programs for FNP Units 1 and 2 are acceptable.

4.2 ReactorVesnel SNC reported that the power increase wil: result in changing the design parameters given in Table 2.1-1 of Reference 36. Table 2.1-2 provides various cases that were developed for use in the power uprate analysis.

SNC evaluated the reactor vessel considering the worst load sets of operating parameters and design transients and a new set of LOCA loads, which was identified for the uprated power condition. The regions of the reactor vessel affected by the power uprate include outlet and inlet nozzles, the RPV (main closure head flange, studs, and vessel shell), control rod drive mechanisms (CRDM) housing, bottom head to shelljuncture, core support pads and the instrumentation tubes. SNC evaluated the maximum ranges of stresses and cumulative fatigue usage factors for the critical components at the core power uprated conditions. The evaluation was performed in accordance with the ASME Code, Section Ill,1968 Edition, with addenda through the Summer 1970 to assure compliance with the code of record.

The calculated maximum stresses and the maximum cumulative fatigue usage factors (CUF) for the reactor vessel criticallocations are provided in Table A of Reference 6. The results indicate that the maximum stresses are within the allowable limits for FNP Units 1 and 2, and the CUFs remain below the allowable ASME Code limit of 1.0.

On the basis of its review, the staff concludes that the current design of the reactor vessel is in compliance with codes and standards under which the plant was licensed, for the uprated power conditions.

4.3 Reactor Core Snanart Structures and Vessel Intemals By letter dated August 5,' 1997, SNC provided additional information requested by the staff, with regard to the evaluation of the reactor vessel core support and intemal structures. The limiting

. reactor intemal components evaluated include the lower core plate, core barrel, baffle plate, baffle / barrel region bolts, and the upper core plate.

SNC evaluated the upper and lower intemals considering the worst case set of operating parameters provided in Table 2.1-2 of Reference 36. The evaluation was performed in accordance with the original design-basis criteria for the FNP reactor intemais, which had been previously reviewed by the staff. For the lower core plate reanalysis, the evaluation was performed using Sechon Ifl, Subsection NG of the' ASME Code,1989 Edition with 1990 Addenda. The maximum calculated stresses and cumulative fatigue factors for the limiting intomal components at the power uprate conditions are identified on page.45 of Reference 4.

The maximum stresses for components were below the Code allowable limits, except the upper

. core plate and the baffle / barrel bolts. For the upper core plate, the maximum combined primary and secondary stress exceeded the 3Sm limit. A simplified elastic-plastic analysis was performed in accordance with ASME NG-3228.3. The reanalysis indicated that the fatigue usage factor was 0.08, which is less than the limit of 1.0, and that the combined primary and

e l secondary stress intensity, excluding thermal bending stresses, was less than 3Sm. No stress was given for the bame/ barrel bolts. SNC indicated that the beme/ barrel bolts were originally -

qualified by test to loads associated with the existing design basis conditions, and these bolts are acceptabla because the existing design basis condition is bounding for the propored power

. update condition. The maximum CUF was (alculated to be 0.gi7 for the baffle / barrel bolts at 1

the proposed power uprate condition.

It is noted that bame/ barrel bolts degradation was reported in European PWR plants. The Westinghouse Owners Group (WOG) has identified a lead plant for inspection in the fall of 1998 for a possible bame/ barrel bolt cracking. SNC should assess the results of the lead plant's inspection for its applicability to the bame/ barrel bolts at FNP and update its evaluation and conclusion as necessary.

. Further, SNC reviewed the potential for a flow-induced vibration on the guide tubes and the upper support column at the uprated power level. The evaluation indicated that the existing analysis provides sufficient margins to accommodate the increase (by approximately 1.g percent) in the flow-induced vibration loads due to the power uprate On the basis of the above evaluation, the staff concludes that the reactor internal components at FNP Units 1 and 2 will retain within the allowable limits of stress and fatigue usage factor for operation at the proposed uprated power conditions.

4.4 Control Rod Dnve Mechanisms SNC evaluated the adequacy of the CRDMs by reviewing the FNP current Model L106A CRDM design specifications and stress report to compare the design-basis input parameters against the operating conditions at the uprated core power. The components reviewed include the full-length (F/L) L-106 CRDMs, the Capped Latch Housing Assemblyynd the Royal industries Part Length (PlL) CRDMs employed at FNP. The maximum temperature for FNP power uprate is 613*F, which is below the design temperature of 650*F. The pressure remains the same at 2250 psia. On the basis of this evaluation, SNC concluded that the original design basis thermal and structural analyses are bounding for the core power uprate.

On the basis of its review, the staff concludes that the current design of CRDMs is in compliance with licensing basis codes and standards for the uprated power conditions.

4.5 Steam Generators SNC evaluated the SGs by comparing the power uprate conditions with the design parameters of the Westinghouse Model 51 SGs at FNP. The comparison shown in Table 2.1-2 of Reference 36 indicates th&t critical design system parameters such as the primary and secondary side pressures, as well as the vessel outlet and secondary side temperatures, are not significantly affected by the uprated power conditions. The variation in the primary-to-secondary pressure differential is within about 8 percent. SNC indicated that there are no significant changes to the design transients as a result of the core power uprate. The evaluation was performed in accordance with the requirements of the ASME Code, Section lil, 1971 Edition.

o-

, o y

The maximum stresses and cumulative fatigue usage factors for the critical SG components are s-providsd in Table B, page 53 of Reference 6. The results indicate that the maximum calculated stresses are below the Code allowable limits except for the divider plate. For the divider plate, SNC performed a plastic analysis considering the actual material stress-strain relation and the st,ess redistribution, in accordance with the NS-3228.1(b) of the 1971 ASME Code. The '

analysis indicated that the maximum strain and the calculated CUF are within the allowable range, and that the divider plate will remain in compliance with licensing basis codes and

. standards for the upratori power condition. The revised CUF values for other SG components excluding the U-bend tubes are less than the Code limit of unity except for the secondary manway bolts at which the CUF was calculated to be 1.18. SNC indicated that it plans to' replace the secondary manway bolts prior to 34 years of service so as to remain within compliance with the fatigue limit requirement.

- SNC assessed the potential for flow-induced vibration for the small radius U-bend tubes at the power uprate condition. The evaluation concluded that changes to vioration levels and cross flow velocity due to power uprate were within the acceptable range. The (1-bend fat'gue evaluation was updated using the FNP existing methodology in WCAP-11875 (Reference 32).

The restAs indicate that the fatigue usage of the U-bend will exceed the acceptance limit of 1.0 it' 13.7 years after the implementation of the power uprate at FNP Units 1 and 2 in 1998 outages. SNC concluded that the U-bend needs to be monitored and would require some type.

of correctiv.e action at that time, as necessary. SNC noted in Section 5.7.3 of Reference 36 that following the implementation of power uprate, the outlet pressure and the steam flow for each steam generator can be documented on a cycle-specific basis for use in any future update of the U-bend fatigue evaluation

'On the basis of its review, the staff finds that the current FNP Units 1 and 2 SGs are acceptable for the proposed core power uprate up to 13.7 years following its implementation at both Units 1 and 2. It should be noted that SNC currently is planning to replace the Unit 1 SGs -

. during the spring 2000 refueling outage and Unit 2 SGs during the spring 2001 refueling outage. Upon replacement, the issue regarding exceeding the cumulative fatigue usage factor for the secondary'manway bolts and U-bend tubes will no longer exist.

4.5.1 SG Tube int *Guk 4.5.1.1 SG Tube Degradation To minimize the 'effect of the power uprate on tube degradation, SNC intends to maintain the same T. (the hot leg temperature) before and after power uprate, with a 0.5 *F allowance to account for measurementpariations and uncertainties. Industry experience has shown that, in

. general, a high T. correlates with increased tube degradation. Therefore, limiting T to the

preuprate value should preverd the rate of tube degradation from increasirs after the power uprate.' However, the power uprate will slightly reduce the steam pressure and the

- corresponding saturation temperature, changes that may increase tube degradation.

SNC evaluated the effect of power uprate on tube degradation mechanisms, including primary water stress corrosion cracking (PWSCC), and outside diameter stress corrosion cracking

. _ (ODSCC), in various regions of tubing. The staffs assessment of the mechanisms is discussed below.

I l

4.5.1.1.1 PWSCC of tubing i

SNC stated that the main contributors to PWSCC are residual, pressure, and thermal stresses.

SNC stated that the power uprate would increase only the through-wall pressure stress. This stress would increase because the primary-to-secondary differential pressure would increase from about 1435 psi to 1463 psi. The resulting pressure stress will increase the PWSCC kinetics by 2 percent to 2.5 percent. SNC concluded that considering the uncertainties in estimating the various contribubons to PWSCC, the increase in PWSCC kinetics is insignificant; therefore, the effect of the power uprate on PWSCC is insignificant. The staff finds that an increase of 2 percent to 2.5 percent in PWSCC kinebcs is insignificant and, therefore, the impact of the power uprate on PWSCC of tubing is insignificant.

4.5.1.1.2 ODSCC of tubing SNC evaluated the regions where ODSCC has occurred, such as in the tube support plate crevices, the sludge pile at the top of the tubesheet, and the free span regions of the tubing.

SNC found that the beneficial effect of lowering secondary temperature tends to be stronger than the deleterious effect of increasing the applied stress in the tube support plate crevices and on the free span regions. Therefore, the power uprate will minimally affect the tube support plate crevices and free span regions. However, SNC predicted the expected ODSCC -

rate in the sludge pile to slightly increase becauw its analysis did not take credit for the lormr l

secondary temperatures in the sludge pile. SNC inspects the parts of the tubes in the skxige I

pile during each refueling outage and would readily detect any increase in tube degradation -

I there. Based on SNC's assessment, the staff finds that the effect of power uprate on ODSCC of tubing would be minimal.-

4.5.1.1.3 Degradation of U-bends in small radius tubes bv stress corrosion credina i

SNC stated that it stress-relieved the small radius U-bends to reduce ttwir residual stresses.

The increased wall pressure stress and the reduced residual stress cancel each other out so that the impact of the power uprate in the small radius U-bends is negligible. To ensure stress corrosion cracking does not increase in the small radius U-bends, SNC inspects all U-bends in rows 1 and 2 at the refueling outage ofter the power uprate. Based on SNC's assessment, the staff finds that the impact of the power uprate on stress corrosion cracking in the small rad.bs U-bends is insignificant.

4.5.1.1.4 Tubes susceptible to wear from anti-v;bie;en bars SNC stated that it replaced the anti-vibration bars on steam generator tubing in Units 1 and 2.

Since replacing them, SNC has not observed any tube wear typically caused by anti-vibration bars.' SNC stated that the power uprate is not expected to cause wear from the replaced anti-vibration bars. Based on SNC's observation, the staff finds that the power uprate should not significantly affect the tube wser by anti-vibration bars.

i 4.5.1.1.5 Additional surveillance to monitor tube dearadation SNC stated that before each SG inspection, it assesses degradation mechanisms active in the FNP SGs and in similar SGs throughout the industry. SNC plans to develop inspection plans that will ensure adequate detection of the degradation mechanism in the affected areas. Any new degradation mechanisms and significant increase in degradation rates should be detectable by the planned inspections. The staff is satisfied with SNC's plan to assess the inspection plan for the FNP SGs should new degradation mechanisms be discovered.

4.5.1.1.6 Minimum tube wall thickness SNC determined the minimum required wall thickness to be 0.022 inch (44 percent of wall thickness) on the basis of a safety margin of three against failure by bursting during normal operations (Reference 27). SNC stated that the plugging limit of 40 percent through wall in the current FNP TS satisfies the required minimum wall thickness under the power uprate conditions. SNC also stated that the 40 percent through-wall plugging limit applies only to tube degradation detected by a qualified sizing technique. The staff finds that the minimum tube wall thickness will maintain the stmetural integrity of the tube under power uprate conditions.

Based on its review of the information submitted, the staff concludes that the structural integrity of steam generator tubing is acceptable under the power uprate conditions.

