ML041200107

WCAP-16193-NP, Salem Units 1 and 2, Containment Response to LOCA and MSLB for Containment Fan Cooler Unit/Service Water System Enhancement Project.

ML041200107
Person / Time
Site:	Salem
Issue date:	03/31/2004
From:	Hutchins C, Jakub R, Ohkawa D, Scobel J Westinghouse
To:	Office of Nuclear Reactor Regulation
References
WCAP-16193-NP
Download: ML041200107 (331)

Text

Attachment 3 SALEM UNITS 1 AND 2 CONTAINMENT RESPONSE ANALYSIS WCAP-1 6193 CFCU/SW ENHANCEMENT PROJECT April 2004

L Westinghouse Non-Proprietary Class 3 WCAP-16193-NP March 2004 Salem Unit 1 and Unit 2 Containment Response to LOCA and L MSLB for Containment Fan Cooler L Unit/Service Water System Enhancement Project SWestinghouse

WESTINGHOUSE NON-PROPRIETARY CLASS 3 WCAP-16193-NP Salem Unit 1 and Unit 2 Containment Response to LOCA and MSLB for Containment Fan Cooler Unit/

Service Water System Enhancement Project R. M. Jakub D. K. Ohkawa March 2004 kel and C. H. Hutchins rnent & Radiological Analysis and Safety Analysis Department Approved: I nka W. inkcacs, Manager Containment & Radiological Analysis Systems and Safety Analysis Department Westinghouse Electric Company LLC P.O. Box 355 Pittsburgh, PA 15230-0355 0 2004 Westinghouse Electric Company LLC All Rights Reserved Official record stored electronically in EDMS 2000.031504

iii TABLE OF CONTENTS LIST OF TABLES ................... v LIST OF FIGURES ................... ix EXECUTIVE

SUMMARY

................. xi I INTRODUCTION........................................................................................................................ 1-1 2 BACKGROUND .2-1 3 ANALYSES DESCRIPTION .. 3-1 3.1 OBJECTIVE .3-1 3.2 ANALYSES APPROACH .3-1 3.3 ACCEPTANCE CRITERIA .3-1 4 STEAMLINE BREAK MASS/ENERGY RELEASE ANALYSIS ... 4-1 4.1 ANALYSIS METHOD .. 4-1 4.2 CASE DEFINiTIONS AND SINGLE FAILURES . .4-1 4.3 ANALYSIS ASSUMPTIONS .. 4-5 4.3.1 Protection Logic and Setpoints .4-5 4.3.2 Secondary Side Assumptions .4-5 4.3.3 Reactor Coolant System Assumptions .4-7 4.4 STEAMLINE BREAK MASS/ENERGY RELEASES . . 4-8 5 LOCA MASS AND ENERGY RELEASES .. 5-1 5.1 LONG-TERM LOCA MASS AND ENERGY RELEASES . .5-1 5.1.1 Input Parameters and Assumptions .5-1 5.1.2 Description of Analyses .5-4 5.1.3 LOCA Mass and Energy Release Phases .5-4 5.1A Computer Codes.5-4 5.1.5 Break Size and Location .5-5 5.1.6 Application of Single-Failure Criterion. 5-6 5.1.7 Acceptance Criteria for LOCA M&E Analyses .5-6 5.2 MASS AND ENERGY RELEASE DATA . .5-11 5.2.1 Blowdown Mass and Energy Release Data .5-11 5.2.2 Reflood Mass and Energy Release Data .5-11 5.2.3 Post-Reflood Mass and Energy Release Data .5-12 5.2.4 Decay Heat Model .5-13 5.2.5 Steam Generator Equilibration and Depressurization .5-14 5.2.6 Sources of Mass and Energy .5-14

5.3 CONCLUSION

S .. 5-15 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

iv TABLE OF CONTENTS (cont.)

6 CONTAINMENT RESPONSE ANALYSES ............................... 6-1

6.1 DESCRIPTION

OFCOCO MODEL . . ................................6-1 6.2 CONTAINMENT RESPONSE TO STEAMLINE BREAK . ........................................ 6-10 6.3 CONTAINMENT RESPONSE TO LOCA . . .............................6-15 6.3.1 Input Parameters and Assumptions .......................................... 6-15 6.3.2 Acceptance Criteria .......................................... . 6-16 6.3.3 Analysis Results .......................................... 6-16 6.3.3.1 Unit I - Double Ended Pump Suction Break with Minimum Safeguards .......................................... 6-17 6.3.3.2 Unit 2 - Double Ended Pump Suction Break with Minimum Safeguards .......................................... 6-18

6.4 CONCLUSION

S ............ . 6-51 7 REFERENCES ......... 7-1 APPENDIX A.A-I APPENDIX B.B-I March 2004 OWCAPl 16193-NP WCAP- 6193-NP March 2004 Offical record stored electronically in EDMS 2000-031504

V LIST OF TABLES Table 3.3-1 Equipment Qualification Temperature Profile ........................ ......................... 3-2 Table 4-1 Spectrum of Salem SLB/Containment Cases ................................................. 4-4 Table 4-2 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, Case 19 I. ft2 DER, 30% Power, Containment Safeguards Failure .4-8 Table 4-3 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, Case 23 1.4 ft2 DER, 30% Power, AFW Runout Protection Failure . 4-11 Table 4-4 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, Case 25 1.4 ft2 DER, 100% Power, Feedwater Reg Valve Failure . 4-13 Table 4-5 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, Case 61-1 -0.33 ft2 Small DER, 100% Power, MSIV Failure . 4-18 Table 4-6 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, Case 67 0.88 ft2 Split Break, 30% Power, Cont. Safeguards Failure . 4-21 Table 4-7 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, Case 79 0.88 ft2 Split Break, 30% Power, MSIV Failure. 4-24 Table 4-8 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 9 4.6 ft2 DER, 100% Power, Feedwater Reg Valve Failure . 4-26 Table 4-9 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 11 4.6 ft2 DER, 30% Power, Feedwater Reg Valve Failure . 4-31 Table 4-10 Salem Unit 2 (Model 51SG) Steamline Break Mass/Energy Release, Case 19-2-1.4 ft2 DER, 30% Power, Containment Safeguards Failure . 4-35 Table 4-11 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 23 1.4 ft2 DER, 30% Power, AFW Runout Protection Failure . 4-38 Table 4-12 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 25 1.4 ft2 DER, 100% Power, Feedwater Reg Valve Failure . 4-41 Table 4-13 Salem Unit 2 (Model 51 SG) Stearnline Break Mass/Energy Release, Case 61 0.6 ft2 Small DER, 100% Power, MSIV Failure . 4-44 Table 4-14 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 67 0.88 ft2 Split Break, 30% Power, Cont. Safeguards Failure . 4-47 WCAP-16193-NP March 2004 Official record electronically stored in EDMS 2000-031504

vi _

LIST OF TABLES (cont.)

Table 4-15 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 79 0.88 ft2 Split Break, 30% Power, MSIV Failure ........................................ 4-49 Table 5.1-1 System Parameters Initial Conditions for Salem Unit 1................................................. 5-8 Table 5.1-2 System Parameters Initial Conditions for Salem Unit 2 ................................................. 5-9 Table 5.1-3 Safety Injection Flow Minimum Safeguards ................................................. 5-10 Table 5.2-1 Unit I Double-Ended Pump Suction Break Blowdown Mass and Energy Releases . 5-16 Table 5.2-2 Unit 2 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases . 5-20 Table 5.2-3 Unit 1 Double-Ended Pump Suction Break Reflood Mass and Energy Releases (Minimum Safeguards) . 5-24 Table 5.2-4 Unit 2 Double-Ended Pump Suction Break Reflood Mass and Energy Releases (Minimum Safeguards) . 5-27 Table 5.2-5 Unit I Double-Ended Pump Suction Break Principle Parameters During Reflood (Minimum Safeguards) . 5-31 Table 5.2-6 Unit 2 Double-Ended Pump Suction Break Principle Parameters During Reflood (Minimum Safeguards) . 5-32 Table 5.2-7 Unit I Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) . 5-33 Table 5.2-8 Unit 2 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) ................................................. 5-35 Table 5.2-9 LOCA Mass and Energy Release Analysis Core Decay Heat Fraction ......................... 5-37 Table 5.2-10 Unit 1 Double-Ended Pump Suction Break Mass Balance (Minimum Safeguards) ................................................. 5-39 Table 5.2-11 Unit 2 Double-Ended Pump Suction Break Mass Balance (Minimum Safeguards) ................................................. 540 Table 5.2-12 Unit I Double-Ended Pump Suction Break Energy Balance (Minimum Safeguards) ................................................. 541 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

vii LIST OF TABLES (cont.)

Table 5.2-13 Unit 2 Double-Ended Pump Suction Break Energy Balance (Minimum Safeguards) .................................................... 542 Table 5.2-14 Unit 1 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) with Recirculation Spray Actuated .................................................... 5-43 Table 5.2-15 Unit 2 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) with Recirculation Spray Actuated .................................................... 544 Table 6.1-1 Containment Heat Sinks .................................................... 6-6 Table 6.1-2 Thermophysical Properties of Containment Heat Sinks ................................................. 6-7 Table 6.1-3 Containment Fan Cooler Performance ................ .................................... 67 Table 6.1-4 Containment Response Analysis Parameters .................................................... 6-8 Table 6.1-5 Containment Spray Performance (Injection Phase) .................................................... 6-9 Table 6.2-1 Summary of Steaxnline Break Peak Containment Pressures and Temperatures ............ 6-10 Table 6.2-2 Containment Air Temperature Composite from SLB Analyses for CFCU/SW Enhancement Program ................................................ 6-11 Table 6.3-1 Double-Ended Pump Suction Break Sequence of Events (Salem Unit 1) ............ ........ 6-20 Table 6.3-2 Double-Ended Pump Suction Break Sequence of Events (Salem Unit 2) .................... 6-21 Table 6.3-3 LOCA Containment Response Results (Loss of Offsite Power Assumed) ...........-........ 622 Table 6.34 Containment Response Tlme History LOCA DEPS Minimum Safeguards Unit I with Recirculation Spray . 6-35 Table 6.3-5 Containment Response Time History LOCA DEPS Minimum Safeguards Unit 2 with Recirculation Spray . 643 WCAP-16193-NP March 2004 Official record electronically stored in EDMS 2000.031 S04

ix LIST OF FIGURES Figure 4-1 Increase in AFW to the Faulted SG Due to AFW Runout Protection Failure ................. 4-3 Figure 6.2-1 Containment Temperature Composite Results for Steamline Break ................. ............ 6-14 Figure 6.3-1 Containment Pressure - Double-ended Pump Suction Break at Salem Unit I WITHOUT Recirculation Spray .................................................... 6-23 Figure 6.3-2 Containment Temperature - Double-ended Pump Suction Break at Salem Unit I WITHOUT Recirculation Spray ................................................... 6-24 Figure 6.3-3 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit 1 WITHOUT Recirculation Spray ................................................... 6-25 Figure 6.3-4 Containment Pressure - Double-ended Pump Suction Break at Salem Unit 2 WITHOUT Recirculation Spray ................................................... 6-26 Figure 6.3-5 Containment Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITHOUT Recirculation Spray ................................................... 6-27 Figure 6.3-6 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITHOUT Recirculation Spray ................................................... 6-28 Figure 6.3-7 Containment Pressure - Double-ended Pump Suction Break at Salem Unit I WITH Recirculation Spray ................................................... 6-29 Figure 6.3-8 Containment Temperature - Double-ended Pump Suction Break at Salem Unit I WITH Recirculation Spray ................................................... 6-30 Figure 6.3-9 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit I WITH Recirculation Spray ................................................... 6-31 Figure 6.3-10 Containment Pressure - Double-ended Pump Suction Break at Salem Unit 2 WITH Recirculation Spray ................................................... 6-32 Figure 6.3-11 Containment Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITH Recirculation Spray ................................................... 6-33 Figure 6.3-12 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITH Recirculation Spray ................................................... 6-34 March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000 0315S04

xi EXECUTIVE

SUMMARY

Containment Integrity Analyses have been performed for design basis LOCA and MSLB transients consistent with a proposed change to the Salem Nuclear Generating Station containment fan cooler and service water system. The proposed change will affect the post-accident operation of the containment heat removal systems. These analyses can be used to update the licensing basis safety analyses to support the service water system enhancement program. The analyses conducted are consistent with current licensed methodology for LOCA and MSLB (References 1 and 6).

The containment integrity analyses consider the containment response to both long-term MSLB and LOCA mass and energy releases. The results of the analyses demonstrate the acceptability of the containment safeguards systems to mitigate the containment consequences of a hypothetical design basis pipe break. The analyses ensure that the containment heat removal capability is sufficient to remove the maximum possible discharge of mass and energy release to containment from the Nuclear Steam Supply System without exceeding the containment design pressure and temperature limits. Contrary to prior containment analyses, these calculations credit recirculation spray.

The peak calculated pressure for the DEPS minimum safeguards LOCA case for Salem Unit I with Model F steam generators was 40.1 psig. The peak calculated pressure for the DEPS minimum safeguards LOCA case for Salem Unit 2 with Model 51 steam generators was 41.6 psig. The long term LOCA temperatures are within the Equipment Qualification (EQ) temperature profile, however the EQ limits are slightly exceeded for a short duration (about two hours).

For MSLB, the limiting containment pressure case is a 1.4 ft2 DER initiated at 30% power with a containment safeguards failure. The limiting containment temperature case is 0.88 ft2 split rupture initiated at 30% power with a MSIV failure. For Unit 1, the peak pressure is 40.2 psig and the peak temperature is 345.7 0 F. For Unit 2, the peak pressure is 42.2 psig and the peak temperature is 345.4 0 F.

While this is less than 351.3 0F and the long term temperature ib less than the current profile, there is a period from approximately 140 seconds to 320 seconds where the new composite exceeds the envelop from about 60 F to as much as 180F.

In general, these results show that the service water system enhancement program is a viable option for the Salem units with respect to containment integrity concerns. The noted EQ temperature limit issues are being addressed by PSEG Nuclear outside of this report.

Included in Appendix A is a copy of PSEG letter EA-CFCU-03-004 and Appendix B contains letter EA-CFCU-03-005. These letters are provided in this format for future convenience of identifying the program input assumptions. Some of the information is proprietary to Westinghouse, so this information does not appear in this non-proprietary document.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

l-l 1 INTRODUCTION The long-term containment integrity analyses demonstrate the acceptability of the containment safeguards systems to mitigate the consequences of a hypothetical loss of coolant accident or main stean-line break.

The calculations conservatively predict the containment pressure and temperature response subsequent to a postulated pipe break. These analyses demonstrate that the changes that PSEG has proposed for the service water (SW) system and the containment fan cooler units (CFCUs) provide adequate cooling to maintain the post-accident containment pressure and temperature within the allowable limits.

This evaluation identifies the most limiting loss of coolant accident (LOCA) and the most limiting main steamline break (MSLB) configuration(s) for the containment for Salem Unit 1 and Salem Unit 2 with the revised containment heat removal systems. The impact of the most limiting single failure is applied to each scenario. This evaluation determined the limiting transients based on the containment analysis methodology described in the following sections.

Note that this analysis is performed specifically in terms of containment response to design basis mass and energy release events; any specific requirements for the service water system, the containment ventilation, and the spray coverage for dose related analyses are outside the scope of this report.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

2-1 2 BACKGROUND PSEG is proposing to modify the configuration of the SW System alignment to the CFCUs for both Salem Unit I and Salem Unit 2. Under the new alignment for normal operation, the CFCUs will transfer heat to a new closed loop chilled water system in order to maintain the containment temperature below a specified limit (currently 1200 F). Under accident conditions, the system alignment will change such that heat will be transferred to the SW System. Overall, the intent of the service water system enhancement program is to result in requiring fewer CFCUs to be operable for normal and accident modes. This should improve the overall system performance, reduce maintenance and avoid Technical Specification limiting conditions for operations (LCO) issues. This plant modification will be referred to as the CFCU/SW enhancement project.

The overall purpose of this analytical effort is for Westinghouse to execute a sufficient number of containment mass and energy (M&E) release scenarios so that PSEG can be assured that the proposed CFCU/SW enhancement project will result in sufficient cooling under postulated M&E release accidents.

The design basis containment pressure and temperature limits are to be maintained and the current acceptable equipment qualification (EQ) temperature profile preferably remains unchanged. Containment work that was recently performed by Westinghouse for PSEG included an increased CFCU delay time and Generic Letter 96-06 (1996-1997), the Salem Unit I replacement steam generator assessment (1997),

and the phase I and phase 2 containment capability studies (2001/2002). These were all documented in References I through 4.

The purpose of the 2001/2002 capability study was to determine whether the CFCUs did not need to be credited for the containment integrity events. Based on the LOCA results showing high second pressure rise exceeding the containment design limit after about 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and peaking around 95 psig twelve hours later, it was clear that relying solely on containment sprays was not adequate for the LOCA event.

The project then considered the change to limited CFCU heat removal via a manual operator action to occur at about I hour. While this was shown under the phase 2 analyses to sufficiently reduce the peak containment pressure for the LOCA event, it effectively removes any CFCU heat removal for the steamline break events. Thus, to ensure that pressure and temperature limits would not be exceeded for the MSLB events, several iterations occurred to regain margin through some modeling changes and taking less restrictive input assumptions.

The limiting phase 2 cases for the main stearmline breaks were close to the limits, so an appropriate spectrum of cases (break size, limiting single failure scenario, and power level) was considered. With respect to the EQ temperature profile, under the proposed manual CFCU initiation scenario, the LOCA event in the phase 2 study resulted in exceeding the current established EQ basis for a considerable amount of time. Since the critical equipment needs to be qualified out through Ilx 7 seconds (approximately 120 days), the new LOCA runs will need to cover through this time period.

The present proposed CFCU/SW configuration includes an automatic swap to service water cooling (accident mode), even for those events where the limiting single failure is not the result of a loss of offsite power, such that accident heat removal (from the CFCUs) will start by 100 seconds following the actuation trip signal. To ensure the appropriate CFCU initiation time is implemented, the set of containment response cases performed with COCO (Reference 5) will provide the necessary information for both the LOCA and MSLB scenarios.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000D031504

2-2 The planned configuration is to have three CFCUs available to swap from the closed loop chiller mode to the service water mode. The service water flow rate will be reduced from the current configuration, such that the CFCU heat removal capability will also be reduced. However, due to the intended CFCU normal closed loop cooling configuration, the fouling factor will be significantly lower than currently achievable.

As such, the exact CFCU heat removal rate as a function of containment temperature was determined by PSEG as part of the input specification. For those cases where the single failure is the loss of a safeguards train, two CFCUs and one containment spray pump are available for containment cooling (three CFCUs and two spray pumps for other single failure scenarios).

As part of the analysis performed in 1996 and 1997 (see Reference 1), the plant design change required to meet Generic Letter 96-06 (head tanks connected to the service water lines used a nitrogen gas cover to ensure the system remained pressurized) resulted in 10% degraded heat removal (due to gas entrainment) for the first two minutes that the CFCUs were running in accident mode. The new CFCU/SW configuration will not have this short term degraded heat removal since in the new chilled-water configuration, the CFCU piping is a closed loop with no potential for column separation during the period when the service water pumps are being restarted on the diesel-generators. The head tanks back-up the closed loop by pressurizing the piping and accommodating any potential piping leakage. Any water injected from these tanks will be minimal, if any. Since the injected water will be little or none, there are no reasons to continue to include a full heat capacity time-delay in the containment analysis.

March 2004 WCAP- 161 16193-NP 93-NP March 2004 Offlicial record stored electronically in EDMS 2000-031504

3-1 3 ANALYSES DESCRIPTION 3.1 OBJECTIVE The objective of this program is to demonstrate through analyses and evaluations that the containment pressure and temperature for Salem Unit 1 and Unit 2 resulting from a design basis large break LOCA or main steamline break will remain within the acceptable design limits for the proposed changes to the CFCUs and the SW system.

3.2 ANALYSES APPROACH Consistent with the methodology reported in References 1 through 4, the LOCA and MSLB cases for Salem Unit I and Unit 2 will be analyzed with the current licensing basis methods and analysis tools that have been reviewed and approved for the Salem units many times over the duration of plant operation.

3.3 ACCEPTANCE CRITERIA This analysis is considered acceptable if the current design limits are maintained. The containment design limits are defined in Section 5.2.2 of the Salem Technical Specifications: maximum internal pressure of 47 psig; air temperature up to 351.3 0 F (providing the containment pressure is in accordance with that described in the UFSAR).

It is also desirable for the containment temperature transients to remain below the EQ temperature profile in Table 3.3-1. However, it is recognized that the temperature transient may shift slightly due to the delayed start of the fan coolers from 60 seconds to 100 seconds, the reduced number of fan coolers (i.e., a maximum of five to a possible maximum of three), and the reduced fan cooler heat removal rate compared to the performance employed in the current licensing basis containment integrity analyses.

March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 200Ds031504

3-2 Table 3.3-1 Equipment Qualification Temperature Profile Time (seconds) Temperature (0 F) 0 120 1 165 3 217 6 240 20 265 60 351 80 351 150 325 240 270 1,000 265 4,000 237 4,800 224 18,000 224 180,000 172 518,400 160 1,000,000 140 4,406,400 132 8,640,000 119 10,368,000 113.2 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-1 4 STEAMLINE BREAK MASS/ENERGY RELEASE ANALYSIS Steamline ruptures occurring inside a reactor containment structure may result in significant releases of high-energy fluid to the containment environment and elevated containment temperatures and pressures.

The magnitude of the releases following a steamline rupture is dependent upon the plant initial operating conditions and the size of the rupture as well as the configuration of the plant steam system and the containment design. These variations make it difficult to determine the absolute worst cases for either containment pressure or temperature evaluation following a steamline break. The analysis considers a variety of postulated pipe breaks encompassing wide variations in plant operation, safety system performance, and break size in determining the main steamline break (MSLB) mass and energy releases for use in containment analysis.

This section discusses the analysis that is done to generate the mass and energy releases from the stean-line break. The containment pressure and temperature response analysis is documented in Section 6.2.

4.1 ANALYSIS METHOD The steamline break mass and energy releases are generated using the NRC-approved LOFTRAN code (Reference 6). LOFTRAN is used for studies of the transient response of a PWR system to specified perturbations in process parameters. The code simulates a multi-loop system including the reactor vessel, hot and cold leg piping, steam generator (shell and tube sides), and the pressurizer. A neutron point kinetics model is used and the reactivity effects of the moderator, fuel, boron, and rods are included. The secondary side of the steam generator is modeled as a homogeneous saturated mixture. Protection and control systems are simulated, as well as the Emergency Core Cooling System. The calculation of secondary side break flow is based on the Moody critical flow correlation (Reference 7) with f[JD = 0.

The Westinghouse steamline break mass and energy release methodology was approved by the NRC (Reference 8) and is documented in WCAP-8822, "Mass and Energy Releases Following a Steam Line Rupture" (Reference 9). WCAP-8822 forms the basis for the assumptions and models used in the calculation of the mass and energy releases resulting from a steamline rupture.

42 CASE DEFINITIONS AND SINGLE FAILURES There are many factors that influence the quantity and rate of the mass and energy release from the steamline. To encompass these factors, a spectrum of cases are analyzed that vary the initial power level, the break type, the break area and the single failure. This section summarizes the basis of the cases that have been defined for the Salem plant.

The power level at which the plant is operating when the steamline break is postulated can cause different competing effects that make it difficult to pre-deternine a single limiting case. For example, at higher power levels there is less initial water/steam in the steam generator, which is a benefit. However, at a higher power level there is a higher initial feedwater flowrate, higher feedwater temperature, higher decay heat, and there is a higher rate of heat transfer from the primary side, which are all penalties. Therefore, cases consider initial power levels varying from full power to zero power.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504 I

4-2 There are two types of pipe ruptures that are considered. First is a double-ended guillotine rupture in which the steam pipe is completely severed and the ends of the break displace from each other. Guillotine ruptures are characterized by two distinct break locations, each of equal area but being fed by different steam generators. The other postulated break type is a split rupture in which a hole opens at some point on the side of the steam pipe but does not result in a complete severance of the pipe. A single, distinct break area is fed uniformly by all steam generators until steamline isolation occurs. Following MSIV closure, the split break is unisolable from one faulted steam generator.

The break area is also important when evaluating steamline breaks. It controls the rate of releases to the containment as well as influencing the amount of entrained water in the blowdown and the steamline depressurization. There are a total of 5 break types/areas that are analyzed.

1. A 4.6 ft 2 double-ended rupture (DER) upstream of the in-line flow restrictor. This break size/location only applies to Unit 2 with model 51 steam generators, since the model F steam generators in Unit 1 have an integral flow restrictor. The reverse flow area for these cases is limited to 1.4 ft 2. the cross-sectional area of the in-line flow restrictor.

2. A 1.4 ft2 DER downstream of the flow restrictor. The reverse flow area for theses cases is limited to 3.2 ft2. the cross-sectional area of the MSIV.

3. Small DERs having the smallest area that gets water entrainment.

4. Small DERs having the largest area that does not get water entrainment.

5. Split ruptures that are the largest break area that will neither generate a steamline isolation signal from the primary protection equipment nor result in moisture entrainment. The safety injection signal is also generated by a high containment pressure signal for these cases.

Several single failures can be postulated that would impair the performance of various steamline break protection systems. The single failures either reduce the heat removal capacity of the containment safeguards, or increase the energy release from steamline break. The single failures that have been postulated for Salem are summarized below.

Containment Safeguards Failure (CSF)

The worst containment safeguards failure is the failure of "C" vital bus that results in the failure of I out of 2 containment spray pumps and I out of 3 containment fan coolers. The effect of this failure is a reduction of approximately 70,000 Btu/sec heat removal.

AFW Runout Protection Failure This failure increases the auxiliary feedwater flowrate to the faulted SG Figure 4-1 shows an example of the increase in AFW flowrate as a function of SG pressure, with either the intact SGs fully pressurized or the faulted SG fully depressurized. The penalty of this failure depends on the SG pressure, but in the long-term will usually be between about 150 to 350 gpm extra AFW to the faulted S&

WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-3 Intact SGs Pressurized, Function of Faulted SG Pressure l . Fa.ited SG Depressurized, Function d Intact SG Pressure

-An 450

£ 400 350 ft4

,t , , ft4 ft 4 300 W250 0

200

~ *ft~

_4 44 7777.4 a 150 0

• g 100 I I I g 50 0

0 200 400 600 800 1000 1200 SG Pressure (psia)

Figure 4-1 Increase in AFW to the Faulted SG Due to AFV Runout Protection Failure Feedwater Reg Valve Failure When the feedwater regulator valve (FRV) on the faulted loop fails open, the feedwater isolation valve (FIV) is credited to close. Additional feedwater enters the faulted SG because the closure time of the FIV is slower (an additional 22 seconds) and because of a slight increase in the unisolable feedline volume.

This failure is the most severe for the largest breaks which depressurize the SG the fastest and thus alloy a higher pumped feedwater flowrate to continue for the extra 22 seconds. The extra pumped feedwater can be on the order of 20,000 Ibm to 30,000 Ibm, and the extra unisolable feedline volume adds another 2000 to 3000 Ibm of water.

MSIV Failure When the MSIVs close, the intact loop SGs are isolated from the break. Even if the faulted loop MSIV fails open, the isolation of the intact SGs is accomplished by the closure of the MSIVs on each of those loops. However, the unisolable steamline volume increases from 542 ft3 to 10,083 ft3 if the MSIV on the faulted loop fails open. This causes approximately an extra 20,000 Ibm of steam to be released out the break.

March 2004 WCAP-16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000 031504

4-4 The full spectrum of steamline break cases that has been analyzed for Salem is summarized in Table 4-1.

However, a subset of cases was selected for this analysis to evaluate the acceptability of the CFCU modifications. The selected cases are indicated in Table 4-1, and represent some of the most limiting containment pressure scenarios, the most limiting containment temperature scenarios, and cases that might experience the largest impact from the CFCU modifications. Cases are separately analyzed for Unit I and Unit 2. Note that the 4.6 ft2 DER cases only apply to Unit 2 with model 51 SGs.

Table 4-1 Spectrum of Salem SLB/Containment Cases Single Failure Break Power CSF AFW FRV MSIV 2

4.6 ft DER 100 Case I Case 5 CASE 9 Case 13 70 Case 2 Case 6 Case 10 Case 14 30 Case 3 Case 7 CASE 11 Case 15 0 Case 4 Case 8 Case 12 Case 16 1.4 ft2 DER 100 Case 17 Case 21 CASE 25 Case 29 70 Case 18 Case 22 Case 26 Case 30 30 CASE 19 CASE 23 Case 27 Case 31 0 Case 20 Case 24 Case 28 Case 32 Small DER With Entrainment 100 Case 33 Case 37 Case 41 Case 45 70 Case 34 Case 38 Case 42 Case 46 30 Case 35 Case 39 Case 43 Case 47 0 Case 36 Case 40 Case 44 Case 48 Small DER Without Entrainment 100 Case 49 Case 53 Case 57 CASE 61 70 Case 50 Case 54 Case 58 Case 62 30 Case 51 Case 55 Case 59 Case 63 0 Case 52 Case 56 Case 60 Case 64 Split Break 100 Case 65 Case 69 Case 73 Case 77 70 Case 66 Case 70 Case 74 Case 78 30 CASE 67 Case 71 Case 75 CASE 79 0 Case 68 Case 72 Case 76 Case 80 Note that cases in BOLD were selected for this service water enhancement program analysis.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

L4-5 4.3 ANALYSIS ASSUMPTIONS 4.3.1 Protection Logic and Setpoints Salem Unit I and Unit 2 steanline break protection, in terms of the pertinent signals and setpoints that are actuated in these analyses is summarized below.

The first SI signal comes from either.

• dLow steamline pressure (514.7 psia) in at least 2 loops coincident with high steam flow in at least 2 loops, or L* High steamline differential pressure (200 psid), or

• High-I containment pressure (5.5 psig).

An SI signal starts the SI pumps and will also result in:

_* Reactor trip (2 sec delay)

• Start of auxiliary feedwater (no delay)

_* Closure of feedwater reg valve (10 sec delay) and feedwater isolation valve (32 sec delay, only credited if FRV fails open)

• Trip of MFW pumps (10 second coastdown, only credited if FRV fails open)

• Start of containment fan coolers (100 sec delay)

Steamline isolation (closure of main steam isolation valves, MSIVs) will also occur on the low steamline pressure coincident with high steam flow signal, after a 12.0 second delay. However, if this signal is not

- generated, MSIVs will close on a high-2 containment pressure (17.0 psig) signal. The high-2 containment pressure signal also causes the start of containment spray pumps, after an 85 second delay.

4.3.2 Secondary Side Assumptions This section summarizes the input assumptions associated with the steam generator and the piping attached to it.

Initial Steam Generator Inventory A high initial steam generator mass is assumed. The initial level corresponds to 44% NRS + 5%

uncertainty for at power cases. At zero power, the nominal initial water level decreases to 33%.

_ WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-6 Main Feedwater System Key assumptions and methods regarding the main feedwater system are summarized below.

I. The initial flow to each SG is based on the initial power.

2. The FRV on each of the intact SGs is assumed to close at the time of the SI signal. This terminates the main feedwater addition to the intact SGs. Since they are isolated from the break long before their inventory is depleted, the overall results are insensitive to the details of this modeling.

3. The FRV on the faulted loop is assumed to quickly open in response to the steamline break.

Starting at 0.2 seconds, the main feedwater flowrate modelling is based on the faulted loop FRV fully open (and the intact FRVs fully closed).

4. Main feedwater is added to the faulted SG until the FRV closes, 10 seconds after the SI signal.

5. If the FRV on the faulted loop fails open, the main feedwater pump trip is credited. However, the condensate pumps are not tripped from an SI signal, and pumped flow continues until the feedwater isolation valve is fully closed 32 seconds after the SI signal.

6. All cases model the flashing of the feedwater in the unisolable section of the feedline between the faulted steam generator and the FRV or FIV, whichever is credited to close. Only the cases initiated from hot zero power do not experience feedwater flashing due to the low temperature of the feedwater.

Auxiliary Feedwater Generally within the first minute following a steamline break, the auxiliary feedwater system will be initiated due to an SI signal. Addition of auxiliary feedwater to the steam generators will increase the secondary mass available for release to containment. Maximum auxiliary feedwater flowrates are assumed, and are input as a function of the pressure in the faulted steam. In addition, the full auxiliary feedwater flowrate is assumed at the time the SI setpoint is reached, with no electronic delay or pump start-up time. Operator action is credited to terminate the auxiliary feedwater flow to the faulted steam generator after 10 minutes.

Quality of the Break Effluent The quality of the break effluent is generally assumed to be 1.0, corresponding to saturated steam that is all vapor with no liquid. However, when a large double-ended break first occurs, it is expected that there will be a significant quantity of liquid in the break effluent. Modeling entrainment is a benefit to the analysis, since it allows a portion of the initial steam generator inventory to be released at the lower enthalpy of saturated liquid rather than saturated vapor. The break quality for the DERs is from WCAP-8822 (Reference 9) for model 51 steam generators, and similar information was generated with the same methodology for model F steam generators.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-7 Heat Transfer to Faulted Steam Generator The ability of the steam generator feeding the broken steamline to transfer heat from the primary coolant to the secondary water inventory can have an important influence on the mass and energy that is released through the break. As discussed in Reference 8, the film coefficient on the outside of the tubes and the forced convection from the reactor coolant pumps will typically maintain a large secondary side heat transfer coefficient. The only mechanism for reducing the heat transfer capability to the steam generator is to lower the effective heat transfer area. Such a reduction occurs when sufficient mass is lost from the steam generator to lower the water level below the top of the tube bundle. To conservatively force a high heat transfer rate to the faulted steam generator, the SG tubes are assumed to be fully covered until the water volume on the secondary side decreases below 100 ft3.

43.3 Reactor Coolant System Assumptions While the mass and energy released from the break is determined from assumptions that have been discussed in the previous section, the long-term rate at which the release occurs is largely controlled by the conditions in the reactor coolant system. The major features of the primary side analysis model are summarized below.

• Continued operation of the reactor coolant pumps maintains a high heat transfer rate to the steam generators.

• The model includes consideration of the heat that is stored in the RCS metal.

• Reverse heat transfer from the intact steam generator to the RCS coolant is modeled as the temperature in the RCS falls below the steam generator fluid temperature.

• Minimum flowrates are modeled from ECCS injection, Io conservatively minimize the amount of boron that provides negative reactivity feedback.

• The core power is 3459 MWt, with a maximum pump heat of 20 MWt, resulting in NSSS power of 3479 MWt. This bounds the current NSSS power of 3471 MWt.

• Maximum reactor power calorimetric uncertainty of +0.6% is used for full power cases.

• RCS average temperature is the full-power nominal (high-end) value of 577.90 F plus an uncertainty of +5.00 F.

• Core residual heat generation is assumed based on the 1979 ANS decay heat plus 2cr model (Reference 10).

• Conservative core reactivity coefficients corresponding to end-of-cycle conditions were chosen to maximize the reactivity feedback effects as the RCS cools down as a result of the steamline break.

• All cases have credited a shutdown margin of 1.3% Ak/k.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000.031504

4-8 4.4 STEAMLINE BREAK MASS/ENERGY RELEASES Steamline break mass and energy release rates are provided in Table 4-2 to Table 4-7 for Unit I and Table 4-8 to Table 4-15 for Unit 2.

Table 4-2 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, Case 19 1.4 ft2 DER, 30% Power, Containment Safeguards Failure Time Flowrate Enthalpy (sec) (Ibmns) (Btu/lbm) 0.0 0.0 0.0 0.2 8942.9 1192.1 1.4 8238.0 1194.7 1.6 8372.8 1171.0 1.8 8895.2 1113.4 2.0 9751.0 1037.1 2.2 10428.3 984.2 3.0 10702.7 943.0 3.2 10953.7 935.4 3.4 11080.1 924.2 6.0 9653.6 953.6 7.2 9107.3 966.8 9.0 8517.4 975.7 11.4 7598.9 1006.0 13.2 7076.7 1025.4 13.4 7076.7 1028.9 13.6 4769.1 950.1 13.8 2971.6 805.7 16.0 2616.1 844.7 17.4 2341.4 885.2 19.2 2029.5 939.5 20.8 1794.2 988.4 22.4 1594.6 1038.1 24.2 1407.9 1094.9 25.8 1269.6 1146.1 27.6 1138.8 1204.3 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-9 Table 4-2 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 19 1A fte DER, 30% Power, Containment Safeguards Vailure Time Flowrate Enthalpy (sec) (lbmns) (BtuAbm) 32.2 1046.1 1204.0 36.8 988.3 1203.8 40.0 961.3 1203.6 46.2 927.7 1203.4 58.8 895.6 1203.2 102.4 860.4 1202.9 163.0 845.9 1202.7 164.2 838.2 1202.6 166.6 800A 1202.2 169.0 742.1 1201.5 171.4 659.6 1200.1 176.8 430.5 1193.8 178.6 367.0 1191.0 180.4 318.3 11885 192.2 297.7 1187A 222.2 294.6 1187.2 255.2 289.6 1186.9 312.4 275.9 1186.0 342.8 264.8 1185.2 373.4 248.0 1184.0 434.4 204.0 1180.1 449.6 196.3 1179.4 464.8 191.0 1178.8 480.2 187.6 1178.5 510.8 184.3 1178.1 600.2 182.5 1178.0 604.0 138.0 1172.4 604.6 132.2 1171.6 612.2 84.4 1162.5 616.6 51.9 1154.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-10 Table 4-2 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 19 1.4 ft2 DER, 30% Power, Containment Safeguards Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btullbm) 617.8 41.6 1152.1 618.6 33.6 1151.2 618.8 33.0 1150.9 619.0 28.2 1150.8 619.2 28.4 1150.5 619A 22.4 1150.5 619.6 22.7 1150.4 619.8 0.0 0.0 700.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-11 Table 4-3 Salem Unit 1 (Model F SG) Steanmine Break Mass/Energy Release, Case 23 1A ft2 DER, 30% Power, AFW Runout Protection Failure Time Flowrate Enthalpy (sec) (Ibntfs) (Btu/lbm) 0.0 0.0 0.0 0.2 8942.9 1192.1 1.4 8238.0 1194.7 1.6 8372.8 1171.0 1.8 8895.1 It 13A 2.0 9750.8 1037.1 2.2 10428.0 984.2 3.0 10701.7 943.0 3.4 11078.9 924.2 7.2 9104.5 966.7 11.4 7595.0 1005.9 13.4 7072.4 1028.8 13.6 4766.0 950.1 13.8 2969.6 805.6 16.0 2614.0 844.6 19.2 2027.3 939.4 20.8 1792.0 988.4 22.4 1592.6 1038.1 24.2 1406.0 1094.9 27.6 1137.0 1204.3 32.2 1044.2 1204.0 36.8 986.3 1203.8 45.8 927.2 1203.4 63.8 886.1 1203.1 100.2 859.0 1202.8 168.4 836.1 1202.6 171.4 788.3 1202.1 174.2 715.4 1201.1 176.2 645.0 1199.9 182.0 415.1 1193.2 WCAP-16193-NP, March 2004 Offifciarecord stored electronically in EDMS 2D00-031504

4-12 Table 4-3 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 23 1.4 ft2 DER, 30% Power, AFW Runout Protection Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btu/ibm) 183.8 360.8 1190.7 185.2 328.1 1189.0 200.8 297.6 1187.4 299.2 290.2 1186.9 370.0 282.4 1186.4 371.6 279.1 1186.2 373.2 282.0 1186.4 374.8 278.7 1186.2 376.4 281.5 1186.4 378.0 278.3 1186.2 379.6 281.1 1186.4 381.2 277.9 1186.2 382.8 280.7 1186.3 600.8 240.0 1183.2 603.2 202.2 1179.8 604.2 194.9 1179.2 608.2 184.6 1178.1 610.2 175.2 1177.1 619.0 121.0 1169.5 628.4 55.3 1154.7 629.4 47.1 1153.0 630.8 33.8 1151.2 631.4 28.4 1150.6 -_

631.8 23.0 1150.4 632.0 0.0 0.0 700.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-13 Table 4-4 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, Case 25.1 - 1.4 ft DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (see) (Ibmls) (Btu/tbm) 0.0 0.0 0.0 0.2 7953.3 1194.9 0.4 7828.9 1195.3 0.8 7660.8 1195.9 1.4 7435.1 1196.7 1.6 7515.0 1179.8 1.8 7620.8 1161.3 2.0 7745.6 1141.2 2.2 7899.1 1119.2 2.4 8087.2 1095.0 2.6 8318.2 1068.2 2.8 8604.4 1038.5 3.0 8963.3 1005.3 3.2 9542.8 993.1 4.0 9670.5 977.3 4.2 9632.7 978.0 5.0 9222.9 999.5 5.6 8945.0 1014.8 6.2 8689.4 1029.4 7.4 8232.1 1056.6 8.0 8023.3 1069.3 8.6 7905.6 1073.4 9.8 7685.8 1077.9 10.4 7546.0 1081.7 13.4 6765.3 1108.9 13.6 4353.6 1061A 13.8 2461.8 960.2 15.0 2295.6 981.8 16.4 2087.4 1015.7 17.6 1923.3 1045.8 WCAP-16193-NP March 2004 Officia reord stored eltonicalcly in EDMS 2000-031504

4-14 Table 4-4 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 25 1.4 ft 2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (Ibmls) (Btullbm) 18.4 1822.3 1066.1 19.0 1751.1 1081.4 19.6 1683.6 1096.8 20.4 1599.1 1117.5 l21.0 1539.7 1133.1 21.6 1483.6 1148.8 22.2 1430.6 1164.6 23.6 1317.9 1201.8 23.8 1306.9 1204.5 24.6 1279.8 1204.5 26.4 1225.9 1204.5 28.0 1184.7 1204.4 29.6 1148.7 1204.3 31.4 1113.1 1204.3 33.0 1085.1 1204.2 34.8 1057.0 1204.1 36.4 1034.8 1204.0 38.2 1012.8 1203.9 40.0 993.8 1203.8 41.6 979.4 1203.7 45.0 955.0 1203.6 48.4 936.6 1203.5 52.0 921.8 1203.4 - _

55.4 910.9 1203.3 58.8 902.1 1203.2 65.8 888.3 1203.1 72.6 878.1 1203.0 79.4 870.2 1202.9 93.2 858.9 1202.8 107.0 851.4 1202.8 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-15 Table 4-4 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 25.1 - IA ft2 DER, 100% Power, Feedwater Reg Valve Failure rime Flowrate Enthalpy (sec) (Ibmls) (Btuilbm) 149.0 839.3 1202.7 192.6 834.9 1202.6 193.0 832.6 1202.6 194.0 823.1 1202.5 196.0 800.6 1202.2 197.8 777.8 1202.0 199.8 750.1 1201.6 203.6 693.5 1200.8 207.6 630.9 1199.6 211 A 567.7 1198.2 215A 498.6 1196.3 219.2 434.7 1194.1 221.0 406.6 1192.9 222.0 391.7 1192.3 223.0 377.7 1191.6 224.8 354.2 1190.5 226.8 330.7 1189.2 228.6 312.2 1188.2 230.6 294.0 1187.1 231.4 287.4 1186.7 232.4 280.0 1186.2 234A 267.1 1185A 235.4 261.5 1185.0 236.4 256.3 1184.6 237.4 251.7 1184.2 238.4 247.7 1183.9 240A 240.7 1183A 242.4 235.0 1182.9 244.4 230.6 1182.5 246.2 227.1 1182.2 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-16 Table 4-4 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 25 1.A ft2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (ibm/s) (Btu/lbm) 248.0 222.9 1181.9 250.0 218.8 1181.5 252.0 215.4 1181.2 254.0 212.7 1180.9 257.8 208.7 1180.6 261.6 205.9 1180.3 265.4 203.9 1180.1 269.4 202.2 1179.9 277.2 199.8 1179.7 284.8 198.0 1179.5 315.8 191.8 1178.9 331.4 189.5 1178.7 377.6 184.6 1178.1 408.4 182.1 1177.9 423.8 181.2 1177.8 452.2 180.5 1177.7 600.2 180.5 1177.8 602.2 158.9 1174.9 605.0 102.9 1166.2 605.2 100.0 1165.6 605.6 94.3 1164.5 606.0 89.3 1163.6 606.8 80.2 1161.5 607.2 76.0 1160.3 607.4 73.6 1159.7 608.4 63.1 1156.7 608.8 58.7 1155.5 609.0 56.5 1154.9 609.4 51.7 1153.8 610.0 44.2 1152.4 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-17 Table 4-4 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 25 1.4 ft2 DER, 100% Power, Feedwater Reg Valve Failure Time Fnowrate Enthalpy (see) (Ibm/s) (Btu/bm) 610.2 41.4 1152.0 610.4 38.6 1151.6 610.8 32.6 1151.0 611.0 29.1 1150.7 611.2 25.1 1150.5 611.4 20.0 1150.4 611.6 0.0 0.0 700.0 0.0 0.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-18 Table 4-5 Salem Unit 1 (Model F SG) Steamline Break MasslEnergy Release, Case 61 0.33 ft2 Small DER, 100% Power, MSIV Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btu/ibm) 0.0 0.0 0.0 0.2 1244.1 1194.7 0.4 1237.6 1194.8 1.4 1218.1 1195.2 2.8 1198.6 1195.7 5.2 1172.4 1196.3 7.8 1149.3 1196.8 10.4 1130.1 1197.2 12.8 1115.4 1197.5 15.4 1102.6 1197.8 19.2 1088.4 1198.1 20.6 1081.5 1198.3 20.8 1105.0 1198.1 21.0 1115.1 1197.9 22.8 1170.6 1196.7 24.0 1204.2 1195.9 25.2 1234.8 1195.1 26.2 1256.4 1194.6 27.4 1274.8 1194.1 28.6 1283.1 1193.9 30.2 1286.0 1193.8 31.4 1281.5 1193.9 48.4 1179.6 1196.1 57.8 1127.5 1197.2 74.2 1046.7 1198.8 75.2 1043.1 1199.6 86.0 888.8 1200.2 95.2 761.2 1200.7 104.6 635.0 1201.4 114.0 511.9 1202.2 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-19 Table 4-5 Salem Unit 1 (M6Wde F SG) Steamline Break Mass/Energy Release, (cont.) Case 61 0.33 ft 2 Small DER, 100% Power, MSIV Failure Time Flowrate Enthalpy (see) (Ibm/s) (BtuAbm) 124.6 375.7 1203.9 124.8 374.1 1203.9 132.6 368.6 1204.0 142.0 363.2 1204.1 151.4 358.8 1204.1 160.6 355.3 1204.2 186.4 349.1 1204.3 219.0 346.2 1204.3 409.8 345.6 1204.3 568.8 347.3 1204.3 572.0 345.5 1204.3 575.2 342.7 1204.3 578.4 339.0 1204.3 581.8 334.3 1204.4 585.0 329.0 1204.4 588.4 322.3 1204.4 591.8 314.8 1204.5 597A 300.3 1204.5 600.6 292.5 1204.5 609.0 232.8 1203.8 619.6 230.1 1203.7 622A 227.3 1203.6 625.8 226.7 1203.6 639.2 218.9 1203.4 649.0 211.8 1203.2 654.0 207.5 1203.0 659.0 202.7 1202.8 664.0 197.1 1202.6 668.8 191.2 1202.4 673.8 184.3 1202.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 20004031504

4-20 Table 4-5 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 61 0.33 ft2 Small DER, 100% Power, MSIV Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btullbm) 678.8 176.5 1201.6 683.8 168.0 1201.1 688.8 158.5 1200.4 693.8 148.2 1199.6 698.8 137.1 1198.6 703.8 125.3 1197.3 716.2 95.4 1192.9 721.2 84.0 1190.6 726.0 73.7 1188.2 728.4 68.7 1187.0 730.8 64.0 1185.7 733.4 59.1 1184.1 735.8 54.9 1182.7 738.2 50.8 1181.2 739.8 48.1 1180.1 740.8 46.7 1179.5 744.8 40.9 1176.9 749.4 34.8 1173.8 752.4 31.1 1171.6 761.4 22.4 1164.9 770.0 16.3 1158.7 779.0 9.9 1152.1 782.0 6.4 1150.7 783.0 5.2 1150.4 783.2 0.0 0.0 1000.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-21 Table 4-6 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, Case 67 0.88 fWtSplit Break, 30% Power, Cont. Safeguards Failure iume Flowrate Enthalpy (see) Ibmts) (Btullbm) 0.0 0.0 0.0 0.2 1813.9 1191.7 3.8 1722.9 1193.5 7.4 1654.0 1194.8 14.8 1549.6 1196.7 20.4 1562.1 1196.6 24.2 1547.4 1196.9 60.0 1258.7 1201.3 63.2 1140.7 1202.7 65.2 1078.6 1203.3 68.8 989.1 1204.0 72.4 920.1 1204.3 76.4 860.0 1204.4 80.6 813.6 1204.5 85.6 775.1 1204.5 88.6 758.4 1204.4 97.6 725.6 1204.4 113.0 700.3 1204.3 141.0 683.2 1204.2 201.4 670.2 1204.1 314.8 666.2 1204.1 316.8 657.9 1204.0 319.0 640.7 1203.9 322.2 602.0 1203.6 324.2 568.7 1203.2 327.2 506.8 1202.3 333.4 366.4 1198.5 335.6 325.4 1196.8 337.8 292.7 1195.2 338.8 280.4 11945 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000.031504

4-22 Table 4-6 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 67 0.88 ft2 Split Break, 30% Power, Cont. Safeguards Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btu/Ibm) 340.8 260.1 1193.2 344.0 237.3 1191.6 347.2 223.0 1190.5 350.2 214.6 1189.8 356.4 205.5 1189.1 360.6 202.7 1188.8 373.2 199.8 1188.6 386.6 199.0 1188.5 395.8 191.6 1187.8 406.6 187.5 1187.4 496.6 187.0 1187.4 542.0 186.9 1187.4 604.2 184.9 1187.2 618.0 179.4 1186.6 642.4 175.1 1186.2 656.2 170.6 1185.7 670.0 164.0 1185.0 683.8 153.6 1183.7 690.8 145.9 1182.7 697.6 136.0 1181.3 704.4 123.0 1179.3 707.8 115.2 1178.0 712.6 102.3 1175.7 717.8 86.0 1172.3 720.0 79.8 1170.6 727.0 56.8 1163.9 732.8 39.2 1156.7 735.4 30.3 1153.3 736.0 28.6 1152.6 736.6 25.0 1152.1 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-23 Table 4.6 Salem Unit I (Modei F SG) Steanline Break MassfEnergy Release, (Cont.) Case 67 0.88 ft2 Split Break, 30 % Power, Cont. Safeguards Failure Time Flowrate Enthalpy (sec) (Ibuds) (Btullbm) 736.8 25.2 1151.7 737.0 23.1 1151.7 737.2 23.3 1151.4 737.4 21.1 1151.3 738.0 19.2 1150.7 738.2 16.8 1150.7 738.4 17.0 11505 738.8 12.9 1150A 739.0 0.0 0.0 1000.0 0.0 0.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-24 Table 4-7 Salem Unit 1 (Model F SG) Steamline Break Mass/Energy Release, Case 79 0.88 ft2 Split Break, 30% Power, MSIV Failure Time Flowrate Enthalpy (sec) (Ibmls) (Btullbm) 0.0 0.0 0.0 0.2 1813.9 1191.7 3.8 1724.7 1193.5 7.4 1656.9 1194.8 14.8 1553.3 1196.6 20.2 1564.7 1196.6 24.2 1550.0 1196.9 60.4 1255.1 1201.4 63.6 1142.2 1202.7 65.6 1085.1 1203.2 69.0 1005.1 1203.9 73.0 931.1 1204.3 76.6 877.9 1204.4 80.6 831.9 1204.5 87.4 779.1 1204.5 94.0 747.2 1204.4 100.8 726.3 1204.4 117.2 700.0 1204.3 146.0 682.6 1204.2 211.6 669.5 1204.1 356.4 666.5 1204.1 359.4 652.2 1204.0 361.8 630.0 1203.8 363.8 604.3 1203.6 366.8 552.2 1203.0 369.0 505.3 1202.3 374.2 385.9 1199.2 377.2 327.6 1196.9 379.2 297.1 1195.5 381.4 270.8 1193.9 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-31504

4-25 Table 4-7 Salem Unit I (Model F SG) Steamline Break Mass/Energy Release, (cont.) Case 79 0.88 ft2 Split Break, 30% Power, MSIV Failure rime lowrate Enthalpy (see) (Ibmts) (Btullbm) 384.4 245A. 1192.2 387.8 227.3 1190.9 391.8 214.9 1189.9 394.0 210.6 1189.5 400.2 203.9 1188.9 406.6 201.1 1188.7 431.8 198.9 1188.5 440.6 191.6 1187.8 510.0 187.1 1187.4 601.0 186.0 1187.2 620.2 181.1 1186.8 622.6 179.0 1186.6 659.8 170.1 1185.7 673.4 163.4 1184.9 687.0 152.7 1183.6 693.8 145.0 1182.5 700.4 135.2 1181.1 707.2 121.9 1179.1 712.2 109.8 1177.0 724.0 74.5 1169.1 733.2 44.6 1159.2 739.8 21.7 1151.1 740.2 19.7 1150.8 740.6 17.4 1150.5 741.0 14.5 1150.4 741.2 0.0 0.0 1000.0 0.0 0.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000.031504