4.5.2 SG Tube Pluaaino and Reoair Criteria SNC evaluated the effect of the power uprate on the ODSCC of the tubes in the tube support plate intersections under the voltage-based attemate repair criteries ia ihe FNP TS. SNC implemented the attemate repair criteria in accordance with the guidelines of GL 95-05 (Reference 26). The criteria were approved by the staff on March 24,1997, for Unit 1 (Reference 42) and October 11,1996, for Unit 2 (Reference 41). SNC determined that the voltage-based repair criteria are not affected by the increase in the primary-to-secondary differential pressure associated with the power uprate under normal conditions. Under the attemate repair criteria, tubing is qualified for a safety margin of 1.4 against steamline break differential pressure, a margin that is not changed by the power uprate. SNC also stated that the upper voltage repair limit of the attemate repair criteria is not directly affected by the power uprate. Based on SNC's assessment, the stafl finds that the power uprate has an insignificant impact on ODSCC of the tubing under voltage-based attemate repair criteria.

SNC stated that the only repair criteria that will be affected by the power uprate are the F*

criteria for Unit 2. Unit 1 has no F* criteria. The F* criteria in Ur it 2 TS 3/4.4.6 are affected by the increased differential pressure between the primary and secondary loops under the power uprate. SNC proposed revising the existing F* distance from 1.54 inches to 1.6 inches in the FNP Unit 2 TS. The F* distanca is the length of the expanded part of the tube inside the tubesheet that provides a sufficient length of undegraded tube expansion to resist the pullout of

. the tube from the tubesheet. Under the power up ate, the F* distance needs to be lengthened to provide additional tube friction surfaces t > resist the increase of the pullout force resulting from increased primary-to-secondary differential pressure during postulated accidents. Based

i.

on the staff's previous review, the staff determined that the proposed F* distance of 1.6 inches is acceptable and may be incorporated into the FNP Unit 2 TS.

I 4.5.3 SG Blogdggp (SGBD) System

- The SGBD system is used to control the chemical composition and buildup of solids in the SG shell water. At FNP, the SGBD can handle a continuous blowdown rate of 12.5 gpm per SG -

and a maximum intermittent blowdown rate of 50 gpm per SG. The actual blowdown rates during plant operation are based on chemistry control and the requirements for controlling solid buildups on SG tubesheets. These parameters will not be significantly affected by power uprate and the blowdown rates for power uprate conditions will be bounded by the current rates. The staff finds that the existing SGBD rates will remain unchanged for the conditions resulting from the power uprate.

4.6 Reactor Coolant Pumos (RCPs)

SNC evaluated the FNP RCPs in accordance with Section lil, Subsection NB of the ASME Code,1971 Edition, with Addenda through Summer 1972. The evaluation was performed by reviewing the design analysis of the Westinghouse Model 93A RCPs in comparison with the proposed uprated conditions as shown in Table 2.1-2 of Reference 36. The components evaluated included the RCP casing, main flange bolts, thermal barrier, casing foot, discharge and suction nozzles, casing weir plate, seal housing, and auxiliary nozzles.

After the core power uprate, the RCS pressure remains unchanged. There are no significant changes to the design thermal transients. The number of occurrences of applicab's transients in 40 years are provided in a table on page 50 of Reference 6. The increase in temperature fluctuation due to power uprate for the RCP was used in the stress analysis for components that constitute the pressure retaining boundary. The evaluation indicated that the maximum stress intensity in the casing weir plate was less than the allowable Code limit. The calculated CUFs were less than the fatigue limit of 1.0.

On the basis of its review, the staff finds that the current Model 93A RCPs, when operating at the proposed power uprated conditions, will remain in compliance with the requirements of the codes and standards under which the FNP Units 1 and 2 were originally licensed.

4.7 Pressunzer SNC evaluated the adequacy of the pressurizer and components including the pressurizer spray nozzle, safety and relief nozzle, upper head and shell, manway pads and bolts, instrument nozzle, support lug, surge nozzle, lower head / heater well, immersion heater, ahd valve support bracket for operation at the uprated conditions. The evaluation was performed in accordance with the requirements of the ASME Code, Section lil,1968 Edition, through Summer 1970 Addenda, for FNP Unit 1 and 1968 Edition, through Winter 1970 Addenda for FNP Unit 2.

The limiting operating conditions of the pressurizer occu'r when the RCS pressur6 is high and the RCS hot leg (Thot) and cold leg (Teoid) temperatures are low. This maximizes temperature A

A:

3 differential and thermal stress that are experienced by the pressurizer. The RCS pressure is unchanged for the FNP power uprate. There is an insignificant change in the design transients regarding type and number of occurrences during the 40 years of plant operation, for FNP power uprate as seen in a comparison table on page 57 of Reference 6. The minimum cold leg temperature decreased by 13*F, with respect to the original design conditions. The original fatigue analyses were updated to account for the uprated power conditions. The CUFs at the criticallocations are provided in a table on page 58 of Reference 6. SNC indicated that the maximum calculated stresses at the critical locations are unchanged except for the surge line nozzle. The maximum stress intensity at the surge line nozzle was recalculated and was found

- to be less than the allowable Code limit. The maximum CUFs at the limiting locations are 0.94 for the surge nozzle 'and 0.78 for the pressurizer upper head and shell.

The performance of the pressurizer safety valves (PSVs) and the PORVs are dependent on the pressurizer operating pressure and temperaturc, which are unchanged for the power uprate at FNP. The transient analysis for the power uprate was performed assuming a maximum tolerance of lift setting, as specified in Sections 3/4.4.2 and 3/4.4.3 of the FNP Technical Specifications. The PSVs and PORVs setpoints, rated capacities, and corresponding dynamic

- loads imposed on the piping and supports due to valve operation do not change as a result of the proposed power uprate.

On the basis of the above review, the staff finds that the existing pressurizer and components remain adequate for the plant operation at the proposed uprated core power.

'4.8 Chemical and Volume Control System (CVCS)

The main role of the CVCS is to maintain RCS water inventory, boron concentration, and water chemistry.. To perform these functions, the CVCS must meet the following requirements: (1) the parts of the system that constitute the reactor coolant pressure boundary can withstand the expected RCS conditions, (2) boration meets the design requirements for reactivity control, and (3) with the exception of RCP seal injection line, the system can be automatically isolated -

during all events requiring its isolation. The proposed power uprate will not affect the CVCS isolation function, but it will have some effect on the integrity of the RCS pressure boundary and on the boration of the RCS. SNC therefore, evaluated the effect of the uprate on the performance of the CVCS.

4.8.1 RCS Temperature During power uprating, a change in reactor coolant temperature may affect 'the integrity of the primary coolant Doundary during normal operation and during thermal transients. However, SNC's evaluation concluded that, after the power uprate, the design basis RCS cold leg temperature of 541.1'F w*ill be well below the system design temperature of 650'F and below

. the maximum RCS inlet operating temperature of 547'F, established in the CVCS overall

' design. Furthermore, the regenerative, letdown, excess letdown,'and seal water heat

. exchangers will also operate within acceptable' limits, and the load on the component cooling water system will not be excessive. The CVCS will, therefore, preserve its design functions.

SNC also analyzed the performance of the CVCS during conditions resulting from thermal

~

't 4 transients and found that it is bounded by the original design parameters. The staff finds SNC's evaluation acceptable.

4.8.2 Boraton A revised average RCS temperature range after the power uprate will result in a decrease of

. the RCS volume, and a smaller volume will make the boration operation more conservative.

However, boron dilution will occur at a faster rate and would adversely affect the RCS shutdown margin. SNC analyzed an uncontrolled boron dilution event for the uprated power level'c identify the minimum amount of time that would be available to terminate an inadvertent boron dilution before a complete loss of shutdown margin. The analysis showed that for both automatic and manual control modes; the boron dilution could be terminated in' time to avoid

~

exceeding the safety margin. The staff finds SNC's evaluation acceptable.

The staff finds the operation of the CVCS at uprated power conditions acceptable because all the requirements for its satisfactory parformance are met.

~ 4.g NSSS Piping and Pine Sunoorts The' proposed power uprate of FNP Units 1 and 2 involves the increase of temperature difference across the RCS. SNC evaluated the NSSS piping and supports by reviewing the design basis analysis against the uprated power condition, with regards to the design system parameters, transients, and the LOCA dynamic loads. The evaluation was performed for the reactor coolant loop (RCL) piping, primary equipruent nozzles, primary equipment supports,-

pressurizer safety and relief valve (PSARV) piping, and the pressurizer surge line piping. The methods, criteria, and requirements used in the existing design basis analysis for FNP Units 1 -

and 2 were used for the power uprate evaluation.

The RCS pressure remains unchanged for the proposed core power uprate. The actual hot leg temperature for the power uprate is projected to be equal to or less than the hot leg temperature at the current rated power level. The cold leg temperature for the power uprate condition will be less than for the curTent power level. The changes in design transients are insignificant for FNP power uprate with regards to the type and number of occurrences during

. the 40-year p. ant operation. ' The loop hydraulic forces will increase slightly due to the decrease in the cold leg temperature and the increase in water density at the power uprate condition.-

The original' structural design basis of FNP RCL piping and ' supports required consideration of dynamic effects resulting from postulated guillotine breaks in the primary loop piping. SNC's leak-before-break (LBB) analyses for the FNP Unit 1 and Unit 2 reactor coolant systems is provided in Westinghouse WCAP-12825 (Reference 33). In this analysis, 'Nestinghouse indicated that the ratio of the entical flaw size to the leakage flaw size was 4.1 for the FNP Unit 1 RCS piping.~ The corresponding ratio for the FNP Unit 2 RCS piping was 5.6. Since both ratios exceeded the required safety margin of 2.0, the staff approved SNC's RCS piping LBB analysis for implementation in its letter of August 12,1991 (Reference 37).

. The staff determined that the proposed 4.6 percent increase in reactor power for the FNP units wou!d only increase the pressure and thermal loadings for the RCS piping. The proposed

, power uprate will not affect the dead weight, safe shutdown earthquake (SSE), and seismic anchor motion (SAM) loadings.' The staff conservatively estimates that the resulting increase in the total loads for the LBB analysis would not reduce the ratio of the critical flaw size to leakage flaw size by more than 10 percent of the values reported in WCAP-12825. These margins are still considerably greater than the minimum requirement for a safety margin of 2.0 on RCS piping LBB applications.. Therefore, the proposed power uprate will not change any of the LBB conclusions in stated in WCAP-12825, or in the stafl's safety evaluation of August 12,1991. In addition, postulated breaks in the primary loop piping have been eliminated and replaced with postulated breaks in the surge line on the hot leg and in the accumulator line on the cold leg.

As a result of the elimination of primary loop piping breaks, the existing margin (approximately

~ 30 percent), based on consideration of the accumulator line and surge line breaks, is suffeient l-to accommodate the increase in loop hydraulic force due to the power uprate.

SNC's evaluation indicated that in all cases, except for the RCL crossover leg usage factor, the existing design basis stress analyses for the RCS system piping and supports and systems connecting to the RCS system, are bounding for the power uprated conditions. The crossover leg CUF experiences a minor increase but remains below the specified limit for a postulated L

break. The evaluation was performed in accordance with Section lli of the ASME Code, to j

l assure compliance with the code of record at FNP Units 1 and 2. SNC concluded that the plant

{

power uprate has no adverse effect on the ability of these components to operate.

The staff finds that the increase in temperature difference scross the RCS system, will not have adverse effect on the N3SS piping, and will minimally impact the design basis analysis of the' piping and pipe supports. Therefore, the existing NSSS piping and supports, the primary equipment nozzles, the primary equipment supports, and the branch lines connecting to the primary loop piping will remain in compliance with the requirements of the design bases criteria, as defined in the FSAR, and are acceptable for the power uprate.

4.10 NSSS/ BOP Interface Systems 4.10.1 Auxiliarv Feedwater System /Conden==*= Storaae Tank l

SNC performed evaluations of the effects of plant operations at the proposed uprated power level on auxiliary feedwater (AFW) system / condensate storage tank (CST). It was determined that the AFW system components have sufficient margin to provide the required flow and pressure. The condensate inventory required for the AFW system CST volume was determined

' to be 131,000 gallons for plant operations at the proposed power level. The current CST has a 500,000 gallon capacity.' The condensate makeup suction is located at an elevation that ensures a reserve of 150,000 gallons for emergency decay heat removal with the AFW system.