4-26 Table 4-8 Salem Unit 2 (Model 51 SG) Steamline Break MasslEnergy Release, Case 9 4.6 ft 2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (Ibmts) (Btu/lbm) 0.0 0.0 0.0 0.2 10588.9 1197.2 0.4 11053.4 1116.9 0.6 13236.7 964.6 0.8 14765.0 881.4 1.0 15083.4 854.7 1.2 15479.0 827.2 1.4 15976.6 799.1 1.6 16596.7 770.2 2.2 14858.3 790.8 2.4 14314.2 798.5 2.8 13303.0 814.0 3.2 12381.6 829.7 3.4 11953.5 837.6 3.6 11764.2 852.1 4.0 11061.7 869.8 4.4 10424.8 887.2 4.8 9856.1 904.6 5.0 9594.6 913.2 5.4 9122.9 930.2 5.8 8706.9 946.9 6.0 8515.4 955.1-6.4 8160.8 971.3 7.0 7692.3 995.0 7.6 7288.5 1017.8 8.2 6938.1 1039.8 8.4 6831.2 1046.9 8.6 6681.6 1059.3 8.8 6496.2 1076.8 9.2 6162.0 1110.1 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-27 Table 448 Salem Unit 2 (Model S1 SG) Steamline Break Mass/Energy Release, (cont.) Case 9 4.6 fe DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (see) (bm/s) (Btu/lbm) 9.4 6011.4 1126.1 9.8 5737.6 1156.5 10.2 5486.2 1186.6 10.4 5374.6 1200.2 13.6 4919.3 1199.7 13.8 4919.3 1199.6 14.6 2486.3 1201.3 14.8 2403.3 1201.3 15.8 2307.8 1200.9 16.8 2220.7 1200.5 17.8 2142.4 1200.0 18.6 2085.6 1199.7 19.4 2033.8 1199.4 20.4 1975.6 I199.0 21.4 1923.8 1198.6 22.4 1877.6 1198.3 24.2 1806.3 1197.8 26.2 1738.2 1197.2 28.2 1676.4 1196.7 30.2 1620.4 1196.2 32.0 1573.8 1195.7 34.0 1526.6 1195.2 35.8 1491.0 1194.9 37.8 1460.8 1194.5 39.8 1436.5 1194.2 41.6 1418.9 1194.0 43.4 1405.2 1193.9 45.4 1393.2 1193.7 49.2 1376.1 1193.5 53.0 1363.9 1193.4 WCAP-16193-NP March 2004 Official record stored clectronically in EDMS 20004031504

4-28 Table 4-8 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 9 4.6 ft2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (see) (Ibmts) (Btu/lbm) 60.8 1346.7 1193.1 76.0 1325.5 1192.9 91.2 1311.5 1192.7 114.4 1299.0 1192.5 114.6 1296.5 1192.4 115.0 1279.6 1192.1 115.4 1256.1 1191.8 116.0 1213.8 1191.2 117.0 1133.5 1189.9 118.0 1044.4 1188.4 118.4 1006.5 1187.7 119.0 947.0 1186.6 120.0 843.2 1184.4 121.0 737.6 1181.7 121.8 655.5 1179.4 122.2 617.8 1178.2 122.6 582.7 1177.1 123.0 549.7 1176.0 123.6 503.1 1174.3 124.0 474.2 1173.2 124.2 460.7 1172.6 124.6 435.3 1171.5 124.8 426.8 1170.9 125.6 386.4 1168.8 126.0 367.2 1167.8 126.4 349.3 1166.8 126.8 333.0 1165.9 127.0 325.6 1165.5 127.4 311.9 1164.7 127.8 299.8 1164.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-29 Table 448 Salem Unit 2 (Modi 51 SG) Steamline Break MasslEhergy Release, (cont.) Case 9 4.6 ft2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (see) (Ibm/s) (Btullbm) 128.0 294.3 1163.7 128A 284.2 1163.1 128.8 275.2 1162A 129.4 263.5 1161.6 129.8 257.1 1161.1 130.2 251.9 1160.6 130A 248.6 1160.4 130.8 243.2 1160.0 131.A 236.8 1159.5 131.8 233.2 1159.2 132A 228.8 1158.8 133.2 224.4 1158.5 134.0 221.3 1158.2 135.0 218.9 1158.0 136.0 217.7 1157.9 137.4 217.3 1157.9 144.2 218.6 1158.0 182.4 217.1 1157.8 188.4 215.8 1157.7 268.8 205.3 1156.8 349.4 190.7 1155.6 394A 185.6 1155.2 448.2 180.8 1154.9 478.8 179.7 1154.8 600.2 179.8 1154.9 600.4 181.4 1154.8 600.6 179.6 1154.6 600.8 176.2 1154.3 601.0 171.2 1154.0 601.2 164.5 11535 March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000 031504

4-30 Table 4-8 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 9 4.6 ft2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btufbm) 601.4 156.1 1153.0 601.6 143.1 1151.0 601.8 0.0 0.0 700.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-31 Table 4.9 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 11-2-4.6 ft2 DER, 30% Power, Feedwater Reg Valve Failure rime lowrate Enthalpy (see) (Ibmts) (Btu/lbm) 0.0 0.0 0.0 0.2 12164.1 1193.6 0.4 13449.9 1070.6 0.6 18717.6 843.7 0.8 19216.4 817.1 1.0 19795.2 789.8 1.2 20512.5 761.8 1.4 21394.1 733.0 2.0 19057.3 752.3 2.2 18323.7 759.1 2.6 16918.8 773.2 2.8 16255.9 780.5 3.2 15056.8 795.2 3.4 14497.6 802.7 4.0 13017.6 827.0 4.4 12125.3 843.1 4.8 11276.8 861.6 5.0 10880.1 871.2 5.2 10505.6 880.9 5.4 10154.4 890.5 5.6 98285 900.0 6.0 9239.2 918.8 6.4 8712.7 937.4 6.8 8242.1 955.6 7.2 78215 973.4 7.6 7445.3 990.8 7.8 7192.2 1007.3 8.0 6953.7 1023.8 8.2 6732.9 1039.8 8.4 6528.1 1055.4 March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000 0315S04

4-32 Table 4-9 Salem Unit 2 (Model 51 SG) Steanline Break Mass/Energy Release, (cont.) Case 11 4.6 ft2 DER, 30% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (see) (Ibmls) (Btu/lbm) 8.6 6337.9 1070.6 8.8 6160.9 1085.4 9.2 5831.5 1115.1 9.4 5667.3 1131.7 9.8 5373.0 1163.2 10.2 5118.2 1192.6 10.4 5040.1 1199.6 11.4 4862.1 1199.4 12.6 4675.6 1199.2 14.8 4380.7 1199.0 15.0 4380.7 1198.9 15.8 2058.1 1199.1 16.0 1983A4 1199.0 17.4 1878.7 1198.3 18.2 1824.7 1197.9 19.2 1762.8 1197.4 20.0 1717.5 1197.0 20.8 1676.2 1196.7 21.6 1638.9 1196.3 23.2 1574.6 1195.7 24.0 1547.7 1195.5 24.8 1523.9 1195.2 25.6 1503.5 1195.0 27.2 1471.5 1194.6 28.8 1448.6 1194.4 30.4 1432.4 1194.2 32.0 1420.9 1194.1 35.2 1406-9 1193.9 41.8 1388.6 1193.7 54.8 1364.9 1193.4 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-33 Table 4-9 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 11 4.6 ft2 DER, 30% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (bmls) (Btu/lbm) 67.8 1346.9 1193.1 80.8 1333.1 1193.0 93.8 1323.1 1192.8 112.4 1313A 1192.7 114.4 1207.4 1191.1 116.4 1010.1 1187.8 118.4 823.2 1184.1 120.2 795.9 11835 122.4 804.2 1183.7 124.0 804.3 1183.7 125.2 801.3 1183.6 127.4 792.6 1183.4 129.6 781.0 1183.1 138.6 721.0 1181.5 140.8 704.3 1181.1 143.2 684.1 1180.5 145.4 663.8 1179.9 147.6 641.9 1179.2 149.8 618.0 1178.5 152.2 589.7 1177.6 154.4 561.3 1176.6 156.6 530.5 1175.5 158.8 497.5 1174.3 162.8 434.1 1171.6 163.2 430.0 1171.3 163.8 421.4 1170.8 167.6 358.8 1167.5 168.6 343.1 1166.6 169.8 325.6 1165.6 170.8 312.2 1164.9 WCAP-16193-sP March 2004 Officia record stored electronically in EDMS 20004031504

4-34 Table 4-9 Salem Unit 2 (Model 51 SG) Steanline Break Mass/Energy Release, (cont.) Case 11 4.6 ft 2 DER, 30% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec)Ibnds) (Btullbm) 172.0 297.4 1164.0 173.2 284.1 1163.1 174.4 272.1 1162.3 175.4 263.1 1161.7 176.0 258.2 1161.3 177.0 251.6 1160.7 178.2 242.7 1160.0 178.8 239.1 1159.7 179.8 234.1 1159.3 181.0 229.3 1158.9 182.2 225.5 1158.6 183.4 222.6 1158.3 184.4 220.7 1158.2 185.6 219.0 1158.0 187.8 217.0 1157.8 190.0 215.9 1157.7 194.6 214.7 1157.6 248.4 205.3 1156.8 302.2 193.4 1155.8 320.2 190.1 1155.6 338.2 187.9 1155.4 374.0 184.5 1155.1 391.8 183.4 1155.1 436.2 182.1 1155.0 600.2 181.9 1155.0 601.0 173.1 1154.1 604.2 68.7 1150.4 604.4 0.0 0.0 700.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-35 Table 4-10 Salem Unit 2 (Model 51SG) Steamline Break Mass/Energy Release, Case 19 1A ft2 DER, 30% Power, Containment Safeguards Failure Trime flowrate Enthalpy (see) (Ibm/s) (Btuflbm) 0.0 0.0 0.0 0.2 8832.5 1192.7 0.6 8569.1 11935 1.0 9010.7 1132.6 1.2 93585 1094.3 1A 9843.6 1048.8 1.6 10541.1 993.9 2.6 11019.5 934.9 3.0 10906.6 930.1 3.2 10999.6 931.2 4.6 10697.4 918.1 7.6 9201.4 952.1 9.0 8353.0 988.2 10.0 7838.9 1012.0 11.4 7215.5 1042A 13.2 6610.9 1075.7 13.4 6610.9 1080.3 13.6 4281.0 1021.0 13.8 2472.1 900.2 15.0 2247.0 940.9 16A 2014.9 988.9 17.6 1851.9 1025.2 20.0 1600.1 1084.4 22.0 1422.0 1134.6 23.4 1269.6 1199.6 23.6 1256.1 1204.5 28.6 1116.0 1204.3 33.8 1018.6 1203.9 39.0 957.7 1203.6 44.0 921.2 1203.3 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-36 Table 4-10 Salem Unit 2 (Model 51SG) Steamline Break Mass/Energy Release, (cont.) Case 19 1.4 ft DER, 30% Power, Containment Safeguards Failure Time Flowrate Enthalpy (sec) (Ibm/s) (Btullbm) 54.2 881.5 1203.0 64.4 862.7 1202.9 105.2 834.2 1202.6 193.2 817.8 1202.4 194.4 805.7 1202.3 196.4 771.3 1201.9 198.8 713.1 1201.1 200.8 650.2 1200.0 210.2 327.1 1189.0 223.6 297.3 1187.4 258.6 292.7 1187.1 279.8 289.3 1186.9 294.4 285.8 1186.7 324.8 277.8 1186.1 354.8 266.7 1185.4 391.4 244.9 1183.7 451.6 199.5 1179.7 466.6 192.9 1179.0 481.6 188.7 1178.6 503.8 185.3 1178.2 600.4 183.8 1178.0 603.6 145.7 1173.5 604.8 132.4 1171.6 609.6 99.3 1165.6 611.8 85.1 1162.6 612.4 79.6 1161.4 613.8 68.6 1158.4 614.8 61.4 1156.3 615.8 53.3 1154.3 617.2 40.2 1151.9 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-37 Table 4-10 Salem Unit 2 (Model S1SG) Steamline Break Mass/Energy Release, (cont.) Case 19 1.4 ft2 DER, 30% Power, Containment Safeguards Failure Time Flowrate Enthalpy (sec) Ibm/s) (Btutlbm) 618.0 31.5 1150.9 618.4 26.1 1150.6 618.6 25.5 1150.4 618.8 0.0 0.0 700.0 0.0 0.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-38 Table 4-11 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 23 1A ft 2 DER, 30% Power, AFW Runout Protection Failure Time Flowrate Enthalpy (sec) (Ibmns) (Btulibm) 0.0 0.0 0.0 0.2 8832.5 1192.7 0.6 8569.1 1193.5 1.0 9010.7 1132.6 1.4 9843.5 1048.8 1.6 10541.1 993.9 2.6 11018.7 934.9 4.6 10695.7 918.1 6.8 9562.1 943.0 9.0 8349.7 988.2 11.4 7211.8 1042.4 13.4 6606.9 1080.3 13.6 4278.3 1021.0 13.8 2470.4 900.1 16.4 2013.2 988.8 18.8 1718.9 1054.6 22.0 1420.2 1134.5 23.6 1254.4 1204.5 28.4 1118.8 1204.3 33.2 1025.7 1204.0 38.0 965.1 1203.6 42.8 926.3 1203.4 52.4 884.0 1203.1 62.0 863.7 1202.9 100.8 833.5 1202.6 198.8 814.1 1202.4 202.2 762.5 1201.8 204.8 698.6 1200.8 212.2 444.0 1194.4 214.2 383.4 1191.8 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-39 Table 4-11 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 23 1A ft2 DER, 30% Power, AFW Runout Protection Failure Time Flowrate Enthalpy (sec) (Ibmis) (Btu/lbm) 216.2 335.8 1189.5 218.2 301.1 1187.5 219.4 287.7 1186.8 221.8 303.1 1187.7 226.2 298.3 1187.4 230.2 297.8 1187.4 234.0 297.3 1187.4 237.4 297.0 1187A 241.0 296.9 1187.4 244.8 296.7 1187.3 248.2 296.3 1187.3 251.8 296.1 1187.3 255.4 295.8 1187.3 259.0 295A 1187.3 262.6 295.2 1187.2 266.2 295.0 1187.2 269.6 294.5 1187.2 273.0 294.2 1187.2 275.0 289.6 1186.9 276.6 293.9 1187.2 280.0 293.5 1187.2 283.8 293.4 1187.1 345.6 287.3 1186.8 347.2 284.0 1186.6 379.4 283.1 1186.5 600.8 240.2 1183.3 603.6 200.1 1179.6 604.8 191.7 1178.9 607.8 182.7 1177.9 611.6 163.6 1175.8 WCAP-16193-NP March 2004 Official record stored clecironically in EDMS 20004031504

4-40 Table 4-11 Salem Unit 2 (Model 51 SG) Steanline Break MasslEnergy Release, (cont.) Case 23 1.4 ft 2 DER, 30% Power, AFW Runout Protection Failure Time Flowrate Enthalpy (see) ibms) (Btu/Ibm) 618.2 119.1 1169.2 622.6 87.0 1163.1 626.8 54.3 1154.5 627.8 45.3 1152.7 629.0 33.2 1151.1 629.4 28.2 1150.7 629.6 27.6 1150.5 629.8 0.0 0.0 700.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-41 Table 4-12 Salem Unit 2 (Model Si SG) Steamline Break Mass/Energy Release, Case 25 1.4 fet DER, 100% Power, Feedwater Reg Valve Failure Time lowrate Enthalpy (sec) (Ibm/s) (Btu/lbm) 0.0 0.0 0.0 0.2 7576.9 11965 0.4 7473.2 1196.7 0.6 7399.5 1197.0 0.8 7415.8 1187.3 1.0 7536.8 1166.2 1.2 7688.1 1142.8 1.4 7877.6 1116.9 1.6 8115.3 1087.8 2.0 8336.4 1057.3 2.2 8472.7 1040.6 2.4 8630.7 1022.8 2.6 8813.5 1003.9 3.0 8851.5 992.5 3.2 9204.8 994.2 3.6 9311.7 983.5 4.2 9229.9 983.7 4.4 9180.5 985.4 6.0 8648.6 1011.7 7.2 8299.6 1030.1 8.4 7978.0 1047.3 10.8 7345.7 1078.2 13.2 66925 1105.4 13.4 66925 1108.2 13.6 4304.3 1060.7 13.8 2434.9 960.1 15.0 2259.2 987.3 16.4 2068.9 1019.4 17.8 1894.8 1052.0 18.4 1825.3 1066.2 March 2004 WCAP- 6193-NP WCAP-r 16193-NP March 2004 Official record stored electronically in EDMS 2000 031S04

4-42 Table 4-12 Salem Unit 2 (Model 51 SG) Steanline Break Mass/Energy Release, (cont.) Case 25 1.4 ft 2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (Ibnis) (Btu/lbm) 19.2 1737.6 1085.2 20.4 1616.2 1114.1 21.0 1559.8 1128.6 21.2 1534.9 1137.1 21.8 1444.9 1173.8 22.2 1389.3 1198.3 22.4 1372.0 1204.4 23.2 1341.7 1204.5 25.2 1274.9 1204.5 27.0 1223.3 1204.5 28.8 1178.3 1204.4 30.4 1142.9 1204.3 32.2 1107.4 1204.2 34.0 1075.7 1204.1 35.8 1047.3 1204.0 37.4 1024.7 1203.9 39.2 1002.1 1203.8 41.0 982.4 1203.7 42.8 965.4 1203.6 46.2 939.1 1203.5 49.8 918.0 1203.3 53.4 901.8 1203.2 56.8 889.7 1203.1 60.4 879.4 1203.0 67.4 864.1 1202.9 74.4 852.8 1202.8 81.6 844.3 1202.7 95.6 833.3 1202.6 109.8 826.0 1202.5 153.4 814.2 1202.4 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-43 Table 4-12 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 25 IA ft2 DER, 100% Power, Feedwater Reg Valve Failure Time Flowrate Enthalpy (sec) (Ibmts) (Btu/ibm) 188.8 810.5 1202A 219A 809.1 1202.3 219.8 806.9 1202.3 220.8 797.1 1202.2 230.6 656.9 1200.1 234.6 591.2 1198.8 242A 456.5 1194.9 253.4 306.9 1187.9 261.2 249.6 1184.1 271.8 217.0 1181.3 285.4 204.1 1180.1 289.4 202.4 1180.0 297.2 200.1 1179.7 312.8 196.7 1179.4 344.2 191.1 1178.8 375A 187.4 1178.4 406.6 184.4 1178.1 437.8 182.0 1177.9 481.2 180.6 1177.7 600.2 180A 1177.8 600.4 181.7 1177.8 605.2 103.6 1166.3 609.0 57.6 1155.2 612.0 16.8 1150A 612.2 0.0 0.0 700.0 0.0 0.0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-44 Table 4-13 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 61 0.6 ft2 Small DER, 100% Power, MSIV Failure Time Flowrate Enthalpy (see) (lbinis) (Btu/lbm) 0.0 0.0 0.0 0.2 2134.9 1196.3 0.4 2116.2 1196.5 1.0 2079.8 1196.9 1.8 2041.9 1197.3 3.4 1983.3 1198.0 6.6 1890.1 1199.0 6.8 1938.2 1198.9 7.0 1950.1 1198.8 8.4 1993.2 1198.3 10.4 2046.9 1197.6 11.4 2070.3 1197.3 12.4 2089.4 1197.0 13.4 2101.9 1196.8 14.4 2106.0 1196.8 15.6 2105.5 1196.8 17.0 2098.0 1197.4 26.8 1621.8 1198.8 31.0 1422.8 1199.5 35.2 1228.3 1200.2 39.4 1039.0 1201.1 43.6 854.3 1202.3 47.6 682.2 1203.9 51.8 660.3 1204.1 56.0 641.2 1204.2 60.2 624.6 1204.3 64.4 610.1 1204.4 68.6 597.3 1204.4 72.8 586.0 1204.4 85.6 559.5 1204.5 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-45 Table 4-13 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 61 0.6 ft2 Small DER, 100% Power, MSIV Failure Time Flowrate Enthalpy (sec) (Ibmfs) (Btuflbm) 97.2 542.5 1204.5 105A 533.3 1204.5 114.4 525.5 1204.5 120.2 521.5 1204.4 135.6 514.1 1204.4 144.2 511.6 1204.4 164A 508.7 1204A 178.8 508.0 1204.4 332.6 509.1 1204.4 340.8 476.4 1204.3 347.6 421.9 1203.7 353.0 421.5 1203.7 368.4 407.0 1203.5 376.2 398.4 1203A 383.8 388.7 1203.2 391.4 377A 1203.0 399.2 364.1 1202.8 406.8 349A 1202.4 421.0 317.7 1201.5 441.6 268.1 1199.5 457.0 235.4 1197.8 468.6 216.5 1196.6 476A 206.8 1195.9 484.2 199.3 1195.3 491.8 193.7 1194.8 499.4 189.4 1194.4 507.2 186.1 1194.1 514.8 183.7 1193.9 522.6 181.8 1193.7 538.0 179A 1193.5 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000D031504

4-46 Table 4-13 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 61 0.6 ft2 Small DER, 100% Power, MSIV Failure Time Flowrate Enthalpy (se)(lbmls) (Btu/lbm) 553.4 177.9 1193.4 568.8 176.9 1193.3 600.2 175.91193.2 602.4 169.2 1192.4 610.0 115.0 1185.4 615.0 85.9 1179.7 620.4 60.8 1173.0 625.0 44.6 1166.5 630.4 30.6 1159.2 637.6 10.4 1150.4 637.8 8.9 1150.4 638.0 0.0 0.0 700.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-47 Table 4-14 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, Case 67 0O88 ft2 Split Break, 30 % Power, Cont. Safeguards Failure Time Flowrate Enthalpy (sec) (Ibmnts) (Btuilbm) 0.0 0.0 0.0 0.2 1786.9 - 1192.3 3.8 1701.2 1194.0 7.6 1631.7 1195.3 15.0 1529.6 1197.1 20.8 1539.0 1197.1 26.2 1518.7 1197.4 60.0 1264.0 1201.2 62.4 1176.5 1202.3 65.2 1088.0 1203.2 69.6 981.3 1204.0 75.6 877.3 1204.4 79.2 830.8 1204.5 84.0 784.7 12045 89.6 747.9 1204A 100.6 706.7 1204.3 119.0 678.6 1204.2 149.6 662.9 1204.1 238.0 649.9 1204.0 350.4 648.5 1204.0 351.8 644.2 1203.9 354.6 622.1 1203.8 357.6 586.0 1203A 360.6 537.1 1202.8 369.4 360.7 1198.3 371.6 323.1 1196.7 373.2 300.1 1195.6 374.6 282.8 1194.7 377.6 254.0 1192.8 379.8 239.0 1191.8 WCAnP-16193-ENP March 2004 Official record stored elkctronicallb in EDMS 2000-031504

4-48 Table 4-14 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 67 0.88 ft2 Split Break, 30 % Power, Cont. Safeguards Failure Time Flowrate Enthalpy (sec) (Ibmls) (Btu/Ibm) 382.8 224.9 1190.7 385.6 216.4 1190.0 391.4 204.4 1189.0 397.4 197.7 1188.4 409.2 192.3 1187.9 488.0 187.1 1187.4 596.0 186.8 1187.4 604.8 185.5 1187.2 611.2 178.7 1186.6 656.0 169.2 1185.6 668.2 162.1 1184.7 674.2 157.3 1184.1 683.4 147.2 1182.8 692.6 132.4 1180.7 698.8 118.6 1178.5 703.2 106.6 1176.5 713.8 72.5 1168.5 723.6 39.4 1156.7 725.4 33.1 1154.2 728.0 21.1 1151.2 729.2 14.7 1150.4 729.4 0.0 0.0 1000.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

4-49 Table 4-15 Salem Unit 2 (Model 51 SG) Steanmine Break Mass/Energy Release, Case 79 0.88 ft2 Split Break, 30% Power, MSIV Failure rime Flowrate Enthalpy (sec) (Ibmi/s) (Btu/Ibm) 0.0 0.0 0.0 0.2 1786.9 1192.3 3.8 1702.8 1193.9 7.6 1634.4 1195.2 15.0 1533.2 1197.0 20.8 1541.6 1197.0 28A 1505.1 1197.6 60.4 1260.3 1201 A 62A 1188.1 1202.2 65.8 1088.3 1203.2 71.0 973.7 1204.1 74.8 909.5 1204.3 78.6 857.3 1204A 82.6 814.4 1204.5 86.0 786.0 1204.5 92.0 749.2 1204.4 103A 708.5 1204.3 122.8 679.0 1204.2 154.4 662.5 1204.1 259.4 649.2 1204.0 393.0 649.0 1204.0 396.2 631.8 1203.9 399.2 600.0 1203.6 402.2 555.0 1203.0 405.2 499.0 1202.1 409.6 407.8 1199.9 412.6 349.7 1197.9 415.6 302.6 1195.8 417.8 276.0 1194.3 420.2 253.9 1192.8 WCAP-16193-NP March 2004 Official .ecord stored elctronically in EDMS 2000.031504

4-50 Table 4-15 Salem Unit 2 (Model 51 SG) Steamline Break Mass/Energy Release, (cont.) Case 79 0.88 ft2 Split Break, 30 % Power, MSIV Failure Time Flowrate Enthalpy l(sec) Ibn/s) (Btu/lbm) 423.2 234.6 1191.4 426.2 222.0 1190.4 429.2 214.0 1189.8 438.2 200.2 1188.6 441.4 197.4 1188.3 453.4 192.4 1187.9 529.8 187.0 1187.4 604.8 186.1 1187.3 622.4 180.6 1186.8 625.0 178.7 1186.6 649.2 173.0 1186.0 668.2 163.7 1184.9 681.0 152.8 1183.6 690.6 140.0 1181.8 696.8 128.5 1180.1 703.2 113.1 1177.6 706.4 104.0 1176.0 716.0 72.9 1168.6 719.4 61.0 1165.1 720.0 58.4 1164.4 723.4 47.1 1160.2 725.6 40.3 1157.1 727.6 33.5 1154.3 730.0 22.5 1151.5 731.4 15.5 1150.4 731.6 0.0 0.0 1000.0 0.0 0.0 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-1 5 LOCA MASS AND ENERGY RELEASES The uncontrolled release of pressurized high-temperature reactor coolant, termed a loss-of-coolant accident (LOCA), will result in release of steam and water into the containment. This, in turn, will result in increases in the local subcompartment pressures, and an increase in the global containment pressure and temperature. Therefore, there are typically both long- and short-term issues reviewed relative to a postulated LOCA that must be considered for a complete containment integrity analysis. Since none of the major components of the RCS are changing (i.e., pressurizer or steam generators) and the licensed power level will remain the same, the short term issues will not need to be reviewed or reanalyzed. Only the long term LOCA transients will be analyzed.

The long-term LOCA mass and energy releases are analyzed to approximately Ix107 seconds and are utilized as input to the containment integrity analysis. This demonstrates the acceptability of the containment safeguards systems to mitigate the consequences of a hypothetical large-break LOCA. The containment safeguards systems must be capable of limiting the peak containment pressure to less than the design pressure and to limit the temperature excursion to less than the acceptance limits. For this service water system enhancement program, Westinghouse generated Salem Unit I and Unit 2 specific LOCA mass and energy releases for containment design using the flexible multi-nodal model (hereafter referred to as "the March 1979 model") described in Reference 11. The Nuclear Regulatory Commission (NRC) review and approval letter is included with Reference 11. This section discusses the long-term LOCA mass and energy releases generated for this program. The results of this analysis were provided for use in the containment response analysis (see Section 6.3).

5.1 LONG-TERM LOCA MASS AND ENERGY RELEASES The mass and energy release rates described in this section form the basis of further computations to evaluate the containment following the postulated accident. Discussed in this section are the long-term LOCA mass and energy releases for the hypothetical double-ended pump suction (DEPS) rupture with minimum safeguards. The maximum safeguards case for the DEPS break and the blowdown portion of the double-ended hot leg (DEHL) rupture break that are typically performed for a full spectrum of design basis cases are not needed for this program. The DEPS maximum safeguards case would not yield a limiting set of mass and energy releases for the changes to the service water system and the containment fan coolers and the DEHL case is only performed for the initial blowdown (approximately 30 seconds in duration) and none of the safety systems actuate that quickly. The mass and energy releases for the DEPS minimum safeguards case for Salem Unit I and Salem Unit 2 are used for the long-term containment response analyses in Section 6.3. The basis for using these cases is discussed in Section 5.1.5 and Section 5.1.6.

5.1.1 Input Parameters and Assumptions The mass and energy release analysis is sensitive to the assumed characteristics of various plant systems, in addition to other key modeling assumptions. Where appropriate, bounding inputs are utilized and instrumentation uncertainties are included. For example, the RCS operating temperatures are chosen to bound the highest average coolant temperature range of all operating cases and a temperature uncertainty allowance of (+5.00 F) is then added. Nominal parameters are used in certain instances. For example, the WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-2 RCS pressure in this analysis is based on a nominal value of 2250 psia plus an uncertainty allowance

(+50.0 psi). All input parameters are chosen consistent with accepted analysis methodology.

Some of the most critical items are the RCS initial conditions, core decay heat, safety injection flow, and primary and secondary metal mass and steam generator heat release modeling. Specific assumptions concerning each of these items are discussed in the following paragraphs. Tables 5.1-1 through 5.1-3 present key data assumed in the analysis.

The core rated power of 3459 MWt, adjusted for calorimetric error (i.e., 100.6% or 3479.75 MWt) was used in the analysis. As previously noted, the use of RCS operating temperatures to bound the highest average coolant temperature range were used as bounding analysis conditions. The use of higher temperatures is conservative because the initial fluid energy is based on coolant temperatures that are at the maximum levels attained in steady-state operation. Additionally, an allowance to account for instrument error and deadband is reflected in the initial RCS temperatures. The selection of 2250 psia as the limiting pressure is considered to affect the blowdown phase results only, since this represents the initial pressure of the RCS. The RCS rapidly depressurizes from this value until the point at which it equilibrates with containment pressure.

The rate at which the RCS blows down is initially more severe at the higher RCS pressure. Additionally the RCS has a higher fluid density at the higher pressure (assuming a constant temperature) and subsequently has a higher RCS mass available for releases. Thus, 2250 psia plus uncertainty was selected for the initial pressure as the limiting case for the long-term mass and energy release calculations.

The selection of the fuel design features for the long-term mass and energy release calculation is based on the need to conservatively maximize the energy stored in the fuel at the beginning of the postulated accident (i.e., to maximize the core stored energy). The core stored energy that was selected to bound the Westinghouse 17 x 17 RFA fuel product that will be used at Salem Unit I and Unit 2 was 4.23 full power seconds (FPS). The margins in the core stored energy include + 15 percent in order to address the thermal fuel model and associated manufacturing uncertainties and the time in the fuel cycle for maximum fuel densification. Thus, the analysis very conservatively accounts for the stored energy in the core.

Margin in RCS volume of 3 percent (which is composed of 1.6-percent allowance for thermal expansion and 1.4-percent allowance for uncertainty) was modeled.

A uniform steam generator tube plugging level of 0 percent was modeled. This assumption maximizes the reactor coolant volume and fluid release by virtue of consideration of the RCS fluid in all steam generator tubes. During the post-blowdown period, the steam generators are active heat sources since significant energy remains in the secondary metal and secondary mass that has the potential to be transferred to the primary side. The 0-percent tube plugging assumption maximizes the heat transfer area and, therefore, the transfer of secondary heat across the steam generator tubes. Additionally, this assumption reduces the reactor coolant loop resistance, which reduces the AP upstream of the break for the pump suction breaks and increases break flow. Thus, the analysis conservatively accounts for the level of steam generator tube plugging.

WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-3 The secondary- to primary-heat transfer is maximized by assuming conservative heat transfer coefficients.

This conservative energy transfer is ensured by maximizing the initial internal energy of the inventory in the steam generator secondary side. This internal energy is based on full-power operation plus uncertainties.

Regarding safety injection flow, the mass and energy release calculation considered configurations, component failures, and offsite power assumptions to conservatively bound respective alignments.

The cases include a minimum safeguards assumption (I chargingesafety injection (CHG/SI) pump, I intermediate head safety injection (IHSI) pump, and 1 low-head safety injection (LHSI) pump) (see Table 5.1-3). In addition, the containment backpressure is assumed to be equal to the containment design pressure. This assumption was shown in Reference 11 to be conservative for the generation of mass and energy releases. Another aspect of the safety injection system that is considered is the recirculation flow that would occur if the operators did or did not initiate recirculation spray.

In summary, the following assumptions were employed to ensure that the mass and energy releases are conservatively calculated, thereby maximizing energy release to containment:

1. Maximum expected operating temperature of the RCS (100-percent full-power conditions)

2. Allowance for RCS temperature uncertainty (+5.00 F)

3. Margin in RCS volume of 3 percent (which is composed of 1.6-percent allowance for thermal expansion, and 1.4-percent allowance for uncertainty)

4. Core rated power of 3459 MWt

5. Allowance for calorimetric error (+0.6 percent of power)

6. Conservative heat transfer coefficients (i.e., steam generator primary/secondary heat transfer, and RCS metal heat transfer)

7. Allowance in core stored energy for effect of fuel densification

8. A margin in core stored energy (+15 percent to account for manufacturing tolerances)

9. An allowance for RCS initial pressure uncertainty (+50 psi)

10. A maximum containment backpressure equal to design pressure (47.0 psig)

11. Steam generator tube plugging leveling (0-percent uniform)

- Maximizes reactor coolant volume and fluid release

- Maximizes heat transfer area across the steam generator tubes WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000D031504

5-4

- Reduces coolant loop resistance, which reduces the AP upstream of the break for the pump suction breaks and increases break flow Thus, based on the previously discussed conditions and assumptions, an analysis of Salem Unit I and Salem Unit 2 was made for the release of mass and energy from the RCS in the event of a large break LOCA at 3479.75 MWt.

5.1.2 Description of Analyses The evaluation model used for the long-term LOCA mass and energy release calculations is the March 1979 model described in Reference 11.

This report section presents the long-term LOCA mass and energy releases generated in support of the Salem service water enhancement program. These mass and energy releases are then subsequently used in the containment integrity analysis and qualification temperature evaluation.

5.1.3 LOCA Mass and Energy Release Phases The containment system receives mass and energy releases following a postulated rupture in the RCS.

These releases continue over a time period, which, for the LOCA mass and energy analysis, is typically divided into four phases.

I. Blowdown - the period of time from accident initiation (when the reactor is at steady-state operation) to the time that the RCS and containment reach an equilibrium state.

2. Refill - the period of time when the lower plenum is being filled by accumulator and emergency core cooling system (ECCS) water. At the end of blowdown, a large amount of water remains in the cold legs, downcomer, and lower plenum. To conservatively consider the refill period for the purpose of containment mass and energy releases, it is assumed that this water is instantaneously transferred to the lower plenum along with sufficient accumulator water to completely fill the lower plenum. This allows an uninterrupted release of mass and energy to containment. Thus, the refill period is conservatively neglected in the mass and energy release calculation.

3. Reflood - begins when the water from the lower plenum enters the core and ends when the core is completely quenched.

4. Post-reflood (Froth) - describes the period following the reflood phase. For the pump suction break, a two-phase mixture exits the core, passes through the hot legs, and is superheated in the steam generators prior to exiting the break as steam. After the broken loop steam generator cools, the break flow becomes two phase.

5.1.4 Computer Codes The Reference II mass and energy release evaluation model is comprised of mass and energy release versions of the following codes: SATAN VI, WREFLOOD, FROTH, and EPITOME. These codes were used to calculate the long-term LOCA mass and energy releases for Salem Unit I and Salem Unit 2.

WCAP- 16193-NP March 2004 Official record stored electronically in EDM5 2000-031504

5-5 SATAN VI calculates blowdown, the first portion of the thermal-hydraulic transient following break initiation, including pressure, enthalpy, density, mass and energy flow rates, and energy transfer between primary and secondary systems as a function of time.

The WREFLOOD code addresses the portion of the LOCA transient where the core reflooding phase occurs after the primary coolant system has depressurized (blowdown) due to the loss of water through the break and when water supplied by the ECCS refills the reactor vessel and provides cooling to the core.

The most important feature of WREFLOOD is the stean/water mixing model (see Subsection 5.2.2).

FROTH models the post-reflood portion of the transient. The FROTH code is used for the steam generator heat addition calculation from the broken and intact loop steam generators.

EPITOME continues the FROTH post-reflood portion of the transient from the time at which the secondary equilibrates to containment design pressure to the end of the transient. It also compiles a summary of data on the entire transient, including formal instantaneous mass and energy release tables and mass and energy balance tables with data at critical times.

5.1.5 Break Size and Location Generic studies have been performed and documented in Reference I with respect to the effect of postulated break size on the LOCA mass and energy releases. The double-ended guillotine break has been found to be limiting due to larger mass flow rates during the blowdown phase of the transient.

During the reflood and froth phases, the break size has little effect on the releases.

Three distinct locations in the RCS loop can be postulated for a pipe rupture for mass and energy release purposes:

• Hot leg (between vessel and steam generator)

• Cold leg (between pump and vessel)

• Pump suction (between steam generator and pump)

The break location analyzed for this program is the DEPS rupture (10.48 ft2). Break mass and energy releases have been calculated for the blowdown, reflood, and post-reflood phases of the LOCA for the DEPS cases. The following information provides a discussion on the three possible break locations and why the DEPS break is limiting for the long term.

The DEHL rupture has been shown in previous studies to result in the highest blowdown mass and energy release rates. Although the core flooding rate would be the highest for this break location, the amount of energy released from the steam generator secondary is minimal because the majority of the fluid that exits the core vents directly to containment bypassing the steam generators. As a result, the reflood mass and energy releases are reduced significantly as compared to either the pump suction or cold leg break locations where the core exit mixture must pass through the steam generators before venting through the break. For the hot leg break, generic studies have confirmed that there is no reflood peak (i.e., from the end of the blowdown period the containment pressure would continually decrease). Therefore, only the mass and energy releases for the hot leg break blowdown phase are calculated. Since none of the WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-6 powered safety systems are assumed to be operational during initial blowdown phase, the service water system enhancement program would not impact the DEHL break.

The cold leg break location has also been found in previous studies to be much less limiting in terms of the overall containment energy releases. The cold leg blowdown is faster than that of the pump suction break, and more mass is released into the containment. However, the core heat transfer is greatly reduced, and this results in a considerably lower energy release into containment. Studies have determined that the blowdown transient for the cold leg is, in general, less limiting than that for the pump suction break.

During reflood, the flooding rate is greatly reduced and the energy release rate into the containment is reduced. Therefore, the cold leg break is bounded by other breaks and no further evaluation is necessary.

The pump suction break combines the effects of the relatively high core flooding rate, as in the hot leg break, and the addition of the stored energy in the steam generators. As a result, the pump suction break yields the highest energy flow rates during the post-blowdown period by including all of the available energy of the RCS in calculating the releases to containment. Thus, only the DEHL and DEPS cases are used to analyze long-term LOCA containment integrity for full scope programs. For this service water enhancement program, the DEHL break would not be impacted from the current design basis cases so it is not reanalyzed here.

5.1.6 Application of Single-Failure Criterion An analysis of the effects of the single-failure criterion has been performed on the mass and energy release rates for each break analyzed. An inherent assumption in the generation of the mass and energy release is that offsite power is lost coincident with the pipe rupture. This results in the actuation of the emergency diesel generators. Operation of the diesel generators delays the operation of the safety injection system that is required to mitigate the transient.

The single failure that is analyzed for the LUCA mass and energy releases for the service water enhancement program is the postulated failure of an entire train of safeguards equipment. Typically, this is synonymous with the failure of an emergency diesel generator to start. However, the Salem plants have a three diesel generator system, so the loss of one diesel would be less limiting than the loss of one complete train of safeguards equipment. The loss of one entire train of safety injection pumps results in only one CHG/SI pump, one IHSI pump, and one LHSI pump available for accident mitigation. The containment heat removal equipment that is assumed to operate for this train failure scenario is discussed in Section 6.3.3.

5.1.7 Acceptance Criteria for LOCA M&E Analyses A large break loss-of-coolant accident is classified as an American Nuclear Society (ANS) Condition IV event, an infrequent fault. To satisfy the NRC acceptance criteria presented in the Standard Review Plan, Section 6.2.1.3, the relevant requirements are the following:

• 10 CFR 50, Appendix A

• 10 CFR 50, Appendix K, paragraph I.A WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-7 To meet these requirements, the following must be addressed:

• Break size and location

• Calculation of each phase of the accident

• Sources of energy The description of the modeling of each phase of the transient with the March 1979 model (Reference 11) and the individual sources of energy are provided in the following section. The break size and location was discussed in Section 5.1.5.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-8 Table 5.1-1 System Parameters Initial Conditions for Salem Unit I Parameters Value Core Thermal Power (MWt) 3479.75 Reactor Coolant System Total Flowrate (Ibm/sec) 34805.56 Vessel Outlet Temperature (F1) 618.1 Core Inlet Temperature (0F) 547.7 Initial Steam Generator Steam Pressure (psia) 888 Steam Generator Design Model F Steam Generator Tube Plugging (%) 0 (bounding)

Initial Steam Generator Secondary Side Mass (Ibm) 112850.0 Assumed Maximum Containment Backpressure (psia) 61.7*

Accumulator Water Volume (ft 3) per accumulator 850.0 N2 Cover Gas Pressure (psia) 592.2 Temperature (0F) 120 Safety Injection Delay, total (sec) (from beginning of event) 35.6 Notes:

• bounding assumption for mass and energy release calculation per Reference I l.

Core Thermal Power, RCS Total Flowrate. RCS Coolant Temperatures, and Steam Generator Secondary Side Mass include appropriate uncertainty and/or allowance.

WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-9 Table 5.1-2 System Parameters Initial Conditions for Salem Unit 2 Parameters Value Core Thermal Power (MWt) 3479.75 Reactor Coolant System Total Flowrate (Ibimsec) 34805.56 Vessel Outlet Temperature (0 F) 618.1 Core Inlet Temperature (OF) 547.7 Initial Steam Generator Steam Pressure (psia) 842 Steam Generator Design Model 51 Steam Generator Tube Plugging (%)0 Initial Steam Generator Secondary Side Mass (Ibm) 127041.0 Assumed Maximum Containment Backpressure (psia) 61.7*

Accumulator Water Volume (ft3) per accumulator 850 N2 Cover Gas Pressure (psia) 592.2 Temperature (OF) 120 Safety Injection Delay, total (sec) (from beginning of event) 35.6 Notes:

• bounding assumption for mass and energy release calculation per Reference 11.

Core Thermal Power, RCS Total Flowrate, RCS Coolant Temperatures, and Steam Generator Secondary Side Mass include appropriate uncertainty and/or allowance.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-10 Table 5.1-3 Safety Injection Flow Minimum Safeguards RCS Pressure (psig) I Total Flow (ft 3/sec)

Injection Mode (Reflood Phase) 0 10.92 20 10.37 40 9.79 47 9.57 60 9.16 80 8.47 100 7.70 120 6.78 140 5.56 160 3.30 180 1.95 200 1.93 RCS Pressure (psig) Total Flow (lbmrsec)

Recirculation Mode Without Recirculation Spray at 0 psig 1 427.32 WITH Recirculation Spray at 0 psig l 165.22 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-11 5.2 MASS AND ENERGY RELEASE DATA 5.2.1 Blowdown Mass and Energy Release Data The SATAN-VI code is used for computing the blowdown transient. The code utilizes the control volume (element or nodal) approach with the capability for modeling a large variety of plant specific thermal fluid system configurations. The fluid properties are considered uniform and thermodynamic equilibrium is assumed in each element. A point kinetics model is used with weighted feedback effects. The major feedback effects include moderator density, moderator temperature, and Doppler broadening. A critical flow calculation for subcooled (modified Zaloudek), two-phase (Moody), or superheated break flow is incorporated into the analysis. The methodology for the use of this model is described in Reference 11. A comparison of these two critical flow correlations is shown in Section m-l of Reference 12.

Table 5.2-1 presents the calculated mass and energy release for the blowdown phase of the DEPS break for Salem Unit 1. Table 5.2-2 presents the calculated mass and energy release for the blowdown phase of the DEPS break for Salem Unit 2. Break path I for the pump suction break in the mass and energy release tables refers to the mass and energy exiting from the steam generator side of the break. Break path 2 refers to the mass and energy exiting from the pump side of the break.

5.2.2 Reflood Mass and Energy Release Data The WREFLOOD code is used for computing the reflood transient. The WREFLOOD code consists of two basic hydraulic models - one for the contents of the reactor vessel and one for the coolant loops.

The two models are coupled through the interchange of the boundary conditions applied at the vessel outlet nozzles and at the top of the downcomer. Additional transient phenomena such as pumped safety injection and accumulators, reactor coolant pump performance, and steam generator release are included as auxiliary equations that interact with the basic models as required. The WREFLOOD code permits the capability to calculate variations during the core reflooding transient of basic parameters such as core flooding rate, core and downcomer water levels, fluid thermodynamic conditions (pressure, enthalpy, density) throughout the primary system, and mass flow rates through the primary system. The code permits hydraulic modeling of the two flow paths available for discharging steam and entrained water from the core to the break, i.e., the path through the broken loop and the path through the unbroken loops.

A complete thermal equilibrium mixing condition for the steam and ECCS injection water during the reflood phase has been assumed for each loop receiving ECCS water. This is consistent with the usage and application of the Reference 11 mass and energy release evaluation model in recent analyses, e.g.,

D. C. Cook Docket (Reference 13). Even though the Reference 11 model credits steamlwater mixing only in the intact loop and not in the broken loop, the justification, applicability, and initial NRC approval for using the mixing model in the broken loop has been documented (Reference 13). Moreover, this assumption is supported by test data and is further discussed below. Please note that the steam/water mixing inside the RCS is not impacted by the containment design.

The model assumes a complete mixing condition (i.e., thermal equilibrium) for the steam/water interaction. The complete mixing process, however, is made up of two distinct physical processes. The first is a two-phase interaction with condensation of steam by cold ECCS water. The second is a single-phase mixing of condensate and ECCS water. Since the steam release is the most important WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-12 influence to the containment pressure transient, the steam condensation part of the mixing process is the only part that need be considered. (Any spillage directly heats only the sump and not the atmosphere.)

The most applicable steam/water mixing test data have been reviewed for validation of the containment integrity reflood steam/water mixing model. This data was generated in 1/3-scale tests (Reference 14),

which are the largest scale data available and thus most clearly simulates the flow regimes and gravitational effects that would occur in a pressurized water reactor (PWR). These tests were designed specifically to study the steam/water interaction for PWR reflood conditions.

A group of 1/3-scale steam/water mixing tests discussed in Reference 14 corresponds directly to containment integrity reflood conditions. The injection flow rates for this group cover all phases and mixing conditions calculated during the reflood transient. The data from these tests were reviewed and discussed in detail in Reference 11. For all of these tests, the data clearly indicate the occurrence of very effective mixing with rapid steam condensation. The mixing model used in the containment integrity reflood calculation is, therefore, wholly supported by the 1/3-scale steam/water mixing data.

Additionally, the following justification is also noted. The post-blowdown limiting break for the containment integrity peak pressure analysis is the pump suction double-ended rupture break. For this break, there are two flow paths available in the RCS by which mass and energy may be released to containment. One is through the outlet of the steam generator, the other via reverse flow through the reactor coolant pump. Steam that is not condensed by ECCS injection in the intact RCS loops passes around the downcomer and through the broken loop cold leg and pump in venting to containment. This steam also encounters ECCS injection water as it passes through the broken loop cold leg, complete mixing occurs and a portion of it is condensed. It is this portion of steam that is condensed that is taken credit for in this analysis. This assumption is justified based upon the postulated break location, and the actual physical presence of the ECCS injection nozzle. A description of the test and test results are contained in References II and 13.

Tables 5.2-3 and 5.2-4 present the calculated mass and energy releases for the reflood phase of the pump suction double-ended rupture, minimum safeguards cases for Salem Unit I and Salem Unit 2, respectively.

The transient response of the principal parameters during reflood are given in Tables 5.2-5 and 5.2-6 for the DEPS cases.

5.2.3 Post-Reflood Mass and Energy Release Data The FROTH code (Reference 12) is used for computing the post-reflood transient. The FROTH code calculates the heat release rates resulting from a two-phase mixture present in the steam generator tubes.

The mass and energy releases that occur during this phase are typically superheated due to the depressurization and equilibration of the broken loop and intact loop steam generators. During this phase of the transient, the RCS has equilibrated with the containment pressure. However, the steam generators contain a secondary inventory at an enthalpy that is much higher than the primary side. Therefore, there is a significant amount of reverse heat transfer that occurs. Steam is produced in the core due to core decay heat. For a pump suction break, a two-phase fluid exits the core, flows through the hot legs, and becomes superheated as it passes through the steam generator. Once the broken loop cools, the break WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-13 flow becomes two phase. During the FROTH calculation, ECCS injection is addressed for both the injection phase and the recirculation phase. The FROTH code calculation stops when the secondary side equilibrates to the saturation temperature (Tsar) at the containment design pressure, after this point the EPITOME code completes the steam generator depressurization (see Subsection 5.2.5 for additional information).

The methodology for the use of this model is described in Reference 11. The mass and energy release rates are calculated by FROTH and EPITOME until the time of containment depressurization. After containment depressurization (14.7 psia), the mass and energy release available to containment is generated directly from core boil-off/decay heat.

Tables 5.2-7 and 5.2-8 present the two-phase post-reflood mass and energy release data for the pump suction double-ended break cases for Salem Unit I and Unit 2. Table 5.2-14 and Table 5.2-15 provide the variation in the Unit I and Unit 2 mass and energy releases when recirculation spray is modeled beginning at 4441.6 seconds into a large break LOCA with a diesel failure. The recirculation flow exiting the RHR heat exchanger (3200 gpm) splits with 1974.8 gpm diverted to spray and the remaining 1225.2 gpm going to the vessel to cool the core.

5.2.4 Decay Heat Model On November 2, 1978, the Nuclear Power Plant Standards Committee (NUPPSCO) of the ANS approved ANS Standard 5.1 (Reference 10) for the determination of decay heat. This standard was used in the mass and energy release model for Salem. Table 5.2-9 lists the decay heat curve used in the Salem Unit I and Unit 2 mass and energy release analysis.

Significant assumptions in the generation of the decay heat curve for use in the LOCA mass and energy releases analysis include the following:

1. The decay heat sources considered are fission product decay and heavy element decay of U-239 and Np-239.

2. The decay heat power from fissioning isotopes other than U-235 is assumed to be identical to that of U-235.

3. The fission rate is constant over the operating history of maximum power level.

4. The factor accounting for neutron capture in fission products has been taken from Reference 10.

5. The fuel has been assumed to be at full power for Ix 108 seconds.

6. The total recoverable energy associated with one fission has been assumed to be 200 MeV/fission.

7. Two sigma uncertainty (two times the standard deviation) has been applied to the fission product decay.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-14 Based upon NRC staff review, (Safety Evaluation Report [SERI of the March 1979 evaluation model

[Reference 111), use of the ANS Standard-5. 1, November 1979 decay heat model (Reference 10) was approved for the calculation of mass and energy releases to the containment following a LOCA.

5.2.5 Steam Generator Equilibration and Depressurization Steam generator equilibration and depressurization is the process by which secondary-side energy is removed from the steam generators in stages. The FROTH computer code calculates the heat removal from the secondary mass until the secondary temperature is the saturation temperature (Tsa,) at the containment design pressure. After the FROTH calculations, the EPITOME code continues the FROTH calculation for steam generator cooldown removing steam generator secondary energy at different rates (i.e., first- and second-stage rates). The first-stage rate is applied until the steam generator reaches T531 at the user specified intermediate equilibration pressure, when the secondary pressure is assumed to reach the actual containment pressure. Then the second-stage rate is used until the final depressurization, when the secondary reaches the reference temperature of T55, at 14.7 psia, or 21 20 F. The heat removal of the broken loop and intact loop steam generators are calculated separately.

During the FROTH calculations, steam generator heat removal rates are calculated using the secondary-side temperature, primary-side temperature and a secondary-side heat transfer coefficient determined using a modified McAdam's correlation. Steam generator energy is removed during the FROTH transient until the secondary-side temperature reaches saturation temperature at the containment design pressure. The constant heat removal rate used during the first heat removal stage is based on the final heat removal rate calculated by FROTH. The steam generator energy available to be released during the first stage interval is determined by calculating the difference in secondary energy available at the containment design pressure and that at the (lower) user-specified intermediate equilibration pressure, assuming saturated conditions. This energy is then divided by the first-stage energy removal rate, resulting in an intermediate equilibration time. At this time, the rate of energy release drops substantially to the second-stage rate. The second-stage rate is determined as the fraction of the difference in secondary energy available between the intermediate equilibration and final depressurization at 21 20F, and the time difference from the time of the intermediate equilibration to the user-specified time of the final depressurization at 212 0F. With current methodology, all of the secondary energy remaining after the intermediate equilibration is conservatively assumed to be released by imposing a mandatory cooldown and subsequent depressurization down to atmospheric pressure at 3600 seconds, i.e., 14.7 psia and 21 20F (the mass and energy balance tables have this point labeled as "Available Energy").

5.2.6 Sources of Mass and Energy The sources of mass considered in the LOCA mass and energy release analysis are given in Tables 5.2-10 and 5.2-11. These sources are the RCS, accumulators, and pumped safety injection.

The analysis used the following energy reference points:

• Available energy: 2120 F; 14.7 psia [energy that could be released] (as discussed in 5.2.5)

• Total energy content: 32 0 F; 14.7 psia [total internal energy of the RCS]

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-15 The energy inventories considered ih the LOCA mass and energy release analysis are given in Tables 5.2-12 and 5.2-13. The energy sources are the following.

• Reactor coolant system water

• Accumulator water (all four inject)

• Pumped safety injection water

• Decay heat

• Core-stored energy

• Reactor coolant system metal (includes steam generator tubes)

• Steam generator metal (includes transition cone, shell, wrapper, and other internals)

• Steam generator secondary energy (includes fluid mass and steam mass)

• Secondary transfer of energy (feedwater into and steam out of the steam generator secondary)

The mass and energy inventories are presented at the following times, as appropriate:

• Time zero (initial conditions)

• End of blowdown time

• End of refill time

• End of reflood time

• Time of broken loop steam generator equilibration to pressure setpoint

• Time of intact loop steam generator equilibration to pressure setpoint

• lime of full depressurization (3600 seconds)

In the mass and energy release data presented, no Zirc-water reaction heat was considered because the cladding temperature does not rise high enough for the rate of the Zirc-water reaction heat to proceed.

The sequence of events for each LOCA transient is shown in Table 6.3-1 and Table 6.3-2 of Section 6.3.