The AFW pump intake lings are located close to the bottom of the CST and provide sufficient useful CST volume to bound the above cited design requirement.

Based on the staff's review and the experience gained from its review of power uprate 1

applications for similar PWR plants, the staff concludes that plant operations at the proposed uprated power level will have an insignificant or no impact on the AFW system / CST.

l l

4 4 4.10.2 Component Cooling Water System (CCWS)

The CCWS is a closed loop system that serves as an intermediate barrier between the service water system and systems that contain radioactive or potentially radioactive fluids in order to eliminate the possibility of an uncontrolled release of radioactnnty. It provides cooling water to various safety and nonsafety systems during all phases of normal plant operation, including startup through cold shutdown and refueling, as well as following an SBO event, LOCA, or MSLB accident. The CCWS heat loads resulting from plant operations at the proposed uprated power level will increase slightly._ SNC performed evaluations of the effects of these increases in heat loads on CCWS and stated that the additional heat loads result in minor temperature increases on the CCWS for normal and accident scenarios and that the CCWS has the capacity to accommodate the additional heat loads and resultant temperature increases. No increase in CCWS flow rates is required to handle the additional heat loads.

Based on the staff's review and the experience gained from its review of power uprate

. applications for similar PWR plants, the staff finds that plant operations at the proposed uprated power level do not change the desi;n aspects and operations of the CCWS and have an insignificant or no impact on the CCV 'S. Therefore, the staff concludes that the FNP CCWS is acceptable for operations at the prope >d uprated power level.

4.10.3 Soent Fuel Pool Coolina System (SFPCS)

{

The SFPCS is designed to remove the decay heat released from the spent fuel assemblies stored in the spent fuel pool (SFP); to maintain the SFP water temp reture at or below the maximum operating temperature limit of 150*F during plant operations and refueling; and to maintain its cooling function during and after a seismic event. The SFPCS heat loads will increase slightly resulting from plant operations at the proposed power level.

SNC performed SFP heatup analyses for plant operations at the proposed power level. For the bounding (emergency full core off-load)* case, the SFPCS heat load increases from 34.77 x 10' Btu /hr to 37.0 x 108 Btu /hr, and the corresponding calculated peak SFP temperature with one SFP cooling train in service increases from less than 170*F to 175*F. With two* SFP cooling trains in operation the SFP can be maintained below 140*F.

SNC stated that FNP operates the SFP cooling system with one SFP cooling train in service and the remaining train on standby. Plant administrative procedures, " Outage Nuclear Safety

• and " Outage Planning Manual" have provisions to ensure that the backup SFP cooling train is available prior to the outage. Plant procedures also require fuel handling operations be suspended upon receipt of the high SFP temperature alarm which is set at 130*F. Plant procedures provide the controls necessary to ensure that the maximum operating temperature limit of 150*F will not be exceeded. Nevertheless, SNC performed evaluations (with domineralizer isolated and fuel handling operations prohibited) to demonstrate the acceptability 3 The maximum SFPCS heat load for the end-of-cycle full core off-load during routine refueling is 36.5 x 10' Btu /hr.

The corresponding calculated peak SFP temperature is 17(F with one SFP cooling train in sonnce 4 Sunuttaneous opershon of both SFPCS trains is not a normal prachce at FNP.

l-

. of SFPCS operation, SFP liner and concrete structure at temperatures below 180*F. SNC concluded that no changes to the SFP cooling or cleaning systems are required to support plant operations at 'the proposed power uprate level.

In the unlikely event that there is a complete loss of SFPCS cooling capability, the SFP water

~ temperature will rise and eventually will reach boiling temperature. SNC performed analysis to demonstrate the time to boil and the boil off rate based on the heat lead for the emergency full core off-load scenario. The calculated minimum time from the pool high temperature (130*F) alarm caused by loss-of-pool cooling until the pool boils is 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and the maximum boil-off rate is 76.4 gpm. However, makeup water from the primary water storage tank can be initiated within the required time utilizing either of two 165 gpm reactor water makeup pumps. The primary water storage tank, reactor water makeup pumps, and piping are seismic Category I.

~

~

In addition, makeup water can be supplied from the refueling water stoinge tank and the domineralized water system.

I in addition, the amount of fission product release and the chemical and radionuclear composition of pool water will not change appreciably after the power uprate and the existing cleanup system will perform adequately. The cleanup system will be able to withstand the temperatures of pool water for partial and full core off-loads, as long as the two cleanup trains are in operation. When only one train is in operation, the temperature of bulk water will exceed 140'F, the upper fimit for the domineralizer resin. _ However, the system has a provision te alarm the operators whenever water reaches 130'F, so that they can manually initiate appropriate actions to prevent damage to the cleanup system. The staff finds that with this provision, the existing SFP cleanup system will be adequate for maintaining purity of the SFP water after the power uprate.

Based on its review, the staff finds the SFPCS acceptable for plant operations at the proposed power uprate level.

4.11 Main Turbine SNC performed evaluations on turbine operations with respect to design acceptance criteria to j

verify the mechanical integrity under the conditions imposed by plant operations at the proposed uprated power level. Results of the evaluations showed that there would be no increase in the probability of turbine overspeed Therefore, the turbine could continue to be operated safely at the proposed uprated power levels.

Based the staff's review and the experience gained from its review of power uprate applications for similar PWR plants, the staff finds that operation of the turbine at the proposed uprated power levelis acceptable.

_ 4.12 Hioh Enerov Line Break (HFI R) On+=ide Coniminns:,nt System operating parameters for uprate were evaluated against the system pressure and/or temperature parameters used in the existing plant bases to demonstrate the acceptability for

' HELB effects. Core uprate will not change the bounding temperature and pressure used as the I

l basis for pipe break analyses. SNC stated that design basis analyses remain bounding for all HELB events.

Based on the staffs review and the experience gained from its review of power uprate applications for similar PWR plants, the staff concludes that plant operations at the proposed uprated power level have an insignificant or no impact on the consequences (e.g.,

environmental pressure and/or temperature parameters, etc.) resulting from HELB outside containment.

I

- 4.13 Safety-Related Equipment Quahfication (EQ)

The effects of all changes due to plant operations at the proposed uprated power level on design and EQ of mechanical components were evaluated. The temperatures, pressures, and -

in some cases flows, in certain systems would be affected slightly by plant operations at the proposed uprated power level. However, these changes in temperatures, pressures, and flows are bounded by the original design of components. The existing parameters used for qualifying mechanical compo:sents inside and outside containment remain bounding for the conditions resulting from plant operations at the proposed power level.

As part of the safety-related electrical equipment qualification evaluation for the power uprate.

SNC reviewed: (1) the radiological dose limit for safety-related electrical equipment located in a harsh environment (e.g., containment), (2) the composite temperature and pressure curves for safety-related electrical equipment qualification, and (3) components that were qualified based on calculated surface temperatures.

(a) Radiological doses SNC's review of the radiological doses for the power uprate showed that many of the original design-basis doses were bounding. For saf7-related electrical equipment not bounded by the original design basis, radiological doses at uprate conditions were compared with the dose threshold limits used for the individual components or individual items of equipment. SNC finds that the comparison showed sufficient margin available to accommodate the increased uprate dose without compromising the equipment qualification.

The staff raised a question that the dose should be bounded by the test report values, not by the dose threshold limits. By letter dated August 5,1997, SNC clarified that the terminology of dose threshold limits and test report values have the same meaning in the context of equipment qualification evaluation prepared for power uprate.

SNC concludes that the radiological cumulative dose or dose rate was either enveloped by the results of previous design-basis radiological analysis or was within the threshold limit for which the individual components or individual items of equipment were qualified.

(b) Containment pressure and temperature evaluation SNC's comparison of the composite uprate temperature profile to the existing composite temperature profile indicated that the uprate maximum accident temperature is approximately

s s

41-10*F less than the existing maximum design-basis accident temperature and that the composite uprate temperature profile is enveloped by the existing design-basis composite temperature profile except during the first 70 seconds and after 30,000 seconds.

Dudng the first 70 seconds, the uprate MSLB temperatures are higher than the existing MSLB temperature.~ Since the higher MSLB temperatures last only a relatively short time, and considering the thermal lag time associated with increasing the temperature of the containment, SNC states that the initial higher temperature would have no significant effect on the qualification of safety-related electrical equipment For more than 30,000 seconds, the uprate temperatures exceed the existing design basis profile by a few degrees (approximately 5'F). SNC states that the safety-related electrical

, equipment qualification test temperatures have enough margin to envelop the higher temperatures because there is adequate margin between the uprate composite profile and the existing design basis composite profile between 70 and 10,000 seconds to compensate for the time when the uprate composite is slightly higher than the existing design-basis profile.

In response to the staff's question about whether composite temperature profiles of the proposed power uprate should be extended further (i.e., beyond 30,000 seconds), by letter dated August 5,1997, SNC fumished the composite temperature profiles (before and after power uprate) that extend to 30 days and provided more details by dividing the time line into three sections: namely, the initial 150 seconds, _150 seconds to 7,000 seconds, and 7,000 secor,ds to 30 days. For the initial 150 seconds, based on engineering experience with.

transient thermal heat transfer analysis (thermal lag analysis), the ramp-up due to exposing the equipment to a high temperature for a short duration would not heat up instantaneously and

. would not reach thermal equilibrium due to thermal transfer from the. environment to the equipment surface. Thus, SNC determined that the short duration is covered by the existing test data. As for the intermediate section, the power uprate composite temperature profile is enveloped by the existing composite temperature profile. For the last section that the power -

uprate composite temperature profile exceeds the existing composite temperature profile by approximately 5'F, SNC stated that a review of the test profiles for equipment inside the containment indicates that sufficient margin exists in the test profiles to envelop the power

- uprate composite temperature profile. By letter dated September 22,1997, SNC fumished two test profiles (i.e., typical of a short-duration and typical of a 30-day test), which showed an adequate margin between the test profiles and the power uprate composite temperature profile.

In addition, SNC finds that the composite uprate pressure profile is enveloped by the exir,tir$g

. design-basis composite pressure profile. Thus, SNC finds that the impact of temperature and pressure conditions as a result of MSLBs or a LOCA at power uprate conditions remains

~ bounded.

s On this basis, SNC concludes that the environmental qualification testing of safety-related

. electrical equipment that envelops the existing e.,omposite temperature profile adequately envelops the composite uprate temperature jofile. However, for typical short-duration test, the staff noted that an equivalency evaluation usu,g Arrhenius methodology is performed (in accordance with the guidelines provided by EPRI and Regulatory Guide 1.89, Rev.1, Section C.S.b) to extend the test duration to the FNP-specific accident requirements. As a i

I

, separate initiative outside the scope of this evaluation, the staff will continue to review the adequacy of an equivalency evaluation using Arrhenius methodology.

(c) Surface temperature analyses Comparison of the MSLB cases used in the current design-basis surface temperature analyses with the corresponding uprate MSLB cases indicated that the surface temperature results are bounding and are not affected by the power uprate. SNC also compared the design-basis post-LOCA containment temperature profile with the uprate post-LOCA containment temperature profile and finds that the original temperature curve was bounding and that the power uprate does not affect the surface temperature.

SNC finds that maximum temperature for the MSLB cases used in the design-basis surface temperature analyses are greater than or comparable with the corresponding uprate MSLB cases.

Based on its review, the staff conc ludes that plant operation at the proposed uprated power level will have en insigni6 cant or no impact on the EQ of safety-related mechanical components inside or outside the containment. In addition, the existing safety-related electrical equipment qualification is not affected by the power uprate and remains bounded for the power uprate, and therefore,is acceptable.

4.14' Safetv/ Relief Valves SNC indicated that relief valve setpoints have been assumed to be 103 percent of the lift setting in the analysis for the power uprate. Ths relief valve setpoints, rated capacities, and corresponding dynamic loads due to valve operation imposed on the piping and adjacent structures do not change as a result of uprate. On the basis of its review, the staff finds the safety and relief valves will continue to perform their function at the power uprate condition.