5.3 CONCLUSION

S The consideration of the various energy sources listed in Section 5.2.6 for the long-term mass and energy release analysis provides assurance that all available sources of energy have been included in this analysis. By addressing all available sources of energy as well as the limiting break size and location and the specific modeling of each phase of the long term LOCA transient, the review guidelines presented in Standard Review Plan Section 6.2.1.3 have been satisfied. The results of this analysis were provided for use in the containment response analysis documented in Section 6.3.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 20004031504

5-16 Table 5.2-1 Unit 1 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC

.00000 .0 .0 .0 .0

.00111 85650.6 46265.2 40440.7 21798.7

.101 40197.5 21734.4 21025.9 11328.2

.202 40835.4 22228.9 22904.7 12348.3

.302 41643.7 22877.3 23142.8 12487.1

.402 42545.4 23638.3 22826.5 12329.7

.502 43403.3 24424.4 22202.3 12002.3

.602 43853.2 24994.0 21551.5 11657.5

.702 43668.4 25177.7 21018.9 11374.1

.801 42739.5 24894.4 20548.3 11122.3

.902 41534.4 24427.3 20189.5 10930.2 1.00 40377.0 23966.7 19961.0 10809.0 1.10 39258.8 23523.5 19826.3 10737.9 1.20 38109.0 23064.4 19755.9 10701.1 1.30 36919.2 22576.3 19727.4 10686.3 1.40 35737.0 22074.9 19731.9 10688.9 1.50 34705.4 21636.8 19751.6 10699.5 1.60 33840.5 21277.9 19782.1 10715.8 1.70 33070.9 20966.8 19811.7 10731.7 1.80 32324.7 20664.7 19822.7 10737 .5 1.90 31583.4 20356.7 19799.6 10724.8 2.00 30790.6 20007.7 19762.0 10704.6 2.10 30068.0 19695.7 19712.5 10678.2 2.20 29333.4 19365.7 19533.5 10581.2 2.30 28571.7 19007.4 19294.6 10452.5 2.40 27772.0 18614.6 19126.0 10362.2 2.50 26847.6 18125 1 189'75.6 10281.8 2.60 25592.8 17393.4 18820.5 10199.0 2.70 23756.7 16237.3 18650.7 10108.4 2.80 21537.6 14793.1 18460.3 10006.7 2.90 20776.8 14359.5 18258.6 9899.0 3.00 20866.4 14477.6 18054.1 9789.8 3.10 20033.5 13914.4 17861.4 9687.2 3.20 19601.3 13641.3 17669.8 9585.3 3.30 19278.3 13431.8 17468.0 9477.8 3.40 18636.7 12993.0 17257.4 9365.4 3.50 18128.9 12652.5 17064.0 9262.6 3.60 17643.3 12322.1 16890 .9 9170.9 3.70 17159.6 11987.9 16719.2 9079.9 3.80 16663.7 11643.7 16541.6 8985.6 3.90 16162.5 11297.3 16372.9 8896.3 4.00 15712.1 10988.0 16223.9 8817.7 4.20 14969.4 10472.6 15939.5 8667.7 4.40 14322.9 10018.3 15666.4 8523.7 4.60 13830.2 9667.7 15420.8 8394.5 4.80 13412.8 9360.5 15178.9 8267.1 5.00 13086.1 9113.1 14959.2 8151.7 5.20 12812.6 8896.0 14740.0 8036.6 5.40 12608.4 8721.5 14538.9 7931.2 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-17 Table 5.2-1 Unit 1 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases (cont.)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/JSEC LBM/SEC BTU/SEC 5.60 12450.6 8573.2 14333.6 7823.5 5.80 12358.4 8465.7 14130.6 7717.1 6.00 12316.1 8384.8 13927.0 7610.4 6.20 13317.6 9013.7 13454.7 7355.9 6.40 12396.6 8335.4 13348.4 7303.8 6.60 11373.7 8022.1 13190.1 7221.8 6.80 9740.8 7371.7 14645.6 8026.2 7.00 9288.9 7099.8 14464.3 7930.9 7.20 9444.5 7114.1 14409.5 7907.2 7.40 9641.4 7149.2 14193.3 7793.7 7.60 9823.3 7194.1 14031.0 7710.6 7.80 9941.2 7205.5 13790.9 7583.8 8.00 9985.3 7176.4 13579.2 7471.9 8.20 9999.9 7141.9 13402.5 7377.9 8.40 9916.3 7052.8 13217.7 7277.6 8.60 9699.0 6893.3 13110.1 7219.4 8.80 9427.9 6726.6 13059.1 7190.7 9.00 9142.9 6578.0 12936.4 7120.2 9.20 8867.7 6449.7 12798.1 7041.2 9.40 8612.8 6333.0 12687.7 6978.9 9.60 8399.6 6232.1 12570.5 6913.1 9.80 8217.8 6131.9 12430.9 6834.8 10.0 8082.2 6043.2 12290.7 6756.4 10.2 7972.1 5957.7 12158.6 6682.9 10.4 7873.0 5873.5 12026.9 6609.5 10.6 7777.2 5791.0 11892.1 6534.1 10.8 7681.1 5711.5 11762.5 6461.8 11.0 7579.9 5633.7 11636.3 6391.4 11.2 7472.7 5558.1 11509.1 6320.4 11.4 7361.7 5485.7 11383.4 6250.4 11.6 7246.2 5415.3 11258.9 6181.2 11.8 7127.0 5347.0 11133.8 6111.8 12.0 7004.5 5280.5 11008.2 6042.2 12.2 6880.2 5216.6 10883.6 5973.4 12.4 6752.4 5153.8 10759.4 5904.9 12.6 6623.4 5094.9 10634.6 5836.3 12.8 6492.4 5037.9 10507.8 5766.7 13.0 6361.9 4981.8 10381.8 5697.6 13.2 6234.9 4926.3 10253.4 5627.4 13.4 6111.0 4871.9 10126.8 5558.1 13.6 5989.8 4819.0 9999.3 5488.4 13.8 5870.4 4767.2 9873.2 5419.5 14.0 5752.8 4717.0 9746.2 5350.1 14.2 5636.9 4667.1 9621.5 5282.1 14.4 5523.7 4618.0 9495.4 5213.4 14.6 5413.7 4570.4 9372.4 5146.4 14.8 5305.4 4524.3 9247.7 5078.7 15.0 5199.1 4479.2 9125.2 5012.2 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2W000031504

5-18 Table 5.2-1 Unit 1 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases (cont.)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 15.2 5094.2 4435.5 9002.2 4945.5 15.4 4988.6 4391.4 8878.1 4878.4 15.6 4876.1 4344.1 8742.7 4805.3 15.8 4758.0 4290.0 8606.9 4732.8 16.0 4642.2 4232.2 8474.4 4662.2 16.2 4530.5 4174.1 8335.9 4588.1 16.4 4420.1 4113.9 8192.2 4511.2 16.6 4313.7 4055.8 7919.2 4362.4 16.8 4213.7 4001.6 7801.7 4292.3 17.0 4109.1 3950.0 7608.5 4154.0 17.2 4000.1 3894.0 7436.7 4003.4 17.4 3893.5 3848.3 7513.3 3969.7 17.6 3778.3 3800.8 7286.7 3772.1 17.8 3665.6 3767.3 7444.3 3771.5 18.0 3492.9 3692.0 6763.0 3361.8 18.2 3288.2 3597.6 6376.4 3085.8 18.4 3056.6 3473.9 6009.6 2842.7 18.6 2840.7 3331.0 5591.6 2584.0 18.8 2693.6 3235.6 5287.8 2386.7 19.0 2481.3 3022.2 4973.5 2197.8 19.2 2324.3 2852.1 4719.7 2043.6 19.4 2188.3 2697.9 4530.8 1924.8 19.6 2071.6 2562.5 4282.4 1786.7 19.8 1955.6 2425.4 4080.2 1669.6 20.0 1847.5 2296.6 4028.0 1614.6 20.2 1726.3 2150 0 5672.2 2233.5 20.4 1565.5 1953.7 7168.5 2833.2 20.6 1456.8 1822.9 5132.6 2045.4 20.8 1381.4 1731.4 4200.5 1684.6 21.0 1318.1 1654.2 2941.6 1179.1 21.2 1240.5 1558.3 2227.0 866.3 21.4 1154.4 1452.1 3310.0 1162.3 21.6 1076.8 1355.9 5459.1 1838.2 21.8 989.4 1247.5 5504.7 1826.8 22.0 909.7 1148.8 4712.0 1554.3 22.2 833.7 1053.8 4128.7 1353.4 22 4 766.6 969.9 3677.0 1193.2 22.6 704.1 891.5 3412.0 1089.8 22.8 638.8 809.3 3190.1 998.7 23.0 585.0 741.8 2918.4 895.2 23.2 521.8 662.0 2652.1 797.9 23.4 496 .7 630.7 2364.0 698.1 23.6 465.5 591.3 2054.8 596.2 23.8 434.0 551.5 1707.7 487.5 24.0 398.4 506.5 1314.2 369.9 24.2 358.5 456.1 872.7 243.1 24.4 316.6 402.9 434.0 120.2 24.6 273.8 348.6 110.7 30.6 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-19 Table 5.2-1 Unit 1 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases (cont.)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 24.8 230.6 293.7 .0 .0 25.0 189.0 240.9 .0 .0 25.2 143.3 182.9 .0 .0 25.4 96.3 123.0 135.5 38.0 25.6 54.1 69.2 122.4 34.3 25.8 15.4 19.8 98.1 27.6 26.0 .0 .0 65.0 18.3 26.2 .0 .0 .0 .0 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-20 Table 5.2-2 Unit 2 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC

.00000 .0 .0 .0 .0

.00111 87155.8 47083.7 40441.1 21798.9

.101 40172.8 21718.5 21070.4 11352.2

.201 40815.6 22204.2 22973.4 12385.1

.302 41645.9 22845.2 23181.1 12507.9

.402 43718.0 24219.2 22860.6 12348.4

.501 43542.2 24394.1 22216.8 12010.5

.601 43920.3 24897.1 21558.1 11661.2

.701 44174.3 25320.3 21020.5 11375.0

.802 43870.1 25405.5 20541.2 11118.6

.902 42977.4 25118.5 20185.2 10927.9 1.00 41918.1 24715.1 19954.8 10805.6 1.10 40862.6 24302.0 19819.0 10733.8 1.20 39833.2 23898.7 19747.4 10696.4 1.30 38792.7 23488.6 19718.1 10681.2 1.40 37720.0 23054.9 19723.0 10684.1 1.50 36637.8 22603.6 19745.9 10696.4 1.60 35618.9 22171.6 19782.1 10715.9 1.70 34727.8 21800.6 19816.1 10734.4 1.80 33913.9 21464.4 19830.8 10742.3 1.90 33114.6 21129.4 19812.2 10732.1 2.00 32318.3 20791.6 19781.7 10715.9 2.10 31476.2 20417.1 19740.3 10694.1 2.20 30716.3 20088.6 19563.5 10598.3 2.30 29920.3 19723.5 19331.6 10473.4 2.40 29077.8 19316.3 19166.7 10385.1 2.50 28234.7 1889fl7 19019.5 10306.5 2.60 27389.8 18460.2 18871.0 10227.2 2.70 26291.5 17836.0 18702.3 10137.1 2.80 24749.5 16885.5 18511.6 10035.2 2.90 22255.1 15251.8 18315.1 9930.2 3.00 20607.4 14204.9 18120.8 9826.5 3.10 20775.3 14405.1 17933.6 9726.8 3.20 20371.6 14149.2 17744.7 9626.1 3.30 19514.8 13569.0 17549.1 9521.8 3.40 19154.2 13344.6 17349.1 9415.1 3.50 18740.2 13069.3 17149.4 9308.5 3.60 18218.0 12712.0 16969.8 9213.0 3.70 17800.2 12426.6 16798.6 9122.0 3.80 17368.9 12127.1 16625.7 9030.1 3.90 16909.8 11806.6 16451.8 8937.5 4.00 16474.4 11503.8 16292.0 8852.6 4.20 15725.5 10979.4 16001.7 8698.9 4.40 15054.6 10503.1 15717.1 8547.9 4.60 14499.6 10106.5 15463.5 8413.8 4.80 14062.9 9784.1 15215.8 8282.6 5.00 13682.2 9496.5 14981.4 8158.5 5.20 13400.3 9273.4 14762.0 8042.6 5.40 13161.2 9072.3 14542.0 7926.1 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-21 Table 5.2-2 Unit 2 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases (cont.)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 5.60 12996.3 8918.3 14340.9 7820.0 5.80 12886.1 8795.2 14114.8 7700.2 6.00 12831.6 8705.2 13887.0 7579.5 6.20 13839.7 9332.2 13411.3 7323.2 6.40 12813.8 8578.5 13308.8 7271.6 6.60 11890.4 8237.8 13603.1 7442.4 6.80 10288.2 7613.9 14649.6 8013.4 7.00 9549.6 7235.0 14395.2 7877.8 7.20 9605.7 7203.9 14337.3 7850.9 7.40 9859.1 7272.9 14139.3 7746.4 7.60 10146.4 7372.7 13959.9 7652.8 7.80 10422.7 7473.3 13749.2 7541.5 8.00 10641.1 7539.7 13523.2 7421.0 8.20 10802.4 7577.5 13325.2 7315.0 8.40 10844.9 7547.2 13192.1 7243.9 8.60 10645.0 7373.2 13128.5 7209.6 8.80 10315.1 7145.3 13015.9 7146.1 9.00 9972.0 6932.1 12878.3 7068.1 9.20 9605.4 6717.6 12776.6 7010.6 9.40 9328.5 6582.6 12681.4 6956.9 9.60 9098.0 6482.9 12556.7 6886.9 9.80 8863.8 6362.6 12422.4 6812.1 10.0 8696.3 6269.8 12297.4 6743.1 10.2 8551.0 6180.6 12173.0 6674.5 10.2 8550.1 6180.0 12172.3 6674.1 10.4 8399.4 6082.3 12046.3 6604.1 10.6 8253.5 5990.2 11911.9 6529.5 10.8 8104.6 5897.4 11787.4 6460.6 11.0 7953.4 5807.1 11667.2 6393.8 11.2 7803.6 5722.1 11539.9 6323.1 11.4 7654.7 5640.0 11415.5 6254.1 11.6 7510.5 5562.1 11291.8. 6185.6 11.8 7369.9 5486.4 11166.2 6116.0 12.0 7233.3 5413.1 11040.4 6046.4 12.2 7100.3 5342.4 10915.6 5977.5 12.4 6967.7 5272.0 10790.3 5908.3 12.6 6838.7 5205.4 10668.5 5841.2 12.8 6710.3 5141.2 10541.9 5771.5 13.0 6582.9 5077.0 10418.5 5703.8 13.2 6458.9 5013.3 10293.8 5635.3 13.4 6339.2 4950.8 10170.6 5567.7 13.6 6222.9 4889.7 10047.4 5500.1 13.8 6109.4 4830.4 9926.2 5433.7 14.0 5998.4 4771.8 9805.3 5367.4 14.2 5889.6 4714.1 9686.4 5302.3 14.4 5783.2 4657.6 9568.2 5237.6 14.6 5679.1 4602.1 9451.8 5174.0 14.8 5577.3 4547.8 9335.9 5110.7 WCAP-16193-NP March 2004 Official ricord stored electronically in EDMS 2000-031504

5-22 Table 5.2-2 Unit 2 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases (cont.)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 15.0 5477. 9 4494.7 9221.8 5048.5 15.2 5380 .9 4443.7 9108.9 4987.1 15.4 5282. 7 4391.7 8994.7 4924.9 15.6 5177.4 4334.4 8866.5 4855.3 15.8 5064. 8 4270.2 8739.7 4787.0 16.0 4950 .6 4199.5 8615.6 4720.6 16.2 4841.8 4125.6 8487.1 4651.6 16.4 4740.1 4051.9 8363.2 4585.2 16.6 4641.9 3977.9 8236.1 4517.2 16.8 4547.2 3905.0 8060.6 4421.9 17.0 4461.2 3837.6 7918.4 4345.0 17.2 4380.6 3774.0 7673.2 4191.5 17.4 4308 .5 3721.8 7804.5 4225.8 17.6 4234. 7 3672.0 7386.6 3944.1 17.8 4164.2 3631.0 7958.3 4187.8 18.0 4085.6 3591.2 7133.8 3687.6 18.2 4006.4 3559.3 8622.0 4402.9 18.4 3909. 7 3523.1 6428.3 3245.2 18.6 3829.3 3509.0 9368.6 4636.0 18.8 3698.7 3460.1 12134.1 6113.5 19.0 3531.0 3400.5 11373.1 5781.2 19.2 3477 . 8 3463.6 4787.5 2412.1 19.4 3359.6 3451.6 11705.6 5658.1 19.6 3096.6 3333.0 9570.5 4755.8 19.8 2897.8 3276.8 4288.9 2121.9 20.0 2691.1 3157.3 4947.9 2240.9 20.2 2520.0 3041.6 4771.9 2111.4 20.4 2317.5 2832.3 4606.5 2000.7 20.6 2168.7 2666.3 4308.7 1836.5 20.8 2024 .9 2499.2 4021.5 1674.8 21.0 1898 .5 2350.1 3792.3 1538 .8 21.2 1782.2 2211.3 3559.4 1411.4 21.4 1670 .0 2076.0 3497.9 1357.7 21.6 1564.7 1948.8 3566.5 1357.6 21.8 1459 .7 1820.9 3650.2 1367.9 22.0 1363 .5 1703.7 3644.2 1348.1 22.2 1269. 5 1588.5 3618.5 1320.5 22.4 1183. 8 1483.3 3777.1 1352.1 22.6 1093.4 1371.4 4044.1 1413.1 22.8 1008 .7 1267.4 4291.7 1461.3 23.0 920 . 3 1157.8 4109.0 1372.2 23.2 838.4 1055.8 3924.3 1289.7 23.4 759.5 957.3 3731.5 1207.9 23.6 683 . 9 862.6 3510.4 1119.5 23.8 603 .7 762.0 3241.1 1017.7 24.0 527.3 666.2 2923.7 903.5 24.2 459. 0 580.3 2633.9 801.0 24.4 400.8 507.0 2333.2 698.3 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-23 Table 5.2-2 Unit 2 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases (cont.)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 24.6 362.7 459.2 2017.2 594.4 24.8 316.8 401.2 1679.8 487.9 25.0 281.5 356.7 1324.4 379.9 25.2 255.7 324.2 933.7 265.2 25.4 227.0 288.0 510.1 144.0 25.6 195.0 247.5 109.5 30.9 25.8 160.7 204.1 .0 .0 26.0 121.8 154.9 .0 .0 26.2 76.4 97.3 .0 .0 26.4 20.0 25.5 .0 .0 26.6 .0 .0 .0 .0 March 2004 WCAP-16193-NP WCAP-l6193-NP March 2004 Officia record sore e nic~y inEDMS 200004315

5-24 Table 5.2-3 Unit I Double-Ended Pump Suction Break Reflood Mass and Energy Releases (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 26.2 .0 .0 .0 0 26.7 .0 .0 .0 .0 26.9 .0 .0 .0 .0 27.0 .0 .0 0 0 27.1 .0 .0 0 0 27.2 .0 .0 .0 0 27.2 .0 .0 .0 0 27.3 36.8 43.3 .0 0 27.4 15.4 18.2 0 0 27.5 15.0 17.7 0 0 27.6 20.9 24.6 0 .0 27.7 27.6 32.5 .0 .0 27.8 32.0 37.7 .0 0 27.9 36.0 42.4 0 0 28.1 40.5 47.7 0 0 28.2 45.0 53.0 .0 0 28.3 48.0 56.6 .0 0 28.4 51.1 60.2 .0 .0 28.5 54.1 63.7 .0 .0 28.6 56.9 67.0 .0 0 28.6 58.3 68.7 .0 0 28.7 59.6 70.3 .0 0 28.8 62.3 73.4 .0 0 28.9 64.8 76.4 .0 .0 29.0 67.3 79.3 .0 .0 29.1 69.8 82. 2 .0 0 29.2 72.1 85.0 .0 0 29.3 74.4 87.7 .0 0 30.3 94.8 111.7 .0 0 31.3 111.9 131.9 0

.0 32.3 126.8 149.5 .0

.0 33.3 140.1 165.3 .0 33.7 148.3 175.0 14.4 2.0 34.3 303.6 359.1 3053 .2 439.5 35.3 406.4 481.6 4210 .5 637.4 36.3 441.0 522.9 4580.5 672 .9 37.3 434.7 515.4 47.0 4520.5 666.1 38.3 428.2 507.6 4458.0 658.7 38.4 427.5 506.9 4451.7 657.9 39.3 421.8 500.0 43 95. 6 651.2 40.3 415.5 492.5 4334.2 643.7 41.3 409.5 485.3 4274 .0 636.4 42.3 403.6 478.2 4215. 2 629.3 43.3 397.9 471.5 4158. 0 622.3 43.9 394.6 467.5 4124.4 618.2 44.3 392.4 464.9 4102.3 615.5 45.3 387.1 458.6 4048. 2 608.9 46.3 382.0 452.5 3995. 5 602.5 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-25 Table 5.2-3 Unit 1 Double-Ended Pump Suction Break Renood Mass and Energy Releases (cont.) (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 47.3 377.1 446.6 3944.3 596.3 48.3 372.3 440.9 3894.4 590.2 49.3 367.7 435.4 3845.9 584.3 50.2 363.6 430.6 3803.4 579.1 50.3 363.2 430.0 3798.7 578.5 51.3 358.9 424.9 3752.8 572.9 52.3 354.7 419.9 3708.0 567.4 53.3 350.6 415.0 3664.3 562.1 54.4 288.1 340.7 2937.9 481.5 55.4 285.2 337.2 2902.6 477.4 56.4 390.0 461.8 313.4 217.8 57.2 408.7 484.4 321.6 229.7 57.4 407.7 483.2 321.1 229.1 58.4 401.0 475.1 318.0 224.9 59.4 394.1 467.0 314.8 220.6 60.4 387.5 459.0 311.7 216.5 61.4 381.0 451.2 308.7 212.5 62.4 374.6 443.6 305.7 208.5 63.4 368.1 435.9 302.7 204.6 64.4 362.1 428.8 300.0 200.9 65.4 356.5 422.0 297.4 197.5 66.4 351.0 415.4 294.8 194.1 67.4 345.6 409.0 292.4 190.8 68.4 340.3 402.7 290.0 187.7 69.4 335.2 396.6 287.6 184.6 70.4 330.2 39^.7 285.3 181.6 71.4 325.3 384.9 283.1 178.6 72.4 320.5 379.2 280.9 175.8 73.4 315.9 373.7 278.8 173.0 74.4 311.3 368.3 276.8 170.3 75.4 306.9 363.0 274.8 167.7 76.4 302.6 357.9 272.8 165.1 77.4 298.4 352.8 270.9 162.7 78.4 294.3 348.0 269.1 160.3 79.4 290.3 343.2 267.3 157.9 80.4 286.4 338.6 265.6 155.7 81.4 282.6 334.1 263.8 153.5 82.4 278.9 329.7 262.2 151.3 83.4 275.4 325.5 260.6 149.3 84.4 271.9 321.3 259.0 147.2 85.4 268.5 317.3 257.5 145.3 86.4 265.2 313.4 256.1 143.4 87.4 262.0 309.6 254.6 141.6 88.7 258.0 304.8 252.9 139.3 89.4 255.9 302.3 251.9 138.1 91.4 250.1 295.5 249.4 134.8 93.4 244.7 289.0 247.0 131.8 95.4 239.5 282.9 244.7 128.9 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-26 Table 5.2-3 Unit 1 Double-Ended Pump Suction Break Reflood Mass and Energy Releases (contL) (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 97.4 234.7 277.2 242 .6 126.2 99.4 230.2 271.9 240.7 123.7 101.4 226.0 266.8 238.8 121.3 103.4 222.0 262.1 237.1 119.2 105.4 218.3 257.7 235.5 117.1 107.4 214.8 253.6 234. 0 115.2 109.4 211.6 249.8 232. 6 113.5 109.5 211.4 249.6 232. 6 113.4 111.4 208.5 246.2 231.4 111.8 113.4 205.7 242.9 230.2 110.3 115.4 203.1 239.8 229.1 108.9 117.4 200.7 236.9 228.0 107.6 119.4 198.5 234.3 227.1 106.4 121.4 196.4 231.8 226.2 105. 3 123.4 194.5 229.6 225.4 104.2 125.4 192.8 227.5 224. 6 103.3 127.4 191.2 225.6 224. 0 102.4 129.4 189.7 223. 9 223 .3 101.6 131.4 188.3 222.3 222 .8 100.9 133.4 187.1 220.8 222.2 100.2 133.5 187.1 220.8 222 .2 100.2 135.4 186.0 219.5 221.8 99.6 137.4 185.0 218.3 221 . 3 99.1 139.4 184.1 217.3 220. 9 98.6 141.4 183.3 216.3 220. 6 98.1 143.4 182.6 215.4 220.3 97.7 145.4 181.9 214.7 220.0 97.4 147.4 181.3 214.0 219.7 97.1 149.4 180.8 213.4 219.5 96.8 151.4 180.4 212.9 219.3 96.5 153.4 180.0 212.4 219. 1 96. 3 155.4 179.7 212.0 218. 9 96. 1 157.4 179.4 211.6 218 .8 95.9 159.4 179.1 211.4 218. 7 95.7 159.7 179.1 211.3 218.7 95. 7 161.4 178.9 211.1 218 .6 95.6 163.4 178.8 210.9 218 .5 95.5 165.4 178.7 210.8 218.4 95.4 167.4 178.6 210.7 218.4 95.4 169.4 178.5 210.7 218.3 95.3 171.4 178.5 210.6 218.3 95.3 173.4 178.8 210.9 218.4 95.4 175.4 179.5 211.8 219.4 95. 8 177.4 180.4 212.9 221.4 96.4 179.4 181.6 214.3 224.2 97.2 181.4 182.8 215.8 227 .7 98.2 183.4 184.1 217.3 231.6 99.2 185.4 185.4 218.8 235.7 100.2 187.3 186.4 220.0 239. 8 101.1 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-27 Table 5.2-4 Unit 2 Double-Ended Pump Suction Break Reflood Mass and Energy Releases li (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 26.6 .0 .0 .0 .0 27.2 .0 .0 .0 .0 27.3 .0 .0 .0 .0 27.4 .0 .0 .0 .0 27.5 .0 .0 .0 .0 27.6 .0 .0 .0 .0 27.6 .0 .0 .0 .0 27.7 45.4 53.4 .0 .0 27.8 17.4 20.5 .0 .0 27.9 12.9 15.2 .0 .0 28.0 14.6 17.2 .0 .0 28.1 25.3 29.9 .0 .0 28.2 29.9 35.2 .0 .0 28.3 34.1 40.1 .0 .0 28.4 38.9 45.9 .0 .0 28.5 41.3 48.7 .0 .0 28.6 45.6 53.8 .0 .0 28.7 48.8 57.5 .0 .0 28.8 51.9 61.1 .0 .0 28.9 54.8 64.6 .0 .0 29.0 57.6 67.9 .0 .0 29.1 58.3 68.7 .0 .0 29.1 60.3 71.1 .0 .0 29.2 63.0 74.2 .0 .0 29.3 65.5 77.2 .0 .0 29.4 68.0 80. 1 .0 .0 29.5 70.4 82.9 .0 .0 29.6 72.7 85.7 .0 .0 30.6 93.4 110.0 .0 .0 31.6 110.6 130.4 .0 .0 32.6 125.7 148.2 .0 .0 33.6 139.1 164.1 .0 .0 34.2 146.0 172.2 .0 .0 34.6 153.9 181.5 225.1 31.4 35.7 419.5 496.7 4367.1 590.5 36.7 435.8 516.6 4418.1 655.3 37.7 430.8 510.6 4371.0 650.7 38.7 424.8 503.5 4314.1 644.0 39.0 423.0 501.4 4296.9 642.0 39.7 418.9 496.4 4256.7 637.1 40.7 413.0 489.4 4199.8 630.3 41.7 407.3 482.6 4143.8 623.5 42.7 401.8 47Z.0 4089.0 616.8 43.7 396.5 469.6 4035.5 610.3 44.5 392.3 464.6 3993.7 605.1 44.7 391.3 463.4 3983.4 603.9 45.7 386.3 457.4 3932.6 597.7 46.7 381.4 451.6 3883.1 591.6 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-28 Table 5.2-4 Unit 2 Double-Ended Pump Suction Break Reflood Mass and Energy Releases (cont.) (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 47.7 376.7 446.0 3834.9 585.7 48.7 372.2 440.6 3788.0 579.9 49.7 367.8 435.4 3742.3 574.3 50.7 363.5 430.3 3697.8 568.9 50.9 362.7 429.3 3689.0 567.8 51.7 359.4 425.4 3654.4 563.6 52.7 355.4 420.6 3612.1 558.4 53.7 351.5 416.0 3570.8 553.3 54.7 347.7 411.5 3530.6 548.3 55.8 286.6 338.8 2821.9 469.8 56.8 283.9 335.6 2790.6 465.9 57.8 387.9 459.2 308.5 210.7 58.0 411.7 487.8 318.8 225.3 58.8 424.3 502 .9 324.2 233.1 59.8 417.3 494.5 320.9 228.8 60.8 409.9 485.6 317.6 224.3 61.8 402.6 477.0 314.3 219.9 62.8 395.6 468.6 311.0 215.6 63.8 388.6 460.2 307.9 211.4 64.8 381.6 451.8 304.7 207.1 65.8 375.2 444.3 301.8 203.3 66.8 369.1 436.9 299.0 199.6 67.8 363.0 429.8 296.3 196.0 68.8 357.2 422.8 293.7 192.5 69.8 351.5 415.9 291.1 189.1 70.8 345.9 409.3 28R .6 185.8 71.7 340.9 403.4 286.4 182.9 71.8 340.4 402 .8 286.1 182.6 72.8 335.1 396.4 283. 8 179.5 73.8 329.9 390.3 281.4 176.5 74.8 324.8 384 .2 279.2 173.5 75.8 319.9 378.4 277.0 170.6 76.8 315.1 372.. 6 274.9 167.8 77.8 310.4 367.0 272.8 165.1 78.8 305.8 361. 6 270.8 162.5 79.8 301.4 356. 3 268.8 159.9 80.8 297.0 351.2 266.9 157. 5 81.8 292.8 346.1 265.1 155.1 82.8 288.7 341.2 263 .3 152.7 83.8 284.7 336.5 261.5 150.5 84.8 280.8 331. 9 259.8 148.3 85.8 277.1 327.4 258.2 146.2 86.8 273.4 323.1 256.6 144. 1 87.8 269.8 318.8 255.1 142.1 88.6 267.1 315.6 253.9 140 .6 89.8 263.0 310.8 252. 1 138.3 91.8 256.6 303.2 249.4 134.8 93.8 250.6 296.0 246.8 131.5 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-29 Table 5.24 Unit 2 Double-Ended Pump Suction Break Reflood Mass and Energy Releases (cont.) (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC' BTU/SEC LBM/SEC BTU/SEC 95.8 244.9 289.3 244.4 128.4 97.8 239.6 283.0 242.1 125.5 99.8 234.6 277.1 240.0 122.8 101.8 230.0 271.6 238.0 120.3 103.8 225.6 266.4 236.2 118.0 105.8 221.6 261.6 234.5 115.8 107.8 217.8 257.1 232.9 113.8 109.0 215.6 254.6 232.0 112.7 109.8 214.3 252.9 231.5 111.9 111.8 211.0 249.0 230.1 110.2 113.8 207.9 245.4 228.8 108.6 115.8 205.1 242.1 227.7 107.1 117.8 202.5 239.0 226.6 105.8 119.8 200.1 236.2 225.6 104.5 121.8 197.9 233.6 224.7 103.4 123.8 195.9 231.2 223.9 102.3 125.8 194.0 229.0 223.1 101.3 127.8 192.3 226.9 222.4 100.4 129.8 190.8 225.1 221.7 99.6 131.8 189.3 223.4 221.2 98.9 132.7 188.8 222.7 220.9 98.6 133.8 188.1 221.9 220.6 98.2 135.8 186.9 220.5 220.1 97.6 137.8 185.9 219.3 219.7 97.1 139.8 184.9 218.2 219.3 96.6 141.8 184.1 217.2 219.0 96.1 143.8 183.3 216.3 218.6 95.7 145.8 182.7 215.5 218.4 95.3 147.8 182. 1 214.8 218.1 95.0 149.8 181.6 214.2 217.9 94.7 151.8 181.1 213.7 217.7 94.5 153.8 180.7 213.2 217.5 94.3 155.8 180.4 212.8 217.4 94.1 157.8 180.1 212.5 217.2 93.9 158.8 180.0 212.4 217.2 93.8 159.8 179.9 212.2 217.1 93.8 161.8 179.7 212.0 217.0 93.6 163.8 179.6 211.8 216.9 93.5 165.8 179.5 211.7 216.9 93.5 167.8 179.4 211.7 216.8 93.4 169.8 179.4 211.6 216.8 93.4 171.8 179.4 211.6 216.8 93.3 173.8 179.4 211.7 216.8 93.3 175.8 179.5 211.7 216.8 93.3 177.8 179.8 212.2 216.9 93.5 179.8 180.7 213.2 218.1 94.0 181.8 181.7 214.4 220.2 94.6 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-30 Table 5.24 Unit 2 Double-Ended Pump Suction Break Reflood Mass and Energy Releases (cont.) (Minimum Safeguards)

TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 183.8 182.9 215.9 223.1 95.5 185.8 184.3 217.5 226.7 96.5 186.4 184.7 217.9 227.8 96.8

-- j WCAP-16193-NP March 2004 Official iecord stored electronically in EDMS 2000-031504

I -- f fr- - - I> . r-r rl ru r- r-5-31 Table 5.2-5 Unit 1 Double-Ended Pump Suction Break Principle Parameters During Reflood (Minimum Safeguards)

TIME FLOODING CARRYOVER CORE DOWNCOMER FLOW INJECTION TEMP RJ WETE FRACTION HEIGHT HEIGHT FRACTION TOTAL ACCUMULATOR SPILL ENTHALPY SECONDS DEGREE F IN/SEC FT FT (POUNDS MASS PER SECOND) BTU/LBM 26.2 183.6 .000 .000 .00 .00 .250 .0 .0 .0 .00 26.9 182.1 20.934 .000 .50 1.16 .000 6835.6 6835.6 .0 89.48 27.2 180.6 24.747 .000 1.09 1.23 .000 6775.7 6775.7 .0 89.48 27.5 180.2 2.715 .111 1.32 1.84 .198 6688.5 6688.5 .0 89.48 27.6 180.2 2.815 .130 1.34 2.06 .226 6669.6 6669.6 .0 89.48 28.6 180.4 2.360 .301 1.50 4.26 .321 6483.1 6483.1 .0 89.48 29.3 180.6 2.287 .380 1.58 5.72 .335 6371.8 6371.8 .0 89.48 33.7 181.9 2.565 .618 2.00 15.18 .364 5723.1 5723.1 .0 89.48 36.3 182.6 4.293 .684 2.29 16.12 .587 5382.1 4849.2 .0 87.35 37.3 182.9 4.169 .696 2.40 16.12 .585 5289.4 4754.9 .0 87.31 38.4 183.2 4.058 .706 2.51 16.12 .583 5194.0 4657.7 .0 87.26 43.9 185.4 3.692 .728 3.00 16.12 .574 4783.0 4238.3 .0 87.03 50.2 188.4 3.428 .737 3.50 16.12 .563 4403.7 3851.3 .0 86.79 55.4 191.1 2.919 .738 3.87 16.12 .518 3384.9 2814.7 .0 85.86 56.4 191.7 3.577 .742 3.94 16.07 .586 547.8 .0 .0 68.00 57.2 192.2 3.658 .742 4.00 15.95 .589 540.1 .0 .0 68.00 64.4 197.1 3.278 .743 4.53 14.98 .581 551.1 .0 .0 68.00 71.4 202.7 2.984 .743 5.00 14.30 .574 559.2 .0 .0 68.00 80.4 210.5 2.676 .743 5.55 13.70 .563 567.1 .0 .0 68.00 88.7 217.9 2.452 .743 6.00 13.37 .5S4 572.0 .0 .0 68.00 99.4 227.2 2.233 .743 6.54 13.20 .543 576.3 .0 .0 68.00 109.5 234.6 2.084 .744 7.00 13.22 .533 579.0 .0 .0 68.00 121.4 242.1 1.964 .746 7.51 13.41 .525 581.1 .0 .0 68.00 133.5 248.6 1.886 .748 8.00 13.72 .519 582.3 .0 .0 68.00 147.4 255.1 1.834 .751 8.54 14.18 .515 583.1 .0 .0 68.00 159.7 260.2 1.808 .755 9.00 14.62 .514 583.4 .0 .0 68.00 171.4 264.4 1.794 .759 9.43 15.07 .514 583.5 .0 .0 68.00 173.4 265.1 1.794 .759 9.50 15.15 .514 583 .5 .0 .0 68.00 187.3 269.6 1.822 .764 10.00 15.62 .524 582.4 .0 .0 68.00 WCAP-16193-NP March 2004 Official rmord word chcairnicalk in m I)% ZiC wAlevt'i

5-32 Table 5.2-6 Unit 2 Double-Ended Pump Suction Break Principle Parameters During Rellood (Minimum Safeguards)

TIME FLOODING CARRYOVER CORE DOWNCOMER FLOW INJECTION TEMP RATE FRACTION HEIGHT HEIGHT FRACTION TOTAL ACCUMULATOR SPILL ENTHALPY SECONDS DEGREE F IN/SEC FT FT (POUNDS MASS PER SECOND) BTU/LBM 26.6 176.6 .000 .000 .00 .00 .250 .0 .0 .0 .00 27.4 175.0 22.231 .000 .65 1.13 .000 6463.8 6463.8 .0 89.48 27.6 174.1 23.689 .000 1.04 1.16 .000 6428.2 6428.2 .0 89.48 27.9 173.8 2.578 .104 1.31 1.70 .188 6347.7 6347.7 .0 89.48 28.1 173.8 2.770 .141 1.35 2.13 .250 6313.8 6313.8 .0 89.48 29.1 174.0 2.341 .299 1.50 4.10 .325 6154.9 6154.9 .0 89.48 30.6 174.5 2.270 .459 1.69 7.41 .351 5919.2 5919.2 .0 89.48 34.2 175.9 2.526 .615 2.00 14.50 .369 5463.2 5463.2 .0 89.48 36.7 176.8 4.285 .680 2.26 16.12 .584 5227.9 4690.5 .0 87.27 37.7 177.2 4.163 .693 2.37 16.12 .583 5138.3 4599.8 .0 87.23 39.0 177.8 4.035 .705 2.51 16.12 .581 5033.0 4492.6 .0 87.17 44.5 180.5 3.684 .728 3.00 16.12 .572 4649.3 4101.4 .0 86.95 50.9 184.2 3.427 .737 3.51 16.12 .562 4288.0 3733.1 .0 86.70 56.8 187.6 2.915 .738 3.92 16.12 .517 3270.6 2698.7 .0 85.72 57.8 188.2 3.586 .743 3.99 16.09 .589 552.8 .0 .0 68.00 58.0 188.4 3.704 .743 4.00 16.06 .593 544.0 .0 .0 68.00 58.8 188.9 3.752 .743 4.07 15.93 .595 538.7 .0 .0 68.00 64.8 193.5 3.406 .744 4.52 15.05 .589 548.8 .0 .0 68.00 71.7 199.4 3.083 .744 5.00 14.30 .581 557.7 .0 .0 68.00 79.8 206.8 2.773 .743 5.51 13.67 .572 565.7 .0 .0 68.00 88.6 215.0 2.505 .743 6.00 13.26 .561 571.6 .0 .0 68.00 99.8 225.1 2.253 .743 6.57 13.04 .548 576.5 .0 .0 68.00 109.0 232.1 2.105 .744 7.00 13.05 .539 579.2 .0 .0 68.00 121.8 240.4 1.965 .745 7.56 13.24 .529 581.5 .0 .0 68.00 132.7 246.4 1.891 .747 8.00 13.52 .523 582.7 .0 .0 68.00 145.8 252.8 1.837 .750 8.51 13.94 .519 583.5 .0 .0 68.00 158.8 258.3 1.807 .754 9.00 14.41 .518 583.8 .0 .0 68.00 173.8 263.9 1.791 .758 9.55 14.99 .517 583.9 .0 .0 68.00 175.8 264.6 1.790 .759 9.62 15.07 .517 583.9 .0 .0 68.00 186.4 268.1 1.810 .763 10.00 15.47 .524 583.3 .0 .0 68.00 WCAP-16193-NP March 2004 Official record stored electronically inEDMS 2000-031504 L- l--. l --- _ - _ - L - (_ . I l, _ -L _ l _ -- l -L l -- __ It --. L __ L __-

5-33 Table 5.2-7 Unit 1 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) without Recirculation Sprays TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 187.4 217.6 271.3 375.7 134.4 192.4 217.3 271.0 376.0 134.3 197.4 217.1 270.7 376.2 134.1 202.4 215.9 269.2 377.4 134.1 207.4 215.9 269.2 377.4 133.9 212.4 214.9 267.9 378.4 133.9 217.4 214.8 267.9 378.5 133.7 222.4 214.8 267.8 378.5 133.5 227.4 213.7 266.5 379.6 133.6 232.4 213.6 266.3 379.7 133.3 237.4 213.5 266.2 379.9 133.1 242.4 212.3 264.8 381.0 133.2 247.4 212.2 264.5 381.2 133.0 252.4 211.9 264.3 381.4 132.8 257.4 210.8 262.8 382.5 132.9 262.4 210.5 262.5 382.8 132.7 267.4 210.2 262.1 383.1 132.6 272.4 209.9 261.7 383.4 132.4 277.4 209.6 261.3 383.7 132.3 282.4 209.2 260.9 384.1 132.1 287.4 207.9 259.2 385.4 132.2 292.4 207.5 258.7 385.9 132.1 297.4 207.0 258.1 386.3 132.0 302.4 206.5 257.5 386.8 131.9 307.4 205.9 256.8 387.4 131.8 312.4 205.4 256.1 388.0 131.7 317.4 205.6 256.3 387.7 131.4 322.4 204.9 255.5 388.4 131.3 327.4 204.2 254.6 389.1 131.2 332.4 203.4 253.6 389.9 131.2 337.4 203.4 253.6 389.9 131.0 342.4 202.5 252.5 390.8 130.9 347.4 202.3 252.3 391.0 130.7 352.4 201.3 251.0 392.0 130.8 357.4 201.0 250.6 392.3 130.6 362.4 200.6 250.1 392.7 130.4 367.4 200.1 249.5 393.2 130.3 372.4 199.5 248.8 393.8 130.2 377.4 198.8 247.9 394.5 130.2 382.4 198.0 246.8 395.3 130.1 387.4 197.7 246.5 395.6 129.9 392.4 197.3 246.0 396.0 129.8 397.4 196.7 245.3 396.6 129.7 402.4 196.0 244.4 397.3 129.6 407.4 195.1 243.3 398.2 129.6 412.4 194.7 242.7 398.7 129.5 417.4 194.5 242.5 398.8 129.3 422.4 204.3 254.7 389.0 131.8 WCAP-16193-NP March 2004 Offcial record stored electronically in EDMS 2000.031504

5-34 Table 5.2.7 Unit I Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (cont.) (Minimum Safeguards) without Recirculation Sprays TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 427.4 203.7 254.0 389.6 131.7 432.4 203.4 253.6 389.9 131.5 437.4 202.7 252.7 390.6 131.5 442.4 202.2 252.1 391.1 131.3 447.4 201.7 251.5 391.6 131.2 452.4 200.8 250.4 392.5 131.1 457.4 200.2 249.7 393.1 131.0 462.4 90.6 113.0 502.7 159.7 _

647.6 90.6 113.0 502.7 159.7 647.7 92.9 115.1 500.4 153.9 652.4 92.8 114.9 500.5 153.6 1411.1 92.8 114.9 500.5 153.6 1411.2 77.7 89.4 515.6 43.5 1748.3 73.7 84.8 519.6 44.2 1748.4 73.7 84.8 353.7 78.7 3000.0 64.9 74.7 362.4 80.2 3000.1 64.9 74.7 366.6 68.0 3600.0 61.3 70.5 370.2 68.7 3600.1 50.8 58.5 380.7 55.2 7000.0 41.1 47.3 390.5 56.6 7000.1 40.5 46.7 391.5 51.7 10000.0 36.5 42.0 395.5 52.2 10000.1 36.2 41.6 395.8 49.1 50000.0 23.7 27.2 408.3 50.6 50000.1 23.1 26.6 408.9 40.9 100000.0 18.9 21.9 411.1 41.3 100000.1 18.7 21.5 413.3 35.5 500000.0 10.8 12.4 421.2 36.2 500000.1 10.7 12.4 421.3 33.7 _

800000.0 8.7 10.0 423.3 33.9 800000.1 8.7 10.0 423.3 32.2 1000000.0 7.9 9.1 424.1 32.2 1000000.1 7.9 9.1 424.1 31.8 5000000.0 3.8 4.3 428.2 32.1 5000000.1 3.7 4.3 428.3 30.0 10000000.0 2.5 2.8 429.5 30.1.

March 2004 WCAP- 16193-NP WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-35 Table 5.2-8 Unit 2 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) without Recirculation Sprays TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 186.4 227.9 284.0 365.4 135.2 191.4 227.3 283.3 366.0 135.1 196.4 226.7 282.5 366.6 135.0 201.4 226.2 281.9 367.1 134.9 206.4 225.8 281.4 367.5 134.7 211.4 225.5 280.9 367.8 134.6 216.4 225.1 280.4 368.2 134.4 221.4 224.6 279.9 368.7 134.3 226.4 224.2 279.4 369.1 134.2 231.4 223.7 278.8 369.6 134.1 236.4 223.2 278.2 370.1 133.9 241.4 222.7 277.5 370.6 133.8 246.4 222.2 276.8 371.2 133.7 251.4 221.6 276.1 371.7 133.6 256.4 221.0 275.4 372.3 133.5 261.4 220.4 274.6 373.0 133.5 266.4 220.4 274.6 372.9 133.2 271.4 219.7 273.8 373.6 133.1 276.4 219.0 272.9 374.3 133.1 281.4 218.9 272.8 374.4 132.9 286.4 218.1 271.7 375.2 132.8 291.4 217.9 271.5 375.4 132.6 296.4 217.0 270.4 376.3 132.6 301.4 216.8 270.1 376.6 132.4 306.4 216.4 269.7 376.9 132.3 311.4 216.0 269.2 377.3 132.1 316.4 214.9 267.8 378.4 132.1 321.4 214.4 267.2 378.9 132.0 326.4 214.5 267.3 378.8 131.8 331.4 213.8 266.4 379.5 131.7 336.4 213.1 265.5 380.2 131.6 341.4 212.9 265.3 380.4 131.4 346.4 212.0 264.1 381.3 131.4 351.4 211.6 263.6 381.8 131.2 356.4 211.0 263.0 382.3 131.1 361.4 210.4 262.1 382.9 131.0 366.4 210.1 261.8 383.2 130.8 371.4 209.2 260.7 384.1 130.8 376.4 208.6 260.0 384.7 130.7 381.4 208.4 259.6 384.9 130.5 386.4 207.9 259.1 385.4 130.4 391.4 207.2 258.1 386.2 130.3 396.4 206.6 257.5 386.7 130.2 401.4 206.2 257.0 387.1 130.0 406.4 205.5 256.1 387.8 130.0 411.4 204.8 255.2 388.5 129.9 416.4 204.3 254.6 389.0 129.8 421.4 203.9 254.1 389.4 129.6 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-36 Table 5.2-8 Unit 2 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (cont.) (Minimum Safeguards) without Recirculation Sprays TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/ SEC LBM/ SEC BTU/SEC 426.4 203.2 253.2 390.1 129.6 431.4 202.6 252.4 390.7 129.5 436.4 202.0 251.7 391.3 129.4 441.4 201.7 251.3 391.7 129.2 446.4 200.8 250.2 392.5 129.2 451.4 91.0 113.4 502.3 157.9 638.8 91.0 113.4 502.3 157.9 638.9 93.4 115.6 499.9 154.8 641.4 93.4 115.5 500.0 154.7 1429.2 93.4 115.5 500.0 154.7 1429.3 77.7 89.4 515.6 44.5 1748.3 73.9 85.0 519.4 45.2 1748.4 73.9 85.0 353.4 79.6 3000.0 65.2 75.0 362.2 81.2 3000.1 65.2 75.0 366.4 69.0 --

3600.0 61.6 70.8 370.0 69.6 3600.1 50.8 58.5 380.7 55.2 7000.0 41.1 47.3 390.5 56.6 7000.1 40.5 46.7 391.5 51.7 10000.0 36.5 42. 0 395.5 52.2 10000.1 36.2 41.6 395.8 49.1 -I 50000.0 23.7 27.2 408.3 50.6 50000.1 23.1 26.6 408.9 40.9 100000. 0 18.9 21.8 413 .1 41.3 100000.1 18.7 21.5 413.3 35.5 500000.0 10.8 12.4 421.2 36.2 500000.1 10.7 12.3 421.3 32.9 800000.0 8.7 10.0 423.3 33.0 800000.1 8.7 10.0 423.3 31.3 1000000 .0 7.9 9.1 424.1 31.4 1000000.1 7.9 9.1 424.1 30.5 5000000.0 3.7 4.3 428.3 30.8 5000000.1 3.7 4.3 428.3 30.0 10000000.0 2.5 2.8 429.5 30.1 J

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-37 Table 5.2-9 LOCA Mass and Energy Release Analysis Core Decay Heat Fraction Time (sec) Decay Heat Generation Rate (Btu/Btu) 10 0.053876 15 0.050401 20 0.048018 40 0.042401 60 0.039244 80 0.037065 100 0.035466 150 0.032724 200 0.030936 400 0.027078 600 0.024931 800 0.023389 1000 0.022156 1500 0.019921 2000 0.018315 4000 0.014781 6000 0.013040 8000 0.012000 10000 0.011262 15000 0.010097 20000 0.009350 40000 0.007778 60000 0.006958 80000 0.006424 100000 0.006021 150000 0.005323 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-38 I

Table 5.2-9 LOCA Mass and Energy Release Analysis Core Decay Heat Fraction (cont.)

Time (see) Decay Heat Generation Rate (Btu/Btu) 200000 0.004847 400000 0.003770 600000 0.003201 800000 0.002834 1000000 0.002580 2000000 0.001909 4000000 0.001355 6000000 0.001091 8000000 0.000927 10000000 0.000808

-J

-I WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504 j

r-I-,

( l: ( ,-.~

-- r - r - , r- rev U I(--r - I or-, r ~ r I1-3 5-39 Table 5.2.10 Unit 1 Double-Ended Pump Suction Break Mass Balance (Minimum Safeguards)

TIME (SECONDS) .00 26.20 26.20 187.31 647.69 1411.09 3600.00 MASS (THOUSAND LBM)

INITIAL IN RCS AND ACC 728.06 728.06 728.06 728.06 728.06 728.06 728.06 ADDED MASS PUMPED INJECTION .00 .00 .00 86.71 359.81 812.74 1806.61 TOTAL ADDED .00 .00 .00 86.71 359.81 812.74 1806.61

• • • TOTAL AVAILABLE *** 728.06 728.06 728.06 814.78 1087.88 1540.81 2534.68 DISTRIBUTION REACTOR COOLANT 509.07 55.52 79.78 148.67 148.67 148.67 148.67 ACCUMULATOR 219.00 163.79 139.52 .00 .00 .00 .00 TOTAL CONTENTS 728.06 219.30 219.30 148.67 148.67 148.67 148.67 EFFLUENT BREAK FLOW .00 508.74 508.74 666.09 939.19 1392.12 2386.00 ECCS SPILL .00 .00 .00 .00 .00 .00 .00 TOTAL EFFLUENT .00 508.74 508.74 666.09 939.19 1392.12 2386.00

• • • TOTAL ACCOUNTABLE *** 728.06 728.05 728.05 814.76 1087.86 1540.79 2534.67 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000.031504

540 Table 5.2.11 Unit 2 Double-Ended Pump Suction Break Mass Balance (Minimum Safeguards)

TIME (SECONDS) .00 26.60 26.60 186.36 638.89 1429.18 3600.00 MASS (THOUSAND LBM)

INITIAL IN RCS AND ACC 748.99 748.99 748.99 748.99 748.99 748.99 748.99 ADDED MASS PUMPED INJECTION .00 .00 .00 86.26 354.73 823.62 1806.75 TOTAL ADDED .00 .00 .00 86.26 354.73 823.62 1806.75

• • • TOTAL AVAILABLE *** 748.99 748.99 748.99 835.25 1103.72 1572.61 2555.74 DISTRIBUTION REACTOR COOLANT 530.29 46.25 77.49 145.99 145.99 145.99 145.99 ACCUMULATOR 218.70 169.11 137.87 .00 .00 .00 .00 TOTAL CONTENTS 748.99 215.36 215.36 145.99 145.99 145.99 145.99 EFFLUENT BREAK FLOW .00 533.62 533.62 689.24 957.71 1426.60 2409.74 ECCS SPILL .00 .00 .00 .00 .00 .00 .00 TOTAL EFFLUENT .00 533.62 533.62 689.24 957.71 1426.60 2409.74

• • • TOTAL ACCOUNTABLE *** 748.99 748.98 748.98 835.23 1103.70 1572.59 2555.73 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504 L _ Lo L_ L L L-- l 1 1 .. .... L --- l. -- I -_ l _- 1 - t _ L-- L_ fr

(( l -: ( i ( r. v r r . r - ( -;<(--I. rev r- r. r 5-41 Table 5.2-12 Unit 1 Double-Ended Pump Suction Break Energy Balance (Minimum Safeguards)

TIME (SECONDS) .00 26.20 26.20 187.31 647.69 1411.09 3600.00 ENERGY (MILLION BTU)

INITIAL ENERGY IN RCSACCS GEN 853.70 853.70 853.70 853.70 853.70 853.70 853.70 ADDED ENERGY PUMPED INJECTION .00 .00 .00 5.90 24.47 55.27 200.02 DECAY HEAT .00 8.01 8.01 27.21 68.79 124.74 250.57 HEAT FROM SECONDARY .00 8.68 8.68 8.68 16.73 27.80 27.80 TOTAL ADDED .00 16.69 16.69 41.79 109.99 207.80 478.39

• • • TOTAL AVAILABLE *** 853.7) 870.40 870.40 895.49 963.69 1061.51 1332.09 DISTRIBUTION REACTOR COOLANT 299.35 12.06 14.23 38.61 38.61 38.61 38.61 ACCUMULATOR 19.60 14.66 12.48 .00 .00 .00 .00 CORE STORED 25.60 13.30 13.30 4.85 4.64 4.30 3.33 PRIMARY METAL 153.38 145.78 145.78 119.57 84.56 64.78 50.05 SECONDARY METAL 102.67 102.65 102.65 93.89 73.13 50.77 39.18 STEAM GENERATOR 253.11 268.48 268.48 241.69 189.88 140.75 112.11 TOTAL CONTENTS 853.70 556.92 556.92 498.62 390.82 299.22 243.28 EFFLUENT BREAK FLOW .00 312.89 312.89 388.23 564.23 750.24 1078.22 ECCS SPILL .00 .00 .00 .00 .00 .00 .00 TOTAL EFFLUENT .00 312.89 312.89 388.23 564.23 750.24 1078.22

• • • TOTAL ACCOUNTABLE *** 853.70 869.81 869.81 886.85 955.05 1049.45 1321.51-WCAP-16193-NP March 2004 Official record storcdelectroniallk in Fit)%t 4wtI iwLsU

5-42 Table 5.2.13 Unit 2 Double-Ended Pump Suction Break Energy Balance (Minimum Safeguards)

TIME (SECONDS) .00 26.60 26.60 186.36 638.89 1429.18 3600.00 ENERGY (MILLION BTU)

INITIAL ENERGY IN RCS,ACC,S GEN 881.82 881.82 881.82 881.82 881.82 881.82 881.82 ADDED ENERGY PUMPED INJECTION .00 .00 .00 5.87 24.12 56.01 200.03 DECAY HEAT .00 8.09 8.09 27.13 68.10 125.97 250.61 HEAT FROM SECONDARY .00 8.97 8.97 8.97 16.89 28.32 28.32 TOTAL ADDED .00 17.06 17.06 41.96 109.11 210.30 478.95

• • • TOTAL AVAILABLE *** 881.82 898.88 898.88 923.78 990.92 1092.12 1360.77 DISTRIBUTION REACTOR COOLANT 311.53 10.52 13.32 37.98 37.98 37.98 37. 98 ACCUMULATOR 19.57 15.13 12.34 .00 .00 .00 .00 CORE STORED 25.60 12.98 12.98 4.85 4.64 4.29 3.33 PRIMARY METAL 156.23 147.74 147.74 121.42 86.22 65.88 50.95 SECONDARY METAL 92.82 93.10 93.10 85.24 66.74 46.36 35.77 STEAM GENERATOR 276.06 292.38 292.38 264.21 209.04 154.48 122.77 TOTAL CONTENTS 881.82 571.85 571.85 513.70 404.63 308.99 250.81 EFFLUENT BREAK FLOW .00 326.45 326.45 401.46 577.67 771.44 1099.73 ECCS SPILL .00 .00 .00 .00 .00 .00 .00 TOTAL EFFLUENT .00 326.45 326.45 401.46 577.67 771.44 1099.73

• • • TOTAL ACCOUNTABLE *** 881.82 898.30 898.30 915.16 982.30 1080.44 1350.54 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504 L__ _' C L_t _ l - _. ( - l ._ -_l- I . ( - L. - I - L___ . -_ ( r

5.43 Table 5.2-14 Unit I Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) with Recirculation Spray Actuated TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 3600.1 50.8 58.5 380.7 55.2 4441.6 47.2 54.3 384.3 55.7 4441.7 47.1 54.2 118.1 16.9 7000.0 41.0 47.2 124.2 17.8 7000.1 40.8 46.9 124.4 17.2 10000.0 36.7 42.2 128.5 17.7 10000.1 36.5 42.0 128.7 17.1 50000.0 23.9 27.5 141.3 18.8 50000.1 23.4 26.9 141.9 15.6 100000.0 19.1 22.0 146.1 16.1 100000.1 18.9 21.7 146.3 14.3 500000.0 10.9 12.6 154.3 15.1 500000.1 10.8 12.4 154.4 13.3 1000000.0 8.0 9.2 157.2 13.5 1000000.1 7.9 9.1 157.3 12.3 5000000.0 3.8 4.3 161.5 12.6 5000000.1 3.7 4.3 161.5 11.6 10000000.0 2.5 2.8 162.7 11.7 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

5-44 r

Table 5.2.15 Unit 2 Double-Ended Pump Suction Break Post-Reflood Mass and Energy Releases (Minimum Safeguards) with Recirculation Spray Actuated TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 3600.1 50.8 58.5 380.7 55.2 4441.6 47.2 54.3 384.3 55.7 4441.7 47.1 54.2 118.1 16.9 7000. 0 41.0 47.2 124.2 17.8 7000. 1 40.8 46. 9 124.4 17.2 10000.0 36.7 42.2 128.5 17.7 10000.1 36.5 42.0 128.7 17.1 50000.0 23.9 27.5 141.3 18.8 50000.1 23.4 26.9 141.9 15.6 100000.0 19.1 22.0 146.1 16.1 100000.1 18.9 21.7 146.3 14.3 500000.0 10.9 12.6 154.3 15.1 500000.1 10.8 12.4 154.4 13.3 1_j II 1000000.0 8.0 9.2 157.2 13.5 1000000.1 7.9 9.1 157.3 12.3 5000000.0 3.8 4.3 161.5 12.6 5000000.1 3.7 4.3 161.5 11.6 10000000.0 2.5 2.8 162.7 11.7

__a I

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

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6-1 6 CONTAINMIENT RESPONSE ANALYSES

6.1 DESCRIPTION

OF COCO MODEL Calculation of containment pressure and temperature is accomplished by use of the digital computer code COCO (Reference 5). COCO is a mathematical model of a generalized containment; the proper selection of various options in the code allows the creation of a specific model for particular containment design. The values used in the specific model for different aspects of the containment are derived from plant-specific input data. Transient phenomena within the reactor coolant system affect containment conditions by means of convective mass and energy transport through the pipe break.

For analytical rigor and convenience, the containment air-steam-water mixture is separated into a water (pool) phase and a steam-air phase. Sufficient relationships to describe the transient are provided by the equations of conservation of mass and energy as applied to each system, together with appropriate boundary conditions. As thermodynamic equations of state and conditions may vary during the transient, the equations have been derived for all possible cases of superheated or saturated steam and subcooled or saturated water. Switching between states is handled automatically by the code.

Passive Heat Removal The significant heat removal source during the early portion of the transient is the containment structural heat sinks. Provision is made in the containment pressure response analysis for heat transfer through, and heat storage in, both interior and exterior walls. Every wall is divided into a large number of nodes. For each node, a conservation of energy equation expressed in finite-difference form accounts for heat conduction into and out of the node and temperature rise of the node. Table 6.1-1 is the summary of the containment structural heat sinks used in the analysis. The thermal properties of each heat sink material are shown in Table 6.1-2.

The heat transfer coefficient to the containment structure for the early part of the event is calculated based primarily on the work of Tagami (Reference 15). From this work, it was determined that the value of the heat transfer coefficient can be assumed to increase parabolically to a peak value. In COCO, the value then decreases exponentially to a stagnant heat transfer coefficient which is a function of steam-to-air-weight ratio.

The h for stagnant conditions is based upon Tagami's steady state results.

Tagami presents a plot of the maximum value of the heat transfer coefficient, h, as function of "coolant energy transfer speed," defined as follows:

h total coolant energy transferred into containment (containment volume) (time interval to peak pressure)

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6-2 From this, the maximum heat transfer coefficient of steel is calculated:

0.60 htp = (Equation I) where:

heax = maximum value of h (Btulhr ft 2 OF).

tp = time from start of accident to end of blowdown for LOCA and steamline isolation for secondary breaks (sec).

V = containment net free volume (ft3 ).

E = total coolant energy discharge from time zero to tp (Btu).

75 = material coefficient for steel.

(Note: Paint is accounted for by the thermal conductivity of the material (paint) on the heat sink structure, not by an adjustment on the heat transfer coefficient.)

The basis for the equations is a Westinghouse curve fit to the Tagami data.

The parabolic increase to the peak value is calculated by COCO according to the following equation:

hs = at ) t tP (Equation 2) where:

hs = heat transfer coefficient between steel and air/steam mixture (Btulhr ft2 OF).

t = time from start of event (sec).

For concrete, the heat transfer coefficient is taken as 40 percent of the value calculated for steel during the blowdown phase.

The exponential decrease of the heat transfer coefficient to the stagnant heat transfer coefficient is given by:

hs = hstag + (h - hstag )eOO°5(ttl) (Equation 3) where:

t> tp WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-3 hang = 2+50X,O<X<1.4.

hstag = h for stagnant conditions (Btu/hr ft2 IF).

X = steam-to-air weight ratio in containment.

Active Heat Removal For a large break, the engineered safety features are quickly brought into operation. Because of the brief period of time required to depressurize the reactor coolant system or the main steam system, the containment safeguards are not a major influence on the blowdown peak pressure; however, they reduce the containment pressure after the blowdown and maintain a low long-term pressure and a low long-term temperature.

Safety Injection - RWST During the injection phase of post-accident operation, the emergency core cooling system pumps water from the refueling water storage tank into the reactor vessel. Since this water enters the vessel at refueling water storage tank temperature, which is less than the temperature of the water in the vessel, it is modeled as absorbing heat from the core until the saturation temperature is reached. Safety injection and containment spray can be operated for a limited time, depending on the refueling water storage tank (RWST) capacity.

Safety Injection - RHR/Sump Recirculation After the supply of refueling water is exhausted, the recirculation system is operated to provide long term cooling of the core. In this operation, water is drawn from the sump, cooled in a residual heat removal (RHR) exchanger, then pumped back into the reactor vessel to remove core residual heat and energy stored in the vessel metal. The heat is removed from the RHR heat exchanger by the component cooling water (CCW). The RHR Hxs and CCW Hxs are coupled in a closed loop system, where the ultimate heat sink is the service water cooling the CCW Hx.

Containment Spray Containment spray (CS) is an active removal mechanism which is used for rapid pressure reduction and for containment iodine removal. During the injection phase of operation, the containment spray pumps draw water from the RWST and spray it into the containment through nozzles mounted high above the operating deck. As the spray droplets fall, they absorb heat from the containment atmosphere. Since the water comes from the RWST, the entire heat capacity of the spray from the RWST temperature to the temperature of the containment atmosphere is available for energy absorption. During the recirculation phase the analysis credits available spray flow.

When a spray droplet enters the hot, saturated, steam-air containment environment, the vapor pressure of the water at its surface is much less than the partial pressure of the steam in the atmosphere. Hence, there will be diffusion of steam to the drop surface and condensation on the droplet. This mass flow will carry energy to the droplet. Simultaneously, the temperature difference between the atmosphere and the droplet will cause the droplet temperature and vapor pressure to rise. The vapor pressure of the droplet will eventually become equal to the partial pressure of the steam, and the condensation will cease. The temperature of the droplet will essentially equal the temperature of the steam-air mixture.

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-4 The equations describing the temperature rise of a falling droplet are as follows.

d (Mu) = mh + q (Equation 4) dt )=b9 -a where:

M = droplet mass U = internal energy I m = diffusion rate

= steam enthalpy q = heat flow rate I t = time 4.4 d(Mu)=m (Equation 5) ,-.T dt where: II q = hcA* (T.7-T) m = kgA* (P,-Pv)

A = area hC = coefficient of heat transfer kg = coefficient of mass transfer -J T = droplet temperature T, = steam temperature P. = steam partial pressure R, = droplet vapor pressure The coefficients of heat transfer (hc) and mass transfer (kd are calculated from the Nusselt number for heat transfer, Nu, and the Nusselt number for mass transfer, Nu'.

Both Nu and Nu'may be calculated from the equations of Ranz and Marshall (Reference 16).

Nu = 2 + 0.6(Re)'12 (Pr)113 (Equation 6) where:

Nu = Nusselt number for heat transfer Pr = Prandtl number Re = Reynolds number -d Nu' = 2 + 0.6(Re)' 2 (Sc)"I3 (Equation 7)

March 2004 WCAP-16193-NP WCAP- 16193-sP March 2004 Of ficial record stored elecronically in EDMS 2000 031504

6-5 where:

Nut = Nusselt number for mass transfer Sc = Schmidt number Thus, Equations 4 and 5 can be integrated numerically to find the internal energy and mass of the droplet as a function of time as it falls through the atmosphere. Analysis shows that the temperature of the (mass) mean droplet produced by the spray nozzles rises to a value within 99 percent of the bulk containment temperature in less than 2 seconds. Detailed calculations of the heatup of spray droplets in post-accident containment atmospheres by Parsly (Reference 17) show that droplets of all sizes encountered in the containment spray reach equilibrium in a fraction of their residence time in a typical pressurized water reactor containment. These results confirm the assumption that the containment spray will be 100 percent effective in removing heat from the atmosphere.

CFCU The containment fan cooler units (CFCUs) are an additional means of heat removal. The main aspects of a fan cooler from the heat removal standpoint are the fan and the banks of cooling coils. The fans draw the dense containment atmosphere (steam/air mixture) through banks of finned cooling coils and discharge the cooled steam/air mixture through the containment ventilation ducting to mix with the rest of the containment atmosphere. The coils are kept at a low temperature by a constant flow of cooling water.

Under accident conditions, the cooling water is provided by the Service Water System. Since this system does not use water from the RWST, the mode of operation remains the same both before and after the spray system and emergency core cooling system change to recirculation mode. See Table 6.1-3 for the CFCU heat removal capability assumed for the containment response analyses.

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6-6 f

Table 6.1-1 Containment Heat Sinks No. Material Heat Transfer Area ft2 Thickness ft I Paint Coating #1 45,169 0.000625 Carbon Steel 0.03125 Concrete 4.5 2 Insulation 14,206 0.2083 Carbon Steel 0.03125 Concrete 4.5 3 Paint Coating #1 29,249 0.000625 -.4 Carbon Steel 0.04167 Concrete 3.5 4 In contact with the sump 11,611 Paint Coating #2 0.0015 Concrete 3.5 '-4 5 Paint Coating #2 6,806 0.0015 Concrete 1.5 6 Paint Coating #2 9,424 0.0015 Concrete 1.71 7 Paint Coating #3 31,660 0.00117 Concrete 1.5 1-I 8 Stainless Steel 13,278.68 0.01773 Concrete 1.9 9 Paint Coating #1 47,589.8 0.000625 Carbon Steel 0.011 10 Paint Coating #1 76,741.2 0.000625 Carbon Steel 0.02102 II Paint Coating #1 19,348 0.000625 Carbon Steel 0.0437 12 Paint Coating #1 9,330 0.000625 Carbon Steel 0.0611 13 Paint Coating #1 7,451.5 0.000625 Carbon Steel 0.086 if 14 Paint Coating #1 3,217.7 0.000625 Carbon Steel 0.11124 15 Paint Coating #1 1,553.18 0.000625 -I Carbon Steel 0.217 16 Paint Coating #1 43,740 0.000625 Carbon Steel 0.0052 -

17 Stainless Steel 4,272 0.0329 18 Paint Coating #1 53,745 0.000625 Carbon Steel 0.0211 19 Paint Coating #1 11,243.59 0.000625 Carbon Steel 0.0379 20 Paint Coating #1 2,989.4 0.000625 Carbon Steel 0.15806 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000.031504

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6-7 Table 6.1-2 Thermophysical Properties of Containment Heat Sinks Thermal Conductivity Volumetric Heat Capacity Material (Btu/hr-ft - OF) (Btulft3 - OF)

Carbon Steel 27.0 58.8 Stainless Steel 8.0 53.6 Concrete 0.92 22.6 Insulation 0.024 3.94 Paint Coating #1 0.083 39.6 Paint Coating #2 0.083 39.6 Paint Coating #3 0.083 39.6 Table 6.1-3 Containment Fan Cooler Performance Heat Removal Rate [Btu/sec] Per Reactor Containment Temperature (OF) Containment Fan Cooler 105 648.6 120 1620.8 140 3198.7 160 4982.6 180 6908.8 200 8856.4 220 10817.0 240 12706.5 260 14625.6 271 15662.5 280 16500.1 Notes:

Service Water Temperature = 93.0F Service Water Flow = 1200 gpm Tube Fouling = 0.0015 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-8 Table 6.14 Containment Response Analysis Parameters Service water temperature (OF) 93 RWST water temperature (OF) lloo Initial containment temperature (OF) 120 Initial containment pressure (psia) 15.0 Initial relative humidity (%) 20 Net free volume (ft3) 2.62 x 106 -J Containment Fan Coolers Total 5 Analysis maximum (bounding configuration following AST* implementation) 3 Analysis minimum (bounding configuration following AST* implementation) 2 Containment High setpoint (psig) 5.5 Delay time (sec)

With Offsite Power 100.0 Without Offsite Power 100.0 Containment Spray Pumps I t Total 2 Analysis maximum 2 Analysis minimum I Flowrate (gpm) i Injection phase (per pump) Variable see Recirculation phase (total) Table 6.1-5 Containment Hi hi setpoint (psig) 17.0 Delay time (sec)

With Offsite Power (delay after Hi hi setpoint) 85.0 Without Offsite Power (delay after Hi-hi setpoint) 85.0 ECCS Recirculation Switchover, sec Minimum Safeguards 17 4 8 .3 y

-4 Containment Spray Termination (injection phase) time, (sec)

Minimum Safeguards 4141.6y Containment Spray - Recirculation (gpm) 1974.8 For minimum safeguards, with recirculation spray, only 1225.2 gpm goes to the core from the total RHR flow of 3200 gpm a delay of 5 minutes (i.e. 300 seconds) will be assumed for operator action to start spray I

I WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000.031504

6-9 Table 6.1-4 Containment Response Analysis Parameters (cont.)

Residual Heat Removal System RHR Heat Exchangers Modeled in analysis' I Minimum Safeguards Recirculation switchover time, sec 1748.3 UA, 106 Btu/hrF 1.75 Flows - Tube Side and Shell Side - gpm Tube Side CCW Flow (Minimum Safeguards) J 4000.0 Shell Side RHR Flow (Minimum Safeguards) l 3200.0 Component Cooling Water Heat Exchangers Modeled in analysis UA, 106 Btu/hr-°F 4.013 Flows - Shell Side and Tube Side - gpm Shellside 4140.0 Tubeside (service water)' 8000.0 Additional heat loads, BtuAlr 2.Ox 106 Notes:

• PSE&G is performing an alternate source term (AST) dose analysis y these values were determined by Westinghouse using conservative flow assumptions and PSEG supplied RWST inventory data z Minimum safeguards data representing the loss of a safeguards train Table 6.1-5 Containment Spray Performance (Injection Phase) with 1 Pump with 2 Pumps Containment Pressure (psig) (gpm) (gpmr) 0 3117.0 6234.0 10 3017.0 6034.0 20 2913.0 5826.0 30 2720.0 5440.0 40 2687.0 5374.0 47 2600.0 5200.0 WCAP-16193-sP March 2004 Official record stored electronically inEDMS 2000-031504

6-10 6.2 CONTAINMENT RESPONSE TO STEAMLINE BREAK I The containment response to a steamline break was calculated with the COCO model described in I

Section 6.1 and the mass and energy releases from Section 4.4. The peak containment pressures and temperatures are summarized in Table 6.2-1. The limiting containment pressure case is a 1.4 ft2 DER initiated at 30% power with a containment safeguards failure. The limiting containment temperature case is 0.88 ft2 split rupture initiated at 30% power with a MSIV failure. For Unit 1, the peak pressure is 40.2 psig and the peak temperature is 345.7RF. For Unit 2, the peak pressure is 42.2 psig and the peak temperature is 345AoF.

I

-j The containment air temperature composite profile from all the cases is in Table 6.2-2. The composite temperature transient is compared to the EQ temperature limit from Section 3.3 in Figure 6.2-1.

Table 6.2-1 Summary of Steamtline Break Peak Containment Pressures and Temperatures II Unit I Unit 2 1.10, Case Description Model F SGs Model 51 SGs Peak Press Peak Press I (psig @ Peak Temp (psig @ Peak Temp -0 Break Power Failure Case see) (F @ see) Case see) (°F @see) 4.6 DER 100 FRV - 9-2 39.0 @ 124 260.1 @ 124 4.6 DER 30 FRV - 11-2 41.0 @ 165 263.1 @ 164 1.4 DER 30 CSF 19-1 40.2 @ 603 261.9 @ 603 19-2 42.2 @ 603 265.0 @ 603 1.4 DER 30 AFW 23-1 37.5 @ 602 257.5 @ 602 23-2 39.3 @ 602 260.4 @ 602 1.4 DER 100 FRV 25-1 39.2 @ 225 260.4 @ 225 25-2 40.5 @ 250 262.4 @ 250 Small DER 100 MSIV 61-1 30.5 @ 649 331.5 @ 119 61-2 31.6 @ 452 327.7 @ Ill I.;

Split 30 CSF 67-1 40.0 @ 690 345.0 @ 113 67-2 41.9 @ 681 344.6 @ 113 Split 30 MSIV 79-1 40.1 @ 378 345.7 @ 113 79-2 41.7 @ 415 345.4 @ 113 t

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6-11 Table 6.-2 Containment Air Temperature Composite from SLB Analyses for CFCU/SW Enhancement Program Maximum Containment Temperature (OF)

Time (sec) Unit 1 Unit 2 0.00 120.0 120.0 0.10 122.0 123.2 0.25 125.9 127.8 0.50 135.3 135.2 0.75 144.2 143.7 1.00 152.7 149.9 2.00 176.0 163.2 3.00 184.9 174.2 4.00 191.5 182.1 5.00 196.1 187.0 6.00 199.1 189.7 7.00 200.8 193.5 8.00 201.6 197.8 9.00 201.6 201.5 10.00 202.1 204.8 12.00 209.6 210.4 13.00 212.9 214.5 14.00 215.0 220.2 16.00 216.3 231.0 17.00 217.6 236.1 18.00 221.7 240.9 20.00 229.5 249.9 22.00 236.8 257.8 25.00 247.1 268.0 27.00 253.4 273.9 29.00 259.3 279.1 32.00 267.5 285.9 36.00 277.4 293.2 39.00 284.0 297.5 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000D031504

6-12 i

Table 6.22 Containment Air Temperature Composite from SLB Analyses for CFCU/SW Enhancement (cont.) Program Maximum Containment Temperature (0 F)

Time (sec) Unit 1 Unit 2 43.00 292.1 302.0 46.00 297.6 304.5 53.00 308.8 308.6 57.00 314.4 314.0 64.00 322.7 322.4 71.00 328.7 328.5 78.00 333.1 333.0 85.00 336.5 336.4 99.00 341.6 341.5 113.00 345.7 345.4 119.00 344.6 344.2 I

133.00 343.9 343.2 151.00 331.7 330.8 164.00 323.8 322.7 190.00 309.7 308.3 216.00 297.7 296.0 242.00 287.5 285.5 268.00 278.7 276.4 294.00 271.1 268.6 320.00 264.5 262.0 331.00 260.6 262.2 354.00 260.8 262.7 378.00 261.8 264.0 403.00 261.2 263.9 415.00 260.9 264.2 429.00 260.6 264.0 603.00 261.9 265.0 627.00 261.3 264.4 680.00 261.6 264.5 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-13 Table 6.2-2 Containment Air Temperature Composite from SLB Analyses for CFCUISW Enhancement (cont.) Program Maximum Containment Temperature (0F)

Time (see) Unit 1 Unit 2 720.00 261.4 264.0 1000.00 251.3 1 253.8 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-14

'.tj 0-.-.UEO Tamperatora Limi t

- Unit I Compostet

--- Unit 2 Composite 400 I 350

-J LIDX I.-

IE T 250 C1 oc)200 150 100

-I f

Figure 6.2-1 Containment Temperature Composite Results for Steamline Break

. j March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000431504

6-15 6.3 CONTAINMENT RESPONSE TO LOCA The Salem containment system is designed such that for all loss-of-coolant accident (LOCA) break sizes, up to and including the double-ended severance of a reactor coolant pipe, the containment peak pressure remains below the design pressure. This section details the containment response subsequent to a hypothetical LOCA. The containment response analysis uses the long term mass and energy release data from Section 5.

The containment response analysis demonstrates the acceptability of the containment safeguards systems to mitigate the consequences of a LOCA inside containment. The impact of LOCA mass and energy releases on the containment pressure is addressed to assure that the containment pressure remains below its design pressure at the licensed core power conditions. In support of equipment design and licensing criteria (e.g.,

qualified operating life), with respect to post accident environmental conditions, long term containment pressure and temperature transients are generated to conservatively bound the potential post-LOCA containment conditions.

6.3.1 Input Parameters and Assumptions An analysis of containment response to the rupture of the RCS must start with knowledge of the initial conditions in the containment. The pressure, temperature, and humidity of the containment atmosphere prior to the postulated accident are specified in the analysis as shown in Table 6.1-1.

Also, values for the initial temperature of the service water (SW) and refueling water storage tank (RWST) are assumed, along with containment spray (CS) pump flowrate and containment fan cooler unit (CFCU) heat removal performance. All of these values are chosen conservatively, as shown in Table 6.1-4. Long term sump recirculation is addressed via Residual Heat Removal System (RHR) heat exchanger performance. The primary function of the RHR system is to remove heat from the core by way of Emergency Core Cooling System (ECCS). Table 6.1-4 provides the RHR system parameters assumed in the analysis.

Several cases were performed for the LOCA containment response. Section 5 documented the LOCA M&E releases for the minimum safeguards cases for the DEPS break for Salem Unit 1and Unit 2. Table 6.1-5 provides the performance data for the containment spray pumps. Emergency safeguards equipment data is given in Table 6.1-4. The minimum safeguards case was based upon a diesel train failure (which leaves available as active heat removal systems one containment spray pump and 2 CFCUs).

The calculations for all of the DEPS cases were performed for 10 million seconds (approximately 116 days).

The sequence of events for each of these cases is shown in Tables 6.3-1 and 6.3-2.

WCAP-16193-NP. March 2004 Official record stored electronically in EDMS 2000-031504

6-16 The following are the major assumptions made in the analysis.

I. The mass and energy released to the containment are described in Section 5 for LOCA.

2. Homogeneous mixing is assumed. The steam-air mixture and the water phases each have uniform properties. More specifically, thermal equilibrium between the air and the steam is assumed.

However, this does not imply thermal equilibrium between the steam-air mixture and the water phase.

3. Air is taken as an ideal gas, while compressed water and steam tables are employed for water and steam thermodynamic properties.

4. For the blowdown portion of the LOCA analysis, the discharge flow separates into steam and water phases at the breakpoint. The saturated water phase is at the total containment pressure, while the steam phase is at the partial pressure of the steam in the containment. For the post-blowdown portion of the LOCA analysis, steam and water releases are input separately.

5. The saturation temperature at the partial pressure of the steam is used for heat transfer to the heat sinks, the fan coolers, and the spray droplets.

6.3.2 Acceptance Criteria The containment response for design-basis containment integrity is an ANS Condition IV event, an infrequent fault. The relevant requirements to satisfy Nuclear Regulatory Commission acceptance criteria are as follows.

I. GDC 16 and GDC 50: In order to satisfy the requirements ofGDC 16 and 50, the peak calculated containment pressure should be less man the containment design pressure of 47 psig;

2. GDC 38: In order to satisfy the requirements of GDC 38, the calculated pressure at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> should .

be less than 50% of the peak calculated value. (This is related to the criteria for doses at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.)

Note that the Salem UFSAR does not reference the general design criteria (GDCs), but lists the draft/interim general design criteria that was proposed by the Atomic Energy Commission (AEC). These do not provide specific system requirements and refer back to the various sections of the UFSAR for the design bases.

Meeting the above GDC requirements along with the Technical Specification design features for pressure and temperature and equipment qualifications temperature limits will ensure all containment design limits remain bounded under the proposed CFCU system modifications.

6.3.3 Analysis Results The containment pressure, steam temperature and water (sump) temperature profiles from each of the LOCA cases are shown in Figures 6.3-1 through 6.3-6 for the DEPS break cases without recirculation spray actuated. The long term containment response for Unit I and Unit 2 with recirculation spray modeled at 1974.8 gpm is shown in Figures 6.3-7 through 6.3-12.

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6-17 633.1 Unit 1 - Double Ended Pump Suction Break with Minimum Safeguards This analysis assumes a loss of offsite power coincidence with a double ended rupture of the RCS piping between the steam generator outlet and the RCS pump inlet (suction). The associated single failure assumption is the failure of a complete train of safeguards equipment. As discussed in Section 5.1.6 for the safety injection pumps, this single failure assumption is conservative because both Salem units have three emergency diesel generators. The loss of a single diesel generator would result in the loss of only a few components. This combination results in a conservative minimum set of safeguards being available. The containment heat removal systems that are assumed to be available are one RHR heat exchanger, one containment spray pump, and two CFCUs. Further, loss of offsite power delays the actuation times of the safeguards equipment due to the required diesel startup time after receipt of the safety injection signal.

The postulated RCS break results in a rapid release of mass and energy to the containment with a resulting rapid rise in both the containment pressure and temperature. This rapid rise in containment pressure results in the generation of a containment Hi-l signal at 1.1 seconds and a containment Hi-2 signal at 4.6 seconds.

The containment pressure continues to rise rapidly in response to the release of mass and energy until the end of blowdown at 26.2 seconds. The end of blowdown marks a time when the initial inventory in the RCS has been exhausted and a slow process of filling the RCS downcomer in preparation for reflood has begun. Since the mass and energy release during this period is low, pressure decreases slightly and then increases in response to the reflood mass and energy release out to a second peak which occurred at 100 seconds.

The turn around in containment pressure at 100 seconds is a result of the initiation of the containment spray pump at 89.6 seconds and the containment fan cooler units (CFCUs) at 101.1 seconds. Reflood continues at a reduced flooding rate due to the buildup of mass in the RCS core which offsets the downcomer head. This reduction in flooding rate and the continued action of the CFCUs and Spray leads to a slowly decreasing pressure out to the end of reflood, which occurs at 187.3 seconds.

At this juncture, by design of the Reference 2 model, energy removal from the SG secondary side begins at a very high rate, resulting in a rise in containment pressure from 187.4 seconds out to 461.0 seconds when the ultimate peak pressure of 40.1 psig is reached. Energy continues to be removed from the secondary side of the faulted loop and intact loop steam generators until 1411.1 seconds. The containment pressure at the end of this steam generator energy release period is similar to peak pressure. After 1411.1 seconds, the containment pressure decreases through the initiation of cold leg recirculation at 1748.3 seconds. At this time, the ECCS is realigned for cold leg recirculation resulting in an increase in the SI temperature due to delivery from the hot sump. At 4141.6 seconds, the containment spray is terminated from the RWST.

Without crediting recirculation spray, the containment pressure and temperature will begin to increase out to approximately 30,000 seconds. At this time, the energy removal from the two operating CFCUs exceeds the energy release and the pressure and temperature turn around. This trend continues to the end of the transient at 1x107 seconds. This can be seen in Figures 6.3-1 through 6.3-3. This is not acceptable from both the aspect of GDC 38 or EQ requirements, but is provided to demonstrate the need for recirculation spray under the proposed CFCU configuration.

When 1974.8 gpm of recirculation sprays are modeled for Salem Unit I beginning at 4441.6 seconds (which is a 5 minute delay from the time that the injection spray was terminated to allow the operators enough time to reposition the necessary valves), the containment pressure and temperature do not increase and the WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031304

6-18 J containment conditions at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are significantly lower. The detailed containment conditions can be seen in Table 6.3-3 and Figures 6.3-7 through 6.3-9 for the containment pressure, steam temperature and sump temperature. Figure 6.3-8 shows that there are two periods of time where the steam temperature exceeds the temperature profile. The first is from about 1500 seconds to about 3500 seconds and the other is from about 4500 seconds to 10,000 seconds. Therefore, the steam temperature transient with recirculation spray exceeds the profile for about 7500 seconds (i.e. approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 5 minutes).

633.2 Unit 2 - Double Ended Pump Suction Break with Minimum Safeguards This analysis assumes a loss of offsite power coincidence with a double ended rupture of the RCS piping between the steam generator outlet and the RCS pump inlet (suction). The associated single failure assumption is the same as the Unit I description in Section 6.3.3.1. The associated single failure assumption is the failure of a complete train of safeguards equipment. As discussed in Section 5.1.6 for the safety injection pumps, this single failure assumption is conservative because both Salem units have three emergency diesel generators. The loss of a single diesel generator would result in the loss of only a few components. This combination results in a conservative minimum set of safeguards being available. The containment heat removal systems that are assumed to be available are one RHR heat exchanger, one containment spray pump, and two CFCUs. Further, loss of offsite power delays the actuation times of the safeguards equipment due to the required diesel startup time after receipt of the safety injection signal.

The postulated RCS break results in a rapid release of mass and energy to the containment with a resulting rapid rise in both the containment pressure and temperature. This rapid rise in containment pressure results in the generation of a containment Hi-I signal at 1.1 seconds and a containment Hi-2 signal at 4.4 seconds.

The containment pressure continues to rise rapidly in response to the release of mass and energy until the end of blowdown at 26.6 seconds. The end of blowdown marks a time when the initial inventory in the RCS has been exhausted and a slow process of filling the RCS downcomer in preparation for reflood has begun. Since the mass and energy release during this period is low, pressure decreases slightly and then increases in response to the reflood mass and energy release out to a second peak which occurred at 100 seconds.

The turn around in containment pressure at 100 seconds is a result of the initiation of the containment spray pump at 89.4 seconds and the containment fan cooler units (CFCUs) at 101.1 seconds. Reflood continues at a reduced flooding rate due to the buildup of mass in the RCS core which offsets the downcomer head. This reduction in flooding rate and the continued action of the CFCUs and Spray leads to a slowly decreasing pressure out to the end of reflood, which occurs at 186.4 seconds.

At this juncture, by design of the Reference 2 model, energy removal from the SG secondary side begins at a very high rate, resulting in a rise in containment pressure from 186.4 seconds out to 449.8 seconds when the ultimate peak pressure of 41.6 psig is reached. Energy continues to be removed from the secondary side of the faulted loop and intact loop steam generators until 1429.2 seconds. The containment pressure at the end of this steam generator energy release period is similar to peak pressure. After 1429.2 seconds, the containment pressure decreases through the initiation of cold leg recirculation at 1748.3 seconds out to 4141.6 seconds when the containment spray is terminated from the RWST. Without crediting recirculation spray, the containment pressure and temperature will begin to increase out to approximately 30,000 seconds.

At this time, the energy removal from the two operating CFCUs exceeds the energy release and the pressure and temperature turn around. This trend continues to the end of the transient at lx I07 seconds. This can be WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-19 seen in Figures 6.3-4 through 6.3-6. As with Unit 1 and the "no recirculation spray" assumption, this is not acceptable from both the aspect of GDC 38 or EQ requirements, but is provided to demonstrate the need for recirculation spray under the proposed CFCU configuration.

When 1974.8 gpm of recirculation spray flow is modeled for Salem Unit 2 beginning at 4441.6 seconds (which is a 5 minute delay from the time that the injection spray was terminated to allow the operators enough time to reposition the necessary valves), the containment pressure and temperature do not increase and the containment conditions at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are significantly lower. The detailed containment conditions can be seen in Table 6.3-4 and Figures 6.3-10 through 6.3-12 for the containment pressure, steam temperature and sump temperature. Figure 6.3-11 shows that there are two periods of time where the steam temperature exceeds the temperature profile. The first is from about 1500 seconds to about 3500 seconds and the other is from about 5000 seconds to 10,000 seconds. Therefore, the steam temperature transient with recirculation spray exceeds the profile for about 7000 seconds (i.e. approximately I hour 57 minutes).

March 2004 WCAP-I 6193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDIVS 2000 031504

6-20 Jl Table 6.3-1 Double-Ended Pump Suction Break Sequence of Events (Salem Unit 1)

J Time (sec) Event Description 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 1.1 Containment HI-I Pressure Setpoint Reached 3.6 Low Pressurizer Pressure SI Setpoint = 1715 psia Reached (Safety Injection Begins coincident with Low Pressurizer Pressure SI Setpoint) 4.6 Containment HI-2 Pressure Setpoint Reached 16.5 Broken Loop Accumulator Begins Injecting Water 16.8 Intact Loop Accumulator Begins Injecting Water 26.2 End of Blowdown Phase II I

35.6 Pumped Safety Injection Begins (after a 32 second delay from the setpoint)

-le 54.0 Broken Loop Accumulator Water Injection Ends i

55.9 Intact Loop Accumulator Water Injection Ends 89.6 Containment Spray (RWST) Begins Pumps 101.1 Containment Fan Coolers Actuate i

187.3 End of Reflood for MIN SI Case 461.0 Peak Temperature Occurs 647.7 Mass and Energy Release Assumption: Broken Loop SG Equilibration to 51.7 psia 1411.1 Mass and Energy Release Assumption: Intact Loop SG Equilibration to 41.7 psia 1748.3 Cold Leg Recirc Begins 4141.6 Containment Spray from RWST is Terminated ,

4441.6 Recirculation Spray Begins 1.01E+7 Transient Modeling Terminated jI WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-21 Table 6.3-2 Double-Ended Pump Suction Break Sequence of Events (Salem Unit 2)

Time (see) Event Description 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 1.1 Containment HI-1 Pressure Setpoint Reached 3.6 Low Pressurizer Pressure SI Setpoint = 1715 psia Reached (Safety Injection Begins co-incident with Low Pressurizer Pressure SI Setpoint) 4.4 Containment HI-2 Pressure Setpoint Reached 16.8 Broken Loop Accumulator Begins Injecting Water 17.1 Intact Loop Accumulator Begins Injecting Water 26.6 End of Blowdown Phase 35.6 Pumped Safety Injection Begins (after a 32 second delay from the setpoint) 54.9 Broken Loop Accumulator Water Injection Ends 57.4 Intact Loop Accumulator Water Injection Ends 89.4 Containment Spray Pump (RWST) Begins 101.1 Containment Fan Coolers Actuate 186.4 End of Reflood for MIN SI Case 449.7 Peak Temperature Occurs 449.8 Peak Pressure Occurs 638.9 Mass and Energy Release Assumption: Broken Loop SG Equilibration to 51.7 psia 1429.2 Mass and Energy Release Assumption: Intact Loop SG Equilibration to 41.7 psia 1748.3 Cold Leg Recirc Begins 4141.6 Containment Spray from RWST is Terminated 4441.6 Recirculation Spray Begins 1.0E+7 Transient Modeling Terminated WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-22 J Table 6.3-3 LOCA Containment Response Results (Loss of Offsite Power Assumed)

Peak Pressure Temperature Peak Press. Temp. (psig) (OF)

Case (psig) (OF) @ 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> @ 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Unit 1 40.1 @ 260.8 @ 16.7 208.4 DEPS Break 461.0 sec 461.0 sec Minimum Safeguards 4 Model F SGs Unit 1 40.1 @ 260.8 @ 7.3 164.9 DEPS Break 461.0 sec 461.0 sec Minimum A Safeguards with Recirculation Spray Model F SGs Unit 2 41.6 @ 263.1 @ 16.8 208.4 DEPS Break 449.8sec 449.7sec Minimum Safeguards Model 51 SGs Unit 2 41.6 @ 263.1 @ 7.3 164.9 DEPS Break 449.8sec 449.7sec Minimum Safeguards with Recirculation Spray Model 51 SGs March 2004 16193-NP WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000 031504

6-23 PWTRG 0 0 0 CONTAINMENT PRESSURE 50 40 -

c_

0 30-a) _

L._

=3 -

10 Time (s)

Figure 63-1 Containment Pressure - Double-ended Pump Suction Break at Salem Unit 1 WITHOUT Recirculation Spray WCAP-16193-NP March 2004 Official record siored electronically in EDMS 2000-031504

6-24 I I TSTM 0 0 0 STEAM TEMPERATURE

- - - -YVALUE 1 0 0 Temperature Profile l 400 -

350 -

f \

I \

I I

'--'300 0-., - I \

CD I -

-D 250-

.),

CL E 200- I' 150 -

I I .11111 I I I11111 I1 111111 I I .111t11 I I 111111 I11 111 I I1111 I I IH1 1 I I I 11111 100

-2 -1 0 I 2 3 4 5 6 7 8 10 10 10 10 10 10 10 10 10 10 10 Time (s) r Figure 6.3-2 Containment Temperature - Double-ended Pump Suction Break at Salem Unit 1 WITHOUT Recirculation Spray March 2004 WCAP- 16193-NP WCAP-1 61 93-NP March 2004 Offcialrecordstored ectronically inEDMS2000031504

6-25 TWT R 0 0 0 WATER TEMPERATURE 260 -_

240 -_

220 - _

CD 200 _

L.-

0 180- /

- 160-140 -

120 100 - I I If II ..

3 10 Time (s)

Figure 6.3-3 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit I WITHOUT Recirculation Spray March 2004 WCAP- 16193-NP WCAP-16193-NP - March 2004 Official record stored electronically in EDMS 2000-031504

6-26 j.

PWTRG P 0 0 0 CONTAINMENT PRESSURE

( '

50-40-co r

I-L30-a) co 2 10 -

0 .4 I I U I I I I I I

-2 -1 0 1 12 13 4 5 6 '7 B 10 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-4 Containment Pressure - Double-ended Pump Suction Break at Salem Unit 2 WITHOUT Recirculation Spray WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-27 TSTM 0 0 0 STEAM TEMPERATURE

--- - YVALUE 1 0 0 Temperature Profile 400 - _

350 - _

Lo_

300-a> _

Ad~250 -_

a)

E 200-a) w -

150- _ _

100- 1111 ll 3

10 Time (s)

Figure 6.3-5 Containment Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITHOUT Recirculation Spray WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-28 TWT R 0 0 0 WATER TEMPERATURE r!

300 250 -

U-

-J a)

-c 200-0~

E 150 -

I IIII I II1 I I I I11 II I I IliII1 I II I IIIll I f III I I I I 111I I I I I I I I I! I I I III1 100 I I I I I I I I I I

-2 -1 0 1 2 3 4 5 6 7 a 10 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-6 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITHOUT Recirculation Spray March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000 031504

6-29 I

I PWTRG P 0 0 0 CONTAINMENT PRESSURE 50 -

Y 40

.0 30 Cn20 a)

CL 10 I i I II I II I I I I Il I 11t I I I I 11111 11111I II IIll I I II I Ie lII I I i 0 l I I I I

-2 -1 0 .1 2 3 I4 I5 I6 7 8 10 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-7 Containment Pressure - Double-ended Pump Suction Break at Salem Unit 1 WITH Recirculation Spray WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-30 I

- TSTM 0 0 0 STEAM TEMPERATURE

-- YVALUE 1 0 0 Temperature Prof i Ie 400 -

350 -

I \

I \

~ 300 I I CD II L_

-> 250 0) 0~L_

E200 150 I IIIII I I I,,,, ,,,, I I ,,,,,,, I II,,III I I I I, I,II , I I ,I111111 I I I 1 1111 100 I I I I I

-2 -t 0 1 2 3 4 II 5 I 6 I 7 1 10 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-8 Containment Temperature - Double-ended Pump Suction Break at Salem Unit I WITH Recirculation Spray WCAP-16193-NP March 2004 Offcial record stored Electronically in EDMS 2000 031504

6-31

- TWTR 0 0 0 WATER TEMPERATURE 260 240 220 200 0)

• 180 a)

" 160 140 120 100 I I I IIft If

-2 -1 0 1 2 3 4 5 6 7 8 10 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-9 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit 1 WITH Recirculation Spray WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-32

-4 PWTRG 0 0 0 CONTAINMENT PRESSURE 50-40- j U,

C .en L-E 20-1n CL- -

10 0

I . I . . I II . . I . ...I . . . . III. . . . . - ... . L. . I . I I . . .. ..I . . . II III

-2 4 5 6 7 8 10 10 10 10 10 10 10 10 10 10 10 -

Time (s)

Figure 63-10 Containment Pressure - Double-ended Pump Suction Break at Salem Unit 2 WITH Recirculation Spray March 2004 WCAP- 161 93-NP WCAP-16193-NP March 2004 Officialrcordstoredelectronically inDMS2000431 MM

6-33 TSTM 0 0 0 STEAM TEMPERATURE

- - - -YVALUE 1 0 0 Temperature Profile 400-350 -

I  %

LL - I  %

` 300 - I v aQ I  %

= 2 -

I.-.

CU CA_

E 200-11\1 111 1 111 1 I111 111 11 111 11 111 111 LIIIL Ia 1 150 -

100 .4. -t 0 1 2 3 1 1 1I7

-2 It o 1 2 3 4 5 6 1 10 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-11 Containment Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITH Recirculation Spray WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-34 I

I TWTR T 0 0 0 WATER TEMPERATURE 280 -

260 -

240 -

220 -

, 200-

'- 180 -

M_

E 160 -

140 -

120 -

I I , , , , , .- ,,,

, .I,,,

' lrX l, I I I llr., -s -[l 100 - , ,, ,,, ,,, ,, ,,,, ,, , I0, , 3. , , ,,, I , , ,, . ..

• I lo-2 -I 0 1 2  : 4 5 6I 7 8 10 10 10 10 10 10 10 10 10 10 Time (s)

Figure 6.3-12 Containment Sump Temperature - Double-ended Pump Suction Break at Salem Unit 2 WITH Recirculation Spray March 2004 16193-NP WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-35 Table 6.34 Containment Response Time History LOCA DEPS Minimum Safeguards Unit I with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 1.OOOOOOOE-03 3.0000001E-01 1.2000000E+02 1.2000000E+02 5.0000101E-01 2.7260156E+00 1.4165230E+02 1.8137114E+02 1.0000020E+00 5.1062460E+00 1.6173720E+02 1.9665706E+02 2.0000031E+00 9.4392405E+00 1.9153883E+02 2.1013640E+02 3.0000041E+00 1.3097981E+01 2.1036015E+02 2.1741302E+02 4.0000048E+00 1.5868888E+01 2.2062317E+02 2.2213249E+02 5.0000062E+00 1.8069145E+01 2.2629613E+02 2.2569394E+02 6.0000072E+00 1.9960789E+01 2.2968062E+02 2.2866058E+02 7.0000081E+00 2.1704916E+01 2.3197597E+02 2.3121120E+02 8.0000086E+00 2.3342367E+01 2.3356621E+02 2.3341003E+02 9.0000095E+00 2.4860209E+01 2.3451663E+02 2.3545322E+02 1.0000011E+01 2.6309299E+01 2.3633391E+02 2.3723018E+02 1.1000012E+01 2.7723980E+01 2.3938966E+02 2.3881845E+02 1.2000013E+01 2.9036766E+01 2.4211263E+02 2.4026927E+02 1.3000014E+01 3.0265560E+01 2.4457111E+02 2.4157213E+02 1.4000015E+01 3.1423462E+01 2.4681372E+02 2.4272820E+02 1.5000016E+01 3.2516171E+01 2.4886853E+02 2.4375357E+02 1.6000017E+01 3.3547142E+01 2.5075580E+02 2.4465933E+02 1.7000017E+01 3.4505260E+01 2.5246750E+02 2.4544768E+02 1.8000019E+01 3.5360104E+01 2.5396187E+02 2.4614850E+02 1.9000019E+01 3.6008636E+01 2.5507603E+02 2.4669174E+02 2.0000021E+01 3.6436409E+01 2.5580182E+02 2.4710703E+02 2.1000023E+01 3.6746380E+01 2.5632297E+02 2.4760428E+02 2.2000023E+01 3.6890816E+01 2.5656421E+02 2.4798822E+02 2.3000025E+01 3.6932072E+01 2.5663239E+02 2.4835863E+02 2.4000025E+01 3.6896519E+01 2.5657230E+02 2.4859210E+02 2.5000027E+01 3.6807278E+01 2.5642252E+02 2.4865271E+02 2.6000027E+01 3.6673508E+01 2. '619772E+02 2.4865120E+02 2.7000029E+01 3.6517330E+01 2.5593443E+02 2.4864276E+02 2.8000029E+01 3.6369461E+01 2.5568431E+02 2.4863477E+02 2.9000031E+01 3.6234234E+01 2.5545480E+02 2.4862434E+02 3.0000031E+01 3.6108845E+01 2.552413BE+02 2.4861436E+02 3.1000032E+01 3.5992043E+01 2.5504201E+02 2.4860246E+02 3.2000034E+01 3.5882744E+01 2.5485495E+02 2.4859102E+02 3.3000034E+01 3.5780552E+01 2.5467963E+02 2.4857799E+02 3.4000034E+01 3.5684834E+01 2.5451505E+02 2.4856465E+02 3.5000034E+01 3.5619915E+01 2.5440268E+02 2.4803056E+02 3.6000038E+01 3.5582115E+01 2.5433661E+02 2.4720964E+02 3.7000038E+01 3.5554710E+01 2.5428833E+02 2.4630370E+02 3.8000038E+01 3.5530315E+01 2.5424522E+02 2.4542055E+02 3.9000038E+01 3.5507725E+01 2.5420523E+02 2.4457846E+02 4.0000042E+01 3.5486542E+01 2.5416766E+02 2.4377774E+02 4.1000042E+01 3.5466942E+01 2.5413283E+02 2.4301257E+02 4.2000042E+01 3.5448586E+01 2.5410013E+02 2.4228400E+02 4.3000046E+01 3.5431641E+01 2.5406989E+02 2.4158641E+02 4.4000046E+01 3.5415802E+01 2.5404155E+02 2.4092123E+02 4.5000046E+01 3.5401234E+01 2.5401541E+02 2.4028320E+02 4.6000046E+01 3.5387657E+01 2.5399101E+02 2.3967398E+02 4.7000050E+01 3.5375229E+01 2.5396860E+02 2.3908859E+02 4.8000050E+01 3.5363686E+01 2.5394772E+02 2.3852901E+02 March 2004 WCAP- 161 93-NP WCAP-16193-NP March 2004 Official record storod electronically in EDMS 2000 031504

6-36 Table 6.3-4 Containment Response Time History LOCA DEPS Minimum Safeguards J (cont.) Unit I with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 4.9000050E+01 3.5353180E+01 2.5392865E+02 2.3799042E+02 5.0000050E+01 3.5343464E+01 2.5391095E+02 2.3747504E+02 5.1000053E+01 3.5334686E+01 2.5389488E+02 2.3697826E+02 5.2000053E+01 3.5326611E+01 2.5388005E+02 2.3650243E+02 5.3000053E+01 3.5319378E+01 2.5386668E+02 2.3604315E+02 5.4000053E+01 3.5311989E+01 2.5385307E+02 2.3561331E+02 -

5.5000057E+01 3.5300194E+01 2.5382684E+02 2.3530933E+02 5.6000057E+01 3.5292027E+01 2.5380034E+02 2.3507285E+02 5.7000057E+01 3.5335617E+01 2.5382901E+02 2.3516068E+02 5.8000057E+01 3.5404121E+01 2.5390103E+02 2.3517375E+02 5.9000061E+01 3.5472454E+01 2.5397266E+02 2.3519133E+02 6.0000061E+01 3.5540066E+01 2.5404298E+02 2.3520706E+02 6.1000061E+01 3.5606815E+01 2.5411172E+02 2.3522562E+02 6.2000065E+01 3.5672672E+01 2.5417886E+02 2.3524348E+02 6.3000065E+01 3.5737595E+01 2.5424431E+02 2.3526189E+02 6.4000069E+01 3.5801594E+01 2.5430811E+02 2.3527962E+02 6.5000069E+01 3.5864700E+01 2.5437032E+02 2.3529790E+02 -

6.6000069E+01 3.5927032E+01 2.5443111E+02 2.3531552E+02 6.7000069E+01 3.5988567E+01 2.5449049E+02 2.3533368E+02 6.8000069E+01 3.6049355E+01 2.5454854E+02 2.3535121E+02 6.9000069E+01 3.6109375E+01 2.5460519E+02 2.3536926E+02 7.0000069E+01 3.6168671E+01 2.5466058E+02 2.3538670E+02 7.1000069E+01 3.6227226E+01 2.5471465E+02 2.3540466E+02 7.2000076E+01 3.6285084E+01 2.5476746E+02 2.3542204E+02 7.3000076E+01 3.6342228E+01 2.5481902E+02 2.3543991E+02 7.4000076E+01 3.6398697E+01 2.5486937E+02 2.3545721E+02 7.5000076E+01 3.6450424E+01 2.5491783E+02 2.3548083E+02 7.6000076E+01 3.6497726E+01 2.S496397E+02 2.3549503E+02 7.7000076E+01 3.6522552E+01 2.5500514E+02 2.3551445E+02 7.8000076E+01 3.6545975E+01 2.5504501E+02 2.3553262E+02 7.9000076E+01 3.6568787E+01 2.5508382E+02 2.3554945E+02 8.0000084E+01 3.6590973E+01 2.5512154E+02 2.3556860E+02 8.1000084E+01 3.6612629E+01 2.5515833E+02 2.3558339E+02 8.2000084E+01 3.6633797E+01 2.5519427E+02 2.3560089E+02 8.3000084E+01 3.6654354E+01 2.5522917E+02 2.3561945E+02 8.4000084E+01 3.6674374E+01 2.5526314E+02 2.3563690E+02 8.5000084E+01 3.6693821E+01 2.5529611E+02 2.3565538E+02 8.6000084E+01 3.6712757E+01 2.5532820E+02 2.3567278E+02 8.7000092E+01 3.6731155E+01 2.5535938E+02 2.3569116E+02 8.8000092E+01 3.6749077E+01 2.5538971E+02 2.3570850E+02 8.9000092E+01 3.6766495E+01 2.5541919E+02 2.3572681E+02 9.0000092E+01 3.6778671E+01 2.5543973E+02 2.3575922E+02 9.1000092E+01 3.6783600E+01 2.5544791E+02 2.3579132E+02 9.2000092E+01 3.6788151E+01 2.5545546E+02 2.3582971E+02 9.3000092E+01 3.6792297E+01 2.5546231E+02 2.3586685E+02 9.4000092E+01 3.6796066E+01 2.5546852E+02 2.3590382E+02 9.5000099E+01 3.6799480E+01 2.5547415E+02 2.3594064E+02 9.6000099E+01 3.6802547E+01 2.5547917E+02 2.3597729E+02 9.7000099E+01 3.6805286E+01 2.5548364E+02 2.3601378E+02 9.8000099E+01 3.6807701E+01 2.5548756E+02 2.3605031E+02 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-IA7 e?> I Table 6.34 Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit 1 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 9.9000099E+01 3.6809826E+01 2.5549100E+02 2.3608649E+02 1.0000010E+02 3.6811657E+01 2.5549393E+02 2.3612251E+02 1.0100010E+02 3.6813221E+01 2.5549640E+02 2.3615837E+02 1.0200011E+02 3.6809452E+01 2.5548984E+02 2.3619455E+02 1.0300011E+02 3.6804913E+01 2.5548196E+02 2.3622992E+02 1.0400011E+02 3.6800186E+01 2.5547377E+02 2.3626541E+02 1.0500011E+02 3.6795261E+01 2.5546524E+02 2.3630319E+02 1.0600011E+02 3.6790127E+01 2.5545634E+02 2.3633835E+02 1.0700011E+02 3.6784817E+01 2.5544717E+02 2.3637576E+02 1.0800011E+02 3.6779324E+01 2.5543767E+02 2.3641061E+02 1.0900011E+02 3.6773682E+01 2.5542792E+02 2.3644769E+02 1.1000011E+02 3.6767868E+01 2.5541788E+02 2.3648248E+02 1.1100011E+02 3.6761929E+01 2.5540762E+02 2.3651784E+02 1.1200011E+02 3.6755856E+01 2.5539714E+02 2.3655325E+02 1.1300011E+02 3.6749691E+01 2.5538651E+02 2.3658643E+02 1.1400011E+02 3.6743439E+01 2.5537572E+02 2.3662123E+02 1.1500011E+02 3.6737083E+01 2.5536475E+02 2.3665622E+02 1.1600011E+02 3.6730640E+01 2.5535362E+02 2.3669069E+02 1.1700011E+02 3.6724113E+01 2.5534236E+02 2.3672534E+02 1.1800012E+02 3.6717514E+01 2.5533098E+02 2.3675949E+02 1.1900012E+02 3.6710854E+01 2.5531949E+02 2.3679381E+02 1.2000012E+02 3.6704140E+01 2.5530791E+02 2.3682762E+02 1.2100012E+02 3.6697376E+01 2.5529623E+02 2.3686162E+02 1.2200012E+02 3.6690578E+01 2.5528452E+02 2.3689511E+02 1.2300012E+02 3.6683750E+01 2.5527274E+02 2.3692877E+02 1.2400012E+02 3.6676907E+01 2.5526091E+02 2.3696196E+02 1.2500013E+02 3.6670044E+01 2.5524907E+02 2.3699530E+02 1.2600013E+02 3.6663177E+03 2.5523721E+02 2.3702818E+02 1.2700013E+02 3.6656307E+01 2.5522536E+02 2.3706122E+02 1.2800012E+02 3.6649452E+01 2.5521352E+02 2.3709378E+02 1.2900014E+02 3.6642605E+01 2.5520171E+02 2.3712651E+02 1.3000014E+02 3.6635780E+01 2.5518991E+02 2.3715878E+02 1.3100014E+02 3.6628983E+01 2.5517818E+02 2.3719119E+02 1.3200014E+02 3.6622219E+01 2.5516649E+02 2.3722318E+02 1.3300014E+02 3.6615494E+01 2.5515486E+02 2.3725529E+02 1.3400014E+02 3.6608810E+01 2.5514331E+02 2.3728697E+02 1.3500014E+02 3.6602177E+01 2.5513184E+02 2.3731880E+02 1.3600014E+02 3.6595600E+01 2.5512047E+02 2.3735020E+02 1.3700014E+02 3.6589081E+01 2.5510918E+02 2.3738174E+02 1.3800014E+02 3.6582626E+01 2.5509802E+02 2.3741286E+02 1.3900014E+02 3.6576237E+01 2.5508696E+02 2.3744412E+02 1.4000014E+02 3.6569927E+01 2.5507603E+02 2.3747496E+02 1.4100014E+02 3.6563686E+01 2.5506522E+02 2.3750595E+02 1.4200014E+02 3.6557533E+01 2.5505457E+02 2.3753651E+02 1.4300014E+02 3.6551460E+01 2.5504404E+02 2.3756723E+02 1.4400015E+02 3.6545475E+01 2.5503366E+02 2.3759753E+02 1.4500015E+02 3.6539581E+01 2.5502344E+02 2.3762798E+02 1.4600015E+02 3.6533787E+01 2.5501338E+02 2.3765802E+02 1.4700015E+02 3.6528088E+01 2.5500348E+02 2.3768820E+02 1.4800015E+02 . . .