4.15 Reactor Trio System /Enaineered Safetv Feature Actuatinn System Instrumeritstien Trio Setooints and Allowable Va!nas SNC proposed one change to Trip Setpoint in TS Table 2.2-1, Reactor Trip System Instrumentation Trip Setpoints, and two changes to Trip Setpoint in TS Table 3.3 4, Engineered Safety Feature Actuation System Instrumentation Trip Setpoints. The change to Table 2.2-1 will lower the Trip Setpoint for Functional Unit 20.C, Power Range Neutron Flux, P-8 from 35 percent to 30 percent of rated power. The first change to Trip Setpoint in TS Table 3.3-4 will increase the Trip Setpoint for Functional Unit 5.a, Turbine Trip and Feed Water Isolation from Steam Generator Water Level-High-High, from 78.5 percent to 78.g percent of narrow range instrument span. The second change to Trip Setpoint in TS Table 3.3-4 will increase the Trip Setpoint for Functional Unit 8.b, Engineering Safety Feature Actuation System Interiocks for

. Low-Low Tavg, P-12, from 544*F to 545'F.

SNC provided justifications for these changes in its submittal dated September 22,19g7, which employed uncertainty calculations using NRC previously approved methodology in WCAP-13751, Westinghouse Setpoint Methodology for Protection Systems, Southem Nuclear

. Operating Company, Farley Nuclear Plant, Units 1 and 2, June 1993," and NSD-NT-OPL-96-152, Revision 2, " Joseph M. Farley Nuclear Plant Units 1 & 2 Licensing Report for Technical Specification Changes Associated with Revised Core Limits, Revised OTAT/OPAT Trip Setpoints and inclusion of RAOC Control Strategy, May 1996."

SNC proposed changes to the Allowable Values in TS Table 2.2-1 and TS Table 3.3 4 (Attachment 1, Tables 4.14-1 and 4.14-2).

In a conference call on September 29,1997, SNC stated that they have calculations based on the above mentioned approved setpoint methodology covering all of the above Allowable Value changes and that when compared to the current TS values, the proposed changes are l

conservative.

' The staff has reviewed SNC's evaluation and justification for Trip Setpoint and Allowable Value chan9es in TS Tables 2.2-1 and 3.3-4. SNC stated that the proposed changes have been supported by uncertainty calculations in accordance with NRC-approved methodology in Westinghouse Reports WCAP-13751 and NSD-NT-OPL-96-152 and meet all plant acceptance criteria. The NRC-approved methodology was determined to be applicable to Farley as addressed in Farley License Amendment Nos.104 and 97, which were issued on December 28,1993. Based on this review, the staff concludes that the proposed TS changes do not involve a significant reduction in safety margin or a significant increase in the likelihood of a false trip, nor a failure to trip upon demand, and are therefore, acceptable.

4.16 Reactor Trio Time Delavs There are various instrumentation delays associated with each reactor trip function, which are modeled directly and considered in the non-LOCA safety analyses. The total delay tima is defined as the time delay from the trip conditions are reached to the time the rods are free to fall. SNC performed an analysis and evaluation to demonstrate that the applicable safety analysis acceptance criteria have been satisfied at the uprate conditions.

l The staff has reviewed the proposed changes to reactor trip time delays for the following reactor trip functions:

litm Reactor Trio Function Time Delav in Seconds Current Uodated i

1.

Overtemperature AT 8

12

- 2.

OverpowerAT 8

12 3.

High Pressurizer Pressure 2

1 In a conference call on December 9,1997, SNC confirmed that the increase to 12-second time delay in items 1.and 2 are due to:

4 l

44 1.

Filter compensation time of 6 seconds (increased from zero second) as reported in Table 1 of NSD-NT-OPL-96-158, Revision 2, dated May 1996. The staff has previously reviewed this report and found it acceptable by letter dated September 3,1996.

2.

Total Resistance Temperature Detector (RTD) response time of 6 seconds including RTD Bypass Piping and Thermal Lag time of 2 seconds, as indicated in Section 2.3 of the staffs safety evaluation, dated March 11,1992, related to Amendment Nos. 85 and 92.

j

(

in a letter dated November 19,1997, SNC stated that the response time of item 3 was based on plant response time testing. Further, in a conference call on December 9,1997, SNC confirmed that its plant maintenance data from 1978 onwards demonstrated a maximum time delay of 740 milliseconds for the RTDs.

The staff has reviewed the proposed changes and SNC's justification and has determined the subject instruments will meet the new response time requirements. The specific instrument response times were relocated from the Technical Specifications to the Final Safety Analysis Report in Farley License Amendment No.116 for Unit No.1 and License Amendment No.108 for Unit No. 2 issued on September 28,1995.

5.0 BALANCE OF PLANT EVALUATION 5.1 Main Steam System SNC performed evaluations of the effects resulting from plant operations at the proposed uprated power level on the main steam system including the main steam isolation valves, SG power operated atmospheric relief valves, main steam bypass valves, and main steam safety valves. Main steam piping thermal expansion at the uprated condition is bounded by the current design basis evaluation. Plant operations at the proposed uprated power level will increase the steam mass flow by approximately 5.3 percent. The above existing components are adequately sized for the uprating. This increase has no significant impact on the main steam piping, valves, in-line components, interconnected branch line, or pipe supports as a result of steam hammer dynamic loads resulting from turbine stop valve closure. Therefore, SNC concluded that plant operations at the proposed uprated power level will have an L

insignificant or no impact on the main steam system and its associated components.

Based on the staffs review and the experience gained from its review of power uprate applications for similar PWR plants, the staff finds that FNP operations at the proposed uprated 4

power level will have an insignificant or no impact on the main steam system and its associated components.

s 5.2 Steam Dump System 4

SNC evaluated the steam dump system for the plant operations at proposed uprated power level and concluded it will have an insignificant or no impact on the steam dump system. Based on the experience gained from its review of power uprate applications for similar PWR plants,

. the staff concludes that operation of the steam dump system at the proposed uprated power levelis acceptable.

5.3 Condensate and Feedwater Systems

~ SNC evaluated the condensate and feedwater systems for the plant operations at 2775 MWt reactor power level and stated that approximately 6 percent increase in condensate flow is necessary to provide sufficient flow to the SGs _to support normal operation at power uprate conditions. Therefore, it is necessary to modify the condensate pumps. Since 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 staff has not reviewed the impact of plant operations at the proposed uprated power level on the design and performance of these systems.

5.4 Circulatina Water Svstem The circulating water system is designed to remove the heat rejected to the condenser by

~ turbine exhaust and other exhausts over the full range of operating loads, thereby maintaining adequately low condenser pressure. SNC stated that performance of this system was

. evaluated for power uprate and determined that the system is adequate for uprated power level operation,

_Since the circulating water system does not perform any safety function and its' failure will not affect the performance of any safety-related system or component, the staff has not reviewed the impact of plant operations at the proposed uprated power level on the designs and performances of this system.

5.5 Service Water Svstem The service water system (SWS) is designed to supply cooling water to varicus nonsafety-related components and heat exchangers in the turbine, reactor, and radwaste buildings during normal plant operation, and to supply cooling water to safety-related t ystems and other essential equipment during a station blackout event and following a LOCA or main -

steamline break accident. The SWS heat loads resulting from plant operations at the proposed uprated power level will increase slightly. SNC performed evaluations of the effects of these increases in heat loads on SWS and stated that the SWS has the capacity to accommodate the

. additional heat loads.

Based on the staffs review and the experience gained from its review of power uprate applications for similar PWR plants, the staff finds that plant operations at the proposed uprated power level do not changgthe design aspects and operations of the SWS and have an insignificant or no impact on,the SWS. Therefore, the staff concludes that the FNP SWS is acceptable for operations at the proposed uprated power level.

5.6 Main Turbine Auxiliarv systems The t'urt>ine auxiliary system together with circulating water system and, main and auxiliary condensers, are designed to remove the heat rejected to the condenser by turbine exhaust and

i other exhausts over the full range of operating loads, thereby maintaining adequately low condenser pressure. SNC stated that performance of these systems were evaluated for power

uprate and determitied that these systems are adequate for uprated power level operation.

Since these systems do not perform any safety function and their failure will not affect the

- performance of any safety-related system or component, the staff has not reviewed the impact of the uprated power level operation on the designs and performances of these systems.

5.7 Main Generator and Auxthanes SNC has reviewed the potential impact of a power uprate on the main generator stator and rotor, exciter and voltage regulator., hydrogen cooling system, and generator protective relays.

Since the power uprate will generate additional heat in the main generator stator and rotor, and in the exciter, the main generator cooling hydrogen pressure must be increased from 72 psig to 75 psig. SNO has reviewed the maximum heatload capability of the hydrogen cooler and maximum exciter cooler heat duty. SNC's review finds that the power uprate does not increase the maximum heat load of the hydrogen cooler beyond its design limits, and the exciter cooler design has sufficient margin to accommodate the heat increase while maintaining the voltage regulation acceptable. Because all protective relay settings are based on the maximum capability of the generator output, SNC finds that the protective relay settings of the main generator did not require any changes for the power uprate conditions.

. Based on the foregoing, the staff finds that the proposed power uprate does not necessitate -

any changes to the existing hydrogen cooling system, exciter cooling system, and generator protective relays.

5.8 Auxiliarv Buildina and Turbine Buildina Heatina. Vent ll inia. Air Conditionina (HVAC). and Filtration Systems The HVAC and filtration systems for the following areas were evaluated to ensure that they are -

capable of supporting the plant uprate conditions:

Control room and technical support center Fuel handling building Engineered safety (esture (ESF) pump rooms Main steam valve rooms Turbine driven auxiliary feedwater (AFW) pump room Turbine building 5.8.1 Control Room And Technical Suonort Center (TSC)

The HVAC and filtration systems for the control room and TSC are designed to provide a reliable and suitable environment for plant personnel and equipment under normal and emergency conditions. SNC performed evaluations and concluded that: (1) the post-accident doses meet GDC-1g, and (2) safety-related componerts do not exceed any design limit considering a single active or passive failure HVAC system at the proposed uprated power level.

.. Based on the staffs review and the experience gained from its review of power uprate applications for similar PWR plants, the staff concludes that plant operations at the proposed uprated power level do not change the design aspects and operations of the HVAC and filtration systems for the control room and TSC. Therefore, the staff concludes that plant operations at the proposed uprated power level will have an insignificant or no impact on the HVAC and filtration systems for the control room and TSC.

5.8.2 Fuel Handhng Budding Fuel handling building heating, ventilating (HV), and filtration systems are designed to provide adequate capacity to ensure that proper temperatures are maintained during normal, shutdown, and emergency conditions, and to ensure thet effluent discharges are maintained within acceptable levels. SNC performed analyses and concluded that the HV and filtration systems for these areas are not impacted by plant operations at the proposed uprated power level.

Based on the staffs review and the experience gained from its review of power uprate applications for similar PWR plants, the staff concludes that plant opcatione at the proposed uprated power level do not change the design aspects and operations of the HV and filtration systems in the fuel handling building. Therefore, the staff finds that plant operations at the proposed uprated power level will have an insignificant or no impact on these HV and filtration systems.

5.8.3 ESF Pumo Rooms. Main Steam Valve Rooms and Turbine Driven AFW Pumo Room The HV systems for these areas are designed to provide a suitable environment for equipment and personnel. SNC performed evaluations and concluded that the HV systems for these areas are not impacted by plant operations at the proposed uprated power level.

Based on the staffs review and the experience gained from our review of power uprate applications for similar PWR plants, the staff concludes that plant operations at the proposed uprated power level do not change the design aspects and operations of the HV systems in the fuel handling building. Therefore, the staff finds that plant operations at the proposed uprated power level will have an insignificant or no impact on these HV systems.

5.8.4 Turbine Buildina SNC stated that the HVAC systems were evaluated against current performance with respect to potential increased demand on each subsystem to perform the design functions, it was determined that changes to current operation heat loads are negligible.

Since these systems do nbt perform any safety function and their failure will not affect the performance of any safety-related system or component, the staff has not reviewed the impact of the uprated power level operation on the designs and performances of these systems.

o

i. 5.g Radwaste Systems (Solid. Liquid. and Gaseous)

The solid, liquid, and gaseous redweste activity is influenced by the reactor coolant activity which is a function of the reactor core power. SNC performed evaluations of the existing design of the radwaste systems and concluded that plant operations at the proposed uprated power level will have an insignificant impact on the radweste systems.

l Based on its review, the staff concludes that plant operations at the proposed uprated power level will have an insignificant impact on the radweste systems.