3.6522491E+01 2.5499377E+02 2. 3771799E+02 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-38 I

Table 6.34 Containment Response rime History LOCA DEPS Minimum Safeguards (cont.) Unit 1 with Reirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F I 1.4900015E+02 3.6516994E+01 2.5498422E+02 2.3774791E+02 1.5000015E+02 3.65116083+01 2.5497485E+02 2.3777745E+02 1.5100015E+02 3.65063258+01 2.5496567E+02 2.3780711E+02 1.5200015E+02 3.65011568+01 2.5495668E+02 2.3783641E+02 1.5300015E+02 3.64960983+01 2.5494788B+02 2.3786583E+02 1.5400015E+02 3.64911543+01 2.5493927E+02 2.3789488E+02 J 1.5500015E+02 3.64863203+01 2.5493085E+02 2.3792406E+02 1.56000153+02 3.6481609B+01 2.5492262E+02 2.3795288E+02 1.5700015E+02 3.64770133+01 2.5491461E+02 2.3798183E+02 1.5800015E+02 3.64725423+01 2.5490680E+02 2.3801041E+02 1.5900015E+02 3.6468189E+01 2.5489920E+02 2.3803912E+02 1.6000017E+02 3.64639663+01 2.5489182E+02 2.3806747E+02 1.61000173+02 3.64598623+01 2.5488463E+02 2.3809595E+02 1.6200017E+02 3.64558873+01 2.5487769E+02 2.3812408E+02 1.6300017E+02 3.6452042B+01 2.5487094E+02 2.3815234E+02 1.6400017E+02 3.64483263+01 2.5486443E+02 2.3818027E+02 1.6500017E+02 3.6444736B+01 2.5485812E+02 2.3820830E+02 1.6600017E+02 3.6441284E+01 2.5485205E+02 2.3823601E+02 1.6700017E+02 3.6437958E+01 2.5484621E+02 2.3826382E+02 1.6800017E+02 3.64347723+01 2.5484059E+02 2.3829132E+02 -J 1.6900017E+02 3.6431713E+01 2.5483519E+02 2.3831894E+02 1.7000017E+02 3.6428799E+01 2.54830033+02 2.3834622E+02 1.7100017E+02 3.64260103+01 2.5482510E+02 2.3837363E+02 1.7200017E+02 3.6423367E+01 2.5482042E+02 2.3840071E+02 1.7300017E+02 3.6420879E+01 2.5481601E+02 2.3842792E+02 1.7400017E+02 3.6418568E+01 2.5481189E+02 2.3845482E+02 1.7500018E+02 3.64164623+01 2.5480812E+02 2.3848186E+02 1.7600018E+02 3.64145893+01 2.5480475E+02 2.3850862E+02 1.7700018E+02 3.6412937E+01 2.5480176E+02 2.3853558E+02 1.7800018E+02 3.6411526E+01 2.5479918E+02 2.3856230E+02 1.7900018E+02 3.6410355E+01 2.5479701E+02 2.3858926E+02 1.8000018E+02 3.64094353+01 2.5479527E+02 2.3861604E+02 1.8100018E+02 3.64087643+01 2.5479396E+02 2.3864307E+02 1.8200018E+02 3.6408352E+01 2.5479309E+02 2.3866994E+02 J

1.8300018E+02 3.6408184E+01 2.5479265E+02 2.3869708E+02 1.8400018E+02 3.6408279E+01 2.5479263E+02 2.3872946E+02 1.8500018E+02 3.6408596E+01 2.5479301E+02 2.3875655E+02 1.8600018E+02 3.6409145E+01 2.5479379E+02 2.3878383E+02 1.8700018E+02 3.6409916E+01 2.5479495E+02 2.3881088E+02 1.8800018E+02 3.6416286E+01 2.5480566E+02 2.3884401E+02 1.8900018E+02 3.64260183+01 2.5482211E+02 2.3888037E+02 1.9000020E+02 3.6435829E+01 2.3891797E+02 -4 2.5483870E+02 1.9100020E+02 3.6445728E+01 2.5485545E+02 2.3895572E+02 1.9200020E+02 3.6455685E+01 2.5487228E+02 2.3899428E+02 1.9300020E+02 3.6465733E+01 2.5488925E+02 2.3903183E+02 1.9400020E+02 3.64758303+01 2.5490633E+02 2.3907018E+02 1.9500020E+02 3.6486019E+01 2.5492354E+02 2.3910753E+02 1.9600020E+02 3.6496258E+01 2.5494083E+02 2.3914568E+02 1.9700020E+02 3.6506580E+01 2.5495827E+02 2.3918285E+02 -

1.9800020E+02 3.6516956E+01 2.5497580E+02 2.3922079E+02 March 2004 WOAf-a I Id95-NP WLAV- st9-NP Marh 2004 Offcial record stored electronically in EDMS 2000 031504

6-39 Table 6.34 Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit 1 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 1.9900020E+02 3.6527386E+01 2.5499341E+02 2.3925778E+02 2.0900020E+02 3.6633911E+01 2.5517308E+02 2.3960063E+02 2.1900020E+02 3.6747734E+01 2.5536473E+02 2.3996521E+02 2.2900020E+02 3.6865688E+01 2.5556288E+02 2.4031891E+02 2.3900020E+02 3.6987389E+01 2.5576685E+02 2.4066481E+02 2.4900020E+02 3.7112648E+01 2.5597626E+02 2.4100420E+02 2.5900021E+02 3.7241314E+01 2.5619080E+02 2.4133661E+02 2.6900021E+02 3.7371418E+01 2.5640714E+02 2.4165730E+02 2.7900021E+02 3.7505718E+01 2.5662985E+02 2.4198532E+02 2.8900021E+02 3.7641098E+01 2.5685373E+02 2.4229327E+02 2.9900021E+02 3.7777912E+01 2.5707928E+02 2.4259952E+02 3.0900021E+02 3.7915432E+01 2.5730536E+02 2.4291023E+02 3.1900021E+02 3.8054379E+01 2.5753308E+02 2.4320731E+02 3.2900021E+02 3.8194233E+01 2.5776163E+02 2.4350847E+02 3.3900021E+02 3.8334248E+01 2.5798975E+02 2.4379712E+02 3.4900021E+02 3.8473942E+01 2.5821664E+02 2.4409009E+02 3.5900021E+02 3.8614056E+01 2.5844354E+02 2.4437105E+02 3.6900021E+02 3.8753578E+01 2.5866879E+02 2.4465623E+02 3.7900021E+02 3.8892998E+01 2.5889319E+02 2.4493008E+02 3.8900021E+02 3.9030643E+01 2.5911407E+02 2.4520836E+02 3.9900021E+02 3.9168457E+01 2.5933459E+02 2.4547566E+02 4.0900021E+02 3.9304729E+01 2.5955197E+02 2.4574715E+02 4.1900021E+02 3.9439934E+01 2.5976703E+02 2.4600844E+02 4.2900021E+02 3.9600636E+01 2.6002222E+02 2.4627594E+02 4.3900021E+02 3.9764610E+01 2.6028174E+02 2.4652217E+02 4.4900021E+02 3.9926823E+01 2.6053760E+02 2.4676793E+02 4.5900021E+02 4.0084110E+01 2.6078479E+02 2.4701418E+02 4.6900021E+02 4.0050648E+02 2.60729°5E+02 2.4731490E+02 4.7900021E+02 3.9994385E+01 2.6063898E+02 2.4760281E+02 4.8900024E+02 3.9943695E+01 2.6055673E+02 2.4788303E+02 4.9900024E+02 3.9897419E+01 2.6048138E+02 2.4816048E+02 5.9900024E+02 3.9602200E+01 2.5999207E+02 2.5053304E+02 6.9900024E+02 3.9490055E+01 2.5979343E+02 2.5246033E+02 7.9900024E+02 3.9436481E+01 2.5968823E+02 2.5403699E+02 8.9900024E+02 3.9448772E+01 2.5968863E+02 2.5538013E+02 9.9900024E+02 3.9506386E+01 2.5976163E+02 2.5650922E+02 1.0990002E+03 3.9603664E+01 2.5989801E+02 2.5749307E+02 1.1990002E+03 3.9730034E+01 2.6008054E+02 2.5836865E+02 1.2990002E+03 3.9877201E+01 2.6029568E+02 2.5914996E+02 1.3990002E+03 4.0039463E+01 2.6053415E+02 2.5986090E+02 1.4990002E+03 3.9538601E+01 2.5971658E+02 2.5694885E+02 1.5990002E+03 3.8848415E+01 2.5858279E+02 2.5304994E+02 1.6990002E+03 3.8203465E+01 2.5750647E+02 2.4955194E+02 1.7990002E+03 3.7569813E+01 2.5643890E+02 2.4802039E+02 1.8990002E+03 3.6946438E+01 2.5537949E+02 2.4825662E+02 1.9990002E+03 3.6344620E+01 2.5434198E+02 2.4844145E+02 2.0990002E+03 3.5757961E+01 2.5331633E+02 2.4859222E+02 2.1990002E+03 3.5186543E+01 2.5230331E+02 2.4871127E+02 2.2990002E+03 3.4626736E+01 2.5129712E+02 2.4880214E+02 2.3990002E+03 3.4079124E+01 2.5029924E+02 2.4886653E+02 WCAP-16193-NP March 2004 Official record stored eectronically in EDMS 2000-031504

6-40 Table 6.34 Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit I with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 2.4990002E+03 3.3540970E+01 2.4930510E+02 2.4890723E+02 2.5990002E+03 3.3013031E+01 2.4831644E+02 2.4892546E+02 2.6990002E+03 3.24930733+01 2.4732938E+02 2.4892352E+02 2.7990002E+03 3.1981947E+01 2.46345763+02 2.4890233E+02 2.8990002E+03 3.1477737E+01 2.4536217E+02 2.4886378E+02 I 2.9990002E+03 3.0981331E+01 2.4438048E+02 2.4880859E+02 I 3.0990002E+03 3.0491455E+01 2.4339839E+02 2.4847218E+02 3.1990002E+03 3.0010233E+01 2.4242035E+02 2.4790459E+02 3.2990002E+03 2.9535343E+01 2.4144186E+02 2.4734714E+02 3.3990002E+03 2.9065716E+01 2.4046080E+02 2.4679865E+02 3.4990002E+03 2.8600178E+01 2.3947475E+02 2.4625851E+02 3.59900023+03 2.8139786E+01 2.38485903+02 2.4572610E+02 3.6990002E+03 2.7584276E+01 2.37276413+02 2.4491057E+02 3.7990002E+03 2.6965515E+01 2.3590576E+02 2.4385629E+02 3.8990002E+03 2.6365526E+01 2.3455046E+02 2.4282724E+02 3.9990002E+03 2.5781137E+01 2.3320457E+02 2.4182153E+02 4.9990005E+03 2.5467739E+01 2.3246004E+02 2.3615184E+02 5.9990005E+03 2.4711176E+01 2.3067358E+02 2.3322934E+02 6.9990005E+03 2.3783638E+01 2.2841882E+02 2.3049898E+02 7.9990005E+03 2.2770773E+01 2.2586980E+02 2.2772287E+02 -_

8.9990000E+03 2.1790558E+01 2.2330971E+02 2.2505815E+02 9.9990000E+03 2.0837652E+01 2.2072533E+02 2.2250249E+02 1.9999000E+04 1.5545770E+01 2.0422050E+02 2.0209698E+02 2.9999000E+04 1.3084527E+01 1.9485435E+02 1.9120732E+02 3.9999000E+04 1.1282461E+01 1.8700775E+02 1.8419492E+02 4.9999000E+04 9.7582741E+00 1.7951279E+02 1.7853201E+02 5.9999000E+04 8.5464277E+00 1.7284229E+02 1.6771574E+02 6.9999000E+04 7.9333830E+0" 1.4917615E+02 1.6264641E+02 7.9999000E+04 7.5116539E+00 1.6652383E+02 1.5986708E+02 8.9999000E+04 7.1420197E+00 1.6410327E+02 1.5789368E+02 9.9999000E+04 6.8098474E+00 1.6184392E+02 1.5633223E+02 1.0999900E+05 6.4717684E+00 1.5945985E+02 1.5140636E+02 1.1999900E+05 6.3056817E+00 1.5826003E+02 1.4955331E+02 1.2999900E+05 6.2046227E+00 1.5752470E+02 1.4850555E+02 J

1.3999900E+05 6.1011190E+00 1.5676228E+02 1.4791800E+02 1.4999900E+05 6.0381112E+00 1.5629259E+02 1.4765912E+02 1.5999900E+05 5.9505854E+00 1.5563820E+02 1.4705800E+02 1.6999900E+05 5.8770161E+00 1.5508237E+02 1.4692900E+02 1.7999900E+05 5.8033247E+00 1.5452374E+02 1.4630753E+02 1.8999900E+05 5.7414117E+00 1.5404649E+02 1.4605373E+02 1.9999900E+05 5.6768575E+00 1.5354349E+02 1.4572557E+02 2.0999900E+05 5.6447368E+00 1.5330322E+02 1.4523669E+02 _J 2.1999900E+05 5.5292363E+00 1.5238893E+02 1.4488057E+02 2.2999900E+05 5.4688549E+00 1.5190778E+02 1.4463622E+02 2.3999900E+05 5.3858562E+00 1.5124127E+02 1.4432556E+02 2.4999900E+05 5.3273826E+00 1.5077419E+02 1.4378133E+02 2.5999900E+05 5.2801900E+0O 1.5039076E+02 1.4360468E+02 2.6999900E+05 5.2025514E300 1.4974837E+02 1.4317856E+02 2.7999900E+05 5.1234341E+00 1.4909151E+02 1.4285222E+02 2.8999900E+05 5.0720429E+00 1.4866269E+02 1.4243784E+02 March 2004 -

WCAP- 16193-NP WCAP-16193-NP March 2004 Offcial record stored electronicallb in EDMS 2000-031504

6-41 Table 6.3-4 Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit I with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 2.9999900E+05 5.0029111E+00 1.4807993E+02 1.4210835E+02 3.0999900E+05 4.9385910E+00 1.4753726E+02 1.4162247E+02 3.1999900E+05 4.8797202E+00 1.4703093E+02 1.4135573E+02 3.2999900E+05 4.8175278E+00 1.4649115E+02 1.4099384E+02 3.3999900E+05 4.7485585E+00 1.4588962E+02 1.4064523E+02 3.4999900E+05 4.6930542E+00 1.4540103E+02 1.4026433E+02 3.5999900E+05 4.6315389E+00 1.4485324E+02 1.3990932E+02 3.6999900E+05 4.5707202E+00 1.4430710E+02 1.3954803E+02 3.7999900E+05 4.5100060E+00 1.4375717E+02 1.3918646E+02 3.8999900E+05 4.4500704E+00 1.4320973E+02 1.3882401E+02 3.9999900E+05 4.3902178E+00 1.4265831E+02 1.3846220E+02 4.0999900E+05 4.3311605E+00 1.4210963E+02 1.3809969E+02 4.1999900E+05 4.2721529E+00 1.4155664E+02 1.3773784E+02 4.2999900E+05 4.2139592E+00 1.4100671E+02 1.3737527E+02 4.3999900E+05 4.1557841E+00 1.4045215E+02 1.3701337E+02 4.4999900E+05 4.0983644E+00 1.3990018E+02 1.3665076E+02 4.5999900E+05 4.0390520E+00 1.3932430E+02 1.3628275E+02 4.6999900E+05 3.9798856E+00 1.3874458E+02 1.3590523E+02 4.7999900E+05 3.9205589E+00 1.3815787E+02 1.3552539E+02 4.8999900E+05 3.8620405E+00 1.3757399E+02 1.3514378E+02 4.9999900E+05 3.8034835E+00 1.3698428E+02 1.3476236E+02 5.0999900E+05 3.6409869E+00 1.3529176E+02 1.3028830E+02 5.1999900E+05 3.5791481E+00 1.3464789E+02 1.2911061E+02 5.2999900E+05 3.5461357E+00 1.3431201E+02 1.2872115E+02 5.3999900E+05 3.5204611E+00 1.3405519E+02 1.2846901E+02 5.4999900E+05 3.4933145E+00 1.3378624E+02 1.2828516E+02 5.5999900E+05 3.4771163E+00 1.3363170E+02 1.2814478E+02 5.6999900E+05 3.4502132E+OA 1.'336435E+02 1.2799187E+02 5.7999900E+05 3.4281323E+00 1.3314337E+02 1.2793654E+02 5.8999900E+05 3.4128430E+00 1.3299763E+02 1.2777354E+02 5.9999900E+05 3.3916128E+00 1.3279294E+02 1.2759531E+02 6.0999900E+05 3.3735938E+00 1.3261484E+02 1.2749806E+02 6.1999900E+05 3.3529289E+00 1.3241527E+02 1.2734690E+02 6.2999900E+05 3.3411689E+00 1.3230734E+02 1.2723758E+02 6.3999900E+05 3.3165784E+00 1.3206030E+02 1.2710819E+02 6.4999900E+05 3.3009677E+00 1.3190846E+02 1.2704033E+02 6.5999900E+05 3.2782815E+00 1.3168372E+02 1.2687099E+02 6.6999900E+05 3.2624838E+00 1.3152867E+02 1.2679495E+02 6.7999900E+05 3.2443173E+00 1.3134641E+02 1.2667471E+02 6.8999900E+05 3.2265754E+00 1.3116847E+02 1.2655743E+02 6.9999900E+05 3.2089186E+00 1.3099104E+02 1.2644072E+02 7.0999900E+05 3.1913440E+00 1.3081407E+02 1.2632439E+02 7.1999900E+05 3.1738501E+00 1.3063757E+02 1.2620844E+02 7.2999900E+05 3.1564336E+00 1.3046149E+02 1.2609283E+02 7.3999900E+05 3.1390910E+00 1.3028578E+02 1.2597753E+02 7.4999900E+05 3.1218188E+00 1.3011043E+02 1.2586253E+02 7.5999900E+05 3.1046133E+00 1.2993539E+02 1.2574780E+02 7.6999900E+05 3.0874720E+00 1.2976064E+02 1.2563331E+02 7.7999900E+05 3.0703917E+00 1.2958612E+02 1.2551904E+02 7.8999900E+05 3.0533700E+00 1.2941185E+02 1.2540498E+02 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

642 -

Table 6.34 Containment Response Time History LOCA DEPS Minimum Safeguards -j (cont.) Unit 1 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 7.9999900E+05 3.0364044E+00 1.2923776E+02 1.2529109E+02 8.0999900E+05 3.0194931E+00 1.2906386E+02 1.2517738E+02 8.1999900E+05 3.0026340E+00 1.2889012E+02 1.2506383E+02 8.2999900E+05 2.9858253E+00 1.2871651E+02 1.2495041E+02 8.3999900E+05 2.9690657E+00 1.2854303E+02 1.2483713E+02 8.4999900E+05 2.9523535E+00 1.2836966E+02 1.2472396E+02 8.5999900E+05 2.9356875E+00 1.2819638E+02 1.2461091E+02 8.6999900E+05 2.9190667E+00 1.2802319E+02 1.2449795E+02 8.7999900E+05 2.9024899E+00 1.2785007E+02 1.2438509E+02 8.8999900E+05 2.8859558E+00 1.2767700E+02 1.2427232E+02 1-J 8.9999900E+05 2.8694642E+00 1.2750400E+02 1.2415961E+02 9.0999900E+05 2.8541934E+00 1.2733717E+02 1.2405628E+02 9.1999900E+05 2.8385956E+00 1.2716589E+02 1.2394580E+02 .- a 9.2999900E+05 2.8229558E+00 1.2699364E+02 1.2383414E+02 9.3999900E+05 2.8073316E+00 1.2682110E+02 1.2372221E+02 9.4999900E+05 2.7917364E+00 1.2664846E+02 1.2361022E+02 9.5999900E+05 2.7761745E+00 1.2647576E+02 1.2349822E+02 9.6999900E+05 2.7606480E+00 1.2630303E+02 1.2338625E+02 9.7999900E+05 2.7451572E+00 1.2613027E+02 1.2327428E+02 9.8999900E+05 2.7297025E+00 1.2595750E+02 1.2316235E+02

-d 9.9999900E+05 2.7147422E+00 1.2579842E+02 1.2304974E+02 1.9999990E+06 2.4768684E+00 1.2097065E+02 1.1700172E+02 2.9999990E+06 2.4380393E+00 1.1761262E+02 1.1469793E+02 3.9999990E+06 2.3855824E+00 1.1397727E+02 1.1243826E+02 4.9999990E+06 2.3760688E+00 1.1001505E+02 1.1014834E+02 5.9999990E+06 2.5356617E+00 1.0823864E+02 1.0651961E+02 6.9999990E+06 2.7736161E+00 1.0739161E+02 1.0596532E+02 7.9999990E+06 3.0092115E+00 1.0644176E+02 1.0541958E+02 -

8.9999990E+06 3.2432728E+00 1.0542276E+02 1.0492331E+02 9.9999990E+06 3.5016551E+00 1.0451715E+02 1.0440598E+02 1.0000000E+07 3.5016904E+00 1.0451775E+02 1.0440579E+02

_J

-J__j J

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504 J

643 Table 6.3-5 Containment Response Time History LOCA DEPS Minimum Safeguards Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 1.OOOOOOOE-03 3.0000001E-01 1.2000000E+02 1.2000000E+02 5.0000101E-01 2.7377696E+00 1.4175690E+02 1.8153883E+02 1.0000020E+00 5.1343589E+00 1.6196132E+02 1.9689900E+02 2.0000031E+00 9.5709763E+00 1.9239671E+02 2.1060091E+02 3.0000041E+00 1.3359940E+01 2.1180504E+02 2.1798988E+02 4.0000048E+00 1.6182543E+01 2.2211842E+02 2.2268262E+02 5.0000062E+00 1.8444284E+01 2.2791052E+02 2.2625830E+02 6.0000072E+00 2.0376295E+01 2.3131262E+02 2.2923253E+02 7.0000081E+00 2.2145123E+01 2.3356015E+02 2.3180357E+02 8.0000086E+00 2.3787363E+01 2.3503026E+02 2.3399254E+02 9.0000095E+00 2.5342987E+01 2.3602611E+02 2.3608826E+02 1.OOOOO11E+01 2.6780718E+01 2.3736647E+02 2.3791733E+02 1.1000012E+01 2.8206589E+01 2.4040240E+02 2.3953009E+02 1.2000013E+01 2.9531761E+01 2.4311273E+02 2.4097713E+02 1.3000014E+01 3.0770304E+01 2.4555682E+02 2.4227254E+02 1.4000015E+01 3.1930042E+01 2.4777309E+02 2.4343179E+02 1.5000016E+01 3.3016243E+01 2.4978954E+02 2.4447365E+02 1.6000017E+01 3.4032555E+01 2.5162741E+02 2.4540987E+02 1.7000017E+01 3.4970993E+01 2.5328467E+02 2.4624951E+02 1.8000019E+01 3.5811737E+01 2.5473863E+02 2.4701794E+02 1.9000019E+01 3.6636105E+01 2.5613721E+02 2.4788234E+02 2.0000021E+01 3.7398861E+01 2.5740851E+02 2.4859787E+02 2.1000023E+01 3.7851036E+01 2.5815213E+02 2.4898529E+02 2.2000023E+01 3.8112339E+01 2.5857825E+02 2.4931332E+02 2.3000025E+01 3.8260201E+01 2.5881793E+02 2.4968272E+02 2.4000025E+01 3.8293922E+01 2.5887186E+02 2.5002792E+02 2.5000027E+01 3.8238850E+01 2.5878183E+02 2.5024706E+02 2.6000027E+01 3.8128895E+01 2.9860266E+02 2.5031232E+02 2.7000029E+01 3.7980820E+01 2.5836093E+02 2.5030611E+02 2.8000029E+01 3.7825226E+01 2.5810614E+02 2.5030029E+02 2.9000031E+01 3.7680557E+01 2.5786841E+02 2.5028958E+02 3.0000031E+01 3.7548203E+01 2.5765027E+02 2.5028166E+02 3.1000032E+01 3.7424873E+01 2.5744641E+02 2.5027269E+02 3.2000034E+01 3.7309559E+01 2.5725531E+02 2.5026326E+02 3.3000034E+01 3.7201584E+01 2.5707593E+02 2.5025294E+02 3.4000034E+01 3.7100319E+01 2.5690729E+02 2.5024231E+02 3.5000034E+01 3.7005581E+01 2.5674915E+02 2.5021291E+02 3.6000038E+01 3.6947170E+01 2.5665094E+02 2.4955557E+02 3.7000038E+01 3.6914814E+01 2.5659589E+02 2.4861476E+02 3.8000038E+01 3.6886406E+01 2.5654739E+02 2.4777684E+02 3.9000038E+01 3.6859982E+01 2.5650220E+02 2.4697656E+02 4.0000042E+01 3.6835258E+01 2.5645987E+02 2.4621265E+02 4.1000042E+01 3.6812187E+01 2.5642026E+02 2.4548227E+02 4.2000042E+01 3.6790600E+01 2.5638315E+02 2.4478413E+02 4.3000046E+01 3.6770481E+01 2.5634851E+02 2.4411566E+02 4.4000046E+01 3.6751686E+01 2.5631607E+02 2.4347580E+02 4.5000046E+01 3.6734200E+01 2.5628583E+02 2.4286221E+02 4.6000046E+01 3.6717907E+01 2.5625760E+02 2.4227408E+02 4.7000050E+01 3.6702797E+01 2.5623135E+02 2.4170927E+02 4.8000050E+01 3.6688751E+01 2.5620691E+02 2.4116724E+02 WCAP- 161 93-NP March 2004 Official record stored elecironically in EDMS 2000-031504

6-44 Table 6.3-5 Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F -d 4.9000050E+01 3.6675770E+01 2.5618427E+02 2.4064600E+02 5.0000050E+01 3.6663750E+01 2.5616324E+02 2.4014519E+02 5.1000053E+01 3.6652687E+01 2.5614380E+02 2.3966302E+02 5.2000053E+01 3.6642483E+01 2.5612585E+02 2.3919925E+02 5.3000053E+01 3.6633137E+01 2.5610934E+02 2.3875224E+02 5.4000053E+01 3.6624565E+01 2.5609412E+02 2.3832187E+02 5.5000057E+01 3.6616764E+01 2.5608023E+02 2.3790663E+02 5.6000057E+01 3.6611145E+01 2.5605908E+02 2.3758192E+02 5.7000057E+01 3.6601173E+01 2.5603027E+02 2.3733751E+02 5.8000057E+01 3.6616737E+01 2.5602713E+02 2.3734253E+02 5.9000061E+01 3.6687080E+01 2.5610001E+02 2.3736633E+02 6.0000061E+01 3.6758919E+01 2.5617529E+02 2.3738217E+02 6.1000061E+01 3.6829876E+01 2.5624905E+02 2.3739824E+02 6.2000065E+01 3.6899700E+01 2.5632080E+02 2.3741827E+02 6.3000065E+01 3.69683071+01 2.5639044E+02 2.3743396E+02 6.4000069E+01 3.7035988E+01 2.5645847E+02 2.3744989E+02 6.5000069E+01 3.7102520E+01 2.5652451E+02 2.3746970E+02 6.6000069E+01 3.7167934E+01 2.5658859E+02 2.3748518E+02 6.7000069E+01 3.7232414E+01 2.5665106E+02 2.3750320E+02 6.8000069E+01 3.7296055E+01 2.5671207E+02 2.3751768E+02 6.9000069E+01 3.7358849E+01 2.5677161E+02 2.3753720E+02 7.0000069E+01 3.7420605E+01 2.5682935E+02 2.3755241E+02 7.1000069E+01 3.7481644E+01 2.5688586E+02 2.3756743E+02 7.2000076E+01 3.7541904E+01 2.5694104E+02 2.3758411E+02 7.3000076E+01 3.7601307E+01 2.5699472E+02 2.3760112E+02 7.4000076E+01 3.7659889E+01 2.5704703E+02 2.3761775E+02 7.5000076E+01 3.7717648E+01 2.5709790E+02 2.3763472E+02 J

7.6000076E+01 3.7771122E+0' 2.5714S91E+02 2.3765675E+02 7.7000076E+01 3.7819515E+01 2.5719342E+02 2.3767015E+02 7.8000076E+01 3.7867302E+01 2.5723886E+02 2.3768607E+02 7.9000076E+01 3.7891651E+01 2.5727908E+02 2.3770618E+02 8.0000084E+01 3.7915112E+01 2.5731781E+02 2.3772354E+02 8.1000084E+01 3.7937843E+01 2.5735532E+02 2.3774089E+02 8.2000084E+01 3.7959869E+01 2.5739166E+02 2.3775821E+02 8.3000084E+01 3.7981209E+01 2.5742682E+02 2.3777550E+02 -j 8.4000084E+01 3.8001888E+01 2.5746091E+02 2.3779265E+02 8.5000084E+01 3.8021915E+01 2.5749387E+02 2.3780971E+02 8.6000084E+01 3.8041363E+01 2.5752588E+02 2.3782535E+02 8.7000092E+01 3.8060329E+01 2.5755707E+02 2.3784048E+02 8.8000092E+01 3.8078720E+01 2.5758731E+02 2.3785786E+02 8.9000092E+01 3.8096554E+01 2.5761661E+02 2.3787473E+02 9.0000092E+01 3.8107521E+01 2.5763455E+02 2.3790787E+02 9.1000092E+01 3.8112530E+01 2.5764264E+02 2.3793829E+02 9.2000092E+01 3.8117176E+01 2.5765012E+02 2.3797371E+02 9.3000092E+01 3.8121258E+01 2.5765668E+02 2.3801244E+02

-J 9.4000092E+01 3.8124866E+01 2.5766245E+02 2.3804808E+02 9.5000099E+01 3.8128056E+01 2.5766751E+02 2.3808357E+02 9.6000099E+01 3.8130829E+01 2.5767191E+02 2.3811909E+02 9.7000099E+01 3.8133224E+01 2.5767569E+02 2.3815408E+02 9.8000099E+01 3.8135231E+01 2.5767883E+02 2.3818939E+02 March 2004 -

WCAP- 161 93-NP WCAP-16193-NP March 2004 Offcial record stored electronically in EDMS 2000-031504

645 I 11 Table 6-3-S Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F

9. 9000099E+01 3.8136913E+01 2.5768143E+02 2.3822437E+02 1.000001E+02 3.8138214E+01 2.5768338E+02 2.3826228E+02 1.0100010E+02 3.8139217E+01 2.5768488E+02 2.3829367E+02 1.0200011E+02 3.8134823E+01 2.5767746E+02 2.3832855E+02 1.0300011E+02 3.8129536E+01 2.5766858E+02 2.3836238E+02 1.0400011E+02 3.8124046E+01 2.5765936E+02 2.3839572E+02 1.0500011E+02 3.8118382E+01 2.5764987E+02 2.3843002E+02 1.0600011E+02 3.8112450E+01 2.5763992E+02 2.3846609E+02 1.0700011E+02 3.8106323E+01 2.5762964E+02 2.3850009E+02 1.0800011E+02 3.8099964E+01 2.5761899E+02 2.3853580E+02 1.0900011E+02 3.8093433E+01 2.5760806E+02 2.3856946E+02 1.1000011E+02 3.8086693E+01 2.5759677E+02 2.3860481E+02 1.1100011E+02 3.8079819E+01 2.5758527E+02 2.3863817E+02 1.1200011E+02 3.8072758E+01 2.5757346E+02 2.3867316E+02 1.1300011E+02 3.8065582E+01 2.5756146E+02 2.3870619E+02 1.1400011E+02 3.8058247E+01 2.5754919E+02 2.3874084E+02 1.1500011E+02 3.8050819E+01 2.5753677E+02 2.3877356E+02 1.1600011E+02 3.8043255E+01 2.5752411E+02 2.3880786E+02 1.1700011E+02 3.8035622E+01 2.5751135E+02 2.3884027E+02 1.1800012E+02 3.8027874E+01 2.5749838E+02 2.3887424E+02 1.1900012E+02 3.8020077E+01 2.5748535E+02 2.3890634E+02 1.2000012E+02 3.8012188E+01 2.5747214E+02 2.3893997E+02 1.2100012E+02 3.8004265E+01 2.5745889E+02 2.3897177E+02 1.2200012E+02 3.7996273E+01 2.5744553E+02 2.3900508E+02 1.2300012E+02 3.7988270E+01 2.5743213E+02 2.3903658E+02 1.2400012E+02 3.7980209E+01 2.5741864E+02 2.3906956E+02 1.2500013E+02 3.7972157E+01 2.5740518E+02 2.3910077E+02 1.2600013E+02 3.7964066E+01 2.F739163E+02 2.3913344E+02 1.2700013E+02 3.7955997E+01 2.5737811E+02 2.3916435E+02 1.2800012E+02 3.7947906E+01 2.5736459E+02 2.3919670E+02 1.2900014E+02 3.7939850E+01 2.5735110E+02 2.3922734E+02 1.3000014E+02 3.7931793E+01 2.5733759E+02 2.3925938E+02 1.3100014E+02 3.7923782E+01 2.5732419E+02 2.3928973E+02 1.3200014E+02 3.7915779E+01 2.5731076E+02 2.3932149E+02 1.3300014E+02 3.7907837E+01 2.5729745E+02 2.3935155E+02 1.3400014E+02 3.7899914E+01 2.5728418E+02 2.3938301E+02 1.3500014E+02 3.7892071E+01 2.5727103E+02 2.3941281E+02 1.3600014E+02 3.7884258E+01 2.5725793E+02 2.3944397E+02 1.3700014E+02 3.7876530E+01 2.5724496E+02 2.3947350E+02 1.3800014E+02 3.7868847E+01 2.5723206E+02 2.3950438E+02 1.3900014E+02 3.7861259E+01 2.5721933E+02 2;.3953365E+02 1.4000014E+02 3.7853722E+01 2.5720667E+02 2.3956424E+02 1.4100014E+02 3.7846291E+01 2.5719418E+02 2.3959325E+02 1.4200014E+02 3.7838921E+01 2.5718182E+02 2.3962357E+02 1.4300014E+02 3.7831665E+01 2.5716962E+02 2.3965233E+02 1.4400015E+02 3.7824478E+01 2.5715753E+02 2.3968237E+02 1.4500015E+02 3.7817413E+01 2.5714566E+02 2.3971089E+02 1.4600015E+02 3.7810425E+01 2.5713391E+02 2.3974068E+02 1.4700015E+02 3.7803562E+01 2.5712234E+02 2.3976894E+02 1.4800015E+02 3.7796787E+01 2.5711096E+02 2.3979846E+02 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-46 Table 6.3-5 Containment Response Time History LOCA DEPS Minimum Safeguards -J (cont.) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 1.4900015E+02 3.7790142E+01 2.5709976E+02 2.3982649E+02 1.5000015E+02 3.7783588E+01 2.5708871E+02 2.3985576E+02 1.5100015E+02 3.7777172E+01 2.5707791E+02 2.3988356E+02 1.5200015E+02 3.7770851E+01 2.5706726E+02 2.3991257E+02 1.5300015E+02 3.7764671E+01 2.5705682E+02 2.3994014E+02 Ii 1.5400015E+02 3.7758591E+01 2.5704657E+02 2.3996890E+02 -. 0 1.5500015E+02 3.7752651E+01 2.5703656E+02 2.3999625E+02 1.5600015E+02 3.7746819E+01 2.57026703+02 2.4002477E+02 I 1.5700015E+02 3.7741131E+01 2.5701709E+02 2.4005190E+02 I

1.5800015E+02 3.7735554E+01 2.5700766E+02 2.4008018E+02 1.5900015E+02 3.7730125E+01 2.5699847E+02 2.4010710E+02 1.6000017E+02 3.7724808E+01 2.5698947E+02 2.4013515E+02 1.6100017E+02 3.7719646E+01 2.5698074E+02 2.4016185E+02 1.6200017E+02 3.7714596E+01 2.5697217E+02 2.4018968E+02 1.6300017E+02 3.7709705E+01 2.5696390E+02 2.4021617E+02 1.6400017E+02 3.7704929E+01 2.5695578E+02 2.4024379E+02 1.6500017E+02 3.7700314E+01 2.5694794E+02 2.4027007E+02 1.6600017E+02 3.7695820E+01 2.5694031E+02 2.4029747E+02

-I 1.6700017E+02 3.7691483E+01 2.5693295E+02 2.4032355E+02 1.6800017E+02 3.7687267E+01 2.5692578E+02 2.4035074E+02 1.6900017E+02 3.7683216E+01 2.5691888E+02 2.4037662E+02 1.7000017E+02 3.7679287E+01 2.5691217E+02 2.4040359E+02 -Jd 1.7100017E+02 3.7675522E+01 2.5690576E+02 2.4042931E+02 1.7200017E+02 3.7671879E+01 2.5689954E+02 2.4045607E+02 1.7300017E+02 3.7668404E+01 2.5689359E+02 2.4048158E+02 1.7400017E+02 3.7665054E+01 2.5688785E+02 2.4050815E+02 1.7500018E+02 3.7661869E+01 2.5688239E+02 2.4053348E+02 1.7600018E+02 3.7658810E+01 2.F687714E+02 2.4055986E+02 1.7700018E+02 IJ 3.7655933E+01 2.5687219E+02 2.4058501E+02 1.7800018E+02 3.7653221E+01 2.5686752E+02 2.4061119E+02 1.7900018E.02 3.7650738E+01 2.5686322E+02 2.4063620E+02 1.8000018E+02 3.7648468E+01 2.5685928E+02 2.4066225E+02 1.8100018E+02 3.7646461E+01 2.5685577E+02 2.4068718E+02 1.8200018E+02 3.7644676E+01 2.5685266E+02 2.4071318E+02 1.8300018E+02 3.7643162E+01 2.5684998E+02 2.4073811E+02 1.8400018E+02 3.7641891E+01 2.5684769E+02 2.4076414E+02 1.8500018E+02 3.7640896E+01 2.5684589E+02 2.4078915E+02 1.8600018E+02 3.7640148E+01 2.5684448E+02 2.4081528E+02 1.8700018E+02 3.7644314E+01 2.5685123E+02 2.4084459E+02 1.8800018E+02 3.7655922E+01 2.5687036E+02 2.4088112E+02 1.8900018E+02 3.7667603E+01 2.5688962E+02 2.4091638E+02 1.9000020E+02 3.7679321E+01 2.5690894E+02 2.4095256E+02 1.9100020E+02 3.7691116E+01 2.5692838E+02 2.4098766E+02 1.9200020E+02 3.7702950E+01 2.5694788E+02 2.4102367E+02 1.9300020E+02 3.7714863E+01 2.5696747E+02 2.4105862E+02 1.9400020E+02 3.7726810E+01 2.5698715E+02 2.4109447E+02 1.9500020E+02 3.7738834E+01 2.5700696E+02 2.4112927E+02 1.9600020E+02 3.7750893E+01 2.5702679E+02 2.4116496E+02 1.9700020E+02 3.7763023E+01 2.5704675E+02 2.4119963E+02 1.9800020E+02 - 3.7775188E+01 2.5706677E+02 2.4123517E+02 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504 J

7 Table 6-3-5 Containment Responie Time History LOCA DEPS Minimum Safeguards (cont.) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 1.9900020E+02 3.7787430E+01 2.5708691E+02 2.4126968E+02 2.0900020E+02 3.7912720E+01 2.5729269E+02 2.4158899E+02 2.1900020E+02 3.8045818E+01 2.5751083E+02 2.4193111E+02 2.2900020E+02 3.8182438E+01 2.5773413E+02 2.4226828E+02 2.3900020E+02 3.8322491E+01 2.5796237E+02 2.4258461E+02 2.4900020E+02 3.8467411E+01 2.5819791E+02 2.4291200E+02 2.5900021E+02 3.8613510E+01 2.5843463E+02 2.4323012E+02 2.6900021E+02- 3.8761776E+01 2.5867413E+02 2.4352977E+02 2.7900021E+02 3.8914639E+01 2.5892032E+02 2.4383749E+02 2.8900021E+02 3.9067951E+01 2.5916644E+02 2.4413802E+02 2.9900021E+02 3.9223305E+01 2.5941504E+02 2.4443173E+02 3.0900021E+02 3.9379341E+01 2.5966391E+02 2.4472960E+02 3.1900021E+02 3.9536758E+01 2.5991418E+02 2.4501567E+02 3.2900021E+02 3.9693714E+01 2.6016287E+02 2.4530608E+02 3.3900021E+02 3.9851971E+01 2.6041284E+02 2.4558521E+02 3.4900021E+02 4.0009895E+01 2.6066147E+02 2.4586845E+02 3.5900021E+02 4.0167667E+01 2.6090900E+02 2.4614134E+02 3.6900021E+02 4.0324749E+01 2.6115466E+02 2.4641826E+02 3.7900021E+02 4.0481602E+01 2.6139920E+02 2.4668520E+02 3.8900021E+02 4.0637718E+01 2.6164175E+02 2.4695602E+02 3.9900021E+02 4.0793339E+01 2.6188278E+02 2.4721730E+02 4.0900021E+02 4.0947842E+01 2.6212134E+02 2.4748244E+02 4.1900021E+02 4.1101254E+01 2.6235742E+02 2.4773849E+02 4.2900021E+02 4.1253361E+01 2.6259079E+02 2.4799832E+02 4.3900021E+02 4.1404278E+01 2.6282159E+02 2.4824939E+02 4.4900021E+02 4.1553745E+01 2.6304950E+02 2.4850412E+02 4.5900021E+02 4.1497303E+01 2.6296097E+02 2.4881248E+02 4.6900021E+02 4.1430805E+01 2.62856P4E+02 2.4910609E+02 4.7900021E+02 4.1369747E+01 2.6276099E+02 2.4939644E+02 4.8900024E+02 4.1313580E+01 2.6267255E+02 2.4967177E+02 4.9900024E+02 4.1261456E+01 2.6259024E+02 2.4994598E+02 5.9900024E+02 4.0906193E+01 2.6202094E+02 2.5228282E+02 6.9900024E+02 4.0755516E+01 2.6176740E+02 2.5418265E+02 7.9900024E+02 4.0700222E+01 2.6166217E+02 2.5572978E+02 8.9900024E+02 4.0707073E+01 2.6165396E+02 2.5705524E+02 9.9900024E+02 4.0759869E+01 2.6171753E+02 2.5816846E+02 1.0990002E+03 4.0852558E+01 2.6184323E+02 2.5914160E+02 1.1990002E+03 4.0974525E+01 2.6201425E+02 2.6000595E+02 1.2990002E+03 4.1118595E+01 2.6221915E+02 2.6078186E+02 1.3990002E+03 4.1278618E+01 2.6244812E+02 2.6148544E+02 1.4990002E+03 4.1017441E+01 2.6202448E+02 2.5994913E+02 1.5990002E+03 4.0285900E+01 2.6085962E+02 2.5601941E+02 1.6990002E+03 3.9608444E+01 2.5976334E+02 2.5250253E+02 1.7990002E+03 3.8944416E+01 2.5867813E+02 2.5095050E+02 1.8990002E+03 3.8291840E+01 2.5760190E+02 2.5116582E+02 1.9990002E+03 3.7661934E+01 2.5654797E+02 2.5133128E+02 2.0990002E+03 3.7047935E+01 2.5550603E+02 2.5146365E+02 2.1990002E+03 3.6449875E+01 2.5447679E+02 2.5156519E+02 2.2990002E+03 3.5863979E+01 2.5345436E+02 2.5163931E+02 2.3990002E+03 3.5290825E+01 2.5244023E+02 2.5168765E+02 WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

6-48 Table 6.3-5 Containment Response Time History LOCA DEPS Minimum Safeguards (cont) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 2.4990002E+03 3.4727585E+01 2.5142979E+02 2.5171295E+02 2.5990002E+03 3.4175045E+01 2.5042479E+02 2.5171637E+02 *I 2.6990002B+03 3.3630894E+01 2.4942137E+02 2.5170013E+02 2.7990002E+03 3.3096016E+01 2.4842136E+02 2.5166512E+02 2.89900023+03 3.2568432E+01 2.4742134B+02 2.5161319E+02 2.9990002E+03 3.2049065E+01 2.4642320B+02 2.5154500E+02 3.0990002E+03 3.1536585E+01 2.45424653+02 2.5119759E+02 3.19900023+03 3.1033150E+01 2.44430043+02 2.5062053E+02 I I 3.2990002E+03 3.0537096E+01 2.4343636E+02 2.5005373E+02 3.3990002E+03 3.00492613+01 2.42445473+02 2.4949631E+02 3.4990002E+03 2.9567591E+01 2.41453453+02 2.4894762E+02 3.5990002B+03 2.90909753+01 2.4045804E+02 2.4840680E+02 3.6990002B+03 2.8516722E+01 2.3924219E+02 2.4756549E+02 3.7990002E+03 2.78772453+01 2.3786467E+02 2.4647102E+02 3.8990002E+03 2.7256548E+01 2.3650125E+02 2.4540343E+02 3.9990002E+03 2.6651463E+01 2.3514609E+02 2.4436050E+02 4.9990005E+03 2.6178232E+01 2.3405884E+02 2.3856117E+02 5.9990005E+03 2.5339073E+01 2.3212007E+02 2.3547710E+02 6.9990005E+03 2.4339323E+01 2.2973772E+02 2.3259241E+02 7.9990005E+03 2.3263578E+01 2.2707968E+02 2.2967346E+02 8.9990000E+03 2.22281363+01 2.2442082E+02 2.2687349E+02 9.99900003+03 2.1225840E+01 2.2174495E+02 2.2419339E+02 I 1.9999000E+04 1.5686809E+01 2.0466176E+02 2.0291525E+02 2.9999000E+04 1.3152152E+01 1.9506615E+02 1.9160211E+02 --j 3.9999000E+04 1.1323038E+01 1.8712329E+02 1.8439781E+02 4.9999000E+04 9.7869539E+00 1.7958183E+02 1.7864931E+02 5.9999000E+04 8.5745497E+00 1.7291682E+02 1.6786551E+02 6.99990003+04 7.9483247E+OCl 1.6917464E+02 1.6274123E+02 7.9999000E+04 7.5054259E+00 1.6638631E+02 1.5992181E+02 8.9999000E+04 7.1604381E+00 1.6412579E+02 1.5792720E+02 9.9999000E+04 6.8242469E+00 1.6183994E+02 1.5629884E+02 1.0999900E+05 6.5069389E+00 1.5960550E+02 1.5168483E+02 I4 1.1999900E+05 6.33630853+00 1.5837563E+02 1.4955984E+02 1.2999900E+05 6.2105260E+00 1.5745557E+02 1.4860063E+02 1.3999900E+05 6.12869643+00 1.5684990E+02 1.4809610E+02 1.4999900E+05 6.0476475E+00 1.5624471E+02 1.4761789E+02 IJ 1.5999900E+05 5.9640379B+00 1.5562007E+02 1.4706854E+02 1.6999900E+05 5.8988228E+00 1.5512570E+02 1.4677753E+02 1.7999900E+05 5.8281584E+00 1.5459109E+02 1.4630420E+02 1.8999900E+05 5.7537870E+00 1.5402026E+02 1.4608250E+02 1.9999900E+05 5.6720600E+00 1.5338788E+02 1.4557355E+02 2.0999900E+05 5.6194324E+00 1.5297566E+02 1.4536119E+02 2.1999900E+05 5.5402665E+00 1.5235068E+02 1.4506827E+02 2.2999900E+05 5.4775329E+00 1.5185699E+02 1.4451189E+02 2.3999900E+05 5.4301362E+00 1.5147841E+02 1.4433202E+02 2.4999900E+05 5.3300710E+00 1.5066556E+02 1.4396130E+02 2.5999900E+05 5.2775216E+00 1.5024387E+02 1.4343665E+02 2.6999900E+05 5.2232108E+00 1.4979723E+02 1.4322131E+02 2.7999900E+05 5.1444354E+00 1.4914409E+02 1.4285654E+02 2.8999900E+05 5.0872226E+00 1.4866550E+02 1.4244060E+02 W%-AY-101Y15-Ntr March 2004 Official record stored electronically in EDMS 20004031504

649 Table 6.3-S Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 2.9999900E+05 5.0107307E+00 1.4801920E+02 1.4211250E+02 3.0999900E+05 4.9592161E+00 1.4758203E+02 1.4171783E+02 3.1999900E+05 4.8942966E+00 1.4702687E+02 1.4137230E+02 3.2999900E+05 4.8119421E+00 1.4631352E+02 1.4091867E+02 3.3999900E+05 4.7697425E+00 1.4594711E+02 1.4063461E+02 3.4999900E+05 4.7076173E+00 1.4539867E+02 1.4027435E+02 3.5999900E+05 4.6466541E+00 1.4485605E+02 1.3991220E+02 3.6999900E+05 4.5853105E+00 1.4430522E+02 1.3955141E+02 3.7999900E+05 4.5251970E+00 1.4376102E+02 1.3918872E+02 3.8999900E+05 4.4646673E+00 1.4320816E+02 1.3882761E+02 3.9999900E+05 4.4054332E+00 1.4266273E+02 1.3846471E+02 4.0999900E+05 4.3457227E+00 1.4210799E+02 1.3810342E+02 4.1999900E+05 4.2873678E+00 1.4156143E+02 1.3774042E+02 4.2999900E+05 4.2284708E+00 1.4100484E+02 1.3737904E+02 4.3999900E+05 4.1709909E+00 1.4045724E+02 1.3701595E+02 4.4999900E+05 4.1128626E+00 1.3989842E+02 1.3665451E+02 4.5999900E+05 4.0542269E+00 1.3932947E+02 1.3628542E+02 4.6999900E+05 3.9943228E+00 1.3874249E+02 1.3590909E+02 4.7999900E+05 3.9357214E+00 1.3816333E+02 1.3552811E+02 4.8999900E+05 3.8764186E+00 1.3757158E+02 1.3514766E+02 4.9999900E+05 3.8186336E+00 1.3699005E+02 1.3476503E+02 5.0999900E+05 3.6517601E+00 1.3525125E+02 1.3032204E+02 5.1999900E+05 3.5937085E+00 1.3464824E+02 1.2912463E+02 5.2999900E+05 3.5588541E+00 1.3429265E+02 1.2871294E+02 5.3999900E+05 3.5347478E+00 1.3405292E+02 1.2847656E+02 5.4999900E+05 3.5080819E+00 1.3378906E+02 1.2829155E+02 5.5999900E+05 3.4869697E+00 1.3358002E+02 1.2817790E+02 5.6999900E+05 3.4674938E+O0 1.3338892E+02 1.2803493E+02 5.7999900E+05 3.4476156E+00 1.3319281E+02 1.2790218E+02 5.8999900E+05 3.4281061E+00 1.3300021E+02 1.2777282E+02 5.9999900E+05 3.4088912E+00 1.3281035E+02 1.2764587E+02 6.0999900E+05 3.3899238E+00 1.3262271E+02 1.2752081E+02 6.1999900E+05 3.3711684E+00 1.3243692E+02 1.2739730E+02 6.2999900E+05 3.3525989E+00 1.3225269E+02 1.2727509E+02 6.3999900E+05 3.3341939E+00 1.3206979E+02 1.2715397E+02 6.4999900E+05 3.3159375E+00 1.3188808E+02 1.2703381E+02 6.5999900E+05 3.2978151E+00 1.3170738E+02 1.2691446E+02 6.6999900E+05 3.2798157E+00 1.3152759E+02 1.2679585E+02 6.7999900E+05 3.2619290E+00 1.3134860E+02 1.2667786E+02 6.8999900E+05 3.2441471E+00 1.3117032E+02 1.2656046E+02 6.9999900E+05 3.2264619E+00 1.3099266E+02 1.2644357E+02 7.0999900E+05 3.2088671E+00 1.3081557E+02 1.2632712E+02 7.1999900E+05 3.1913571E+00 1.3063896E+02 1.2621109E+02 7.2999900E+05 3.1739268E+00 1.3046281E+02 1.2609542E+02 7.3999900E+05 3.1565716E+00 1.3028708E+02 1.2598009E+02 7.4999900E+05 3.1392877E+00 1.3011168E+02 1.2586506E+02 7.5999900E+05 3.1220710E+00 1.2993661E+02 1.2575030E+02 7.6999900E+05 3.1049190E+00 1.2976183E+02 1.2563579E+02 7.7999900E+05 3.0878279E+00 1.2958730E+02 1.2552150E+02 7.8999900E+05 3.0707958E+00 1.2941299E+02 1.2540742E+02 March 2004 WCAP- 16193-NP WCAP-16193-NP March 2004 Olficial record stored electrorically in EDMS 20004031504

6-50 Table 6.3-5 Containment Response Time History LOCA DEPS Minimum Safeguards (cont.) Unit 2 with Recirculation Spray TIME, SECONDS PRESSURE, PSIG STEAM TEMP, F WATER TEMP, F 7.9999900E+05 3.0538201E+00 1.2923891E+02 1.2529352E+02 8.0999900E+05 3.0368989E+00 1.2906497E+02 1.2517979E+02 8.1999900E+05 3.0200295E+00 1.2889122E+02 1.2506622E+02 8.2999900E+05 3.0032113E+00 1.28717613+02 1.2495280E+02 8.3999900E+05 2.9864416E+00 1.2854410E+02 1.2483951E+02 8.4999900E+05 2.9697199E+00 1.2837071E+02 1.2472633E+02 8.5999900E+05 2.9530442E+00 1.2819743E+02 1.2461327E+02 8.69999003+05 2.9364138E+00 1.2802422E+02 1.2450031E+02 8.7999900E+05 2.9198272E+00 1.2785108E+02 1.2438744E+02 8.8999900E+05 2.9032838E+00 1.2767801E+02 1.2427466E+02 8.9999900E+05 2.8867826E+00 1.2750499E+02 1.2416196E+02 'I 9.0999900E+05 2.8703227E+00 1.2733202E+02 1.2404933E+02 9.1999900E+05 2.85390333+00 1.2715907E+02 1.2393678E+02 9.2999900E+05 2.8386970E+00 1.2699222E+02 1.2383377E+02 9.39999003+05 2.8231702E+00 1.2682097E+02 1.2372340E+02 9.4999900E+05 2.8076012E+00 1.2664874E+02 1.2361184E+02 9.5999900E+05 2.7920470E+00 1.2647621E+02 1.2350002E+02 9.6999900E+05 2.7765210E+00 1.2630357E+02 1.2338812E+02 9.7999900E+05 2.7610278E+00 1.2613087E+02 1.2327621E+02 9.8999900E+05 2.7455690E+00 1.2595813E+02 1.2316431E+02 9.9999900E+05 2.7305019E+00 1.2579782E+02 1.2305104E+02 1.9999990E+06 2.4957139E+00 1.2113444E+02 1.1695563E+02 2.9999990E+06 2.4334910E+00 1.1745471E+02 1.1475826E+02 3.9999990E+06 2.3778954E+00 1.1381356E+02 1.1248933E+02 4.9999990E+06 2.3807366E+00 1.1010735E+02 1.1012410E+02 5.9999990E+06 2.5233934E+00 1.0808177E+02 1.06595283+02 6.9999990E+06 2.7762849E+00 1.0750563E+02 1.0629495E+02 I 7.9999990E+06 2.9947212E+00 l.0628163E+02 1.0548473E+02 8.9999990E+06 3.2582438E+00 1.0561956E+02 1.0494935E+02 9.9999990E+06 3.4866848E+00 1.0448335E+02 1.0438900E+02 1.0000000E+07 3.4867876E+00 1.0448510E+02 1.0438864E+02

-. a

-. j WCAP- 16193-NP March 2004 Official record siored electronically in EDMS 2000-031504

6-51

6.4 CONCLUSION

S The MSLB and LOCA containment response analyses have been performed as part of the service water system enhancement program for Salem Unit I and Unit 2. The analyses included long-term pressure and temperature profiles for each unit. As illustrated in the results in Section 6.2 and 6.3, all cases resulted in a peak containment pressure that was less than 47 psig. In addition, all long-term cases were well below 50% of the peak value within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Based on the results, all applicable SRP criteria for Salem Unit I and Unit 2 have been met.

The peak calculated pressure for the DEPS minimum safeguards LOCA case for Salem Unit I with Model F steam generators was 40.1 psig. The peak calculated pressure for the DEPS minimum safeguards LOCA case for Salem Unit 2 with Model 51 steam generators was 41.6 psig.

For MSLB, the limiting containment pressure case is a 1.4 ft2 DER initiated at 30% power with a containment safeguards failure. The limiting containment temperature case is 0.88 ft2 split rupture initiated at 30% power with a MSIV failure. For Unit 1, the peak pressure is 40.2 psig and the peak temperature is 345.70 F. For Unit 2, the peak pressure is 42.2 psig and the peak temperature is 345.40 F.

From the standpoint of the acceptability of the service water enhancement project, the operation of the recirculation sprays are necessary for the long term LOCA containment temperature to be less than the qualification temperature profile in Table 3.3-1. However the EQ limits are slightly exceeded for a short duration (about two hours for both units). Also, while the peak temperature from the composite of all of the steamline break cases is less than 351.3 0F and the long term temperature is less than the current profile, there is a period from approximately 140 seconds to 320 seconds where the new composite exceeds the envelop from about 60 F to as much as 180 F. The noted EQ temperature limit issues are being addressed by PSEG Nuclear outside of this report.

-C WCAP-16193-NP March 2004 Official record stored electronically in EDMS 200D-031504

7-1 7 REFERENCES

1. Westinghouse Project Letter, PSEBO-97-022, "Safety Evaluation for Revised Fan Cooler Delay Time (SECL-96-178, Revision 2)," 9-2-97.

2. Westinghouse Project Letter, PSE-97-509, "Steam Generator Replacement Project (LOCA/Containment Assessment)," 1-10-97.

3. Westinghouse Project Letter, PSE-01 -524, "Containment Capability Study - Phase 1," 7-9-01.

4. Westinghouse Project Letter, PSE-02-19, "Summary Report for Phase 2 of Containment Capability Study for Salem Unit I and Unit 2," 3-6-02. -

5. "Containment Pressure Analysis Code (COCO)," WCAP-8327, July, 1974 (Proprietary),

WCAP-8326, July, 1974 (Non-Proprietary).

6. "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), Burnett, T.W.T., et al., April 1984.

7. Moody, FJ., "Maximum Flow Rate of a Single Component, Two-Phase Mixture," Journal of Heat Transfer, 87, 134 (1965).

8. Letter from Cecil 0. Thomas (NRC), "Acceptance for Referencing of Licensing Topical Report WCAP-882 I(P)/8859(NP)," "TRANFLO Steam Generator Code Description," and WCAP-8822(P)/8860(NP), "Mass and Energy Release Following a Steam Line Rupture,'

August 1983

9. "Mass and Energy Releases Following a Steam Line Rupture," WCAP-8822 (Proprietary),

WCAP-8860 (Nonproprietary), Land, R.E., September 1976

10. ANSI/ANS-5.1 1979, "American National Standard for Decay Heat Power in Light Water Reactors," August 1979

11. "Westinghouse LOCA Mass and Energy Release Model for Containment Design - March 1979 Version," WCAP-10325-P-A, May 1983 (Proprietary), WCAP-10326-A (Nonproprietary).

12. "Westinghouse Mass and Energy Release Data For Containment Design," WCAP-8264-P-A, Rev. 1.

August 1975 (Proprietary), WCAP-8312-A (Nonproprietary).

13. Docket No. 50-315, "Amendment No. 126, Facility Operating License No. DPR-58 (TAC No. 71062), for D. C. Cook Nuclear Plant Unit I," June 9, 1989.

14. EPRI 294-2, "Mixing of Emergency Core Cooling Water with Steam; 1/3-Scale Test and Summary,"

(WCAP-8423), Final Report, June 1975 WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

7-2

15. Takashi Tagami, "Interim Report on Safety Assessments and Facilities Establishment Project in Japan for Period Ending June 1965," No. 1

16. E. W. Ranz and W. R. Marshall, Jr., "Evaporation for Drops," Chemical Engineering Progress, 48, pp. 141-146, March 1952 I

17. Parsly, L. F., "Design Consideration of Reactor Containment Spray System. Part VL The Heating of Spray Drops in Air-Steam Atmospheres," ORNL-TM-2412 Part VI, January 1970

-e I

-4

-I

_4 t

March 2004 WCAP- 16193-NP WCAP- 16193-NP March 2004 Official record stored electronically in EDMS 2000 0315S04

A-l APPENDIX A The information that follows is a copy of the PSEG Nuclear LLC transmittal letter EA-CFCU-03-004, dated July 10, 2003. This information was transmitted to Westinghouse as the PSEG Nuclear LLC confirmation of the analysis input assumptions for the work presented in the main body of this report.

Portions of EA-CFCU-03-004 and its attachments contain Westinghouse proprietary information. This information has been designated by brackets (i.e., [ i^).

WCAP-16193-NP March 2004 Official record stored electronically in EDMS 2000-031504

PSEG Nuclear LLC P.O. Bx 236. Hanoocks Bridge; New Jersey 080384236 EA-CFCU-03-004 2 PSEG NuclearLLC July 10, 2003 Customer Projects Manager Westinghouse Electric Company P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 Attn: Mr. Jerold Kusky

Dear Mr. Kusky:

PSEG Nuclear Response to Westinghouse Input Request for CFCU Project Containment Mass and Energy Release Analyses PSEG Nuclear has validated andlor provided the specific input requested by Westinghouse (Reference I) needed to perform the LOCA and Main Steam Line Break (MSLB) containment response analyses proposed as described in References 2 and 3.

This information was transmitted via e-mail to Mr. Robert Jakub on July 2, 2003.

Note that some items, too large to fit in the available space, were noted and provided as attachments at the end. There are some items that will require further discussion between Westinghouse and PSEG, specific Westinghouse references or possible follow-up calculations. Some items of note include Safety Injection (SI) switchover to recirculation with minimum safeguards, time for recirculation spray to be initiated and some SI flows I . _ not matching current-references&under-cltainagigments,-PRR-beat-exchanger-flow-during recirculation (subsequent UA values will then be provided by PSEG).

Additionally, information provided to Westinghouse regarding the main feedwater pump trip and coastdown for MSLB with a single failure of the feedwater control valve (Reference 4) needs to be validated by Westinghouse as it dates back to 1992.

To further support the filled in Westinghouse input request document, the following are also provided: Attachment I provides information regarding the concurrent vessel head change-out project, including the increased metal mass associated with the integrated head package; Attachment 2 provides additional information regarding AFW flow rates; Attachment 3 is the hard copy of the EXCEL file that provides Proto-Flo AFW results and curve fits; Attachment 4 contains the SI information; Attachment 5 covers the Accumulators; Attachment 6 covers Containment Spray Pumps; Attachment 7 is the validation of the various data tables, Attachment 8 covers the Bypass Flow Control Valve set points. Attachment 9 provides information data for the Heater Drain Pump Curves.

Also included are P&ID's for Salem Unit I and 2 Bleed Steam and Heater Drains. Item C.5 Lo-lo Tavg set point value will be provided later.95-216 REV. 7199

Mr. Jerold Kusky July 10, 2003 Note that all the Replacement Steam Generator data has been provided with the exception of the secondary side fluid mass at various power levels (Franatome only has performed calculation at 100% power). PSEG will provide this information later as it becomes available. Also, PSEG is evaluating a reduction in the maximum moderator density coefficient (currently set at 0.52 delta-k/gm/cc) to recover some MSLB containment pressure margin. The final value that is acceptable to the core design engineers will be -

provided to Westinghouse under a separate letter.

Following your review of this input information, could you provide an update to the analysis schedule, with the various deliverables (even preliminary results) in terms of actual dates. Please distribute this letter with attachments to Robert Jakub, Debra Ohkawa and William Turkowski.

If you have any questions, please contact Mr. Kiran Mathur (CFCU Project Engineer) at 856 339-7215, or Mr. Glenn Schwartz (Nuclear Fuel) at 856 339-1216.

Very truly yours, Ashok Moudgill CFCU Project Manager (Original signed and on File)

C Dave Hughes John 0 Connor Mike Mannion Tom Ross Ken Fleischer Greg Morrison Doug McCollum Glenn Schwartz Kent Halac Michael Crawford John Rowey Kevin King _

Scott Beckham Tina Nolte Paul Finch -

John Pehush

Mr. Jerold Kusky July 10, 2003

References:

I) Westinghouse letter PSE-03-25, CFCU/Service Water Enhancement Project Input Request for LOCA and MSLB Mass & Energy Releases and Containment Integrity Analyses, June 24, 2003

2) Westinghouse letter LTR-NEM-03403, Containment Response Analysis to Support the Containment Fan Cooler Unit Service Water Enhancement Project, April 29,2003

3) Westinghouse letter LTR-NEM-03-458, Revised Offer for Containment Response Analysis to Support the Containment Fan Cooler Unit Service Water Enhancement Project, May 15, 2003 PSEG Letter NFU-92-173, Salem Units 1 & 2 Feedwater Control Valve / Main Feedwater Pump Trip Assumption, March 9, 1992

Lii ,A.U3-1UI

- age 4 of 40 PSEG Nuclear Respones Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response J Westinghouse LOCA Valuea l Waestgbouse SLB Value PSW Coalirmed Value Nots Dcsign and Ucetulag Parameters A. CORE P4AMAEES Nominal Reactor Core Power, MWt (100' 3459.0 n/a OK - PCWG254 1 Increase value Is conservative.

I.

power)

2. Pump hea, MWt n/a 20 OK

• 20MWth max (bounding) 12 MWUh nominal (WCAP-15553 and PCWG) n/a 3479 OK based on maximum Increaed value is consrvatIe.

3. NSSS Power. MWt

4. Calorimetric uncitainty 0.65 0,6% OK - Licensing Anendmants 243 nd 224

.. rent cor digps will

5. Fuel Type & Fuel Mechanl Design 17 x 17 RFA Fuel 17x17 RFA Fuel dike RFA, but will likly ave onc V5H assembly In tie Vlucs ;enter lcaon for Ile next y.e of ac Salem unit

.essentially d__oug 2005). _.-.

IA

6. Core Stored Energy, Full Power Seconds 4.23 rig n/A- W"Nomus scope

.current . lcoenits

7. Total Peaking Factor, VqT 2.4 n/a Westingoue laens WPps 2.45, OIPSE..094) owever, LOCA analyses hould use PqT - 2.5 to rovide for uur core esIn

8. Core Enthalpy Rise Factor, FAh 1.65 n/e OK - curroent core limits L_ (.C L (.-. (-- ( -- ( - -1 (---, (- --- ( -, ( - L-

(~ C~ 1.--- L[ C L~~1~(1~ f? t) t- f~1 VTh r-, r-, (~I rf (j§ =,0lo

- -1;ag- 5 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response W tIlughouse LOCA Westinghouse SLB Value MSEG Coafirmed Design nd Ucenting Parameters Va+ Value Note" OK - acntal parameter is the

9. CoreRadial Peeking F or, . 1.469 W "relative power inhot azsseVbly", alue Consistent i with the current core limits

10. Shutdown margin,% k . 1.3% OK - Tech Spec 3/4.l.1.C1 [ 3 II. Moderdor density hedback, klgm/cc nh 0.52 Increased value Is conservative.

B. REACTOR COOLANTSYSrEM (Se Attachmenst Ifor iqformation regardting addiional metal mass added by the Replacement Reactor Hcad Profect) aC

1. Thermal Design Flow, gpmlloop 32,5t0 OK - Margin Recovery Program RTSR epon

2. Vessel/Oudet Temperature, *F 6134 A OK - PCWO-2541

3. Vessellore Inlet Temperatur 'IF 542.7 nha OK- PC .2S41 .

4. Steam Generator Outlet Temperature. *F 542.5 . OK - PCWO.2541

-I

L7 IRA-03-103

-#age 6 of40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Contalinment Response Wesdaghouse LOCA Wutiagbouse SLB Value PSEG Coaarsid Valve Notes m

Design and Uceasing Parametrs

. O C.

5. RCS Avwe Temperatre, F

• Full Power WA 577.9

• 70% Powr 513.6

• 30% Power 556.3

• 0% Power 547.0

.. 1- OX ~

0Cconsident withr_

6. Vesse Average Temperaure Uncainty 5.0 OF Minimum Measured Flow

7. Pressurizer Presure. psi. 225b 2250 O-PW.S

8. Pressurizer Pmsure Uncertainty, psle +50 Nis OK - consistent with Margin Recovery Program C. PROTECrIONVSYSEMLOGIC. SE OIh7 DELAYS I u- , t _ C. (-, (- - t -

_(; C L-(--- (-- t -- C --- ( ---. (---,

ri i C- } & r:- t'2> r (7 1 m

-) 1---4 - ( - ' [T tr-j; t~r 354.

ag. 7 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Wefttughousg LOCA Wustnithow" SLW Value PSEG Confirmed D"el aud Lkenalug Parametr Val e Valve No

1. Stewnne break protection logic (SI a nh See F. C.I Fig. C4l correct Ret DwS.

SLI signals) Seres 221050 353.5 psI. caF Lhmlt SO0peig AC.

2. Low tamli pressure setpol't 575 psIk Rot SC-CN002.01

3. Loadlag on low steamline pressue signal 5015 V1D 304209

4. High steam flow setpoint .Power(FONon Noanalytil Valwe

. 0.2 0.6454

.3143 0.8022 Power Flow

.4286 0.9236

.5429 1.0264 0-20% <-40%

.6572 1.1172

.7715 t9M "100%A vl0%

.1353 1.2750 1.0 1.4389 t2 1.4589 Ret SC.CN007-01 5, Lo-lo Tavg selpoit, 'F nfl. WDl be provided later

6. High steamline differential pressure, psi 200. Allowable Valu 112.0 Roet SC-CN002.01

7. MlJmh nbMne er o tImA 7 M n/a

. high stimlins differential pressure

• high'steamline

• low-low Tvig 2

• low steamline prsure 2

L1 RA.03.103

- -Page8 of40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamliue Break Mass & Energy and Containment Response Wesdugboue LOCA Westingboue SLB Value PSEG Comlimed Value Value Notes Design ad icenulng Parameters S. LowpressurizerpressureSl[ set ,poit 1715 1700 A yallmnIII7Wpeig RefSC.RC00501

9. Low prsuriutrprOssure ructor trip Sobit. IUO 14U AnalytIa Limit l1p4 Psi . iiSsc@aOso_

LAW 0 l .O Nha Lead 10.0 O"jC

10. Lcada Por Compenat Pru uiz Presuto Reactor Trip LAg- -.0 Lag

• 2.1 E I RoC SI(2).IC-CC.RCP40017 Compensated Prewsutri Pressure Trip 18650 Nha Westinghouse sould 11.

Setpolnt, pg . determine this value baed on a.cI

12. SO Throttle Vulve Cloure Sgnal e w.0 OK - u bounclag value C.

I.o We OK - use boWWdA value I

13. SO Throttle Valve Stroke Time, sec M

I L- L- (--_ C__ _

1 (, ( ( .- t _- - t( - -. (- -. C

I .6( 1. I .- I ---4 Page9of40 ago PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Westinghouse LOCA Westinghouse SLD Value PSEG Conflrmed Design and Ucenslng Parameters Val Value Nt

14. SG Throttle Valve Signal Processing 0.0 WNe OK - use bounding value Deays ror Los ot'Offile Power, se IS. Hl continment presure setpont. Ps 60 6.0 35 Analytical Linm . psig Ro. Setpoinl for Fan Cooler Initiation SC.CS002.01 (see Section K)and SI signal

.6 17 .

16. HI-l ontainment prssue spont, psg -17.0 17.0 Analytical Limit I7psig Re. Se-podnt fbr Spray Pump Initlition SCS0O02-01 (see ection n)and Steamline Isltion

17. Reactor trip electroni detay oowC Tech Spec 3/43 D. STAM GENEASUTORS

1. Unit I Model Mode) F Model F Ok Model F a) Full power opersting Pressure, psba 869.D 74 Unit I - 854 psi bsed on [

PCWOT2541 b) Tube Pluggh,. % Q0. 0.0 1:[] 0aC

LA Ra-03-103

-' ae 10 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Weadngsou"e LOCA Wulaghousee SLB Volue PSEG Confirmed Desig and Utenueg Parameters Valut Value Notes c) Soondaay Side ToWl Fluid M s,Lbs per SO TBD TBD Based on Wostingbouse CN-TA.99-13 GENF mosutt raJ for mavdauuass: .

100%- 10U394 lb 70%-120172 30%-141273 10%. 151447 0%- 169474.1 Thee should be AP(Abo ibr 1.4% power rerat d) MainPoed/soertonlowrate.10fLbhr 15.10 / PCWO.2541 OK-

2. Unit 2 Model Moda 51 Model 5 OK Model 51 a) Full power operating Preure, psia 122.0 127.4 122 pla basd on PCWO. J a C.

2541*

6)C b) Tube Plug&4 % 0.0 0.0 L.J .J Bedo Westinghouse -W Secondary Side Toul Fluid Mass, Lbs per TBD TBD CN-TA40030 GENP tesults so or maximwumae 102% . 114771 lb 100%- 116042 60% 132605 10% 157754 0%. 157890 These sould be acceptable for 1.4% power ress, but Wesc*4use wil need to detenmine values at 30 and

.____ 70% RTP.

(-__ C_ _

(- , t ' ( ---- _ l -

t-V .( - . _ - _ --.. -

I [ l- -I,. t- ( _

r ; 1..-- . (,-. r-- .- - ( --. t-- , r) --( ,( ) Jl I f- l 1 F, r-m T1r A.3

-- 'iage 1I of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response WestIngbouts LOCA Watllgbouse SLD Value PSEG Confirmed Dfeign and ULcensng hat era v Ves Voalv Nots d) Main Feedistem total flow rate, 10 Lb/hr 150 nA OK - PCWG-2541

3. Unit 2 RSO Model Frumatome model 61/9.T n/4 nh High - 911 psia sarted. _

a) Full power operating Pressure, psi

@100% power. 82,500 gpm, Tavg 577.9 deg-F. nominal 830 polo (based on Pramatome cak NPPMO DC

6. Rev A, still under PSEC OLI C b) Tube Plugging, % n/A W

j c) Secondary Side Total Fluid Mass, Lbs per n/a All dat h not yet aailabl For LOCA so Curent Fnma calculatin cover 100%

power{ sf 4C hot g 99,60 gpm For mechanics design flow at MSLE, Oim mass is a function of 577.9 des!P- 111610 lbs, ~0%30% 70% and 100% power.

No plans in plabc to change At 20% powr Om progmmed current program level, level changes.

d) Main Feed/stem total flow rate. 10' Lbhr n n/a 15.12 - Framatome design Coal

LT

• RA.03-103

--rago 12of40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamilne Break Mass & Energy and Containment Response Weadughouse LOCA Westaghouse SLW Value PSEG CozlnUed Design and Ucmalaig Paramnetrs Value Value Not" c) Tosl Dry Weight of RSG, Ibm per SG n/s nta 661,400I based on Frumn me drawings (NFPMG-DB-002 Rev B is for one of the four SOs, all have the sam woight) f) Total Number ofTubes per SG n/a n/ 504f, Frantoma deign oslo NFPMG DC 6, Rev A tube Diameter, inches or fee T) n/a n/a 0.75 inOD, 0.0429 inthick (NFPMG DC 6, Rev A) h) Total Tube Bundle Surface Arem, 1 per n/a nl 66,236 SG (NFPMG DC 6. Rev A)

E. STEAMLINE

1. Main stcarnline cross-sectional are, Rm n/a 4.6 OK Ref. VTD 140319 Ref. Stress Isomottic 267130A & 267132A t - -- C- - c-- (--- (ii ( -,

I i_ (.- (- - ( - (-- k-- ( --- A ---

h-. ~--IT U r--- f.7)F>tr-,- ,

7i( - .:- ,t2F {- 1'-- >F17.,I r4.n, l1-- r--r-,, < r - r-r- 1 a-

_. igag 13 of 40 i PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamllne Break Mass & Energy and Containment Response W"tlnghoawv LOCA Westinghouse SLB Value PSEG Confirmed Design and Utenuing Parameters Value Voluv Notts

2. Flow restror flow are f n/ 1.4 OK - consistent with SWlen Also need flow restrictor UPSAR. Per Fromatome. areailocation ror Unit 2 RSG (unit I - interal flow restrictor ANP Technical Proposal, No. 02.5073, Rev. 3, unit 2 - in-line flow restrictor) Frmtome IMconffmned th 1.4 f steam flowae Exactv"We Is1.3981P for the seven venturies.

3. MSIV flow area 1 n/r 3.2 f* OK Ref. VTD 140319

4. MSIV closure time. see nwe 12.0 OK Ref. VTD 140319 Includes electronic delay and 135130 stroke lime or main and bypass

_ valves 5420OK Ref. Stress Isomanoi d S. Steamline volumes: n/a 5

• between SO and MSIV (I loop) 542 267130A & 267132A

• downstream of MSTVs to turbine isolation 9541 OK by Westinghouse valve or cthock valve (plant total) 9541 comparison with other similar plants (Westinghouse to document this conclusion)

F. MAIN AND AUXILIARY FEEDWATER

LI RA.03.103

.-.fago 14 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA a!nd Steamline Break Mass & Energy and Containment Response Westiagbou* LOCA Weudegbouse SLU Value rs9G Continued V*lut Valet9oe Design and Ucenaing P*rameters BMo n data from ih. aCc Main Ftedwte Temperature, OF PSEG Nucle Ta haia Full Power 432.8 432.; Pomane EufIwner, the 395.0 curetM U" l power It- 427.4 4-F oewater

. 70%A Power 30% Power .329.8

• 0% Power .00.0Un242L4F We3iowev wue consie wit lb Unit I DBa Deck (CN-TA.99.134 The feedwater eatlilpy values for Unil 2 differ orom Unit I I 10 and 60% RTP (sameat 100 and 0% The Unit 2 Bast Deck cak (CNt TA40-30) did not include values at 30 and 70% RTP.

100%.411.4 BWAb (U1)

- 411 (U2) 60%. 355.2(UI)

.360.0 (U2) 10Q-239.1 (Ul)

.232.0(V2) 0%K *70.7 n/a 10.0 OK RE OperAllo1s Includes eectrole c delay and

2. Feedwatar control valve closure time. see Procedure S1(2).RA.ST.MS Ihe tim for t valve to flly 0002(Q) cou. Thi isa saakty-rde valve.

n/a 32.0 OK Ref. Operations Incudes an electron toly and

3. Feedwator isolation valve closure time, ec i Procedure S (2)RA4T.MS. the time hr the valve to fly 0002(Q) clo" Feedwater isolation valve osure characteristic n/a Flowa i linealy ramped VTD 124574 4.

down over the last 20 seconds

( -- -, (-,-, t -- t-, 1- l LI .: L-

• l_

• f I L - ( . V

r. - r

{-, V r -)r V C- t 't-T (- 1- Wt-- r rm r-rm) *e CZ ---rp 15 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA d Steamllne Break Mass & Energy and Containment Response W"tingchouse LOCA Westinghouse SLB Volue PSEG Confirmed ValW Value Not" Design and Ucensing Parameters

_ iiMFW pump trip is not credited As per PSEG letter NFU92 e eaes witb FCV falur would

5. Coautdown ofmain feedwttterpumps

.In current anaisis r lo obe helpftl to credit MPW pump (39011992)1 toe trip ot the Iripd need infomion on main fd pumps cn costdoown of MFW pumpt (PON be credited as lhlorws 2.0 l n' tioW) second signal processIng delay, then 10 pump co.stdown (bounding high)

Per Westinghouse folcon, this a typical eonstdown value for feed pumpst (Westinghouse to confirm)

OCI Feedline volume, 1u: nwe Assumed values are very 6.

Between SO and FCV 3SI OonseI tive ctual pipe 438.0 conservatrve acup _

Between SO and FiV 438.0volume Calculations are.

Unit 1: 356/39 (S.I.BF.

MDC-I80)

Uni 2: 325/376 (S-2.BF.

MDC It04)

Number of main feedwater pumps running: n/A OK Ref Sl(2).OP.AB.CN-7.

• 'Fult power 2OOO(Q)

• 70% power 2

• 30%povwr I I.I I I

• 0% power i

LT 2A-03-103

- -rago 16of4O PSEG Nuclear Responses Key Input Assumptions for LOCA Ind Steamflue Break Mass & Energy and Containment Response WIalagboute LOCA Westlngbouse SLD Valve PS&G Coullrmed Val+ Valvee Not Design and UIAiuag Parameiter

8. Number orcondensat pwmps running: n/a OK Rot SI(2)10P.AB.CN1

• Full power 3 OOOI{Q)

• 70% power 3

• 30%power 1 2

• 0%power I 04b C.

9. Auxiliay Feedwwr Flow peW SO, gpm 19T0.0 Table III and TabIe IV in Soe Auacments 2 &3 NFU.93.013 Unit I4 15 a,0 1.0 Unit I 172 (S-1.BF.MDC.

10. Auxiliary FcdwierSystem Purge Volume-Latest 2ource 180Aiuloos s1oveu h a Maximum of ay single loop, th of Unit 2 131.0 Latet Sowcc Is: all four loops is 141.5 RW3. Voiume ofppinlg IW aeeds to be fled oW igh euilpy mai NFS-99-179 Unit2 - 131 (S-2BDF MDC- fedwatrbefors cdit can be 1804) taJen for lowr enalpy aux. feed.

o6 C 120.0 120 Confinmed I1. Auxiliay Feedwaer Temperatr. OF n/A. Ret. VTD 123779

12. Heater drain pump peoormae curve t -. ---. l -. L :_ C .' - C l--

-, L-I.: (- l - (- .- .-- t .-- (I - I .-- ( -- -

L (-

r I.7 rV f -> [ (- r- T t;  ;- r" rrI rm r' u 'r;L2.t , -

t'-rge 17 of 40 I PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamiline Break Mass & Energy and Containment Response Design and Ucenhing Parameters Westintghoue SLD Value j PSEG ConIrwned Valae 1 Notes

13. Number ofrHeater dnin pumps running Wva OX Rot SI1(2).OP-AB.CN-0001(Q)

• Full Power 3

• 70h Power 3 0 30% Power 0

• 0%Power 0

14. Mainfeedwatercontrolvadve(FCV)fullopen nh 1450 OK Ret VTD 119162 Cv

1. Main feedwater bypass control valve (BFCV) n1h 72 Cv is 72 Rt VD 1209S%

size and run open Cv ReE Design Change Pacge

16. Normal position of 8FCV at >0% power nha aosed IEC.3206 Advanced Digital System

17. Accident operation otBFCV Ope-Closed The BFCV mains closed Refers to position of faulted loop when FCV goes fall open. BFCV when FCV goes full open See Attachment t for more

_ __ __ _ __ ______ _______ ____ _____ __ __ __ _ __ __ _ ___ ____ ___ _ __ _ ___ ___ ___ _ __ _ ___ ____ _in _ info_orma oon U I has an inoperble cross IS. Significant differences in Unit I and 2 n/a None Assumed tie for beater drain system.

condensate and feedwater systems affecting sytem Unit14,I has 1iheatersyle anddifferent of drain 91TinS13. an condnsat feewatr hydraulic modeling bypass vave. This bypass valve will be replaced with Unit 2 design In IR17 refueling outage_

LT HA-UW-10 augo 18 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA iu'd Sleamilue Break Mass & Energy and Containment Response Westlogboule LOCA Westiagbouse SLU Value PSEG Conulnued Dealgn and Licensing Parameter Value Value Notes

19. Significant changes to condensate and feedwater n/a None Assumed Digital faedwater system components since 1989 impAing modifat hydraulic modeling (e.g. condensate or feedwwar pump performance curves. FCV wim, etc.)

1. 21 Heater Dram pump trips automatically. The PSEG to confirm that pumps are

20. Availability of drain tank pumps. post turbine rretnuaining pumps for Units I 2 uc nually tripped by rAip rippcd operator. (Ref SlOP.

_SO.TD-0001) _

21. Operator action time to re-align AFW from n/A 600 OK Ref EOP Sl(2)-EOP-faulted SG. sec T_!P-_

C. SAFETY INJECTION (PUMPEDSI)

I. Safety Injection Configuration for both the ns See Attchmen 4 Assumag the loss ofoffite injection and recirculation phases (Minimum powor, th limiing single failuro Safeguards) of the limiting bus or the limiting diesel, whichever results in minimum flows (this daa should be biased low for conservatism).

2. Safety Injection Configuration for both the n/a See t 4 injection and recirculatlon phase. (Maximuw Safeguards)

Minimum Deliverable RWST Volume, gallons 3l3.000. roai _ _ a _wm 4 Dcasd values are conervadiv 3.

193,000 Low Level 120,000 Low-low Level C. - C(112 L I.- 47 - L-L , K. L , ( ( ---. L. - , t .- (----

rF r- r r --, rv} - F--

--- z-z *r. v! r rm rm r_  ; .I I -rigo19of4O PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Westinghouse LOCA Westinghouse SLB Value PSEG ConfIrmed Design and ULensing Parameters Valte Valve Not"

4. Maximum Safety Injection Water 100.0 tO See Atchment 4 maximum RWST water Temperature during the Injection Ph"n."F temperature This value must be consistent with the InJectbon phase Si flows avid Containment Spray Flows (see section J).

.. Maximum delay to reach rIl flow for the 32.d 22.0 See Attachment 4 l" d valve Iscons""Ove.

46 e.

minimum safeguards configuration (including Loss of Ofte Power, diesel strt-up tOme signal I processing times.v vahme sttoke thnes ltor ALL SI pump) sec M

6. Minimum delay to reach ul flow for the 320 nWs See Attachment 4 For loss ofoffilte power, the maximum safeguards configuration (including minimum tme and maximum time Loss of Oftsite Power, diesel statp time, signal should be similar.E processing times valve stroke times for al Si pumps) sec _______

ObC

7. Time of sa" Inection switchover to 1704,n See Attachmentw4 recirculation with minimum safeguards (after SL setpoint Isreached) sec S. Time ofsfety injection swfltchvrto 1090.b nha SeeAttachment4 [ ] A, It recirculation with maximum saftguards (aftr ST setpolnt Isreached) see l I

Li i.-O4103

--vg. 20 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamlile Break Mass & Energy and Coztainmeut Response Westiaghoip LOCA Westinghouse SLW Value PSEC COfimed Val C Value Not" Design and ULeUIdg Pa t Table G I h e evalues are coservative.

9. Safety Injection Flows for ECCS Train Failure

. NFU-9 1-501 br IHSI fow (congurallO f"Oboth t eOOa aid"S.

Lim rae recircatlion phases) wi No Spilling

[LocA) ____________________________

Table 0G2 . a Scc Ataltumtn 4 iceasd values ue conervauive

10. Safety Injection Flows for all ECCS pwnps operational (configuraton for both the Injection and recirculatIon phases) with No Spilling Line (LOCA)

Table G-3 See Attachioent 4 dereue values ur conservative I 1. Minimum Safely lrection flow Raes fotm I Charging/SI pump and I [HSI pwnp with No Spilling Line (SLB) n/ 1 197.1 See Au oent 4 decresd value is conservative

12. Si volume between RWST nd RCS, fi'

13. Si line initial boron concentration, ppm WsS! O .4 n/a 0 See Attachent 4 Hu BIt been pibl ly re oved

14. Boron Injection Tank boron concentration, ppm valved ot or boron coneafto, f~_

f i _ _ wem42l

15. MinimumContainmentSump Elevon 70.

46.3 n/ See Atachment 4

16. RJHR Pump Suction Contedine elevation, QL 46.53 ala See Atta i4

17. RHR Pump Discharge Cnterilne elevation, ft

. L, L-- L

- L L. t _

, I. I . L. -, t . ( k. (- . ' L L "-

F.' (7; ( ,I r", - r- r r- r- r--, u' r;- r-- r--, rm r1 r; ,-3w-

-~-4ge21 of40 7 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Wettloghouse LOCA Westinghouw StLD Value PSft w Conirmed Valle _Valie Not" Design avd Utmnsing P_ attes I S. RCS Cold Leg Elevations, 97.0 WA See Aftsetanfent 4

19. RCS Hot Leg ElevationsM __ S" Atahment 4 um See Attchmet 4 See e.mall from 11.1241 in

20. Minimum CCP Pump Attachm~ent A Minimum Sl Pump Cmne. . SeAtta *e from 11-12401 In tSom f4 21.

S" Attachment A Sume 4 S 11.1241 In (Attmcment

22. MInimum RHR"s C Afttchmenit A

23. Maximum CCP Pump On"yq See Attment4 See" omafl from 11.12401 b Attchmentl A

24. Maximum SI Pump Curve Se.Anaehment4 See eiafl Irm 11-12-01 in Attachment A

25. Maximum RHR Pump Cur"e S S"tefmall ftom 11.12401 In See Attachment A

26. RWST boron concentratlon. ppr nWe 2300 Sff Attachment 4 H. SA FEr1i'JECTION(ACCUMTL TRS;

_ . _ _See Aftnliment 3 I. Number of Accumulators 4 4 Su Attc4mnt-

2. Maximum Water Gas Temperature. OF 120.0 120. S Atachment S incresed value is conservative.

Should be equal to the initial containment temperature

LT ".Q3-i03 PSGNc e 22 of 40 PSEG Nuclear Respowies I

Key Input Assumptions for LOCA aad Steamline Break Mass & Energy and Contalument Response Wesdaghous LOCA Wultngbouse SU Volvo PSEG Collramed Val, Value Notes Design and Ucesvlog Parameaers 3 850.0 n/1 See Aa e Should NOT inclute any line

3. Nominal Accumulator Water Volume, R volume or any undelivorable volume.

4. Rangs o Accumulaor Waer Vwnme, R1. See Atlachnt S S. Uncenainty on Accumulator Wler Volume, f? 1i/_ See AtAcwwlt 5 See Attacmnt5 Vu W nHOU unalanty.

any

6. Minimum Gas Cover Pree, PA,& 595't 595.5 DoSueaod valce is c0on atIve.

_ll Soo AtacM S

[

7. Uncertainty on Ga Cover Preate. psi 15.q Range of Gas Cover Pressure, psi&. 595.5 to 647.5 n/a See A ce S B.

1350.0 1350. See A chtld Iclude n lin

9. Nominal Tank Volvne, IU See List ofDrwings i n/ e Should revSew fo botb unlg.

10. Individual Line Volumes (3 Table -I _

I G iVENEALCONTAINMENTA&SUMPTIOVSANDU LM

1. Containment Net Free Volume, fl 2.62xxlO 2.62x 10' J OK. Ret. 5.2.vg l value is conservative.

120.0 OK. Ref .TS 3/ 4.6.1.5 increued value is conservative.

2. Initial Containment Temperature. 'F 120.0 a a a I

L -- L i' I f I I . l1 _ 1:._ ,._ l_ .

L- - .- l - . (L I (L I

r-. ( vi. r71 F-- viIT>r r 7 r r rz dr.

-_ --4go 23 of 40 PSEG Nuclear Responses I

Key Input AssunmptFons for LOCA and Steamline Break Mass & Energy and Containment Response Weatingboule LOCA Westinghouse SL8 Velue PSEG Confirmed Design and UMensing Parameters V*olI Vae Notn I 15.0OK- ROeC TS 3/ 4.6.1.4 AIC.

3. Initial Containment Pressure, pils (Max) 15. R

.o 14.7paig+O.31.l.S psi Input is typically atmospheric pressure plus the Tech Spec maximum allowrable value.

,%At 4, InItial Containment Relative. Humidity, % 20.0, 20.0 20h RH is documented in PSEG ilbe S;C-VAR-NZZ-0020, RO. paop 95 of219 (attachment C table 2.1 Ito Westinghouse PSE 97.516).

5. Containment Wells / Heat Sink Pioperties Table l.- and rable 1-2 Table I-I and Table 1-2 See footnote, decreased value is conservative.

Note, aocumulators excluded

6. Containment Design Pressur psig 47.0. 47.0 OK Ret TS 5.2.2

7. Containment Temperature Limit, OP Table 43 Table 1.3 Values in Table 1-3 ame the current Salem EQ temperature profile.

While ft Isdesirable to remain within this romfle to avoid EQ

,timpac the vahues may shift due to reduced heat removal. However, TS Section 5.2.2 Identifes the single design tempernatr of 3513

_ i *_F IWestinghouse Key Input Assumption table Isconsistent with UFSAR Table 15.4-20 (Passive Heat Sinks. This is based on the Salem UFSAR Revision 9 (1989). This table is calculated by Westinghouse using the best estimate values provided in Table 15.4-21 (Structural Heat Sinks). However, Table 15.4-21 his been updated a number ottimes since Revision 9. Westinghouse will need to review the current UFSAR (Revision 20) to evaluate whether cunent passive heat sink values are accepo"Ile

LT tA4-103

- -r°24 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamilne Break Mass & Energy and Containment Response Weatlngbouie LOCA Wesdagbouse SLB Valve PSl Comed Design and Lcenslag Parameters vliu value Nol S. Worst containment safeguards alluer: n/W For th proposed new 4en. the alluuw ofNWC" Vital bus resultS in e loss of I condainanet spray pump and I CFCU (fiom the new

. with ofaite power diesel rallurc, lose I spray lose I spray mdi Itcoolers tot of 3 CFCUs)

• without o pump and 2 coolerl ,in J. COPTAiNMENTSPR.rPUuS Soc A tt nt 6 d v is conservative.

1 Number of Containment Spray Pumps Operating

• wilth offsite power and no fallure 2 2

• with offslte power and single failure WA I

• without offite power and no failure 2 n/A

• without offaite power and diesel failure I nh Containment Spray Ring Nozzle Elevations, ft Upper 2 ringl 2665 Upper 2 rings - 2665 See Attachment 6 2.

Lower 2 rino - 244.5 Lower 2 rings - 244.5 Table $. Table J- Se Attchmet 6 decS value is conservative.

3. Containment Spray Flowrate during the injection phase. gprn (I pump & 2 pumps) 2600 15200 gpni 09 47 psig 19148U2i36.2 n/sSee Atachmen 6 decrased value is conservative.

4. Containment Spray Flowrate per pump during the recirculation phase with minimum safeguards and maximum safeguards, gpm See Attachment 6 n/Wl SI.0 85,0 / nWe increased value is ooservadve.

S. Maximum post accdent delay time for effective spray fow to enter containment afer ther setpoint is reached with Nd without offaite power available, sec.

IL , L[-- .+i V: (i-L -

J [ -- L.- -1, Z, I . , I , -- L, -. l ,~ l-

I- I r[ - V-- I r- r- rr[ r- rr r- r r-fr-L LT ri-0 F-M-31 u3

--ege 25 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Wettlughotise LOCA Westinghouse SLB Value PSEG ConfIrmed Design and Ucenuing Parometera V*. Vaole NOe AS e

6. Time injection spray flow is terminated with 4473.86/4073.86 Ws See Atacmen 6 minimum safeguardsmiadmum safeguards (after ST setpoint Isread) sec

7. Time recirculation spray flow IsInitiated with 4473.t6/4073.6 n/a See Attchment 6 constent with pevious item.

minimum safeguards/maxlmum serfguards Include any period without flow.

(after Si setpoInt Is eWhed), seo S. RWST Temperatur OF l00Oo 100.0 See Attachment 6 i conerve Value must be consistent with htection Phase Si flows and Contanment Spray Flow. Se Itemt 0.3.

X COTvAINAfE rFANCOOLERSs 3 cfcu's in new design. Any I Number ofContainment PFaCoolrs Operating bus or cfcu failure leaves 2 Decreased value isconservative.

• with oMite powerand no hilure nh 3 2

• with offifte power nd single hilurm nh 3

• without offtite power and no failure n/a 3

• without offiite power and diesel bilure 3 _Ws_2

2. Fan Cooler Heat Removal Rate, STU/sec per Table K.l Table K-I See revised Table K-I besed decreased value Isconservative.

Fan Cooler on new PSEO culo.

SSW-MS DC196t8 o oRD

LT RA'03.103

-i/ae 26 of 40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Weatlegkous LOCA Wetingbouse SLB Value PSEC Continued Valu Value Notes Design and Ucensing Parameters n/a /60.0 60.0 n/a 120 second delay for new increased value is conservative.

3. Maximum post accident delay time for effective Fan Cooler Performance 4ft he setpoint is design reached with offitite power availableiwithout ofisite power available, sc L. HEAT EXCHANGER Simplified P&ID's provided For both the l.jeoion and I Sketch illustrating the service water system as it for U2 ECCS, RHR CS SW reciroulation phaes relates to the safety equipment Including containment fan coole, containment sprays, Si. and SI.

CCW Hemt Exchanger. RHR Heat Exchanger.

etc.

Confiumed. There are two CCW Heat ;sa W CCH7C (ome per ta) - decrcAd nVue Ik cRvaive.

2 Minimum number of avaible Refrnca P&ID 205231).

Exchne Mtlnm safeguards based.

.Oa single hare ono train.

r

3. CCW Heat Exchanger UA, 10' fTUhr.'P 4.013 n/

Cod:inne; Reloce PoWHX CCHX L

..modafrom PSO Cak S.C CC.MDC.1798. Rev. 3, with the following inpu&s:

SW Inlet temp

• 90*F SW flowinIOOOgpm CC inlet temp a 170'F CC flow - 4140 gpm Totl (ouling 0.0016 2% tube plugging L. . . l I 1-.- L 1 .

[. I L'

I I I l. ( 1. . I II (II ~ lS -

I

I I I. [7 r r --- F r--

f- 1 7 - l rv r-- r- r- r- T rzo03-lr

.- go 27 of40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamilne Break Mass & Energy and. Containment Response WestIngbohlie LOCA Westinghouse SLB Valve PSEG Confirmed Value Valve Notes Design and Utenshig Parameters Confirmned. This isa Decreased value is conservative.

4. CCW flow through CCW Heat Exchanger, gpm 4140.0 n/a conserave minimum value Value appears to be based on a based on 4000 gpm to System Descriptimon PSEJPNl.

RHRW( and 140 gpm to 200C/3, Table 82.1 dated prior to imiscelaneous cornponents 1989.

on a single CC train.

5. Maximum Service Water Temperature, F 95.0 95.0 Use 93F for consistency Increased value Isconservative.

with CFCUs. All other references Indicate that the maximum value should be 8S.O.

0 5.0 Degrees would be consistent with the heat removal data for the fAn coolers.

Confirmed - Reference

6. Minimum Sevica Water Flow per CCW Hest t0060 s/a Westinghouse Transmittal decreased value is conservative.

PSE.94.605, Section 3.0.

Exchanger, gPm Confirmed. There ar two

7. Minimum number of available RHR Heat I nh RHRJ (one per train). - decreased value isconservative.

Rxarence P&ID 205232).

Exchanger Minimum safeuards based on single fillure ofone train.

Cannot conlmm at this thec -. _ 4,C

8. RHR Heat Exchanger UA (recirculation and post I.75/l.i75 nn recircuatlon spray) 10' BTIJ/hr,7; ineed Ibrther information.

derased value is consevtive

9. RHR flow through R.HR Heat Exchanger 3237.5/7367.6 n/a Cannot confirm at this time -

(recirculation and post recirculation spray), gpm need frthe information.

Confirmed. Minimum C C

10. CCW flow per RHR Heat Exchanger. gpm 4000b wit flow In prior Contiinment decreased value is consevtive.

awnlyses. (Er.Watinghouse Transmittal PSE.94-605),

Section 8.0). Flow setting In field based on obtaining this Value under limiting

_ __ __ _ _ _ _ _ _ _ _ _ cond~ito s_ _ _ _ _ _ _ _ _ _

L7 DRA-1Q3IO

-'age 28of40 PSEG Nuclear Responses Key Input Assumptions for LOCA and Steamilue Break Mass & Energy and Containment Response Wetinghouse LOCA Waianghouse SLU Volve PSEW ConIlnmud Design and UJealg Parameters WVoe Value Notes Cofirmed. Assumed value It. Additional hoa loads on thc CCW sysdm In 2.0 nwe I pnot Containmenl addition to the RHR Heat Exchanger ho4ds, such .lss (ES hOUse u misocllaneou equipiet toad (L.., Oil SUioa 8.0).

Coolers for SI pumps. Speal Fuel Poole.

etc 1OBTUJhr I l - l - L - .I l [ '> I I ( . l L I IL

L LTR-CRA-03-103 Page 29of40

) PSEG Nuclear Responses L Figure C-1 Salem Steamline Break Protection System Logic L

Low H5IighIo L

onahwd tk"an L

L

LTR-CRA-03-103 Page 30of40 PSEG Nuclear Responses TABLE G-I SALEM UNIT I & UNIT 2 PUMPED SAFETY MRECTION IJEClION PHASE DATA (MINIMUM SAFEGUARDS, aLa, Trab Failure or Diesel Failure)

[No Lhes Spilling Asumedl RCS Prenure . , _ .e_

CHGJSI IHSI LHSI Ibm'sec IGPM) hmlsec [GPM) lbnmsec [GPM) 14.7 50.97(369.0) 76.791555.8) 5492213975.921 34.7 50.73 76.13 1551.7) 51S.99 13735.39)

S4.7 50.49 75.57(547.1) 430.72 [3480.011 74.7 50.26 74.96 [542.81 42.66 13304.54) 94.7 50.02 74.361538.3) 400.3912902.15) 114.7 49.781360.41 73.75 1533.8) 353.6912560.431 134.7 49.54 73.25 297.51 2153.71) 154.7 49.30 72.76 222.69(1612.03)

J 174.7 49.06 72.S S294 1600.39) 194.7 41.82 71.79 0 214.7 4t551351.7) 71.301516.0] 0

• Scvcial values delemibd by imnerpohlion p 62.0 IbnIft3

LTR-CRA-43-103 Page 31 of 40

!- PSEG Nuclear Responses TABLE G- (toot.)

SALEM UNIT I & UNIT 2 FUMPED FLOW DURING RECRCULATnON PIASE' (MINIM SAFEGUARDS)

RCS E Flow Igpml C00ntlmuent Presure IPS_ __

Total Pumped FLOW No spilling line 14.7 3209..

l

• Flow is the total pump RHR flow through the pump/heat exchanger. Flow to the reactor vessel is less if recirculation LO sprays are operational.

I- _ __...-. .....

LTR-CRA-M3-103 Page 32 of 40 -

PSEG Nuclear Responses TABLE G-2 SALEM UNIT I & UNIT 2 PUMPED SAFETY INJECTION INJECTION PHASE DATA (MAXMUM SAFEGUARDS, s." No Failure)

INo ises Spilliog Asumed)

RCS Prsure lb l 2 CHGISI

• 2 IHSI

• 2 LHSI Mbnmsec [GPM) Ibm/sec [GPM) Ibmvsec [GPM) 14.7 121.02 [876.10) 114.06 182.631) I155.01 13367.181 34.7 120.62 113.34 199.0 17955.88) 54.7 120.22 112.62 1033.317520.13] i 74.7 119.31 I I1.9 974.5717055.13)

J 94.7 119.41 IlI.t 905.3916554.29) 114.7 119.0 [61.441 11046 1799.62) 829.9816008.391 134.7 18.59 109.72 746.4715403.851 154.7 118.18 108.93 651.9214719.361 174.7 117.77 108.3 541.33 3913.77) 194.7 11736 107.62 405.2 12933.45) 214.7 116.94(146.55] 106.741772.731 223.2311616.01)

' Sevend vales dtermined by interpolation p- 62 .0 flxn/fi3

LTR-CRA-03-103 Page 33of40 PSEG Nuclear Responses TABLE G-2 (ConL)

SALEM UNIT I & UNIT 2 PUMPED FLOW DURING RECIRCULATION PIIASE (MAXIMUM SAFEGUARDS)

RCS & tput Ceotainment tressur IPS}2 Total Pumped Flows No spilling line 14.7 7367.6

• Flow is the total pump RHR flow through the pump/heat exchanger. Flow to the reactor vessel is less if recirculation sprays are operational.

LTR-CRA-03-103 -J Page 34 of 40 PSEG Nuclear Responses TABLE G-3 SALEM UNIT I & UNIT 2 SI Flow Assumed for s13 (I CHGISI & I IHSI)

[No Uses SpIling Assumed)

~u nFlow libulsec)

IS 12137 415 111.4 615 . 101.41 915 84.4 1315 45.65 1415 31.04 11s 23.10

-- - 21t -- - - 15.91 2315 5.29 2340 0.0

LTR-CRA-03-103 Page 35of440 PSEG Nuclear Responses L Table H-1 PSEG Document References for Accumulator Line Volumes L Unit I

1) Calc Note #267211 I) Drawing 307036 z 2) Calc Note #267241

3) Calc Note #267246

4) Calc Note #267241C

5) Calc Note #267242

6) Calc Note #267243

7) Calc Note #267244 Unit 2

1) Drawing 138128 L 2) Calc Note #267241, Rev. 2

3) Calc Note #5671203LSI, Rev. 1 L 4) Calc Note #5671218, Rev. I L 5) Calc Note #567122, Rev. l

6) Calc Note #5671223, Rev. 1

-- 7)-Calc-Note4-5671-2-25,R-ed. . ...