5.10 Additional Balance of Plant Reviews The impact of plant operations at the proposed power uprate power level on High Energy Line Break Outside Containment and Equipment Environmental Qualification is addressed in sections 4.12 and 4.13.

j l

. 5.11 Miscellaneous Electncal Reviews A power uprate that increases the electrical output of the main generator from 885 MWe to '

910 MWe, requires increased horsepower for the reactor coolant pumps (RCPs) and condensate pumps (cps).~ To determine how those increased non-Class 1E loads would affect the station auxiliary electrical distribution system, SNC evaluated the onsite electrical distribution system by using a peak value of 920 MWe, instead of 910 MWe (to be

- conservative), to ensure that all station auxiliary loads can continue to perform their intended safety-related and nonsafety-related functions. Yhe following electrical systems and components were reviewed-

- main power transformer (MPT)

- emergency diesel generators (EDGs)

- startup transformer (SAT)

- CP motors

-l unit auxiliary transformer (UAT)

- RCP motors

-isophase bus

- station service assessment

- station blackout (SBO)

- grid stability SNC finds that:

1). a comparison of electricalloadings on MPT, SAT, and UAT transformers before and after power uprate, indicates that the transformers would have sufficient capacity and capability to handle the uprated generator output. In addition, the evaluation of those transformer protective relay setpoints for the increased generation during the assumed worst grid voltage conditions indicates that the transformers could reach their present alarm setpoints'without exdeeding the transformer temperature design limits.

2) the isophase bus for Units 1 and 2 remains capable of supporting the output of the main generator at uprated conditions without modifications since the maximum current flows under power uprate condition are less than those of the rating for the isoptase bus. The isophase cooling units are capable of removing the additional heat generated by the j

. power uprate. No known hot spots currently exist, and none are expected to result from the power uprate condition.

~

3). the EDG load during the loss of offsite power (LOOP), LOOP with LOCA, and SBO events is within the design ratings of the EDG; thus, the existing EDG loading analysis remains bounding and valid to perform its intended safety-related function. Also, the response time for EDG starting and loading for the above events is not affected by power uprate.

4) the changes to load, voltage, and short circuit values from power uprate conditions at all electrical bus levels are minimally impacted when compared with current values. ' Total projected loads on the 4160 V buses remain within the rated capacity of the buses,,

breakers, and transformers. Non-Class 1E loads (i.e., RCPs and cps) that increase as a I

result of the power uprate are within the design capability of the motors and the cable ratings. As an example, steady state voltages at the 4160 V buses decrease by no more than 0.4 percent, motor starting voltages remain within acceptable limits, ard short circuit currents are within acceptable values. Since those load changes were not sufficient to affect the voltage setpoints for the loss of voltage and degraded grid voltage protection relays, no TS revision is needed for the electrical power system.

5) the acceleration time for pumps, motor structural and torque loadings, motor insulation f

life, and existing relay setpoints are acceptable for operation for the increased horsepower i

required to support the condensate flow increase, in addition, bus and transformer relay settings are not affected, and also protective relays are adequata for RCP motor protection under uprate conditions.

6)

SNC's evaluation of the electrical grid stability impact of increasing FNP generation to i

g20 MWe indicates that the grid remains stable and that safety-related buses continue to l

be supplied by the preferred offsite power source for single contingency events and faults.

1 Upon the staffs request for a sample of onsite load flow studies and grid stability cases, SNC, by letter dated September 22,1977, submitted one-line diagrams that illustrate the load flows and voltages for before and after power uprate cases at their worst (i.e., minimum) expec+ed grid voltage at Unit 1 (Unit 2 would be the same) and the summary of grid stability studies SNC performed; The staff concurred with SNC that the bus loadings and voltage changes throughout the onsite and offsite power system for the power uprate are minimal at FNP The result of stability cases summarized under" Single Event Cases Used to Validate FSAR

Commitments" reaffirms that the grid will remain stable and that safety-related buses will

- continue to be supplied by the offsite power source for single contingency events and faults.

On the basis of the above evaluation, for all the secondary-side systems reviewed, the staff

. finds that the power uprate will have no significant impact on the Balance of Plant design bases.

i 6.0 HUMAN FACTORS The staff reviewed SNC's submittals dated February 14 and September 22,1997, for power, uprate. The staff s evaluation of SNC's responses to five review topics is provided below.

. Topic 1 - Discuss whether the power uprate will change the type and scope of plant emergency and abnormal operating procedures. Will the power uprate change the type, scope, and nature of operator actions needed for accident mitigation and will it require any new operator actions?

By letter dated September 22,1997, SNC stated that the power uprate would not change the type and scope of plant emergency and abnormal operating procedures. SNC also stated that the power uprate would not change the type, scope, or nature of operator actions needed for accident mitigation and that it would not require any new operator actions, with one possible exception. This exception arises as a result of an assumed increase in allowable charging and safety injection pump head degradation allowance from 8 percent to 10 percent, which may require opening a pressurizer PORV. SNC added that (1) the PORV action is consistent with the generic guidance in the Westinghouse Owners Group Emergency Response Guidelines, and (2) the increase in charging pump degradation is not directly related to the power uprate.

The staff finds SNC's responses satisfactory.

Topic 2 - Provide examples of operator actions potentially sensitive to power uprate and address whether the power uprate will have any effect on operator reliability or performance.

Identify operator actions that would necessitate reduced response times associated with a power uprate. Please specify the expected response times before the power uprate and the reduced response times. What have simulator observations shown relative to operator response times for operator actions that are potentially sensitive to power uprate? Please state why reduced operator response times are needed. Please state whetharthe reduced time <

available to the operator as a result of the power uprate will significantly affect the operator's ability to complete manual actions in the times required.'

SNC's letter of September 22,1997, stated that there were no changes made to opemtor action assumptions in the FSAR Chapter 15 accidents and transients that resulted in reduced operater response times. ' SNC stated that emergency response procedure operator actions potentially c.

sensitive to power uprate are those that are performed on the basis of setpoint values that are calculated using the design parameters for power uprate. SNC noted that changes in design parameters can affect the setpoints calculated for operator actions but should not affect the type and scope of operator actions. Further, SNC stated that emergency response and normal and operating procedure revisions will be incorporated, where appropriate, before implementation of power uprate. The staff finds SNC's responses acceptable since the subject changes are enhancements that are covered under SNC's existing program, and procedures, for changes to plant procedures.

Topic 3 - Discuss any changes the power uprate will have on control room instruments, alarms, and displays. Are zone markings on meters changed (e.g., the normal range, the marginal range. and the out-of-tolerance range)?

SNC stated in its letter of September 22,1997., that preliminary engineering reviews indicate that power uprate will have a minimum impact on the control room controls, alarms, and displays. SNC noted several examples of potential control room changes. One potential

. change concemed color-coding indicators of normal operating steamline pressure, which may be adjusted to a low value of 770 psig. A second potential change involved the setpoint for the reactor coolant system high T-average annunciator. A third potential change dealt with the

~

l

l 7

j-

, setpoints for the low suction pressure of the steam generator feed pump. SNC stated that required changes would be implemented. The staff finds SNC's responses satisfactory since the potential changes are enhancements to control room controls, alarms, and displays.

' - Topic 4 - Discuss any changes the power uprate will have on the Safety Parameter Display System (SPDS).

By letter dated September 22,1997, SNC stated that on the basis of an SPDS computer point '

list review, no SPDS setpoint changes are anticipated at this time. SNC explained, however, that there is a potential for changes in the plant process computer and/or SPDS scaling / calibration curves and the high/ low alarm limits for some uprate-affected instrumentation inputs that are non-SPDS computer points. The staff finds SNC's responses satisfactory.

Topic 5 - Describe any changes the power uprate 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.

Specifically, please propose a license condition and/or commitments that address the following:

(a)

Provide classroom and simulator training on the power uprate modification.

SNC's letter of September 22,1997,' stated that classroom and simulator training on the uprate changes for Units 1 and 2 will be provided to operations crews before the Unit 2 startup in the spring of 1998. The staff finds this information acceptable.

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

" Simulator. Performance Testing."

~

Simulator revalidation will include 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.

SNC notes that the simulator is referenced to Unit 1, and therefore, final simulator i

modifications will be implemented following the Unit i uprating. SNC also commits to a j

temporary simulator modification on the basis of the Unit 2 power uprate, including hardware and software changes. Simulator testing will be based on existing simulator certification tests consistent with the requirements of ANSI /ANS 3.5-1985. Best estimate i

data derived from applicable design change packages and engineering reports will be i

used to initially validate simulator modifications. The staff finds this information j

acceptable.

.(c)

Complete control room and plant process computer system changes as a result of the power uprate.

4

3 Hardware and plant process computer modifications will be temporarily implemented

- before the. Unit 2 startup training. Final, permanent implementation will occur following the reference unit modifications. The staff finds this information acceptable.

(d) ' Modify training and plant simulator relative to issues and discrepancies identified during the startup testing program.

After final modifications to the reference unit and complete implementation of simalator modifications, the simulator will be further evaluated with respect to actual plant performance data and updated accNient analysis data. The results of this final testing will j

.be integrated into the quadrennial certification testing program. The staff finds this information acceptable.

On the basis of the information provided by SNC in response to Topic 5, the staff finds the proposed simulator modifications and associated simuistor testing plans, as identified in items (a) through (d) above, are satisfactory with respect to SNC's commitment to ANSI /ANS -

3.5-1985, as endorsed by Regulatory Guide 1.149, Revision 1; On the basis of SNC's commitments relative to training, the staff finds that SNC has proposed satisfactory charges to

- the operator training program as a result of the power uprate. These commitments, as -

identified in items (a) through (d), above, have been incorporated into the Facility Operating Licenses for both units as License Conditions.- The change is described in Section 7.0 of this safety evaluation.

The staff concludes that the previously discussed review topics associated with the proposed FNP Units 1 and 2 power uprate have been or will be satisfactorily addressed. The staff further

~ concludet that the power uprate should not adversely affect operator performance or operator reliability.

7.0 EVALUATION OF CHANGES TO FACILITY OPERATING LICENSE (FOL) AND TS The FOL and TS changes requested by SNC in its power uprate submittal are discussed below.

7.1 Evaluation of Chanoes to the TS and Ooeratino License 7.1.1 License Condition 2.C.(1). Maximum Power Level The License Condition 2.C.(1) " Maximum Power Level" is being revised from 2652 MWt to l

2775 MWt. SNC has provided the results of its reanalyses or evaluation including LOCA and l

Non-LOCA transients and accidents, containment response, radiological consequences, NSSS i

and Balance of Plant (BOP) systems and comoonents to support the operation of FNP Units 1 and 2 at the uprated powd level. The staff has reviewed SNC's submittal and concludes that both FNP units can safely operate at a core power of 2775 MWt.

1

. (

7.1.2 Haw Assendix C. " Additional Conditians " to Ooeratina Unanse The staff will impose four new license conditions for each unit, to be located in a new l

Appendix C of the respective operating license. The new license conditas are needed in order to grant approval of the power uprate license amendments. By letter dated April 17, 1998, St%C proposed the following license conditions for Unit 1: (1) SNC shall complete classroom and simulator training for operations crews prior to Unit 2 entering Mode 2 from the spring 1998 refueling outage; (2) SNC shall complete final simulator modifications in -

accordance with ANSl/ANS 3.5-1985 and review results of the Cycle 16 startup testing to determine any potential effects on operator training within 2 years after restart from the Unit i fall 1998 refueling outage; and (3) SNC shall provide an SGTR radiological consequences analysis that incorporates a flashing fraction, which is appropnate for the Unit 1 design prior to i

the Unit 1 SG replacement outage in spring 2000.

In addition, by letter dated April 17,1998, SNC proposed the following license conditions for Unit 2: (1) SNC shall complete classroom and simulator training for operations crews and temporary simulator modifications prior to Unit 2 entering Mode 2 from the spring 1998 refueling outage; (2) SNC shall review the results of the Cycle 13 startup testing to determine any potential effects on operator training and incorporate these cha1ges into licensed operator training prior to Unit 1 startup from the fall 1998 refueling outage; and (3) SNC shall provide an SGTR radiological consequences analysis that incorporate' a flashing fraction, which is s

appropriate for the Unit 2 design prior to the Unit 2 SG replacement outage in spring 2001.

7.1.3 TS 1.25. Djin-,s PM Thent,al Pc r The definition for rated thermal power is being changed to increase the rated power from 2652 MWt to 2775 MWt.- SNC has provided the results of its reanalyses or evaluation including LOCA and Non-LOCA transients and accidents, containment response, radiological consequences, NSSS and BOP systems and components to support the operation of FNP Units 1 and 2 at the uprated power level. The staff has reviewed SNC's submittal and concludes that both FNP units can safely operats at a core power of 2775 MWt.

7.1.4 TS Table 2.2-1. Reactor Trio System Instrumentation Trip Setpoints TS Table 2.2-1 was modified to change the setpoints and allowable values for the trip setpoints.

The allowable values were based on the FNP instrumentation and were modified to support the amendment request. All applicable LOCA and non-LOCA transient analyses were performed using the new setpoints with acceptable results. The Power Range, Neutron Flux allowable value for the low setpoint was changed from 26 percent to 25.4 percent, and the high allowable value was changed from 110 percent to 109.4 percent. The Power Range, Neutron Flux, High Positive and Negative ratef allowable values were changed from 5.5 percent to S.4 percent. The Pressurizer Pressure values for the low allowable value was changed from 1855 pal to 1862 psi

. and the high allowable value was changed from 2395 psig to 2388 psig. The Pressurizer Water Level-High allowable valve was changed from 93 percent to 92.4 percent. The Loss of Flow allowable value of 88.5 percent of 89,290 gpm was changed to 89.7 percent of 88,100 gpm.

The Steam Generator Water Level-low-low allowable value of 23.3 percent was changed to 24.6 percent. The Reactor Trip System Interlocks for Low Power, Power Range Neutron Flux,

1

.. and the Reactor Trip Block following a turbine trip were adjusted. Because all applicable LOCA and non-LOCA transient analyses were performed using the new setpoints with acceptable results, the staff finds the new setpoints and allowable values acceptable. In addition, the staff concludes that the proposed TS changes do not involve a significant reduction in safety margin l

or a significant increase in the likelihood of a false trip, or a failure to trip on demand.

t l-7.1.5 TS T=Na 3.2-1. rkn=rture From Nnci==ia Boilino ( DNB) Parameters and TS R==

B 3/4 4.2.5 The DNB parameters for average temperature (T ), RCS pressure and RCS flow were changed from 580.7 'F,2205 psig, and 267,880 gpm to 580.3 "F,220g sig, and 264,200 gpm..

.p

[

Where applicable, the NRC-approved revised thermal design procedure (RTDP) continues to j

be used in the evaluation of the DNB. A reduced core flow of 86,000 gpm per loop was utilized l

in the analysis, which corresponds to an indicated flow limit of 87,800 gpm per loop. The steam generator tube plugging was assumed to be 20 percent. The limiting DNB events were analyzed using these new values in the safety analysis with acceptable results to assure the new DNB parameters are acceptable.' As a result, these changes are acceptable. The TS Bases were also modified to reflect these changes.

7.1.6 TS Table 3.34 Enaineered Safetv Features Aren=+ian Svstem InstrumerMian Trio Setootnts TS Table 3.3 4, Engineered Safety Features Actuation System (ESFAS) Instrumentation Trip l;

Setpuints, was modited to change the setpoints and allowable values for the ESFAS setpoints.

l~

The allowable values, based on the FNP instrumentation, were modified to support the amendment request. All applicable LOCA and non-LOCA transient analysis were performed using the new setpoints with acceptable results. The SAFETY INJECTION, TURBINE TRIP AND FEEDWATER ISOLATION Pressurizer Pressure-Low allowable value was changed, the Steamline ISOLATION high steam flow coincident with low-low average temperature allowable

. values was modified, the TURBINE TRIP AND FEEDWATER ISOLATION steam generator high-high water level setpoint and allowable value was modified, the AUXILIARY FEEDWATER steam generator low-low level allowable value was modified, and the ESF ACTUATION INTERLOCKS pressurizer pressure and low-low average temperature setpoints and allowable values was modified. The staff finds the new setpoints and allowable values acceptable, in addition, the staff concludes that the proposed TS changes do not involve a significant reduction in safety margin or a significant increase in the likelihood of a false trip, or a failure to trip on demand.

7.1.7 TS 3/4 4.6. SG F* Criteria (Unit 2 Oniv)

SNC proposed revising the existing F* distance from 1.54 inches to 1.6 inches in the FNP Unit 2 TS. Unit 1 has no F* criteria in the TS. The F* distance is the length of the expanded

. part of the tube inside the tubesheet that provides a sufficient length of undegraded tube expansion to resist the pullout of the tube from the tubesheet. Under the power uprate, the F*

distance needs to be lengthened to provide additional tube friction surfaces to resist the increase of the pullout force resulting from ircreased primary-to-secondary differential pressure during postulated accidents. The F* criteria in Unit 2 TS 3/4.4.6 are affected by the increased v

s-l

}y

,. differential pressure between the primary and secondary loops under the power uprate. Based -

on the staff's previous review, the staff determined that the proposed F* distance of 1.6 inches is acceptable and may be incorporated into the FNP Unit 2 TS.

7.1.8 TS 4 5.2.a Emeraenev Core CMino Systems L

l The required ufferential pressure developed by the centrifugal charging pumps and the residua!

l heat removal pumps has been revised from 2458 psig to 2323 paid and 136 psig to 145 psid, respectively. The applicable analysis, including the LOCA and non-LOCA transients, have been reperformed using the reduced flows with acceptable results. The LOCA analysis concluded that limits established in 10 CFR 50.46, Acceptance Criteria for Emergency Core i

Cooling Systems for Light-Water Nuclear Power Reactors, are met. As a result, the change is acceptable.

l.

7.1.g TS Bases B 3/4.6.1.4. B 3/4 8.1.8. and TS 8.18 SNC proposed to revise the Containment Systems Bases B 3/4.6.1.4 and B 3/4.6.1.6 to reflect l

the new peak calculated containment pressure obtained from a LOCA event from 48 psig to L

' 43 psig and add that the maximum pressure from an MSLB event is 53 psig. SNC also proposed to indicate that these containment analyses calculations include an initial positive pressure of up to 3 psig and that the analyses results demonstrate that the maximum containment pressure will remain below the design limit of 54 psig. Structural integrity is required to ensure that the containment will withstand the maximum peak calculated intamal pressure of 53 psig in the event of an MSLB, including an initial positive pressure of up to 3 psig.' in accordance with Appendix J, Option B, the LOCA peak calculated containment intemal pressure defines the Pa value for the containment leakage rate testing program

- required by Surveillance Requirement 4.6.1.2.

In TS Section 6.16,

• Containment Leakage Rate Testing Program / SNC proposed to revise the peak calculated containment intomal pressure for the design basw LOCA, Pa value from 48 psig to 43 psig.

The revised Bases and test program reflect the results of new containment analyses performed j

for uprate. The staff has reviewed SNC's submittals and finds the proposed changes i

l acceptable.

I 7.1.10 TS 4.7.1.5 and TS Bases B 3/4 7.1.1 The required closure time for the main steam isolation valves has been increased from 5 seconds to 7 seconds. The analysis of the main steamline failure was reperformed using the higher time with acceptabfe results. The analysis of the steamline failure concluded that no

. DNB would occur, no fuel failure is predicted, and the calculated offsite and onsite. doses are acceptable. As a result, the change is acceptable. The TS Bases section for the secondary

]

safety valve was modified to reflect changes to the secondary code safety relieving capacity 1

and total steam flow. Although the total capacity of the secondary code safety relief valves is i

not being changed, the relative capacity has gone down.' The new steam flow in the secondary system is increased from 11,613,84g Ibs/hr to 12,270,000 lbs/hr and the relieving capacity is l

l l

j i

. reduced from 112 percent of total flow to 105.8 percent total flow.- SNC performed an analysis of overpressure protection and the limiting overpressure transients to venfy that there continues to be sufficient secondary relieving capacity. The staff has reviewed this change and concludes that operation at the proposed uprated power level will have an insignificant impact on the main steam system and its associated components. As a result, the changes are acceptable.

.7.1.11 TS Table 5.7-1 SNC proposed to increase the number of secondary system hydrostatic tests limit to 10 to allow '

a relaxation of the cunent limit of 5 specified in Table 5.7-1," Component Cyclic or Transient Limits" of the FNP TSs. SNC indicated that the power uprate fatigue analysis assumed a

. maximum number of occurrences of 10 for the secondary site hydrostatic tests, as shown in a table on page 52 of SNC's August 5,1997, response to the staff's request for additional information.- The staff has reviewed SNC's power uprate evaluation and finds that the proposed change is acceptable.

7.1.12 TS SA. Design Features The value given for the total water volume and steam volume in the RCS is being changed from 9723 to 5829 ft*. The new value reflects the current calculated total and steam volume of the -

RCS at 567.2*F. The new calculated RCS fluid volume is supported by the overall uprate program that included the reanalysis or evaluation of the LOCA, non-LOCA, thermal-hydraulic, and nuclear aspects of the NSSS and BOP structures, systems, and components. As a result, the staff finds this acceptable.

7.1.13 TS 6 9. Administrative Controls

. The references to WCAP-10266-P-A, Rsv. 2, "The 1981 Version of the Westinghouse Evaluation Model Using BASH Code," is being deleted and replaced with a reference to the approved version of WCAP-12945-P-A, " Code Qualification Document for Best Estimate LOCA -

Analysis" M-Propnetary), March 1998. Because the new code has been reviewed and approved for LOCA analysis and the code is used in accordance with all limitations and restrictions, this is acceptable. A reference to the Westinghouse fuel design Topical Report,-

WCAP-12610-P-A, " VANTAGE + Fuel Assembly Reference Report," April 1995 M-Propnetary),

using ZlRLO cladding is also being added to the TS. This is acceptable because ZlRLO clad fuel is being used at FNP and the referenced topical report is approved for'FNP. The use of these methodologies will ensure that values for cycle-specific parameters are determined such that all applicable limits of the plant's safety analysis are met.

8.0 STATE CONSULTAT. ION In accordance with the Commission's regulations, the State of Alabama official was notified of the proposed issuance of the amendments. The State official had no comments.

l

! (

9.0 ENVIRONMENTAL CONSIDERATION

1 Pursuant to 10 CFR 51.21,51.32 and 51.35, an Environmental Assessment and Finding of No -

Significant impact was published in the Federal Register on April 23,1998 (63 FR 20221).

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

1

10.0 CONCLUSION

l l

The Commission has concluded, based on the considerations discussed above, that (1) there is l

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.