LTR-CRA-03-103 Pagc 36of40 PSEG Nucle2r Responses I Table 1-1 Sale. Unit I and Unit 2 Stnctural Heat Sink Assoptions For Coutalameat Ist ity .23 SURFACES TOTAL THICXNESS Sink Description Material EXPOSED ARKA (it) 2

_( ) I 1 Paint Coafi *1 Paint Carbon Stecl.& 45,169 0.03125, Concrete 4.5 2 Insuladon, Carbon 14206 0.20S3,0.03125, SteeL & Concrete 4.5 3 int Coatng Paint, Carbon Steel, & 29,249 0.0417 Concrete 3.5

-j 4 In contac wit the sump; Paint Coating J2 & Comet Wnt 3.5 5 Paint Coating 52 Paint & Conret 6,S06 1.5 6 PaintCoatingl2 Paint &Concrete 9,424 1.71 7 Paint Coating 13 Paint &Concreta 31,660 1.5 SStainless Steel 13,273.61 0.01773 Concre 1.9 9 Paint Coasing *1 Paint & Carbon Stee 47,539.1 0.011 10 Paint Coatin *I Paint & Carbon SWl 76,741.2 0.02102 1 Paint Coating *1 Paint &Carbon Stel 19,343 0.0437 12 Paint Coating *1 Paint & Carbon Steei 9,330 0.0611 13 Paint Coating o1 Paint & Carbon Steel 7,451.5 0.086

-J 14 Paint Coating 1 Paint & Carbon Sel 3,217.7 0.11124 15 Paint Coating 1 Paint & Carbon Steel 1,S53.18 0.217 16 Paint Coating Jl Paint & Carbon Stecl 43,740 0.0052 17 Stainless 4,272 0.0329

-- a 1 Paint Coating_ 1 Paint Carbon Steel 53,745 0.0211 19 Paint Coating 11 Paint & Carbon Sted 11,243.59 0.0379

-j 20 Paint Coating *1 Paint I Carbon Steel 2,9S9.4 0.15S06 NOTES:

PAINT COATING SYSTEM 7lICKNESS:

Coating II: 0.000625 R Coating S2:0.0015 ft Coating 13:0.00117 R

LTR-CRA-03-103 Page 37of40 PSEG Nuclear Responses Table 1-2 Stradura! flat Sink Anamptions For Containment Integrity MATERIAL CONDUCTIVITY VOLUMETRIC HEAT CPACTlY (Bt.br-ft-F) (11Bu1. F)

Carbon SteW 27.0 58.1 Stainicss Sted L.0 53.6 Concrete 0.92 22.6 Insulation 0.024 3.94 Point Coating #1 0.0:3 39.6 Paint Coating 12 0.013 39.6 Paint Coating #3 0.033 39.6

LTR-CRA-3-103 Page 3 of40 PSEG Nuclear Responses Table 1-3 Containment Temperature Limit Profile Time (seconds) Temperature (deg-P) 0 120 1 165 3 217 6 240 20 265 60 351 80 351 150 325 240 270 1,000 265 _@

4,000 237 4,800 224 18,000 224 180,000 172 518,400 160 1,000,000 140 4,406,400 132 8,640,000 119 10,368,000 113.2 J

LTR-CRA-03-103 Page 39of40 PSEG Nuclear Responses TABLE J-1 1MM DELIVERED SPRAY FLOW (INJECTlON PHASE)