Attachments: 1. Tables l

2. References PrincipalContributors: C. Jackson J. Hayes l

J. W u J. Medoff J. Tsao R. Goel G. West F. Collins l

P. Kang D. Shum S. Mazumdar J. Zimmerman M. Banic K. Parczewski l

E. Murphy Date: April 29,1998 l

l I

i

TABLES Q

l

i Table 3.5.1-1 Assumptions for Loss of AC Power Event Parameter Value Core Thermal Power Level (MWt) 2831 Mass of steam released fror.: hree steam generators (Ibs)

(0-2 hours) 448,000 (2-8 hours) 861,000 Feedwater flow to the three steam generators (Ibs)

(0-2 hours) 603,000 (2-8 hours) 953,000 Primary-to-Secondary Leak Rate 150 (gpd/SG)

Reactor Coolant concentrations Noble Gases Based upon 1% failed fuel Dose Equivalent l 60 (pCi/g)

Secondary Side Activity Dose Equivalent l 0.1 (pCi/g) lodine Partition Factor in 0.1 SGs Duration of Plant Cooldown 8

(hrs)

f L

=

l' Table 3.5.1.3-1 Assumptions for LOCA Analysis l

l i

Parameter Valut Core Thermal Power (MWt) 2831 l

Activity Released to the Reactor Building Airborne (fraction of core) lodine 0.5 Noble Gases 1.0 l

Elementallodine Plateout Rate l

(1/hr) i DF s 100 2.7 100 < DF s 1000 0.27 l

1000 < DF 0

lodine Species (fraction)

Elemental 0.955 Particulate 0.025 Organic 0.02 Activity Released to Sump (fraction) lodine 0.5 -

Noble Gases 0.0 1

Containment Free Volume (ft')

2.03E6 Leakage Rate ( percent / day) 0-24 hours 0.15 i

> 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 0.075 I

2

Table 3.5.1.3-1 Assumptions for LOCA Analysis (cont.)

i Parameter Value Sump Liquid Volume (ft')

4.92E4 Reactor Building Spray Svstem 1

Actuation Time (sec) 30 Spray Removal Constants (/hr)

Elemental ~

10 Particulate DF s 50 4.8 50 < DF 0.48 l

Fraction of Reactor Building 0.178 l

Unsprayed Recirculation Loop Leakage Rate 7.78E4 l

(cc/hr) l Minimum Time to Recirculation (min) 20 Passive Component Failure Leak NA Rate (gpm) for 30 minutes @24

- hours post-LOCA Control Room Free Volume (ft')

1.16E5 Filtered Recirculation Flow (cfm) 2700 Control Room Recirculation 95 Filtration System Efficiency for all forms of lodine (%)

Control Room Makeup Air Filtration 270 t

Rate (cfm) l l --

Control Room Makeup Filter 99 Efficiency for all forms of lodine (%)

l Control Room Unfiltered Air 10 Infiltration Rate (cfm) 3 1

t

F o

Table 3.6.1.31 Assumptions for LOCA Analysis (cont)

Parameter Value l

Control Room Occupancy Factors 0-1 day 1.0 14 days 0.6 30 days 0.4 l

Atmospheric Dispersion Factors (sec/m*)

EAB 6.5E-4 LPZ 0-8 hours 1.0E-4 l

8-24 hours 6.6E-5 1-4 days 2.6E-5 l

4-30 days 6.8E-6 l

l Control Room j

0-8 hours 3.3E-3 8-24 hours 2.2E-3 1-4 days 1.6E-4 l

4-30 days 1.1 E-4 l

8 Breathing Rates (m /sec) l Offsite 0-8 hours 3.47E-4 l

8-24 hours 1.75E-4 1-30 days 2.32E-4 Control Room 3.47E-4 i

r 4

1 i

4

Table 3.5.1.5-1 Assumptions for SGTR Accident Parameter Value lodine Partition Factor 0.1 Steam Release from Defective Steam Generator

' 0-0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (Ibs) 7.33E4 0.5-8 hours (lbs) 0 Steam Release from Intact SGs (Ibs) 0-2 hours 3.39E5 2-8 hours 7.30E5 Feedwater Flow to intact SGs (lbs) 0-2 hours 4.42E5 2-8 hours 7.91E5 i

Reactor Coolant Released to 1.50E5 Faulted Stean. Generator (Ibs)

Primary-to-Secondary Leak Rate for

-150 Intact Steam Generator (gpd/SG) i isolate Faulted SG (min) 30 Primary Coolant Activity Level-Dose Equivalent *l (pCilg)

Pre-existing Spike 60 Accident initiated Spike 1

Flashing Fraction 0-20 minutes 0.18 20-28.5 minutes 0.25 28-60 minutes 0.10 5

Table 3.5.1.6-1 Assumptions for Locked Rotor Accident Parameter Value Core Thermal Power Level (MWt) 2831 Duration of Plant Cooldown by 8

l Secondary System (hr) i Gap Fraction:

• l 0.12

'5Kr

'O.30 l

All others 0.10 i

Failed Fuel Rods (%)

20 Primary-to-Secondary Leak Rate 150 (gpd/SG) e lodine Partition Factorin Steam 0.01 Gencators Steam Released from three SGs (ibs) 0-2 hours 4.27E5 2-8 hours 8.20E5 Feedwater Delivered to three SGs (ibs) 0-2 hours 5.74E5 -

2-8 hours 9.08E5 I

i l

l' 6

b Table 3.5.1.7-1 Assumptions for Fuel Handling Accidents Parameter Value Core Power (MWt) 2831 Total Number of Assemblies in 157 Core Highest Power Discharged Assembly Axial Peak to 1.7 Average Ratio

~

Radial Peak to 1.7 Average Ratio Occurrence of Accident (hours 100

)

after shutdown)

Damaged Fuel Rods 264 Fractional Activity Released from the Gap Allisotopes except as 0.10 noted below

'5Kr 0.30

'8'l 0.12 lodine Gap inventory organic (%)

0.25 inorganic (%)

99.75 J

Pool DF organic (%)

1 inorganic (%)

133 i

Purge Isolation Time (seconds)

NA 1

7

^ ',

l l

Table 3.5.1.7-1 Assumptions for Fuel Handling Accidents (cont.)

t Parameter Value Adsorber Efficiency Containment Purge Exhaust Filter System organic (%)

30 inorganic (%)

90 Penetration Room Filtration System organic (%)

70 inorganic (%)

90

)

)

6 8

s Table 3.5.1.8-1 Assumptions for Rod Ejection Accident Parameter Value Core Thermal Power (MWt) 2831 l

Fuel Defects l

Clad Failure (%)

10 L

Fuel Melting (%)

0.25 Primary-to-Secondary Leak Rate 150 (gpd/SG)

Percent of Fuel which melts and

~

releases activity to reactor coolant Noble Gases (%)

100 lodines (%)

50 Percent of Fuel which melts and releases activity to containment

(

Noble Gases (%)

100 lodinas (%)

25 lodine Partition Factor in the SGs 0.01 before and after the accident Containment Volume (ft*)

2.03E6 Containment Leak Rate (%/ day) t = 0-1 day 0.15 t > 1 day 0.075 lodine Form in Containment i-(fraction) i Particulate 0.05 Organic 0.04 Elemental 0.91 Steam Dump from Relief Valves 4.26E5 I

(Ibs)

Duration of Steam Dump from Relief 98 Valves (sec)

Time between Accident and 2500 Equalization of Primary-to-Secondary System Pressure (sec) 9

Table 3.5.2-1 Thyroid Doses from Postulated Accidents (Rem) l.

Accident EAR E

1.

Loss of AC Power 0.32 0.14 l

2.

Large Break LOCA l

Containment 200 82 ECCS Leakage 21 52

. Initial Purge

-13 1.9 H Purge 0

31 2

3.

Main Steamline Break Coincident Spike 13 29.8 Pre-existing Spike 24 13 4.

Steam Generator Tube Rupture l

Coincident Spike 39 6.6 -

Pre-existing Spike 270 42 5.

Locked Rotor 1.3 1.9 6.

Fuel Handling Accident inside Containment 41 6.3 Spent Fuel Pool Area 25 3.8 7.

Rod Ejection Secondary Side Pathway 2.4 0.37 Containment Pathway 39 80 8.

Small Break LOCA 83 35 l

1-6 10

4 1

Table 3.5.2-2 Whole Body Doses from Postulated Accidents (Rem)

Accident gag jp_Z.

1.

Loss of AC Power 0.016 0.0052 2.

Large Break LOCA Containment 4.2 1.6 ECCS Leakage initici Purge H Purge 0.077 2

3.

Main Steamline Break Coincideat Spike

<1

<1 Pre-existing Spike

<1

<1 4.

Steam Generator Tube Rupture i

Coincident Spike

<1

<1 Pre-existing Spike

<1

<1 i

5.

Locked Rotor 0.32 0.10 6.

Fuel Handling Accident Inside Containment 0.39 0.059 Spent Fuel Pool Area 0.39 0.059 7.

Rod Ejection i

Secondary Side Pathway 0.086 0.013 Containment Pathway 0.16 0.084 8.

Small Break LOCA 0.65 0.21 l

11 1

a Table 3.5.2-3 Control Room Operator Doses from Postulated Accidents (Rem)

Accdent Thyroid Whole Body 1.

Loss of AC Power 0.0204 0.0075 2.

Large Break LOCA Containment 13 2.2 ECCS Leakage 6.9 Initial Purge H, Purge 3.2 0.06 3.

Main Steamline Break Coincident Spike 2.0

<1 Pre-existing Spike 4.4

<1 4.

Steam Generator Tube Rupture Coincident Spike '

O.97

<1 Pre-existing Spike 6.1

<1

5. -

Locked Rotor 0.29 0.15 6.

Fuel Handling Accident inside Containment 0.92 0.086 Spent Fuel Pool Area 0.56 0.086 7.

Rod Ejection Secondary Side Pathway 0.54 0.019 Containment Pathway 8.7 0.12 i

8.

Small Break LOCA 5,3 0.30 l

l l

12

{

o 4

Table 4.15-1, Changes to TS Table 2.2-1 Allowable Values FUNCTIONAL DESCRIPTION CURRENT 1)EfMIE ilhil VALUE VALUE 2-Low Setpoint Power Range Neutron Flux 26 %

25.4 %

(less than or equal to) of Rated Thermal Power High Setpoint Power Range Neutron Flux 110%

109.4 %

(less than or equal to) of Rated Thermal Power 3

Positive Rate Power Range Neutron Flux 5.5%

5.4%

(less than or equal to)

.of Rated Thermal Power 4

Negative Rate Power Range Neutron Flux 5.5%

5.4%

(less than or equal to) of Rated Thermal Power 9

Pressurizer Pressure--Low 1855 psig 1862 psig (greater than or equalto) 10 Pressurizer Pressure-High 2395 psig 2388 psig (less than or equal to) 11 Pressurizer Water Level-High 93%

92.4 %

(less than or equal to) of Instrument span 12 Loss of Flow 88.5 %

89.7 %

(greater than or equal to) of minimum measured flow perloop 13 Steam Generator Water 23.3%

24.6 %

Level-Low-Low (greater than of narrow range instrument or equal to) span 20.8 Reactor Trip System interiocks 11 %

10.4%

Low Power Reactor Trips Block, P-7 of Rated Thermal Power (less than or equal to)

' 20.C Reactor Trip System Interlocks 36 %

30.4 %

Power Range' Neutron Flux, P-8 of Rated Thermal Power (less than or equal to) 20.D Reactor Trip System Interlocks 7%

7.6%

Power Range Neutron Flux, P-10 of Rated Thermal Power (greater than or equal to) 20.F Reactor Trip System Interlocks 51 %

50.4 %

Reactor Trips Block Following of Rated Thermal Power Turbine Trip,P-9 (less than or.

equal to) 13

?>

l Table 4.15-2, Changes to TS Table 3.3 4 Allowable Values FUNCTIONAL DESCRIPTION CURRENT UPRATE 1)MI VALUE VALUE

)

1.d Safety injection, Turbine Trip 1840 psig 1847 psig and Feedwater isolation, Pressurizer Pressure-Low (greater than or equal to) -

4.d Steamline Isolation, Steam Flow in Two Steamlines--High, Coincident with Tavg-Low-Low 0-20% Load 44 %

' 40.3%

(less than or equal to) of full steam flow At 100% Load 111.5 %

110.3 %

(less than or equal to) of full steam flow T., (greater then or equal to) 540*F 542.6*F 5.a Turbine Trip and Feedwater 80.5 %

78.9%

lsolation, Steam Generator Water of narrow range instrument Level-High-High (less than or span equal to) 6.b Auxiliary Feedwater, Steam 23.3 %

24.6 %

I Generator Water Level-Low-Low of narrow range instrument (greater than or equal to) span 8.a Engineered Safety Feature Actuation 2010 psig 2003 psig System Interlocks, Pressurizer Pressure, P-11 (less than or equal to) 8.b Engineered Safety Feature Actuation System interlocks, Low-Low Tavg, P-12 Increasing (less than or equal to) 547*F 545.4*F Decreasing (greater than or equal to) -

540'F-542.6*F j

l-1 14

s Table 4.1.1-1.

Comparison of NRC and SNC Determined End of Life (EOL) Upper-Shelf Energy (USE) Values for the Beltline Plate and Weld Materials in the FNP Unit 1 Reactor Pressure Vessel' Plate No.

Cu Content 1/4T Unirradiated Decrease NRC EOL SNC Projected (wt.%)

Fluence USE (ft4b)m Decrease in USE (ft-USE 1/4T USE (ft4b)m (E19 nicm")

in USE m Ib)'

g 114T (ft-Ib)

EOL USE Decrease Int.

0 0.13 2.705 99.0 27.5 27.2 72 28 71

,,90 2 I"

0.12 2.705' 87.0 ~

26.3

'22.9 64 27 ' ~

64' B690 N

0.14 2.705 86.0 23.5

• 20.2 m 65 a 29

• 65

• O.14 2.705 86.0 28.8 24.8 61 24 61 B6 9 int Shell Amial Welds 0.258 0.841 149.0 23.1

• 34.4

• 115a 23

• 115*

19 894 A/B d

0.205 2.705 104.0 43.5 45.2 59 43 59 Low. Shell Axial Welds 0.197 0.841 82.5 32.5 26.8 56 34 54 20-894 A/B Footnotes:

1.

All projections for the EOL USE values were performed in accordance with the rnethodology of Position 1.2 of Section C of Regulatory Guide 1.99, Revision 2, " Radiation Embrittlement of Reactor Vessel Materials," except as noted in Footnote No.

3.

2.

Calculational methods for calculating the neutron fluence at the 1/4 thickness (1/4T) location of the reactor pressure vessel (RPV) wall are as defined in Equation (3) of Regulatory Position 1.1 in Regulatory Guide 1.99, Revision 2, Radiation Embnttlernent of Reactor Vessel Materials," or in the equivalent equation in the revised rule 10 CFR 50.61," Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock."

3.

Projections for the EOL USE values using surveillance data were performed in accordance with the methodology of Regulatory Positinn 2.2 of Regulatory Guide 1.99, Revision 2," Radiation Embrittlement of Reactor Vessel Materials."

a 15

a Table 4.1.1-2.

Comparison of NRC and SNC Determined End of Life (EOL) USE Values for the Beltline Plate and Weld Materials in the FNP Unit 2 eactor Pressure Vessel 5 Plate Cu 1/4T Unirradiate

% Decrease Decrease NRC EOL USE SNC Projected No.

Content Fluence d

in USE "8 in USE g il4T (ft-lb)

USE (ft-lb) "3

( wt. %)

(19 n/cm')

QSE (ft-Ib)

(ft-lb) '

EOL USE Decrease Lower Shell 0.140 2.736 99.0 28.9 28.6 70 29 70 B7210-2 Int. Shell 0.140 2.736 100.0 28.9 25.1 71 29 71 57203-1 Int. Shell 0.200 2.736 100.0 41.4 88 41.4 m 59(8) 39 m 61 88 B7212-1 Lower O.130 2.736 103.0 27.6 28.4 75 28 74 Shell B7210-1 Cire. Weld 0.153 2.736 102.0 37 37.7 64 37 64 11-923 Lower Shell 0.057 0.873 126.0 18.5 23.3 103 18.5 103 Axial Wolds20-923 A/B Int. Shell 0.027 0.873 148.0 6.9 m 10.2 m 139 m gm 135 Axial Wold

)19-923 B i

Inr. Shell 0.027 0.873 131.0 18.4 24,1 107 18.5 107 i

Axlal Welds19-923 A Footnotes:

1.

All projections for the EOL USE values were performed in accordance with the rnethodology of Position 1.2 to Section C. of Regulatory Guide 1.99, Revision 2,

• Radiation Embratiement of Reactor Vessel Materials," except as noted in Footnote No.

3.

)

2.

Calculational methods for calculating the neutron fluence at the 1/4 thickness (1/4T) location of the reactor pressure vessel (RPV) wall are as defined in Equation (3) of Regulatory Position 1.1 in Regulatory Guide 1.99, Revision 2, " Radiation Embrittlernent of Reactor Vessel Materials.* or'in the equivalent equation in the revised rule 10 CFR 50.61,

• Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock."

3.

Projections for the EOL USE values using surveillance data were performed in accordance with the methodology of Regulatory 2.2 of Regulatory Guide 1.99, Revision 2, " Radiation Embrittlement of Reactor Vessel Materials?

e 16

[

e

h i

REFERENCES

m A

1.

February 14,1997 - Letter.from D. Morey, Vice President - Farley Project, Southem Nuclear Operating Company (SNC) to the U.S. Nuclear Regulatory Commission (USNRC)

Document Control Desk, " Joseph M. Fariey Nuclear Plant Facility Operating Licenses and Technical Specifications Change Request for Power Uprating."

2.

June 20,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Facility Operating Licenses and Technical Specifications Change Request for Power Uprating."

3.

July 1,1997 - Letter from J. Zimmerman, Project Manager, USNRC, to D.N. Morey, Vice President - Farley Project, SNC, " Request for Additional Information Related to Power Uprate Submittal - Joseph M. Farley Nuclear Plant, Units 1 and 2 (TAC Nos. M98120 and M98121)."

4.

July 23,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Technical Specifications Change Request, Pressure Temperature Limits Report."

5.

July 24,1997 - Letter from J. Zimmerman, Project Manager, USNRC, to D.N. Morey, Vice President - Farley Project, SNC, " Supplement to July 1,1997, Request for Additional Information Related to Power Uprate Submittal-Joseph M. Farley Nuclear Plant, Units 1 and 2 (TAC Nos. M98120 and M98121)."

6.

August 5,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

7.

August 21,1997 - Letter from J. Zimmerman, Project Manager, USNRC, to D.N. Morey, Vice President - Farley Project, SNC, " Request for Additional information Related to Power Uprate Submittal - Joseph M. Farley Nuclear Plant, Units 1 and 2 (TAC Nos.

M98120 and M98121)."

8.

September 22,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

9.

October 14,1997 Letter from J. Zimmerman, Project Manager, USNRC, to D.N. Morey, Vice President - Farley Project, SNC, " Request for Additional Information Related to Power Uprate Submittal - Joseph M. Farley Nuclear Plant, Units 1 and 2 (TAC Nos.

. M98120 and M98121) "

10. November 19,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

1 I

I 4

1

r 4

}

l

11. December 9,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Radiological l

Analyses."

12. December 17,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

i

13. December 18,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Technical Specifications Change Request, Pressure Temperature Limits Report."

14. December 31,1997 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

15. January 23,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and j

Technical Specifications Change Request. "

16. February 12,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the i

USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and

)

Technical Specifications Change Request. "

l 17.~ February 26,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

18. March 3,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

19. March 6,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Gontrol Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information'Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

20. March 16,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and Technical Specifications Change Request. "

l 2

+

21. - March 31,1998 - Letter from H. Berkow, Project Director, USNRC, to D.N. Morey, Vice President - Farley Project, SNC, " Acceptance For Referencing of Pressure Temperature Limits Report."

22. Section 50.61 to Part 50 of Title 10, Code of Federal Regulations, " Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock."

23. Appendix G to Part 50 of Title 10, Code er Federa/ Regulations, " Fracture Toughness Requirements."

24. Appendix H to Part 50 of Title 10, Code of Federal Regulations, " Reactor Vessel Material Surveillance Program Requirements."

' 25. January 31,1996 - Generic Letter 96-03, " Relocation of the Pressure Temperature Limit Curves and Low Temperature Overpressure Protection System Limits."

26. August 3,1995 - Generic Letter 95-05, "Vo'tage-Based Repair Criteria for Westinghouse.

Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking."

27. August # ;76 " Regulatory Guide (RG) 1.121, " Bases for Plugging Degraded PWR Steam Generaior Tubes."

28. Westinghouse WCAP-7588, Revision 1A, "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors using Spacial Kinetics Methods," January 1975.

29. Westinghouse WCAP-9227-P-A, Revision 1, " Reactor Core Response to Excessive Secondary Steam Releases," February 1998.

L

30. Westinghouse WCAP-10054-P-A, " Westinghouse Small Break LOCA ECCS Evaluation i

Model Using NOTRUMP Code," August 1985.

31. Westinghouse WCAP-10263, "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor," January 1983.

32. Westinghouse WCAP-11875, " Joseph Farley Unit 1 and 2 Evaluation For Tube Vibration Induced Fatigue," July 1988. (Proprietary)

33. Westinghouse WCAP-12825, " Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Joseph M. Farley Units 1 and 2 j

Nuclear Power Plants," January 1991. (Proprietary)

34. Westinghouse WCAP-12945-P-A, Volume 1, Revision 2, and Volumes 2 through 5, Revision 1, " Code Qualification Document for Best Estimate LOCA Analysis,"

March 1998 3

7

35. Westinghouse WCAP-13751, " Westinghouse Setpoint Methodology for Protection Systems, Southem Nuclear Operating Company, Farley Nuclear Plant, Units 1 and 2,"

June 1993.

36. Westinghouse WCAP_-14723, "Farley Nuclear Plant Units 1 and 2, Power Uprate Project NSSS Ucensing Report," January 1997. (Nonproprietary)

37. August 12,1991 - Letter from S.T. Hoffman, Project Manager - USNRC, to W.G. Hairston, Ill, Senior Vice President, Alabama Power Company," Safety Evaluation of Elimination of Dynamic Effects of Postulated Primary Loop Pipe Ruptures from Design Basis for Joseph M. Farley Nuclear Plant, Units 1 and 2 (TAC Nos. M79660 and M79661)."

38. March 11,1992 - Letter from S.T. Hoffman, Project Manager, USNRC, to W.G. Hairston, Ill, Senior Vice President, Alabama Power Company, Issuance of Amerdment No. 92 to Facility Operating License No. NPF-2 and Amendment No. 85 to Facility Operating License No. NPF Joseph M. Farley Nuclear Plant, Unit 2 (TAC Nos. M81025 and M81026).

l

39. - April 7,1995 - Letter from B.L. Siegel, Senior Project Manager, USNRC, to D.N. Morey, j

Vice President - Farley Proj9ct, SNC, Issuance of Amendment No.114 to Facility l

Operating License No. NPF-2 and Amendment No.105 to Facility Operating License No.

l NPF Joseph M. Farley Nuclear Plant, Unit 2 (TAC Nos. M89839 and M89840).

40. September 3,1996 - Letter from B.L. Siegel, Senior Project Manager, USNRC, to D.N.

Morey, Vice President - Farley Project, SNC, issuance of Amendment No.121 to Facility Operating License No. NPF-2 and Amendment No.113 to Facility Operating License No.

i NPF Joseph M. Farley Nuclear Plant, Unit 2 (TAC Nos. M95700 and M95701).

41. October 11,1996 - Letter from J. Zimmerman, Project Manager, USNRC, to D.N. Morey, l

Vice President - Farley Project, SNC, issuance of Amendment No.115 to Facility OperMing License No. NPF Joseph M. Farley Nuclear Plant, Unit 2 (TAC No.

M95140.

42. March 24,1997 - Letter from J. Zimmerman, Project Manager, USNRC, to D.N. Morey, Vice President - Farley Project, SNC, issuance of Amendment No.124 to Facility Operating License No. NPF Joseph M. Farley Nuclear Plant, Unit 1 (TAC No. M97510).

43. October 1978 - NUREG/CR-0009, " Technological Bases for Models of Spray Washout of l

Airbome Contaminants in Containment Vessels."

44. 1988 - NUREG-0800, "U.S. Nuclear Regulatory Commission Standard Review Plan, Section 6.5.2, Containment Spray as a Fission Product Cleanup System, Revision 2."

L

45. SECY-97-042,

• Response to OlG Event inquiry 96-04S Regarding Maine Yankee,"

February 18,1997.

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46. April 3,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Power Uprate Facility Operating Licenses and Technical Specification Change Request."

47. April 13,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional information Related to Power Uprate Facility Operating Uconses and Technical Specifications Change Request. "

48.. - April 17,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant Response to Request for Additional Information Related to Power Uprate Facility Operating Licenses and j

Technical Specifications Change Request. "

i l

49. April 17,1998 - Letter from D. N. Morey, Vice President - Farley Project, SNC, to the USNRC Document Control Desk, " Joseph M. Farley Nuclear Plant License Conditions t

L

. Related to Power Uprate Facility Operating Licenses and Technical Specifications Change

{

Request."

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