Flow (GPM)

~~~~Contlmen esr Crnt V21veCurret WieLD IPSIG) (with I Pump) (with 2 Pumps) t 311t.0 6234.0 10 3017.0 6034.0 20 2913.0 5826.0 30 2720.0 5440.0 40 2687.0 5374.0 47 2600.0 5200.0

LTR-CRA-03-103 Page 40of40 PSEG Nuclear Responses J

TABLE K-l MINIMUM FAN COOLER HEAT REMOVAL RATE vs. CONTAWINENT TEMPERATURE Beat Removal Rate

.BTU/see per Fan Coolee Containment Temperature Curre Desit Basi Value* PSEG Confirmed Vaue

.- O LOCA/MSLB PSEG Confmned Vahle 105 100.0 606.6 120 1600.0 1502.3 140 3355.56 2922.

160 5318.19 4522.1 ISO 7666.66 6205.2 200 9197.22 flS.0 240 14511.11 11257.2 260 16158.33 12950.t 271 1047.22 13169.6 280 19052.77 14518.1 Basins: Service Water Temperature 93.0F II Service Water Flow lOGOgpM

- ~- . ' - - p-Z 90 lf~flgi 13 O O-1A4Ph I81" !oe foeaina~: 'tor o f.

service waftar eystsm scavimula on

• Al values takes from PSEG calculation S-C-SW-MDC-196M o0 .

-4

-4

Key Input Assumptions for LOCA and Steamline Break Mass & Enerey and Containment Response Signatures Section Items Prepared By - Reviewed By A.CoreParameters thru11 B. Reactor Coolant I .o Fuels Group

.'System ______Fuels Gru .S .HJfZ Fes Group C. Protection System Logic, Setpoints, I thru 17 Delays PaulFinch A John Pehush /

1 &2 Fuels Groua D. Steam Generators Fuels Group (f (? A Fuels Group SG Group SG Group 74 M AAbt 1,3,4 R l

,_3___Valve Engineeing Grouf j7'/°5 A ineeringgre g11 E. Steamline 2 FuelsGroup FuelsGroup 4 -

Kiran Mathur PaulFinch 01_J _

Fuels Group k*?-&*crt p kfi*.,

I Fuels Group G Fuels Group i=:2L A F. Main & Auxiliary 2,3,4,7,8, t i/Usj Feedwater 12 thru 20 Valve Engineril aEngnering 9,

S 11 Kevin King i < 1 Kiran Mathur Paul Finch G. Safety Injection I thru 26 4e .

(Pumped SI) Mike JohnRowey H. Safety Injection (Accumulators)

I thru 10

.vl wd oiweeRowy 9fte

i. General Containment I thru8 A 7 Assumptions & Limits John Rowey , y Kevin King J. Containment Spray I t 8 Pumps I____ , John__wy K. Containment Fan I thru 3 Coolers _____ John Kiran Mathur L. Heat Exchangers I thru 11 Kn Kevin King

) 1)c J J/,7 Rowey Page I of I

Attachment A E-mail Verifying that Plant Configuration has not changed From: Ted DelGaizo Imailto mmlea.com)

Sent Monday, November 12,2001456 PM To: ' iUwestinghouse.com' cc-' Rob DeNight

Subject:

FW. 3604.tif -

Chuck: The attached TIF file (3604tif) provides copies of the Salem RHR pump curves (from the CBD). I compared these curves with the individual pump curves in the Salem (DMS) data base (for the 3 of 4 pumps that were located - also attached as TIF files), and the curves were identical to the attached CBD curves. AJso, discussions with the System Manager and RHR Design Engineer confirm that the original RHR pumps are still installed.

A search of the Salem DMS system and my review of the RHR CBD did not uncover any modifications to the system throughout the 1990s that would impact the RHR PEGISYS model. Discussions with the System Manager and RHR Design Engineer also confirmed that piping, valves, or equipment elevations have not been changed since 1991 that would otherwise invalidate the flow model.

Please contact me if you have further questions. Regards, Ted DelGaizo, Main Line Engineering Associates IJ Page 1 of 1

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 1 Vessel Head Changes Both Salem reactor vessel heads are being replaced during the 2005 refueling outages. In general, the primary change to the heads is that the excess penetrations are being removed. For Unit 1, there will be53 CRDM penetrations in addition to head vent and RVLIS penetrations.

For Unit 2, there will be 57 CRDM penetrations (with 53 CRDMs/RCCAs installed) in addition to head vent and RVLIS penetrations.

Regarding dimensions, the new head will be roughly the same as the old head such that it mates up with the vessel and RCCAs properly. Below are a few of the critical dimensions, locations, movements, and modifications.

Inner Head Radius = 83.72 inches - 0.25 inch cladding Radius Rotation Point = 3.38 inches above bottom of vessel head Head Height (Flat Plane of CRDM Penetrations Top to Bottom of Head) = 108.00 inches Penetration Housing Protrusion Depth Below Head Inner ID = 2.00 inches Penetration Housing OD = 4.00 inches Penetration Housing ID = Unchanged Head Thickness = 7.00 inches + 0.25 inch cladding Head Flange Height = 29.00 inches Head OD at Flange = 205.00 inches Number of Stud Holes = 54 equally spaced Stud Hole Diameter = 7.50 inches

-~ M~e'n'etr-a~i~i~ca'to-n-s fo-r Unh' i

j ' '

B6, B8, BlO, C3, CS, C7, C9, Cl l, C13, D4, D8, D12, E3, E9, E13, F2, F6, Fs, Fl 0, F14, G3, G5, G13, H2, H4, H6, H8, Hi0, H12, H14, J3,11 1, J13, K2, K6, K8, KI0, K14, L3, L7, Li 3, M4, M8, M12, N3, N5, N7, N9, NI l, N13, P6, P8, PlO CRDM Penetration Locations for Unit 2 B4, B6, B8, BIO, B12 (Old / Spare), CS, C7, C9, ClI , D2 (Old / Spare), D4, DS, DI 0 (New),

D12, D14, E3, E13, F2, F4 (New), F6, F8, FIG, F14, G3, G13, H2, H4, H6, H8, HI0, H12, H14, J3, J13, K2, K6, K8, KI0, K12 (New), K14, L3, L13, M2, M4, M6 (New), M8, M12, M14 (Old/

Spare), N5, N7, N9, NI l, P4 (Old I Spare), P6, P8, Pl , P12 Page 1 of 2

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 1 The plan is to move four Shutdown Bank A RCCAs from the 'Old / Spare" locations to the "New" locations listed above for Unit 2. The "Old I Spare' locations will be penetrations in the head, but no CRDM will be mounted at those locations.

While the information above may change with the final as-built vessel heads, it is considered acceptable to access impacts to the CFCU containment analyses. This also holds true for the descriptions of the vessel internals modifications and integrated head assembly provided below.

Internals Modifications Since all part-length RCCAs are being removed, the internals will have to be modified accordingly. For Unit 1, plates will be mounted on the top of the internals locations for all eight part-length RCCAs since the will no longer be installed and penetrations will not be created in those locations.

For Unit 2, the "New" CRDM locations are where four of the old part-length RCCAs were installed. Thus, eight plates will be installed at the top of the internals similar to Unit I, but four will be in the other part-length locations. The other four will be installed in the "Old / Spare' locations listed above since no RCCAs will be installed in these penetration locations.

Integrated Head Assembly (IHA) Package In addition to the changes noted above, PSEG plans to install a Framatome-designed IHA which is similar to those used at other Westinghouse plants (such as Shearon Harris, Vogtle, Seabrook, South Texas, Byron, and Braidwood). The salient difference in light of containment response -

post-LOCA I post-SLB relates to the weight of the new structure in comparison to the currently installed structure. The new IHA is expected to be approximately 60,000 pounds heavier than the current control rod drive service structure. This extra weight is attributable to the integral missile shield, which is being added. Consistent with the current structure, the IHA will be adequately cooled via three properly sized fans at the top of the structure. Thus, with respect to modeling of this structure in the Westinghouse containment models in relation to heat sinks / sources, the modeling should be consistent in nature with that used in the current licensing-basis analyses, only with a larger mass assumption. -

Page 2 of 2

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 2 Item F-9: Auxiliary Feedwater Flow Rates LOCA L 190 gpm is a conservative minimum. Value based on PSEG Fuels Letter NFU-93-083 for MDAFP failure, which states 1120 gpm total, with a minimum of 190 gpm to any one SG. Thus a higher value could be supported, if necessary. Note that the flow is higher for a non-AFW failure - 320 gpm per SG, 1280 gpm total; flow is lower for a TDAFP failure - 700 gpm total.

MSLB Use flow rates determined from Proto-Flo AFW model per PSEG Calculation S-C-AF-MDC-0445, Rev. 2, with 5%margin added - see Table F-9 on Pages 2 and 3 of this attachment. Except for the cases where faulted SG pressure = non-faulted SG pressure, the flows are less than those from NFU-93-083, and will provide margin for the MSLB analysis. Note that the peak SG pressure is reduced from 1133 psia to 1 17 psia.

To our understanding, it is desired by Westinghouse to input individual SG AFW flows for the non-faulted SGs. Due to the limitations of Proto-Flo, only select cases from the faulted/non-

-faulted SG pressure matrix were performed. The flows for the remaining cases were determined using curve-fits (Reference Jandel Scientific 'TableCurve Windows", ver. 1.0). For the non-faulted SG flow, the curve-fits were done on the sum of the three non-faulted SG flows, rather than individually. Thus, the only individual SG flows available are from the specific Proto-Flo L cases run. For individual SG flows for all the matrix cases, additional curve-fits will be needed.

Included in Pages ### of this attachment are the Proto-Flo results per SG (with model error cludedvu.ve4its and resultaflow -mztx (withrmdwithout the 7ddd 5%emnarginiTh-is data can be used to support development of the additional curve-fits required for the individual SG flows.

Page 1 of 1

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 3 Table F-9A: MSLB AFW flows with no AFW-failure Unfaulted SG 500 600 650 700 750 8W 850 900 1000 1117 Faulted SG 4 1117 638

_ _1601 _ _ _ _ _ _ _ _

1000 _1802 154 900 754 856 1010

- 1956 1705 1349 850 769 811 919 1062 2018 1916 1662 1321 80 781 821 865 980 1117 2068 1982 1880 1621 1288 750 791 828 870 914 1030 1166 2106 2033 1948 1847 1586 1258 700 800 835 870 916 961 1079 1210 700 2139 2073 2001 1915 1815 1553 1232 650 810 842 876 912 957 1002 1123 1248 2171 2108 2042 1970 1885 1786 1523 1210 600 820 851 882 920 956 997 1041 1161 1271 2202 2141 2078 2008 1936 1856 1759 1497 1205 840 897 929 961 991 1027 1066 1110 1236 1343 2260 2144 2082 2019 1954 1883 1803 1711 1445 1157 400 914 971 999 1029 1061 1096 1133 1175 1298 1392 2206 2090 2029 1967 1901 1830 1754 1663 1402 1129 982 1036 1064 1093 1123 1156 1192 1233 1354 1445 300 2156 2040 1981 1918 1853 1784 1706 1620 1363 1091 200 1046 1097 1126 1155 1186 1218 1246 1285 1402 1483 2109 1994 1933 1871 1806 1737 1666 1581 1328 1069 1105 1156 1182 1211 1240 1270 1299 1337 1451 1533 1 2064 1950 1891 1829 1764 1696 1624 1540 1293 1030 1152 1201 1226 1253 1282 1311 1345 1382 1494 1581 15 2029 1916 1857 1796 1732 1664 1589 1505 1263 991 Note: 1) Top Number Is AFW flow to faulted SG (gpm)

2) Bottom Number is total AFW flow to 3 non-faulted SGs (gpm)

Pae 1-of

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and

- Containment Response Attachment 3 i

i Table F-9B: MSLB AFW flows with runout Drotection failure Unfaulted SG- 500 600 650 700 750 800 850 900 1000 1117 Faulted SG .

1117 644 10__ 18 1676 1000 753 864 184611516 9C00 892 930 1028 1840 16399 1425 8iO 959 965 1006 1083

. 1832 1787 1645 1397 1005 1020 1031 1085 1143 1853 1798 1744 1598 1371 750 1036 1058 1077 1093 1138 1198 1887 1830 1769 1710 1569 1351 700 1066 1089 1109 1133 1153 1195 1249 7C_ 1922 1864 1808 1745 1681 1542 1334

-. 01096 1117 1138 1158 1182 1202 1246 1295 650_._._._._1956 1899 1843 1787 1723 1659 1521 1320 600 1123 1145 1166 1189 1210 1230 1251 1283 1323 1988 1934 1877 1821 1765 1704 1639 1510 1312 1176 1218 1240 1260 1278 1297 1317 1335 1378 1414 500 2052 1945 1890 1834 1781 1726 1668 16081 1475 1283 400 1269 1308 1327 1346 1365 1383 1400 1418 1451 1483 2010 1905 1852 1797 1743 1688 1635 1576 1448 1257 0135S 1391 1409 1427 1444 1460 1477 149 1523 1558 -J 1972 1868 1815 1762 1707 1654 1598 1541 1412 1219 200 1435, 1469 1487 1505 1522 1538 1547 1560 1585 1615 2 1936 1833 1780 1726 1673 1619 1559 1505 1381 1188 -j 1511 1544 1560 1575 1592 1607 1617 1630 1656 1687 100 1901 1800 1748 1695 1641 1588 1525 1470 1345 1154 1571 160 1617 1632 1648 1662 1677 1692 1720 1752 15 1874 1773 1722 1669 1616 1563 1509 1453 1329 1140 Note: 1) Top Number isAFW flow to faulted SG (gpm)

2) Bottom Number is total AFW flow to 3 non-faulted SGs (gpm)

J Page do2 -j

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 4 G. Safety Injection (Pumped SI)

1. Minimum Safeguards I LOCA:

INJECTION PHASE Vital Bus Fails 4Operating ESF Pumps

• Bus A Fails: #2 (B) RHRP, #2 (C) IHSIP, #1 (B) and #2 (C) HHSIP;

1. 2 (C) CSP

• Bus B Fails: #1 (A) RHRP, #1 (A) and #2 (C) IHSIP, #2 (C)

HHSIP; #1 (A) and #2 (C) CSPs

• Bus C Fails: #1 (A) and #2 (B) RHRP, #I (A) IHSIP, #1 (B) HHSIP;

1. 1 (A) CSP if> Hi-Hi on 2/4 Containment Pressure

• Ref. Dwg. 205350 RECIRC. PHASE Vital Bus Fails Operating ESF Pumps

• Bus A Fails: #2(B) RHRP, #2(C) IHSIP, #1 (B) HHSIP; #1 (A)

CC]6 No power to Open4No CCW for #I RHRHX; Open #2 (B)

CS36 for RHR Recirc Spray

• Bus B Fails: #1(A) RHRP, #1 (A) IHSIP, #2(C) HHSIP; #2 (B)

CCI6 No power to Open+No CCW for #2 RHRHX; Open #I (A)

CS36 for RHR Recirc Spray

• Bus C Fails: Start #2 (B) RHRP, #1 (A) IHSIP, #1 (B) HHSIP; Close

1. 1 (4)CC16 4no CCW to#I RHRHX; #2B_)CCI6Open,.CCW to #2 RHRHX; Close #2 (B) SJ49 valve; Open #2 (B) CS36 for ReciTc Spray.

The resulting alignment has I RHRP, IIHSIP, I HHSIP, and 1 recirc spray and no RHR cold leg injection.

• At 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> post-LOCA, commence hot leg injection with operating lHSIP by closing associated SJ134 valve and opening associated SJ40 valve.

• Per W: 3 lines inject and lowest resistance line spills into containment backpressure; RHRP and IHSIP inject into Accumulator line which then injects into cold leg; HHSIP injects directly into cold leg; pump performance degraded and line resistances calculated conservatively high; RCP seal flow not included in delivered flow.

Page 1 of 8

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 4 SLB:

For the circumstance where offsite power is lost, the EDGs are relied on to supply emergency power to the safeguards equipment If one EDG fails in this situation. power will be lost to the RCPs and one train of SI as well as one train of containment safeguards equipment.

Minimum SI flow assumed in all cases because reduced boron addition maximizes return-to-power resulting from RCS cooldown and the higher power I generation increases heat transfer to the secondary side, maximizing steam flow out break SI delay time = 22 seconds with offsite power available (42 seconds without offsite power available)

Effect of reduced containment safeguards accounted for in the Containment Response analyses The assumption of a trip of all RCPs coincident with reactor trip is less limiting than with offsite power available because the mass and energy releases are reduced due to the loss of forced reactor coolant flow resulting in less primary-to-secondary heat transfer Containment Response: _

Same as for LOCA except that assume no injected flow spills before entering core; i.e., break on hot leg side of reactor vessel so that all of injected flow first passes through core before passing out break in RCPB.

References:

l I) EOP-LOCA-3 -

2) Ref. Dwg.205350

2. Maximum Safeguards I LOCA:

INJECTION PHASE: -

LBLOCA:

/ No safety-related equipment or bus failure or single active failure

/ 2 RHRP, 2 IHSIP, 2 HHSIP; and 2 CSPs; 3 lines inject and highest resistance line spills into containment backpressure Page 2 of 8

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 4 V RHRPs and IHSIPs inject into Accumulator line which then injects into cold leg I HHSIPs injects directly into cold leg

/ Pump performance increased by 10 percent and line resistances calculated conservatively low

/ RCP seal flow is considered in developing SI flows and seal injection is included in delivered flow for maximum safeguards cases.

/ Maximum Fan Cooler Heat Removal Capacity per cooler (NFU-92-804).

NOTE: the maximum CFCU heat removal rates will ultimately be reduced, since our intent is to reduce the number of operable Fan Coolers from 5 to 3. Also, cooling water flow to each Fan Cooler will be reduced.

It is our understanding that maximum CFCU heat transfer was used only in the LOCA PCT analysis. If needed by Westinghouse, PSEG can provide new (i.e. lower) maximum heat transfer rates OR if not overly penalizing, the current values can be used recognizing that they are conservative. Westinghouse to advise.

Safety Injection Flows -based-on-data-provided by NFUJ 151, PSE-91-038, and WCAP-12491 SBLOCA:

Maximum seal injection flow considered in developing SI flows but is not credited as an RCS injection path for safety injection Containment Spray System and Containment Fan Coolers not tnodelled Typically RCS pressure does not fall to RHR pump shutoff head during modelled portion of transient so RHR pump flow is not included FPump performance degraded 5% and line resistances are calculated conservatively high Page 3 of 8

Key Input Assumptions for LOCA and Steamline Break Mass & EnerZy and Containment Response Attachment 4 3 lines inject and minimum resistance line spills to RCS backpressure RECIRC. PHASE: -

LOCA:

I No safety-related equipment or bus failure or single active or passive failure V 2RHRP, 21HSIP, 21IHSIP and I CS Header I One RHR pump is feeding suction of both HHSI and IHSI pumps and a containment spray header but isolated from low head cold leg injection. One RHR pump is feeding suction of both HHSI and IHSI pumps and low head cold leg injection.

SLB:

V N/A (from W Table)

Containment Response:

V Same as for LOCA except that assume no spillage of injected flow; i.e, all injected flow passes through core before passing out break to maximize energy release to containment.

3. Minimum Deliverable RWST Voiume (gal)

-/---Salem Unit I (I) Total Usable Volume (T/S Min @ 40.5') = 338,446 (2) Low Level Alarm Usable Volume (@15.25')= 124,543 (3) Low-Low. Level Usable Volume (@ 1.0') = 6062 (4) Total Contained Volume (T/S Min @ 40.5') = 364,500 U (5) Low Level Alarm Contained Volume (@15.25') = 150,597 (150,153

@ 15.2' per Ref. 3)

(6) Low-Low Level Contained Volume (@ 1.0')= 19089 (29,691 @ 1.0' Low-Low per Ref. 3)

(7) Process Limit between T/S Min and Low Level Alarm = 207,800 gal (Ref 3)

(8) Process Limit between Low Level Alarm and Low-Low Level Alann =

105,192 gal (Ref. 3)

I Salem Unit 2 (I) Total Usable Volume (TIS Min @40.5') = 338,446 (2) Low Level Alarm Usable Volume (@15.25') = 124,543 Page 4 of 8

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 4 (3) Low-Low Level Usable Volune (@1.0') = 5,677 (4) Total Contained Volume (T/S Min @ 40.5') = 364,500 (5) Low Level Alarm Contained Volume (@15.25) = 150,597 (150,577 @

15.25'per Ref. 4)

(6) Low-Low Level Contained Volume (@ 1.0') = 31,731 (31,727 @

1.24' Low-Low per Ref. 4)

(7) Process Limit between T/S Min and Low Level Alarm = 204,500 gal (Ref. 4)

(8) Process Limit between Low Level Alarm and Low-Low Level Alarm -

108,500 gal (Ref. 3)

I Minimum Initial RWST Volume = 313,000 gallons (1) T/S 3.5.5 (2) W ELE-93-0314 (3) Sums of Process Limits in items (7) and (8) above for both Salem Units are (approximately for Unit 1)= 313,000 gal - Process Limit volumes account for instrument uncertainty in RWST Level instrumentation (for Unit 1: LT-920 and LT-921; and for Unit 2: LT-960, LT-961, LT-962, and LT-963)

(4) Volumes from Ref. I are calculated based on RWST diameter measurement and heights of alarms wrt bottom of tank (5) AV/Ah = 8483.2 galft (Ref. I and 2)

I

Reference:

(1) S-C-VAR-MDC-1429 (Basis for Usable Volumes)

(2) Sl(2).OP-TM.ZZ-0002 (3) SC-S1006-01, Salem Unit I RWST Level Uncertainty Calculation

~-(Page~63f~ -.

(4) SC-SJ007-01, Salem Unit 2 RWST Level Uncertainty Calculation (Page 52)

I Volumes same for LOCA, MSLB, or Containment Response.

4. Maximum Safety Injection Water Temperature during Injection Phase (7F)

" 100 'F(Range40to100 °F)

I

Reference:

S-C-CS-MEE-0561, Maximum Temperature of RWST

5. Maximum Delay Analysis Time to Reach Full Flow for Minimum Safeguards (LOP, EDG S/L, Signal Process Time, Valve Stroke Times, etc.)

1 32 seconds for LOCA

' 22 seconds for MSLB with Offsite Power 1 42 seconds for MSLB without Offsite Power Page 5 of 8

Keg Input Assumptions for LOCA and Steamline Break Mass & EneMr and Containment Response Attachment 4

Reference:

Page 5-161 of Fuel Upgrade & Margin Recovery Reload Transition Report and Page 54 of S-C-VAR-NZZ-0020.

6. Minimum Delay Tine to Reach Full Flow for Maximum Safeguards (LOP, EDG SAI, Signal Process Time, Valve Stroke Times, etc.)

1 32 seconds

7. Tune for SI Switchover to Recirculation with Minimum Safeguards I Total time unknown and requires calculation to determine. (See VTDs 323585 and 323001 for possible times)

S. Tune for SI Switchover to Recirculation with Maximum Safeguards I - Total time unknown and requires calculation to determine.

9. Safety Injection Flows for ECCS Train Failure (LOCA)

I See Data Tables below: Item #I, Table G-I.

10. Safety Injection Flows for all ECCS Pumps (LOCA) -

I See Data Tables below: Item #2, Table G-2.

I1. Minimum SI Flow Rates from I IHSI and I IHSI with no spill (SLB)

See Data Tables below: Item #3, Table G-3.

W to advise and/or provide reference for data to be confirmed. Combined data from two cases based on different W letters

12. SI Volume between RWST and RCS (fe3)

(For HHSI only because RCS pressure for SLB remains greater than shutoff head of LHSI (RHR) pumps and probably IHSI pumps, also.)

V See Discussion under Data Tables below: tem #4, Table G-12.

V From NFS 9-170 (S-C-VAR-NZZ-0020, pg. 54 and Figure 5-1)

High Head Safety Injection System Volumes Section Boundaries Volume (f 3)

RWST to HHSI Pump Suction Hdr. Isol. (S) I and SJ2) 28.8 Page 6 of 8

Key lnp ut Assumptions for LOCA and Steamline Break Mass & Enerff and Containment Response Attachment 4

[HSI Pumnp Suction to BIT disch. (Dwnstm. SJ4lSJS) 41.2 E

BIT Path (Volume between SJ4/S15 and SI12/SJ13) 120.0 L Comrnon Header From SJ 12/S13 to Individual C/Ls 2.5 UL Injection Path I1.11 C/L Injection Path 0.83

_ C C YL Injection Path 1.34 C/L Injection Path 1.31

! 1Total volume in SI lines from RWST to RCS = approximately 197 ft3

\_ 13. SII~ine Initial Boron Concentration (ppm)

.- fi O ppm. Concentration may vary from 0 to 2500 ppm.

0 LC H

~6 on Injection Tank Boron Concentration (ppm)

14. Boro

( 0 ppm. Concentration may vary from 0 to 2500 ppm.

15. Mini mum Containment Sump Elevation (fl)

/ -70 ft is bottom of sump. For RHR switchover, sump level must be > 62% or 80'-I I" (includes uncertainty) per EOP-LOCA-3 to ensure RHR NPSHR met.

L " RHR NPSH Requirements from UFSAR Table 6.3-13: (See Calculation S-C-RHR-MDC-1711 for NPSHA)

a. Unit 1:

• CAL Recirculation = 25.0 ft

^ H/iL Recirculation= 24.Oft

b. Unit 2:

• CIL Recirculation = 22.8 ft

• HIL Recirculation = 24.0 ft 16 R-

c.

Reference:

1.*1.R

• W PSE-97-527 (0212111997)

IRPump Suction Centerline Elevation (fi)

-I 46'-10" (

R Pump Discharge Centerline Elevation (fl)

Page 7 of I

Ker Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 4

' 46X-10" (267202,267202)

I 8. RCS Cold Leg Elevations (ft)

/ 97'-O"

19. RCS Hot Leg Elevations (fl)

V 97'-0"

20. Minimum HHSI Pump Curve

/ See Data Tables below: Item #5, Table G-20.

21. Minimum IHSI Pump Curve 1 See Data Tables below: Item #6, Table G-21.

22. Minimum RHR Pump Curve

/ See Data Tables below: Item #7, Table G-22.

23. Maximum HHSI Pump Curve

/ See Data Tables below: Item #8, Table G-23.

24. Maximum IHSI Pump CiRve

/ See Data Tables below: Item #9, Table G-24.

25. Maximum RHR Pump Curve v See Data Tables below: Item #10, Table G-25.

26. RWST Boron Concentration (ppm) 2300 to 2500 ppm (T/S 3.5.5.b; SI(2).OP-ST.CVC-00l0; UFSAR Table 6.34)

Page 8 of 8

¶ Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 5 H. Safety Injection Accumulators

1. Number of Accumulators

, 4 L 2. Maximum WaterlGas Temperature (mF)

_ 120 0 F

3. Nominal Accumulator Water Volume (Oi) i 850 R3

4. Range of Accumulator Water Volume (f 3 )

1 831.95 to 868.98 ft3 (6223 to 6500 gal)

5. Uncertainty on Accumulator Water Volume (fi0)

V Normal Uncertainty = 81.89 gal (Rounded to 85 gal)

Max -893.85 ft3 and Min = 807.09 ft (includes 101 gal tank uncert.)

TIS High = 868.98 f 3 and TIS Min = 831.95 ft' i Accident Uncertainty = 348.59 gal (Rounded to 350 gal)

-- Post-Accident Uncertainty =207.33 gal (Rounded to 21 0gl1F-L I W indicated enough margin exists in Safety Analysis to allow 100 gal instrument uncertainty Max = 895.86 ft and Min - 805.08 If (includes 101 gal tank uncert.)

-~ TIS High = 868.98 ft? and T/S Min =831.95 ft3

References:

1) SC-SJOOI-0l

2) W ELE-92-0587

3) T/S 3.5.1

4) S-C-VAR-MDC-1429 L 6. Minimum Gas Cover Pressure (psig) 5577.5 psig (Accident Analysis)

Page 1 of 2

Key Input Assumptions for LOCA and Steamline Break Mass & Enerfyy and Containment Response Attachment 5

1. 595.5 psig (T/S Minimum = Accident Analysis + Overall Channel Uncertainty) 1 600 psig (UFSAR Table 6.3-2)

Reference:

VTD 304209

7. Uncertainty on Gas Cover Pressure (psi) v Overall Channel Uncertainty = 18 psi(y)

V Instrument Uncertainty as calculated by PSEG Calc SC-SJ002-01 =15 psi

References:

I) W ELE-92-0578

2) SC-SJO02-01

8. Range of Gas Cover Pressure 1 595.5 to 647.5 psig

9. Nominal Tank Volume (f1) v Total Volume = 1350 ft

References:

VTDs 107630,107633,109845, and 109847

10. Individual Line Volumes (19)

See Data Tables below: Item #11, Table H-1, Document References for Accumulator Line Volumes.

Page 2 of 2

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 6 J. Containment Spray Pumps I. Number of Containment Spray Pumps Operating (Injection Phase Only)

• With offsite power and no failure:

I 2 CSPs

• With offsite power and single failure:

I For single failure of either CSP or failure of either A or B bus, I CSP; otherwise, 2 CSPs

• Without offsihe power and no failure:

V 2 CSPs

• Without offsite power and EDG failure:

I For A or C EDG failure, I CSP; for B EDG failure, 2 CSPs

2. Containment Spray Ring Nozzle Elevations (fit)

Salem Unit I Spra-Y Headers:

• 12A Header 269'-O", 67 spray nozzles

• I IA Header 266'-6", 67 spray nozzles

• 12B Header 247'-0", 96 spray nozzles

• 1lB Header 244'-6", 96 spray nozzles Salem Unit 2 Spray Headers:

• 22A Header 269'-0", 68 spray nozzles

• 21A Header 266'-6", 68 spray nozzles

• 22B Header 247'-0", 96 spray nozzles

• 21B Header 244'-6", 96 spray nozzles

Reference:

Dwgs. 237435,237438,207466,218216 Construction Iso's CSI2A, Sheet I; CSI2B, Sheet I;CS23, Sheets 3-6 Per PSEG Letter, PSE-416 (05/17175), Westinghouse infonned that one nozzle in both upper spray ring headers was eliminated in Salem Unit 1. W iodine analysis (BURL-3149 dated 06106175) assumes 68 spray nozzles. Negative impact of less spray nozzles offset by higher spray efficiency caused by reduction in droplet size due to increased differential pressure across remaining nozzles.

Page 1 of 5

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and -

Containment Response Attachment 6

3. Containment Spray Flowrate during Injection Phase (gpm)

Containmen Spray Header Flow Rates (gpm)

Containment Pressure 1 CS Pump Flow 2 CS Pump Flow (psig) (gpm) WM) 0.0 3117.0 6234.0 10.0 3017.0 6034.0 20.0 2913.0 5826.0 30.0 2720.0 5440.0 40.0 2687.0 5374.0 47.0 2600.0 5200.0

References:

1) S-C-VAR-NZZ-0020

2) W SECL 96-178 Same as Table J-1 in W LTR-CRA-03-XYZ (06/16/03) -- !

a. In addition, see Table 12: J-3 Containment Spray Pump Flow-Head Curves during Injection Phase.

b. Nominal Spray flow = 2600 gpm for one pump (Containment Integrity) except for dose calculations (RG 1.4) only in which spray flow is degraded = 2460 gpm and = 2469 gpm for containment sump pH (7 to 10) during recirculation phase.

c. Maximum Spray header flowrate = 713R gpm for minimum system resistance and contaimnent badpressure = 10 psig.-

NOTE: In order to agree with assumptions in LOCA analyses about containment backpressure applied to the fluid that is escaping via the RCPB break, CS system flow rate must not exceed 3800 gpm (single pump) or 7600 gpm (two pump)

Unit I RWST Drain Down Analysis, W PSEBO-97-024 (12/23/1997)

Unit 2 RWST Drain Down Analysis, W PSEBO-97-014 (05/15/1997)

d. (UFSAR Table 15.4-3; S-C-VAR-NZZ-0020, Attachment A; W PSE-95-837)

4. Containment Spray Flowrate Per Pump During Recirc Phase with Minimum and Maximum Safeguards (gpm)

a. There is no Containment Spray Pump flow during the Recirculation Phase. At the RWST low level (-15.25 feet), if two CSPs running, one is secured. The other runs until the RWST low-low level (-1 feet) is reached at which point it is Page 2 of 5

Key Input Assumptions for LOCA and Steamline Break Mass & Enerxy and Containment Response Attachment 6 secured. During the Recirculation Phase, containment spray is provided by one RHR pump via the CS36 valve to one containment spray header. The RHR pump is also supplying the suction of the HHSI and IHSI pumps, but its cold leg injection path is blocked (SJ49 closed).

b. The minimum case would have one RHR pump providing I HHSI and I IHSI pump suction plus spray and no low head cold leg injection.

c. The maximum case would have 2 RHR pumps providing 2 HHSI and 2 IHSI pump suctions (via the SJ45s and SJI 13s). One RHR pump would also provide spray (via its CS36) but no cold leg injection (its SJ49 closed) and the other RHR pump would provide no spray (its CS36 closed) but two low head cold leg injection (its S49 valve open).

d. Caveat: for RHR to inject, RCS pressure must be low enough for low head to overcome accumulator pressure that prevents low head injection by seating the 543 check valves until accumulator pressure decreases below RHR SOH or SJ54 is closed. For LBLOCA, assume delay of 45 seconds for accumulator Blowdown before RHR cold leg injection flow can commence.

5. Maximum Post-Accident Delay Time for Effective Spray Flow to Enter Containment After the Hi-Hi Containment Pressure Setpoint Reached

• With Offsite Power (seconds) 85 seconds

• Withoit Offsite Power (siiso&) .

85 seconds

6. r'me Injection Spray is Terminated with Minimum and Maximum Safeguards

a. Minimum Safeguards Time (seconds) = at time reach Low-Low RWST Level in EOP-LOCA-3---one CSP, I HHSI, and I IHSI pumps running from Low to Low-Low Level in RWST. The HHSI and IHSI pumps are supposed to be switched over to recirculation before reaching Low-Low Level. The RHR pump may be stopped during switchover and the means for switchover differs between Salem Units I (manual) and 2 (semi-automatic). Drain down times from T/S minimum level (40.5 fi) to Low Level (I 5.2/15.25 ft) based on I CSP + I HHSI + 1 1HSI +

I RHR pumps injecting at 0 RCS pressure backpressure.

b. Maximum Safeguards Time (seconds) = at time reach Low-Low RWST Level in EOP-LOCA-3--one CSP, 2 HHSI, and 2 IHSI pumps running from Low to Low-Page 3 of 5

Key Input Assumptions for LOCA and Steamline Break Mass & Energ and -

Containment Response Attachment 6 Low Level in RWST. The HHSI and IHSI pumps are supposed to be switched over to recirculation before reaching Low-Low Level. The RHR pumps may be stopped during switchover and the means for switchover differs between Salem Units I (manual) and 2 (semi-automatic). Drain down times from TIS minimum level (40.5 ii) to Low Level (15.2/15.25 R) based on 2 CSP + 2 HHSI + 2 IHlSI +

2 RHR pumps injecting at 0 RCS pressure. For Unit 1, the minimum duration to reach Low Level is 12.9 minutes; for Unit 2, the minimum duration is 12.5 minutes.

C. Operator Actin Times:

For Unit 1:

• 5 4.0 minutes from RWST Low Level to initiate RH4 closure

• 511.7 minutes for transition to sump recirculation ForUnit 2:

• 2 minutes 43 seconds for Operators to push Auto Arm. Semi- Automatic -

Switchover

• *3.0 minutes from RWST Low Level alarm to initiating SJ69 closure -

• 55.5 minutes from RWST Low Level alarm to only one CS pump in operation _

• *11.2 minutes for transition to sump recirculation (Accumulator Line Small Break LOCA assuming 2-minute stroke time for RH4)

d.

References:

(1) V s 323585 and 323001, RWST Drain Down and Cold Leg Recirculation Report (2) Manual Operator actions for Salem Unit 2 are < 5.5 minutes maximum after RWST Low Level alarm per SC.CE-BD.CS-000l, pg. 17.

(3) EOP-LOCA-3 (4) UFSAR Table 6.3-6

7. Time RecirculatlouSpray Initiated with Minimum and Maximum Safeguards

a. Maximum Safeguards rime (seconds) = at time that associated CS36 valve is opened in EOP-LOCA-3. Probably will be greatest for Unit I with manual switchover.

b. Minimum Safeguards Times (seconds) = at time that associated CS36 valve is opened in EOP-LOCA-3. Probably will be greatest for Unit I with manual switchover.

Page 4 of 5

Key Input Assumptions for LOCA and Steamline Break Mass & Enet and Containment Response Attachment 6

c. SDray Tune Delays:

LBLOCA: 85 seconds Spray Delay Time (fastest initiation = 35 seconds)

SBLOCA: Not Modeled Non-LOCA: 85 seconds Spray Delay Time

d. Times not available and would require calculations to determine. Times would change with conditions assumed in analyses.

NOTE: Items 6 and 7 are calculated times that depend on analysis assumptions and cannot be verified without knowledge of ECCS alignment. The times depend on RCS pressure that controls the actual ECCS flows. The RWST Drain Down analyses assume maximum flows to generate shortest times for Operator action. For less than maximum flow, the time to recirculation increases and may not be bounded. The analysis may end before recirculation begins. This Is certainly the case for SLB and for some SBLOCA depending on break size. Westinghouse to advise.

S. RWST Temperature (F)

a. I00F

Reference:

S-C-CS-MEE-0561, Maximum Temperature of RWST Page S of 5

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 Data Tables

1. Table G-1: Minimum Safeguards SI Injection Minimum SafeguardsInjection Data (No Spill Cases) _

RCS Pressure (psig) I HHSI Pump I IHS, Pump (gpm) I LHSI (RHR)

(gpm) Pump (lb/sec) 0 369.0 555.8 0 psig, 549.22 100 360.4 533.8 20psig, 515.99 200 351.7 516.0 40 psig, 480.72 300 343.0 492.7 60 psig, 442.68 400 334.0 468.6 80 psig 400.89 500 324.1 443.0 100 psig, 353.69 600 314.1 416.5 120 psig,297.51 700 303.8 389.1 140 psig, 222.69 800 293.4 359.6 160 psig, 82.94 900 282.5 325.6 180 psig, 0.00 1000 271.5 289.6 1100 259.6 246.0 1200 247.9 187.9 1300 235.9 93.0 1400 223.6 0.0 _

1500 211.0 1-600 198.1 1700 182.5 1800 166.4 1900 149.8.

2000 132.5 2100 114.6 2200 81.6

References:

(The LHSI or RHR Flows are from Ref "c" only)

a. LCR 91-03 (04/24/92)

b. W PSE-91-038 (02128/91)

c. FSA-II-M-2533 (02/21n4) ECCS Flowrates for Containment Energy Releases NOTE: The HHSI flows do not match those in FSE/SS-PSE-1557 (1/18/91), FSE/SS-PSE-6769 (01/23/91), or FSA-II-M-2533 (0212174).

PSE-1557 differs, for example, in C/SI pump runout flow assumed, Page 1 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Ener" and Containment Response Attachment 7 increasing flow from 550 gpm to 560 gpm. Westinghouse to advise.

Same question pertains to Table G-3 for SLB.

d. Actuation Delay = 42 seconds for Non-LOCA events i:

2. Table G-2: Maximum Safeguards SI Injection Maximum Safeguards Injection Data

____ (No Spill Cases)

RCS Pressure (psig) 2 HHSI Pump 2 IHSI Pump (gpm) 2 LHSI (RHR)

(gpm) Pump (lb~sec)*

0 953.5 896.4 0 psig, 1155.81 -s 100 934.6 863.8 20 psig, 1099.00 200 915.5 830.4 40psig, 1038.80 300 895.9 796.1 60 psig, 974.57 400 873.8 758.4 $0 psig, 905.39 500 851.6 718.4 100 psig, 829.98 600 828.9 676.7 120 psig, 746.47 700 806.0 633.1 140 psig, 651.92 800 781.5 592.6 160 psig, 541.33 900 756.2 550.0 180 psig, 405.22 1000 730.6 503.9 200 psig, 223.23 1100 704.7 454.4 220 psig, 0.00 1200 678.1 400.3

---

1.

1300 4 651.1 327.9 ,I I--, -

1400 623.6 231.9 1500 594.9 95.2 1600 560.9 0.0 1700 526.0 _

1800 498.7 1900 472.9 2000 446.2 _

2100 2200 _

References:

(*LHSI from Ref "a" Only)

a. W FSA-I1-M-2533 (02121/74), ECCS Flowrates for Containment Energy Releases

b. LCR 91-03 (04/24/92)

c. W PSE-91-038 (02/28/91)

d. W FSE/SS-PSE-6769 (01/23/91)

Page 2 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energ and Containment Response Attachment 7

e. Actuation Delay = 42 seconds for Non-LOCA events

3. Table G-3: 1 HHSI and I IHSI -No Spill SLB: I HHSI and I IHSI-No Spill RCS Case (1) Case (2) Both Case (1) Case (2) Case (I) Case (2) W Pressure I HHS1 I HHSI Cases I HHSI + 1 HHSI GPM to GPM to ReL (psig) No Spill No Spill I HSI I IHSI +Ibm/s 11 IHSI Ibm/s Data (gpm) (gpm) No Spn (gpm) (gpm)

(gpm) 0 369.0 374.6 555.8 924.8 930.4 127.73 128.51 128.37 100 360.4 366.2 533.8 894.2 900.0 123.51 124.31 200 351.7 357.8 516.0 867.7 873.8 119.85 120.69 300 343.0 349.4 492.7 835.7 842.1 115.43 116.31 400 334.0 340.2 468.6 802.6 808.8 110.86 111.71 111.40 500 324.1 330.6 443.0 767.1 773.6 105.95 106.85 600 314.1 320.8 416.5 730.6 700.0 100.91 101.84 101.41 700 303.8 310.9 389.1 692.9 660.4 95.70 96.68 800 293.4 300.8 359.6 653.0 660.4 90.19 91.21 900 282.5 289.9 325.6 608.1 615.5 83.99 85.01 84.40

-1000 271.5- 278.8 289.6 561.1 -568.4 77.50 78.51 1100 259.6 267.6 246.0 505.6 513.6 69.83 70.94 1200 247.9 256.2 187.9 435.8 444.1 60.19 61.34 1300 235.9 244.5 93.0 328.9 337.5 45.43 46.62 45.65 1400 223.6 232.5 0.0 223.6 232.5 30.88 32.11 32.04 1500 211.0 220.4 211.0 220.4 29.14 30.44 1600 198.1 207.1 198.1 207.1 27.36 28.60 1700 182.5 192.0 182.5 192.0 25.21 26.52 1800 166.4 176.4 166.4 176.4 22.98 24.36 23.10 1900 149.8 160.3 149.8 160.3 20.69 22.14 2000 132.5 143.7 132.5 143.7 18.30 19.85 2100 114.6 126.4 114.6 126.4 15.83 17.46 15.91 Page 3 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 SLB: I HHSI and I IHSI-No Spill i

RCS Case (1) Case (2) Both Case (1) Case (2) Case (1) Case (2) W Pressure I HHSI 1 HHSI Cases 1 HHSI + 1 H1SI GPM to GPM to Ret (psig) No Spill No Spill I IHSI I ]HSI +1 IHSI Ibmis Ibm/s Data (gpm) (gpm) No Spill (gpm) (gpm) (lbm/s) (bm/s) (Ibm/s)

(gpm) 2200 81.6 92.8 81.6 92.8 11.27 12.82 2300 38.1 0.0 38.1 0.0 5.26 0.0 5.29 2325 0.0 __0.0 0.0 0.0

References:

For Case (11:

a. W PSE-91-038 (02/28/91)

b. LCR 91-03 (04/24/92)

For Case (2): -J

c. W FSEJSS-PSE-1557(01/18/91)

d. W FSEJSS-PSE-6769 (01/23/91)

NOTE: Case (1) and Case (2) reflect the discrepancy noted in The flows for the HHSI pumps earlier. Salem Licensing basis is Case (1). The difference may be related to the assumed HHSI runout flow. For Case (1) the runout f flow is 550 gpm and for Case (2) the runout flow is 560 gpm. Current Design

-Basis is to limitHllHSIrunout-fw to no-morelhan-354 gpm&See WPSE 759 (11/08/94). Westinghouse to advise.

4. Table G-12: RWST to RCS Volumes

/ Salem does not have system dimensional isometric drawings. There are small bore piping spool drawings and large bore piping spool drawings that are dimensional but which would require review of several thousand drawings to tabulate the volume and would not show any of the small diameter piping. The Stress Calculation isometrics, which are not always updated when plant changes are made, could be used. These would require review of approximately 500 drawings; however, they are the best choice for modeling in that they provide the information in the most concentrated form.

I At present, there is no calculation that provides the volume of ESF piping from the RWST to the RCS for the containment spray, high head safety injection, intermediate head safety injection, and low head safety injection piping from the Page 4 of 15

Key Input Assumptions for LOCA and Steambne Break Mass & Enermy and Containment Response Attachment 7 RWST to the RCS. To compile the data for computing these volumes is a monumental task that would involve converting data from perhaps a 1000 Stress Calculation isometric drawings-too many to list here. (See Table H-I under Item II below for just the piping volume from the accumulators to the RCS, for example.)

V The values given are taken from S-C-VAR-NZZ-0020, UFSAR Chapter 15 DB/LB Accident Analysis Input Assumptions, citing W PSE-93-645, Consolidated Input Assumptions Document for Accident Analyses, Salem Units I and 2, Fuel Upgrade / Margin Recovery Program, Non-LOCA Transient Analyses, Rev. 3, June, 1993.

5. Table G-20: Minimum HHSI Curve Centrifugal Cha ring Pumps (HHSI)

Flow (gpm) Minimum Head (feet H20) 0 5414 100 5394 200 5094 300 4284 400 3194 425 2884 450 2569 500 1794 525 1464 550 _ -_-_014 560 704

References:

(1) W PSE-91-038 (02-28-91)

(2)WFSE/SS-PSE-1671 (I 1/25/91) Salem Unit I PEGISYS Model (3) W FSEISS-PNJ-1662 (11/02/91) Salem Unit 2 PEGISYS Model

6. Table G-21: Minimum IHSI Curve Safety Injection Pumps (1HSI)

Flow (gpm) Minimum Head (feet 1130) 0 3200 100 3070 200 1 3000 300 1 2835 Page 5 of 15

Key Input AssumPtions for LOCA and Steamline Break Mass & Energy and -

Containment Response I I Attachment 7

. I Safety InjectioI Pumps (IHSI)

Flow (gpm) Minimum Head (feet H2O) 400 2520 500 2100 525 1985 550 1870 575 1755 6600 1635 650 1400 675 1260

References:

(I) W PSE-91-038 (02-28-91)

-J (2)W FSE/SS-PSE-1 671 ( 1125/91) Salem Unit 1 PEGISYS Model (3) W FSEISS-PNJ-1 662 (11/02/91) Salem Unit 2 PEGISYS Model

7. Table G-22: Minimum RHR Curve Residual Heat Removal Pumps (RHR)

Flow (gpm) Minimum Head (feet H20) 0 383 500 382 1000 379 1500 377 2000 375 2500 __ 1_

3000 354 3500 338 4000 318 4500 296 5000 267 5500 232

References:

(1) W FSEISS-PSE-1671 (11125191) Salem Unit I PEGISYS Model Documentation (2) W FSEISS-PNJ-l 662 (11/02/91) Salem Unit 2 PEGISYS Model Documentation Page 6 of 15

Key Input Assumptions for LOCA snd Steamline Break Mass & Energy and Containment Response Attachment 7

8. Table G-23: Maximum HHSI Curve Centrifugal Chargin Pumps (HHSI)

Flow (gpm) Masimum Head (feet H2 0) 0 - 6200_

100 61_55 200 5811 300 _ _ _ 5000 400 - 3910 425 3610 450 3250 500 2470 525 2070 550 1640 560 1495

References:

(1) W PSE-91-038 (02-28-91)

(2)WFSE/SS-PSE-1671 (11/25/91) Salem Unit I PEGISYS Model (3) W FSE/SS-PNJ-1662 (11/02/91) Salem Unit 2 PEGISYS Model

9. Table G-24: Maximum IHSI Curve Safety Injection Pumps (lHSI)

Flow (gpm) Maximum 1lead (feet H2 0)

.* 1 ... _- - _-----.35.-- .-

100 3450 200 3385 300 3165 400 2855 500 2455

_ _525 2355 550 2270 575 2150 600 2025 650 . 1785 675 1645

References:

(1) W PSE-91-038 (02-28-91)

(2) W FSEISS-PSE-1671 (11/25/91) Salem Unit I PEGISYS Model (3) W FSE/SS-PNJ-1662 (11/02/91) Salem Unit 2 PEGISYS Model Page 7 oftIS

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and -

Containment Response Attachment 7

10. Table G-25: Maximum RHR Curve Residual Heat Removal Pumps (RHR)

Flow (gpm) Maximum Head (feet H220) 0 502 500 492 1000 478 1500 462 2000 449 2500 448 3000 439 3500 425 4000 398 4500 374 5000 1348 5500 321

References:

(1) W FSE/SS-PSE-1671 (11/25/91) Salem Unit I PEGISYS Model Documentation (2) W FSE/SS-PNJ-1 662 (11/02/91) Salem Unit 2 PEGISYS Model Documentation 11 . Table H-I: PSEG Document Refernces for Accimulastor Line Volumes Salem does not have system dimensional isometric drawings. There are small bore piping spool drawings and large bore piping spool drawings that are dimensional but which would require approximately 250 drawings to tabulate volume and would not show any of the small diameter piping. The Stress Calculation isometrics are not always updated when plant changes are made; however, they are the best choice for modeling in that they provide the information in the most concentrated form.

Salem Unit I Accumulator PipingStress CalculationIsometrics No. 11 (ISJE6) No. 12 (1SJE7) No. 13 (ISJE8) No. 14 (ISJE9) 267241B 267241C 267243 267244 267241F 267241CC 267243CC 267244BC 267246 267242 267246 267242 2671277 2671283 2671272 2671270 2671293 2671300 2671274 2671292 I 2671297 2671285 2671278 2671282 Page 8 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Enem and-Containment Response Attachment 7 2671291 A 2671299 267241E 2671279A 2671211 2671280 2671269 2671296 2671279 _ 267241 E 267241E 267241E Salem Unit 2,Accumulator PipingStress CalculationIsometrics N2 LNo.n22 (2SJE) No. 23 (2SJE8) No. 24 (2SJE9) 5671217 5671218 5671223 5671225 5671294 5671296 5671293 5671295 5671203 5671221 5671203 5671221 5671254 5671261 5671249 5671248 5671220 5671289 5672326 5671275 5671277 5671263 5671251 5671260 5672333A 5671288 5671251 5671257 5671287 5671258 5672327 5671220 5671211 5671256 5671255 233442,Sh.23 5672334 5671220 5671220 233442, Sb. 24 5671285 233442, Sh. 25 Accumulator Line lMDs and Volumes (1) (2) (3) (4)

Loop Total L/D [ID Total Volume Volume

__ _ _ _(fk) )--(ft3 ---- 1l 3 1 536 208 31.7 4.0 2 542 205 34.8 3.8 3 502 175 27.6 3.9 4 519 209 23.5 4.2 (1) Accumulator Line Total (2) Line LID from RHR injection point to RCS (3) Volume between Accumulator to check valve closest to RCS (SJ56s)

(4) Volume between the two check valves (SJS5s and SJ56s) in the Accumulator line (5) Assumes a friction factor of 0.01436 for 10-inch Schedule 160 pipe

Reference:

FSSE/SS-PSE-1 230 (12-21-88)

Page 9 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 (Superceded by FSSE/SS-PSE1230 above)

Accumulator Line Piping Volwnes Drawines 207463. 207464. 218269 Volume from bottom of Volume from 2d Check to Loop Accumulator to e' Check RCS Loop (ft) (A) 1 37.17 7.63 2 37.85 7.63 3 31.93 6.51 4 34.82 7.64

Reference:

W FSA-II-BU-2576, Accumulator Line Piping (05tl3174)

12. Table J-3A (Unitl) and J-3B (Unit 2): Containment Spray Pump Head-Flow Curves Salem Unit 1: Containment S ray Pump Flow-Head Curves Flow (gpm) Minimum (feet #11 Pump Nominal #12 Pump Nominal H20) TDH (feet H2 0) TDH (feet H20) 0 472 506 502 400 471 506 502 800 469 506 501 1200 465 506 500 1600 459 500 499 2000 451 491 492 2400 439 - 473 - 48...

2800 422 454 455 3200 399 432 431 3600 362 399 390

Reference:

W FSEISS-PSE-1671 (1 125/91) Salem Unit I PEGISYS Model Salem Unit 2: Containment S ray Pump Flow-Head Curves Flow (gpm) Minimum (feet #21 Pump Nominal #22 Pump Nominal

_ 120) TDH (feet H20) TDH (feet H 2 0) 0 472 501 500 400 471 500 499 800 469 497 498 1200 465 493 493 Page lOof 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 Salem Unit 2: Containment Spra Pump Flow-Head Curves Flow (gpm) Minimum (feet #21 Pump Nominal #22 Pump Nominal HIO) TDH (feet H2 0) TDH (feet H20) 1600 459 489 487 2000 451 479 481 2400 439 467 478 2800 422 450 458 3200 399 427 435 3600 362 407 402

Reference:

W FSE/SS-PNJ-1662 (11/02/91) Salem Unit 2 PEGISYS Model

13. Table 13: RHR Flow verses RCS Pressure: (Containment Mass and Energy Release)

Minimum RHR Flow (gpm) Verses RCS Pressure RCS Pressure (psig) RHR Flow (Ib/sec) 0 393 20 318 40 241 60 165 80 114 100 51.9 120 0

References:

(1) W SAEIFSE-PSE-0487 (09/08/96)

(2) W FSEISS-PSE-7505 (01/08/97)

(3) VTD 323585 (Unit 1) and 323001 (Unit 2)

Page 11 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 Additional Information:

Relative Valve/Line Elevations for Salem Component Elevation SI Suction RWST 101 '-9" HHSIP Suction 87'-5" IHSIP Suction 86'-6" LHSIP Suction 46'-10" -

S1I and SJ2 S"n-3" SJ3 91 '-7 5116" S30 85'-3" SJ31 85'-1 %"

S145s 85'-3" -

SJ31Us 87'4- 1/4/ 86'-5 518" CS36s 86'-0" J 87'-O 1/8" SJ49s 86'-0 %"

RH26 _ 0_-5" 2RH75 46'-10" 2RH76 46'.1O 21RH4 5g'-9" 22RH4 56'-8" 2S170 59g-9" 2SJ69 60'-5" 21S344 51'-9" 22SJ44 51'-9" Cont Sump bottom 69'- 1 Y4" SJ4Yis 9 R- 1J8 S355s and SJ56s 112'-O" 21SJ144 ____82_-3_

22SJ144 81-3" 23S3145 79'4 7/8" 24S1144 80'-3" Page 12 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 July 03, 2003 (CFCU Project Letter #l Mr. Jerold Kusky

- Customer Projects Manager Westinghouse Electric Company P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355

Dear Mr. Kusky:

PSEG Nuclear Response to Westinghouse Input Request for CFCU Project Containment Mass and Energy Release Analyses

--- PSEG-Nifcear has validated andfor proviaed the speci ic input requested by Westinghouse (Reference 1) needed to perform the LOCA and Main Steam Line Break (MSLB) containment response analyses proposed as described in References 2 and 3.

i This information was transmitted via e-mail to Mr. Robert Jakub on July 2, 2003.

Note that some items, too large to fit in the available space, were noted and provided as attachments at the end. There are some items that will require further discussion between Westinghouse and PSEG, specific Westinghouse references or possible follow-up calculations. Some items of note include Safety Injection (SI) switchover to recirculation with minimum safeguards, time for recirculation spray to be initiated and some SI flows

_ not matching current references under certain alignments, RHR heat exchanger flow during recirculation (subsequent UA values will then be provided by PSEG).

Additionally, information provided to Westinghouse regarding the main feedwater pump trip and coastdown for MSLB with a single failure of the feedwater control valve (Reference 4) needs to be validated by Westinghouse as it dates back to 1992.

Page 13 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Energy and Containment Response Attachment 7 To further support the filled in Westinghouse input request document, the following are also provided: Attachment 1 provides information regarding the concurrent vessel head change-out project, including the increased metal mass associated with the integrated head package: Attachment 2 provides additional information regarding AFW flow rates; is the hard copy of the EXCEL file that provides Proto-Flo AFW results and curve fits; Attachment 4 contains the SI information; Attachment 5 covers the Accunulators; Attachment 6 covers Containment Spray Pumps; Attachment 7 is the validation of the various data tables, Attachment 8 covers the Bypass Flow Control Valve set points.

Note that all the Replacement Steam Generator data has been provided with the exception of the secondary side fluid mass at various power levels (Framatome only has perforned calculation at 100% power). PSEG will provide this information later as it becomes available. Also, PSEG is evaluating a reduction in the maximum moderator density coefficient (currently set at 0.52 delta-k/gm/cc) to recover some MSLB containment pressure margin. The final value that is acceptable to the core design engineers will be provided to Westinghouse under a separate letter.

Following your review of this input information, could you provide an update to the analysis schedule, with the various deliverables (even preliminary results) in terms of -

actual dates.

If you have any questions, please contact Mr. Kiran Mathur (CFCU Project Engineer) at -

856 339-7215, or Mr. Glenn Schwartz (Nuclear Fuel) at 856 339-1216.

Very truly yours, Ashok Moudgill CFCU Project Manager C Dave Hughes John 0 Connor Mike Mannion Tom Ross Ken Fleischer Greg Morrison Doug McCollum Glenn Schwartz Kent Halac Michael Crawford John Rowey Kevin King Page 14 of 15

Key Input Assumptions for LOCA and Steamline Break Mass & Enerfy and Containment Response Attachment 7 Scott Beckham Tina Nolte Paul Finch John Pebush W - Robert Jakub W - Debra Ohkawa W - William Turkowski

References:

1) Westinghouse letter PSE-03-25, CFCU/Service Water Enhancement Project Input Request for LOCA and MSLB Mass & Energy Releases and Containment Integrity Analyses, June 24, 2003

2) Westinghouse letter LTR-NEM-03-403, Containment Response Analysis to Support the Containment Fan Cooler Unit Service Water Enhancement Project, April 29, 2003

3) Westinghouse letter LTR-NEM-03-458, Revised Offer for Containment Response Analysis to Support the Containment Fan Cooler Unit Service Water Enhancement Project, May 15, 2003

4) PSEG Letter NFU-92-173, Salem Units 1 & 2 Feedwater Control Valve I Main Feedwater Pump Trip Assumption, March 9,1992 Page 15 of 15

ATTACHMENT 8 Page 1 of 3 L Rev. 0 S-I -CN-ECS-0 118 (003E)

ADFCS Set Points List for Units I and 2 Page 4 I Description l Reference Value l L 1.2 Main Feedwater Pumps AP Controller L PI Proportional Gain K33 I rad I sec / psi (0.203400)

PI Integral Tme Constant t3s 100 sec / (rad / sec I psi) (493)

L (Feed Header - SG Exit) FCN32 AP Setpt Steam flow (%)

Pressure AP Program ' (psid)

L - 50 50 0.0 15.0

, ,. 151 100.0 L a 151 120.0 Lag on Total Steam Flow t34 120 seconds 1.3 Cv Demand Calculation L -Dynamic Pressure Loss KKL 0.0072 psi I (% flow) 2 Coefficient L

l Static Head Loss APEL, 9.0 psi L Valve Cv Scaling Factor Lag on Computed Valve -

Kv 6 .

80.95 gpm / % flow 5 seconds L Pressure Drop 1.4 Control Valve Sequencing and Tracking Logic Bypass Valve Demand XBD Lift Demand Cv Demand (epm / psi" 2)

(BF40) ffe)

FCN7 0 0.0 20 14.4 30 21.6 40 28.8 50 36.0 70 50.4 80 57.6 90 64.8 100 72.0

Page 2 of 3 ATTACHMENT B ATTACHMEIIT 8 Page 2 Of 3 S-I-CN-ECS-01 18 (003E)

Rev. 0 ADFCS Set Points List for Units 1 and 2 Page 5 Description Reference Vaue Main Valve Demand Lift Demand Cv Demand (-pm /psi"'

(BF1 9)

FCN8 -

0 0.0 17 145.0 30 290.0 40 435.0

'58 725.0 66 870.0 75 1015.0 84 1160.0 100 1450.0 Bypass Valve Cv CCv Demand Lift Demand (%)

(gpm / ,si" 2 )

FCN9 0.0 0 I 14.4 20 21.6 30 28.8 40 36.0 50 50.4 70 57.6 80 64.8 90 72.0 100 Man Vv . Cv Demand Lift Demand (%W Main Valve Cv CAMQ(pm / Psi";)

FCNIO 0.0 0 145.0 17 290.0 30 435.0 40 725-0 58 870.0 66 1015.0 75 1160.0 84 1450.0 100

Page 3 of 3 ATTACHMENT 8 S-I-CN-ECS-01 18 (003E)

Rev. 0 ADFCS Set Points List for Units I and 2 Page 6 I Description Reference l Value Cv Distribution Function FCNI 1 Bypass Valve Total (Bypass Valve) Cy Demand Cv Demand (2pm / psi' 2 )

(2pm I psi")

0.0 0.0 36.0 36.0 72.0 108.0 72.0 507.0 0.0 647.0 0.0 1450.0 Cv Distribution Function FCN12 Main Valve Total (Main Valve) Cv Demand Cy Demand (gpm / psi'l)

(gpm / psi" 2 )

0.0 0.0 0.0 36.0 36.0 108.0 435.0 507.0 647.0 647.0 1450.0 1450.0 1.5 Notch Gains Notch Gain on Narrow FCN16 NR Level Gain Out Range Level Error(%)

-100.0 1.0

-1.0 1.0 0.0 0.0 1.0 1.0 100.0 1.0 Notch Gain on FW Pump FCNI 7 DP Error Gain Out AP Error (psid)

-250.0 1.0

-5.0 1.0

-2.5 0.25 0.0 0.0 2.5 0.25 5.0 1.0 250.0 1.0

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B-I APPENDIX B The information that follows is a copy of the PSEG Nuclear LLC transmittal letter EA-CFCU-03-005, dated October 20, 2003. This information was transmitted to Westinghouse by PSEG Nuclear LLC for revision and clarification of several of the analysis input assumptions. The information contained in Appendix B supercedes the information contained in EA-CFCU-03-004 for the work presented in the main body of this report.

Please note that the service water flow in Item S should read "...increased from 1000 gpm to 1200 gpm" based on the data provided in Attachment 4 of EA-CFCU-03-005.

WCAP-16193-NP March 2004 Official record stored elecronically in EDMS 2000-031504

PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 18-0236 October 20, 2003 0 PSEG.

NuclearLLC EA-CFCU-03-005 Mr. Jerold Kusky Customer Projects Manager Westinghouse Electric Company P.O. Box 355 Pittsburgh, PA 15230-0355

Dear Mr. Kusky:

Additional Clarification for CFCU Project Containment Analyses Input Parameters Based on further review of the CFCU project containment analyses input data (Reference I), it was determined that some further clarifications and input values are required.

1. The Westinghouse values for the high steam flow setpoint assumptions (trip setpoint as a function of power level, Item C.4) included an environmental allowance that is not required. This resulted in analytical trip setpoint values that were significantly over-conservative. Attachment I provides the appropriate uncertainty allowance to apply to the trip setpoint along with the necessary basis and reference.

2. With respect to the input data required for the Salem Unit 2 replacement steam generators, the secondary side fluid mass as a function of power level (Item D.3.c),

needed to be provided by Framatome and was not available at the time the containment analysis input data was transmitted to Westinghouse. This information has recently been provided and we have modified it to be consistent with current level program and temperature range. This information is provided in Attachment 2.

3. To provide additional margin for the limiting steamline break cases, PSEG has determined that a reduction in the end-of-cycle moderator density coefficient (MDC),

Reference I Item A. I 1, from 0.52 to 0.45 delta-k/gm/cc is acceptable from a core design standpoint.

4. PSEG has developed Residual Heat Exchanger UA values for the recirculation phase of the LBLOCA event. These values, provided in Attachment 3 are based on the RHR flow rates recently transmitted by Westinghouse. The information provided covers both active and passive failure situations. Note that to reduce potential equipment qualification impacts, the containment response to LBLOCA will credit recirculation spray flow, and the attachment also provides the minimum spray flow for both the noted scenarios.

95-216a REV. 7M

Mr. Kusky 10/20/03

5. To provide additional margin in the containment response results, PSEG has recalculated the CFCU heat transfer rates with Service Water System flow increased from 1000 gpm to 12 gpm. Other parameters such as fouling factor and Service Water temperature were not changed from the initial values provided in Table K-l.

The revised CFCU heat removal rates are provided in Attachment 4. Note that these differ slightly from the preliminary values provided informally back in early September.

6. The CFCU system actuation time (Reference 1, Item K.3), has be shortened from 120 seconds to 100 seconds.

-4 The first three items are applicable for the steam line break mass and energy release cases. The fourth item is only pertinent to the LOCA containment response cases, and items 5 and 6 apply to both LOCA and MSLB calculations. Please distribute this letter and attachments to all the appropriate functional organizations.

If you have any questions, please contact Mr. Glenn Schwartz at (856) 339-1216, or Kent Halac at (856) 339-1280.

Very truly yours, Ashok Moudgill CFCU Project Manager

Reference:

1) EA-CFCU-03-004, PSEG Nuclear Response to Westinghouse Input Request for CFCU Project Containment Mass and Energy Release Analyses GSS C IC Halac K. Mathur L. Gonzalez P. Finch T. Nolte S. Beckham K. King J. Rowey J. Arias T. DelGaizo

ATTACHMENT i High Steam Flow Trip Setpoint Uncertainty In the determination of the trip uncertainty, Westinghouse currently assumes a 14.75% span environmental allowance. This is not consistent with WCAP-12103 (Setpoint Methodology, PSEG Calc S-C-RCP-CDC-0440), Table 3-24 (High Steam Flow), which shows an environmental allowance of 0.0% span. Note'that Table 3-11 (Steam/Feedwater Flow Mismatch) and Table 3-18 Low Steamline Pressure include 14.75% span environmental allowance.

PSEG Nuclear is the holder of the setpoint calculation of record and has regenerated the rack-up of the channel uncertainty for steam flow safety injection in Section 7.9 of Engineering Calculation SC-CN007-01. The following is a summary of the channel uncertainty determination that is considered appropriate for the steamline break events (transmitter through rack/bistable):

Process Measurement Allowance = 3.000% span Steam Flow Transmitter = 2.77% span Turbine I" Stage Pressure Transmitter = 1.05% span Rack I (with bistable) = 1.328% span Rack 2 (without bistable) = 1.230% span Channel uncertainty = [((2.77%)2 + (1.05%)2 + (1.328%)2 +(1 . 23)2]Iff +/- 3.000

= 6.472% span (where span = 120% of nominal steam flow)

This uncertainty is applied to the trip setpoint as defined in the Salem Technical Specifications:

Steam flow in two steam lines - High coincident with steam line pressure- Low is < to a function defined as: a Ap corresponding to 40% of full steam flow between 0% and 20% load and then a Ap increasing linearly to a Ap corresponding to 110% of full steam flow at full load.

ATTACHMENT 2 Salem Unit 2 Replacement Steam Generator Secondary Side Fluid Mass Below is an array for steam generator total mass inventory (steam plus water masses) as a function of power level for maximum RSG masses, per the original AIS request.

Power (FON) Fluid Mass fIbs) 0.0 152761 0.10 152159 0.20 148543 0.30 142115 0.40 136591 0.50 131570 0.60 126548 0.70 122530 0.80 118513 0.90 114496 1.00 111543 This data is consistent with 0% SGTP, full power Tavg of 577.90 F, and NRS + 5% (49% = 44%

+ 5%). The data points for 0% and 10% span are at span levels higher than the current program in an effort to ensure that the data is conservative (37.8% NRS instead of 22% NRS for 0 % powcr and 43.4% NRS instead of 33% NRS for 10% power).

If the Westinghouse methodology requires that use of any additional biases, these will need to be applied to the above listed data as appropriate.

ATTACHMENT 3 Salem Residual Heat Exchanger UA Data for LBLOCA Recirculation Phase (The following provides clarification to input assumptions L 8 and 9)

The RHR heat exchanger UA values are based on flow calculations performed by Westinghouse and provided electronically to PSEG Nuclear in late September 2003. For the maximum safeguards alignment (passive failure scenario), the minimum RIHR pump flow is 3141.6 gpm (rounded down to 3100 gpm for UA determination). For the minimum safeguards alignment (Emergency diesel failure or loss of a safeguards train), the minimum RHR pump flow is 3200 gpm. In all cases, the flow through Salem Unit 2 Train A provides a minimum bounding flow rate for either Salem Unit.

The following table summarizes the minimum spray flow, RHR flow and RHR UA values for both the limiting single failure (minimum safeguards) and CFCU passive failure (maximum safeguards) scenarios:

Case Min Spray Flow (gpm) Min RHR Pump Flow RHRHX UA (rounded down; gpm) (Btu/hr- 0F)

Min Safeguards 1974.8 3200 (EDG failure) (Unit 2 Train A) (Unit 2 Train A) _________

Max Safeguards 1181.7 3100175E0 Max__Safeguards__ (Unit 2 Train B) (Unit 2 Train A) I.757E+06 As stated in a previous E-mail, the RHRI-X UA values were determined using the Proto-HX model from S-C-CC-MDC-1798, Rev. 3. The following inputs and assumptions are common to both cases:

• CC flow = 4000 gpm

• CC inlet temperature = 120'F

• RHR inlet temperature = 260'F

• Design fouling

• 1%tube plugging Notes:

While the passive failure or "maximum" safeguards case has two running RHR pumps with one recirculation spray path OPEN, there is also one RHR cold leg injection path OPEN (SJ49). Since the RHR cold injection path provides little flow resistance, flow from both RHR pumps is "in effect" diverted from recirculation spray to this path.

For this case, there would be no other failures and both containment spray pumps would be running in the injection phase along with all three CFCUs. The CFCUs would continue to run until the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> point.

ATTACHMENT 4 Revised Containment Fan Cooler Heat Removal Rates Heat Removal Rate jBtulSec per Fan Cooler]

Current PSEG Revised PSEG Confirmed Value at Confirmed Value at Containment 931F and 1000 gpm. 930 F and 1200 gpm.

Temperature Fouling at 0.0015 Fouling at 0.0015 Percent Increase

[OF] (from Table K-I) above Current Value 105 606.6 648.6 6.9%

120 1502.3 1620.8 7.9%

140 2922.8 3198.7 9.4%

160 4522.1 4982.6 10.2%

I 180 6205.2 6908.8 11.3%

200 7888.0 8856.4 12.2%

220 9617.3 10817.0 12.4%

240 11257.2 12706.5 12.8%

260 12950.8 14625.6 12.9%

271 13869.6 15662.5 12.9%

280 14588.8 16500.1 13.1%

Attachment 4 SALEM UNITS 1 AND 2 SYSTEM DESCRIPTION CFCU/SW ENHANCEMENT PROJECT April 2004

System Description

CFCU CH System (Including Modification on SW System)

Salem Generating Station Ashok Moudgill, Project Manager

I System Description CFCU Chilled Water System Rev 2 04/04/04 Prepared by:

Harold Trenka, Project Engineer Reviewed by: '- ),JACy Ted Delgaizo, Conc,6ual & Analwa-l Support Approved by: LLrt i. UP Ashok Moudgill, PM Page 2 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 Table of Contents REVISION 1 TO REVISION 2 CHANGES: ................................................. 5 SYSTEM DESCRIPTION LIMITATIONS ................................................. 5 DEFINITIONS. 6 KEY DESIGN PARAMETERS. 8 FIGURE 1 CHILLER COOLING CAPACITY VERSUS COOLING DEMAND ............................. I 1..........

FIGURE 3 MECH PEN AND SW VALVE ROOMS VALVE ARRANGEMENT ..................................... 13 FIGURE 4 TYPICAL CH AOV CONTROL LOGIC .............. ................................... 14 FIGURE 5 TYPICAL SW SUPPLY HEADER AOV'S CONTROL LOGIC ........................................... 15 FIGURE 6 TYPICAL SW RETURN HEADER AOV'S CONTROL LOGIC .......................................... 16 FIGURE 7 CFCU CH SYSTEM ONE LINE ELECTRICAL ................................................. 17

1. SYSTEM OPERATION ................................................. 18 1.1. OVERVIEW OF MODIFICATION .............................................. . 18 1.2. NORMAL MODE OF OPERATION . .. ........................................... 20 1.2.1. CFCUCHSystem Pump and Chiller Operation.20 1.2.2. Head Tank and Accumulator Operation.21 1.2.3. ControlRoom SW and CFCUCHSystem I&C.24 1.2.4. CFCUOperation.25 1.2.5. SW Operation.25 1.2.6. ElectricalPlant Operation.26 1.3. ABNORMAL/EMERGENCY MODES OF OPERATION .................................... 28 1.3.1. Failureof a CFCUCH System Chiller or Pump.28 1.3.2. Tripping of all CFCUCHSystem Pumps.30 1.3.3. Failureof a CFCU.30 1.3.4. Failureof a CFCUCHSystem or CFCUSWIsolation Valve .31 1.3.5. PartialLoss ofPower to CFCUCH System .31 1.3.6. Total Loss ofCFCUCH System .32 1.3.7. Using SWfor non-DBA Short Term "Abnormal" Containment Cooling 32 1.3.8. CFCUCH System Leaks/PartialIsolation.34 1.3.9. CFCUCHSystem Operationat Extreme Cold Weather.35 1.3.10. SWInadvertent InitiationDuringNormal Operation.36 1.3.11. System Flush Following SWActuation .37 1.4. DBA OPERATION ............................................... 39 1.4.1. Active Component Failures................................................. 40 1.4.2. Passive (SWPiping) Failure................................................. 41

2. DESIGN REQUIREMENTS ............................................... 42 2.1. MAJOR CFCU CH SYSTEM COMPONENTS PER SALEM UNIT . .................................... 42 2.2. KEY DESIGN PARAMETERS ............................................... . 42 2.2.1. Accumulator Design Parameters.................................................. 42 2.2.2. CH Head Tank Design Parameters................................................. 43 2.3. GL 96-06 DESIGN REQUIREMENTS ............................................... 43 2.3.1. PostulatedTransients - CHSystem Initially in Operation................................... 44 2.3.2. Postulated Transients - SWSystem Operation.45 Page 3 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 2.4. GL 89-13 REQUIREMENTS ................................................. 46 2.5. CONTAINMENT ACCIDENT ANALYSIS REQUIREMENTS ................................................. 46 2.6. SW AND CFCU CH SYSTEM VALVES FAIL POSITION ................................................ 47 2.7. SW & CFCU CH VALVES, CH PUMP, AND CHILLER CONTROL SIGNALS .. 47 2.7.1. SW CFCUValves .47 2.7.2. CHSystem Valves .48 2.7.3. CHSystem Pumps.49 2.7.4. CH Chillers.49 2.8. IN-SERVICE TESTING REQUIREMENTS .. 49 2.9. SW PUMP DESTAGING REQUIREMENTS .50 2.10. CFCU WATER Box COATING, SEALING, AND MINIMIZATION OF LEAKS ............... 51

3. DISCIPLINE DESIGN REQUIREMENTS .53 3.1. MECHANICAL .53 3.2. ELECTRICAL .58 3.3. I&C .59 3.4. CORROSION/WATER CHEMISTRY CONTROL .61 3.5. CIVIL/STRUCTURAL .61 3.6. DESIGN SPECIALTIES .61 3.7. LICENSING .62

4. KEY PROJECT DOCUMNENS .63 Page 4 of 64

(4) 33% CHILLERS O

ACCUMMULATOR CON T A NVIENT ENCLOSURE

-1 (5) CFCU (3) INSERVICE

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WATER PUMPS

. 4 NO.12 SW SUPPLY NIJC. HDR 4 16' 1 _1-

'FUEL HAND iNG BLDC ANNEX j NO.11 SW NUC.

SUPPLY HDR 16' I I 1 NO.11 SW RETURN NUC. HDR NO.12 SW RET iRN NUC. HDR 16" TYP)

'ENETRATiON AR EA Eu. 78I SW223- SWY72 NOTE: THROTTLE C Iv RED INDICATES NEW VALVES PIPING & EQUIUPMENT.

SALEM UNIT 1 & UNIT 2 CFCU CHILLED WATER (CH) SYSTEM

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 Revision I to revision 2 changes:

(1) Revised sections on chiller failures and CH bus to include the cross-tie between 480 V buses. This tie allows one 480 bus to power up to 3 chillers and two pumps (provided that no more than one chiller and one pump are on the oppo-site bus). Also, the limitation is that the failure on the opposite bus is on the power to the 480 V bus and not a failure of the 480 bus itself.

(2) Revised information on the GL 96-06 design basis to reflect that the accumulator is not critical when the transient commences with the CFCU Chilled Water Sys-tem in operation. However, it is critical when SW is providing cooling with the unit at power.

(3) Clarified that the chillers will be elevated a nominal 3 feet to clear snow, improve access to key components, improve air-flow, and reduce potential for any local-ized flooding from severe weather.

System DescriptionLimitations The purpose of this System Description is to serve as a communication tool to consoli-date the decisions made by the Project Team on the design of the CFCU CH System and to communicate this information for review, comment, and use by others.

It is anticipated that the System Description be updated on a continuous basis as the decisions evolve.

Although specific values are included for key parameters, these numerical values are not to be considered final nor is this System Description to be used as the reference source/input for these values. Rather, the source documents listed in Section 7 should be cited.

'i--h,

. . ig+.

Page 5 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 Definitions Anticipated Power operation, shutdown, refueling, and start-up. Excludes DBA acci-Operations dents which are postulated, but not anticipated.

AOV Air Operated Valve AST Alternate Source Term CH Chilled Water (as used herein, refers only to new, non-SR system)

CFCU Containment Fan Coil Unit condenser The heat exchanger on the chiller that cools the refrigerant coils (air cooled chillers use fans on the chillers and outside air as the UHS)

DBA Design Basis Accident DM Demineralized Water EDG Emergency Diesel Generator (On-site backup to vital buses)

EO Equipment Operator evaporator The heat exchanger on the chiller that cools the chilled water FHB Fuel Handling Building FHB Annex Non-RCA portion of the FHB truck bay; also called "storage area".

Group Bus Non-vital, 4160 VAC (without on-site diesel backup power)

GL Generic Letter IST In-Service Testing LCWT Leaving Chilled Water Temperature (outlet of chiller)

LOCA Loss of Coolant Accident LOP Loss-of-offsite-Power (but no loss of vital power from diesels)

MSLB Main Steam Line Break Non-SR, NSR Non-Safety Related "Operable" Available as defined by Salem Technical Specifications RCA Radiologically Controlled Area Page 6 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 RCFC Reactor Containment Fan Cooler, same as CFCU SACF Single Active Component Failure SEC Safeguards Equipment Controller SGFP Steam Generator Feed Pump Si Safety Injection SIS Safety Injection Signal SR Safety Related SSE Safe Shutdown Earthquake (lose non-SR equipment)

SW Service Water TB Turbine Building TDH (pump) Total Driving Head Ton Cooling ton = 12000 BTU/hr UHS Ultimate Heat Sink (the final heat sink for the containment air). For antici-pated operations this is the outside air; for DBA it is the Delaware River UV Under-voltage (as used herein, refers to UV on two or more vital buses which causes the vital power to transfer from normal to EDG. It is also called "SEC Black-out" is some documents).

Vital Bus Powers SR Equipment for Safe-Shutdown Page 7 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l Key Desiqn Parameters Containment Heat Load at 86IF 12.6 MBTUH Chilled Water Pump Heat Load (total 2 pumps) 0.3 MBTUH Total CFCU CH System Heat Load 12.9 MBTUH (1074 tons)

Nominal CFCU CH System Flow, total 2400 gpm Nominal CH System flow/CFCU air cooler 780 gpm Nominal CH System flow/CFCU motor cooler 20 gpm Nominal CH System Flow/pump 1200 gpm LCWT, Chilled-water temperature to CFCU's, normal 460F LCWT operating range 40-601F Chilled-water temperature rise across CFCU's -110F Normal CFCU air flow/CFCU (unchanged from present) 110,000 cfm Normal containment ambient temperature (3 CFCU's) 2 -86°F Abnormal containment ambient temperature (2 CFCU's) 3 -104°F Containment TS Limit maximum temperature for normal Ops 120OF SW and CFCU CH System Piping Design Pressure 200 psig CFCU, Accumulator, and Head Tank Design Pressure 150 psig Head Tank N2 Pressure 65 psig,+0, -5 Head Tank Static Head (125'- 102') -10 psid Head Tank Total Pressure at tank outlet line 75 psig,+0, -5 CFCU Chilled Water Pump TDH 65 psid CFCU CH System Supply Pressure at Accum. Connection -105 psig, + 0, -5

' The system description assumes 46 0F setpoint, which will result in a containment temperature of 86 0F.

The actual setpoint will be determined in the detailed design. Operation at lower LCWT setpoints will in-crease power consumption and decrease chiller capacity. The converse is true.

2 The containment temperature will be - 40 0F higher than the LCWT.

3 This value conservatively assumes that the chilled water to the inoperative CFCU is not isolated; there-fore the chilled water flow to the two operating CFCU's remains at 800 gpm. The containment tempera-ture will be - 581F higher than the LCWT setpoint.

Page 8 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 CFCU CH System Supply Pressure at SW Valve Interface -110 psig, + 0, -5 Accumulator Nominal N2 Pressure - 80 psig Accumulator Total Pressure at tank outlet line - 90 psig CFCU Supply Header Low Pressure Isolation Setpoint < 80 psig Head Water Volume 8000 - 12000 gallons Head Tank Water Height (Above bottom of tank) 17' - 25' Accumulator Water Volume 8000 - 12000 gallons Accumulator Water Height (Above bottom of tank) 17' - 25' Number of CFCU's required 'Operable' 5 Number of CFCU's credited for DBA after SACF 3 Start of DBA Containment CFCU Cooling 4 <60 seconds SWS flow rate/CFCU credited for DBA heat removal 1,200 gpm Estimated SWS flow rate/CFCU in DBA9 >1,500 gpm Accident CFCU air flow/CFCU 6 (unchanged) 39,000 cfm Maximum outside air ambient temperature assumed 105°F Design maximum SWS inlet temperature 90OF 7 SW pump design flow No change SW system strainer backwash (normal and accident) Constant 8 2 Stage SW pump head (relative to 3 stage, Preliminary) - 66%

SW pump motor loading (3 Stage pump) 1000 Hp (746 KWe)

SW pump motor loading (2 Stage pump) Estimated 666 Hp (496 KWe) 4 The design is based on meeting the technical specifications of 60 seconds for full CFCU SW flow. The Containment analysis conservatively assumes 100 seconds.

5This higher flow rate will be used to mitigate the SW outlet temperature and flashing when the SW flow enters the low pressure SW return header.

6 No airside CFCU hardware changes. 39,000 cfm assumed with 5 CFCU's running. 40,000 cfm assumed when there are 3 or fewer CFCU's running.

0 7The DBA containment analysis assumes a 93 F SW temperature. This provides for added margin and contingency.

a The CFCU Chilled Water System Project will not perform this modification; it will only evaluate the SW System performance with this added load since it isa bounding assumption.

Page 9 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 l EDG allowable for continuous operation (no time restriction) 2600 KMe EDG max allowable 2-hour (110% of continuous) 2860 KWe KVA Rating for CFCU CH Substation feed (each of two) 2500 KVA Amps rating for CFCU CH Substation (each of two) 3200 amps Page 10 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 Figure 1 Chiller Coolina Capacitv versus Cooling Demand Cooling Demand:

If 4 chillers available and 44°F LCWT (containment at 860F): 270 tons/chiller If 3 chillers available and "OF LCWT (containment at 860F): 360 tonslchiller If 2 chillers available and 600F LCWT (containment at 102iF): 530 tons/chiller Capacity vs. LWCT & Outside Air Temperature 550 AOtsie H 85AF

_ 500 c

In 0

1050 F

0) 450 I-Outside Air n 400 0

0 350 300 44 46 48 50 51 52 53 54 55 56 57 58 59 60 Leaving Chilled Water Temp Page 11 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 Figure 2 CFCU CH System Simplified P&ID P NC recirc line Safety Related Portion Annex Anne _ . , Byy_.Pen FHBii B Area /Containment

!;cim. (see Figure 2 for added details) refilter and Chiller  ! psg demin . . . . . . .65 I evaporators i .......

f _  ;

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i 12 sw a fil+

12 sw

~_2ii TMak D up, Ii 2 pum ps provide rated I

ii*

SW11 SW i 600 gpm, 400 flow, 2400 gpm. ton cooling, each Normal: 3 CFCU's from closed loop at 800 gpm flow each.

Accident: up to 5 CFCU's from

S\\ats.1504Qprreach>._._._._._._._._-i I Page 12 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 Figure 3 Mech Pen and SW Valve Rooms Valve Arrangement Typical for all eight SW AOV I Header valves: (1) redundant qir

-supplies and (2) redundant sole-

.iM . Mnoids Dowered from seoarate DC

.- Return:'-'-

CH Supply ine. 12SW77'

, :;- .. 12SW78 4.........-;.:.:.:

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,, ......',' ,,,bdX:'

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Page 13 of 64

B train CH Outlet.tif Figure 4 Tvyical CH AOV Control Lopic Page 14 of 64

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-0.1 - -11 I- B TRAIN OF CFCU CH WATER OUTLET ISOLATION VALVES p

- -_-__---,-,--- -- II I.. I , I I

11 sw inlettif Figure 5 Typical SW SuppIy Header AOV's Control Logic Page 15 of 64

I a I 8

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It t

REFERENCE DRAWINGS Ii s-Cal1r 0101 T **It I-I _______ Kr ________

OESCnFREEEISSUE - 3/S604 mi.sC 10YC 0.11Wm REV8 NOTE: ,'o 9tIll 'NN Iii fMW WA^sSI o0tr o l som Ml' tL555 f aml t~s or 7?x A1$ENTION_.:- w .- 1 SAEn NUCLEAR GENERATJN STATION dCFlNIMsfEIY REUATED I-~ I CfsLtED WATER SYSTEM I - aiiniisi Tw rr Im- n* I w-iz

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tO(1C ACGRAM COITROLS I I I I 17 nilI "l I I('EI liKtE 011 IES gn u AtIA 11dI II Y U VW 1tlak tLE WAVEI I1001 WE5 M10300 KIT1CQITM KfTFINWVIVIL1E UNM I-vf cmm r~ias l _1 1 0 Wtit<ll WA - - . w w. 0s-1_

LVI N 11.SW HEADER INLET WATER FLOW VALVES ("B" CHANNE L) - -

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11 sw outlet.tif Figure 6 Typical SW Retum HeaderAO V's Control Logic Page 16 of 64

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r. s .11s F I I IOI Im I .

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One Line - Design Freeze Issue - Draft.tif Figure 7 CFCU CH System One Line Electrical Page 17 of 64

v- I I

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System Description CFCU Chilled Water System Rev 2 04/04/04

1. SYSTEM OPERATION 1.1. Overview of Modification An independent Containment Fan Coil Units (CFCU's) Chilled Water (CH) Sys-tem with redundant components is supplied for each Salem Unit. The CFCU CH System provides chilled water for containment cooling during normal power op-eration, normal shutdown, and refueling. It is not relied upon for design basis ac-cident (DBA) cooling.

The CFCU CH System circulates a total of 2400 gpm of demineralized water in a closed loop between three CFCU's and four air-cooled chillers, mounted outside, to transfer the containment heat to the outside air. Three CFCU's and three chillers are sufficient to maintain the containment less than 901F providing over 300F mar-gin to the maximum allowable temperature during normal operation, 1200F.

Service Water (SW) cooling is required during any DBA that releases mass/energy into the containment, even if the CFCU CH System remains available, since the DBA heat load would trip out the chillers on overload. A revised Westinghouse analyses, that credits improved CFCU fouling factor and improvements in accident modeling, shows that only two CFCU's, each with a minimum of 1200 gpm 9 SW flow, are adequate for DBA containment cooling. However, since the present dose calculation credits 3 CFCU's for DBA containment air mixing and iodine scrubbing, and a single active component failure (SACF) may disable two CFCU's, the CFCU Technical Specifications will retain the requirements to maintain five CFCU's

'Operable". When Alternate Source Term (AST) is implemented, the analyses will support a licensing change to reduce the number of "Operable" CFCU's from 5 to 4.

On a Si signal, the CFCU flow is automatically realigned from CH to SW. The CFCU CH System is immediately isolated and SWS flow is then aligned by first opening the CFCU SW supply header isolation valves and then opening the SW return header isolation valves. However, if a LOP occurs at the same time, the SW valve opening is delayed until after the SW pumps are restarted.

Since the CFCU CH System shares some common piping and components with the SW system (e.g., CFCU's, and CFCU supply and return headers in the me-chanical penetration area and containment), SW leakage into the demineralized water system has to be prevented during normal operation. This is done by using two in-series, SW isolation valves in each SW header and by maintaining the cleaner system at a slightly higher pressure than the SWS. All CFCU CH System components that are part of the DBA pressure boundary are designed to the higher standards imposed on the SW system. This includes the valves that isolate the non-safety related portion of the CFCU CH System.

9 However, approximately 1500 gpm will be provided to ensure no flashing of the SW outlet water when it is discharged into the common, low pressure SW return headers.

Page 18 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 l One of the two SWS accumulators is retained as an accumulator. It keeps the CFCU piping full and pressurized to prevent two-phase flow and water hammer during the post-DBA switch from chilled water to SW (Thermal relief valves, lo-cated immediately downstream of the CFCUs, protect the CFCU from thermal expansion when isolated). The other accumulator is used by the CFCU CH Sys-tem as a head tank. It maintains NPSH and provides surge volume to accommo-date thermal expansion, flow transients, and system leaks.

Since SW is not required for anticipated operations and the accident SW flow is significantly reduced, the complex flow control valve scheme previously required to establish different CFCU SW flows is eliminated. CFCU flow rates are fixed and hydraulically balanced by orifice plates and throttled valves. The resistance is set to assure (1) the nominal flow CH System flow of 800 gpm/CFCU to three CFCUs and (2) a minimum accident SW flow rate of - 1300 gpm/CFCU. With fixed resistance, the flow is determined by the pump head.

Overall, there is a significant gain in CFCU reliability and a significant reduction in maintenance1 s by using clean water to reduce the corrosion, erosion, and fouling of the CFCU's and by eliminating the flow control valves.

The reduced accident flow/CFCU allows the SW pumps to be destaged from 3 to 2 stages since it eliminates the CFCU as the dominant pressure loop. All normal and accident flows can be met with a 2 stage SW pump. Each destaged pump reduces vital power consumption by -250 KW. Presently the EDG's operate during the ECCS injection phase close to the maximum allowed by the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> short term limit, 2860 KWe. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is 110% of the continuous allowable limit of 2600 KWe. The SW pump destaging decreases the peak EDG loading below the continuous loading, 2600 KWe, even during the ECCS injection phase.

The new chillers and pumps will be powered from the non-vital (group) buses. The 4160 VAC "G"and "E"buses will each power a 480 VAC CFCU CH substation. In turn, each of these substations powers two chillers, two pumps, and all common power (through an auto transfer). A limited cross-tie between the 480 VAC buses allows one bus to power up to three chillers in case the power feed to the other 480 VAC bus has failed. These 4160 VAC non-vital buses have the spare capability and breakers as a result of removing the Circ Water Pumps from these buses.

The power required to operate the Salem Units during peak (summer) demand is not increased. This is due to the savings from operating with 4 destaged SW pumps (1000 KW savings) and one less CFCU (224 KW savings) being greater than the added load of four chillers (<800 KW) and two CH pumps (<100 KW).

° This is achieved by significantly reducing, if not eliminating, the numerous water side problems, CFCU Reliability White Paper 7 22 03, Reference 7.11.

Page 19 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l 1.2. Normal Mode of Operation 1.2.1. CFCU CH System Pump and Chiller Operation During normal plant operation, plant shutdown, and refueling activities, the CFCU CH System operates with 2 (of 4) chilled water pumps and 3 or 4 (of 4) 400 ton rated chillers to supply 3 CFCU's with 2400 gpm (total for all three CFCU's) of 460F cooling water. This flow rate and supply temperature will remove 12.6 MBTUH from the containment and maintain containment ambient temperature less than 900F.

Two of four 50% chilled water pumps are required for 2400 gpm flow. The other two are installed spares. A fixed CH flow of 2400 gpm will be maintained. Flow control to the CFCU's is set solely by fixed resistances and by hydraulically balancing system resistance to provide a simpler and more reliable design (All flow control valves including those in the CFCU branch lines are eliminated).

Fixed resistances include orifices and manual throttle valves. Flow modulation is not required since the chiller loading automatically compensates for changes in the containment heat load.

The single fixed resistance is set for each of the two CFCU headers to establish CFCU flow rates for normal and accident conditions. Each CFCU header pro-vides cooling water to three CFCU's (see Figures 1 and 2). The fixed resistance will provide a normal, chilled water flow of 800 gpm/CFCU to three CFCUs and a minimum SW, accident flow of 1300 gpm/CFCU. The post-implementation testing will confirm the CFCU's flows for both the chilled water system and the SW sys-tem. Once set, no flow adjustment should be required. The flow balance is checked periodically, using the chilled water system, to confirm that the fixed re-sistance is adequate for postulated accident conditions. The flow balance proce-dure would be repeated in the future only if the testing shows that the flows have degraded or if the throttle valves are repositioned for maintenance or repairs, etc.

Flow indication for each CFCU will be maintained.

CH pump controls from the control room will be minimized. The chiller control panel will control pump operation. Since check valves are provided in each pump's individual discharge path, the suction and discharge valves can be kept open for the standby pump. All manual butterfly valves shall have clear "open" and 'close" indication. Pump stops/starts are anticipated no more frequent than monthly to balance the service hours between pumps. On a low flow or indication of a pump failure, a back-up is automatically started. A signal from the high-low flow switch located in the common discharge header of the pumps indicates that the system flow is abnormal. This signal alarms locally and causes a general trouble alarm in the main control room.

Normally all 4 chillers are in operation to maintain maximum chiller efficiency and minimize power requirements. However, one chiller can be removed from service for maintenance without impacting containment temperature since 3 chillers can meet a containment-cooling load of 1074 tons even with an outside air tempera-ture of 105OF (each chiller can provide 380 tons at 105OF ambient air). The chill-Page 20 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 ers automatically adjust their loading to maintain a constant chilled water supply temperature, selected as 460F. A vendor supplied, central control unit coordi-nates all four chillers.

During normal shutdown and refueling, the chilled-water system continues to op-erate to maintain containment cooling to significantly reduce worker heat stress.

However, the number of in-service CFCU's may be reduced due to the much lower containment heat load. All major CFCU CH System equipment is located in the yard or in the FHB Annex and is easily accessible.

1.2.2. Head Tank and Accumulator Operation The sketch below is a simplified pictogram that omits 4 of the 5 CFCU's and re-dundant flow paths. The sketch is to illustrate the functions of the two tanks. Tank elevations are taken from PSEG Drawing 605395, Rev 0.

The parameters for both the accumulator and head tank, and the rationale for se-lecting them, is addressed in section 2.2, Key Design Parameters and in section 2.3, GL 96-06 Design Requirements.

Top - 152' To - 143' SW Accumulator Head Tank SR and Seismic Mid - 125.5' Pressure Bound-ary Spec Break, 120' Efev Bottom - 108' int

...... ....... J h CH Return CH Supply, 103' elev 101.9' elev.

SW Supply, NC SW72 SW223 RO SW Return, 92' elev. NC, 92' elev SW Accumulator:

The SW accumulator, on the supply header side, is required to satisfy GL96-06 concerns. It operates in conjunction with the CH supply header check valves and return side AOV's to maintain the CFCU's full and the fluid subcooled (as dis-cussed in Sections 1.4 and 2.3). The accumulator is always aligned to the CFCUs during anticipated operation (CH cooling) and during abnormal line up (SWS cooling due to the CFCU CH System being out of service).

Page 21 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 The CH supply header pressure at the connection to the SW Supply headers will be a nominal 110 psig to meet the objective of maintaining the CH supply header pressure at -10 psid above the anticipated SW supply header pressure with de-staged SW pumps.The accumulator is pressurized with N2 gas to - 80 psig. Hy-drostatic pressure between normal level and the outlet line from the tank (point A) adds another 10 psid. Therefore, except for some postulated CFCU flow tran-sients, the accumulator will remain isolated from the discharge flow path by the accumulator outlet check valve due to the higher pressure on the CFCU supply header.

The accumulator water volume is kept between 8,000 to 12,000 gallons. Maxi-mum discharge in a transient, based on Reference 7.4, is - 1000 gallons.

Head Tank:

A head tank is provided on the CH pump suction side. This tank allows for vol-ume changes due to thermal expansion, and it provides a significant make-up volume in case of system leakage. The tank was originally safety related, and the pressure boundary will be retained as safety related.

In addition, the N2 pressure above the head tank is used to establish the CFCU Chilled Water System operating pressure. This gas pressure plus the pump TDH is sufficient to maintain the CFCU CH System pressure above SW pressure at the SW valve rooms. This scheme (as opposed to relying solely on pump TDH) allows lower head pumps to be used. Lower head pumps lower the required Hp, throttling, and heat input to the system. The nitrogen blanket also serves to keep air out and minimize the corrosion of the carbon steel piping.

The head tank water volume is 8,000 to 12,000 gallons. This provides a volume for system leaks and feed and bleed. Each CFCU branch line has an approxi-mate volume of 2200 gallons. The head tank contains sufficient volume to refill a CFCU even without make-up to the tank.

The head tank has a 2" nominal diameter make-up line from the DM system rated for > ~Q-piMi. This line has a normally shut manual isolation valve located in the 78' Mechanical Pen Area, near and above the abandoned-in-place SGBD HX's. A hard-piped line with normally shut valve allows for quick alignment of make-up water without requiring any temporary hoses. Reliance on Operator ac-tion should allow early detection of even small leaks.

Page 22 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 Recirculation Line:

In case the CH System isolation valves are shut, a manually operated recircula-tion path is provided around the pumps and chillers. This allows for system start-up and it allows for the head tank and CH pumps to provide a source of pressur-ized clean water for flushing the CFCU's. The head tank will provide NPSH to the pumps. In order to protect the pump from damage, this tank is not isolated from the CH pump suction except by manual valves.

Anticipated Tank Fluctuations:

During normal operation, level changes are expected to be very small. Volumet-ric expansion/contraction corresponding to a 450 F change in CH water tempera-ture will result in - 2" level change inthe head tank.

Levels and pressures on the head tank should be monitored. Drops in water level (and consequently small pressure drops in operating pressure) pressure will alert the Operators of system out-leakage. The converse is true in case of SW leak-age into the CH system. A 0.1 gpm leakage will cause a tank level change of 4"Iday. Thus, during normal operation, even small leakages should be detect-able' .

The accumulator has a 10" check valve on the outlet that allows for outlet flow from the 10" line. Make-up to this tank is through a normally shut bypass valve around the check valve. A drain line, that is connected to the lower pressure head tank, allows for draining the tank in case there is leakage through the shut check valve. Since the accumulator is normally isolated from the flow path, there should be no level oscillations in this tank.

The CH AOV closure signals are designed to automatically isolate the CH return header AOV's if the CH pumps are tripped (as discussed in section 1.3.2) or there is a supply header depressurization. The in-series isolation valves should prevent the accumulator from draining into the head tank. The preferred pump alignment, as discussed in section 1.3.5, is to operate with one pump from the "E" bus and one from the "G" bus to minimize the possibility of simultaneously losing both operating CH water pumps.

Tank Sequencinq/Alignment During System Start-up and Shutdown:

The following sequence is suggested during system start-up.

1) With the pumps off, fill both tanks to the desired water level (see section 2.2).

2) Pressurize both tanks more or less simultaneously with N2 to the nominal gas pressure recommended for the head tank.

This assumes that the Operator logs record this reading for at least daily comparison.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l

3) Start the CH pumps and verify that the tank levels do not change to con-firm that the accumulator check valve has shut. Increase the accumulator gas pressure to the desired set-point.

The chilled water system can remain in service throughout a refueling outage.

However, if it is to be taken out of service, the accumulator should be isolated prior to all the pumps being tripped.

1.2.3. Control Room SW and CFCU CH System I&C A near term effort is required to provide a more detailed assessment and review against human factors, commitments, and to obtain Ops concurrence.

Although the system is not SR, the CFCU Chilled Water System is critical to power operation. As such, the Operators should be capable of monitoring the fol-lowing key parameters in the CR that indicate if the cooling water to the CFCU's is operating as designed. These are:

1) Rated water flow to the operating CFCU's (The existing flow instrumenta-tion on the CFCU lines should be reviewed to confirm that they are ade-quate for this purpose).

2) CH temperature on the supply and return headers (In addition, there is the temperature on the outlet of each CFCU).

3) Water level and N2 pressure on the head tank and accumulator (confirma-tion of system integrity).

4) Adequate number of components operating (rely on the trouble alarms described below).

The first two (temperature and flow) are the minimum indication to allow the Op-erators to assess if the cooling water is performing its design functions, and therefore, to determine if a containment temperature excursion should be antici-pated, or altematively, if that temperature excursion can be attributed to a cooling water malfunction. The last two items are key to alert the Operators of a system degradation that may shortly cause system degradation or failure.

A high or low water temperature signal or chiller safety circuit trouble will alarm locally and cause a general trouble alarm in the main control room. Chiller pro-tection is provided to automatically shut down chillers if supply or discharge tem-peratures are abnormally high or low. Local control panels will indicate chiller trouble before automatic trip setpoints are reached and a general CFCU CH Sys-tem trouble alarm will signal in the control room. Automatic chiller trip actuation is locked in and must be manually reset. Loss of a single chiller will not cause a loss of flow and CFCU CH System pumps remain in-service.

Control Room changes are required to reflect removal of the individual CFCU flow control valves (i.e. SW57, SW223, SW65) and installation of new AOV's on the CFCU headers. This includes but is not limited to providing controls for the power operated valves and indication of valve position.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 1.2.4. CFCU Operation The preferred alignment for normal cooling is three CFCU's each with 800 gpm CH flow to keep the containment ambient temperature less than 900F.

Closure of the CH return path AOV's from either the east or west SW valve room limits the CH flow to 3 CFCU's but maintains all 5 CFCU's 'operable'. For exam-ple, closure of the CH AOV's in the west room prevents CH flow to the 14 and 15 CFCU, allows CH cooling to the 11, 12, and 13 CFCU, but in case SW is initi-ated, all CFCU's can be cooled by SW.

If the fan on 1 of the 3 operating CFCU is tripped and the flow path is not iso-lated, the two other CFCU's each with a nominal flow of 800 gpm will maintain containment temperature - 102 0F, - 18IF below containment maximum allow-able.

Four (4) CFCU's for normal cooling with 600 gpm each is an acceptable align-ment but it will only provide a marginal improvement in cooling over 3 CFCU's.

The Technical specifications will require all five CFCU's to be "Operable" to en-sure 3 CFCU's operate post DBA and SACF for containment cooling and iodine scrubbing. Any 4 "Operable" CFCU's ensures that two CFCU's remain after a SACF which is adequate for containment cooling as discussed in section 1.4.

Any 4 "Operable" CFCU's will also satisfy the design basis for iodine scrubbing after AST is implemented.

1.2.5. SW Operation SW flows will remain the same except for the changes below.

1) No CFCU SW flow during normal operations

2) Reduced CFCU SW flow in a postulated DBA

3) SW strainer will be kept in constant backflush12 Reducing the CFCU required accident flow from 2500 gpm to 1200 gpm/CFCU significantly reduces the required SW pump TDH. The SW pump will be de-staged from 3 to 2 stages. A 2-stage pump retains the same flow capacity, but the pump power and head will be reduced to 2/3 of its original value. The hy-draulic model will verify that the 2-stage pump can provide all revised normal and accident SW flow rate. The modification will make any required changes to the SW control valves/orifices in all branch lines.

With the exception of the added AOVs to isolate SW from the CFCU's during an-ticipated operation, the CFCU SW accident flow path remains the same. Specifi-cally, because of check valves SW53 and SW77, the 11 SW header can only 12 The CFCU Chilled Water System Project will not be doing this modification, but it will factor this into the SW hydraulic modeling since it is anticipated that it will be implemented by the SW up-grade project.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l cool the 11, 12, and 13 CFCU's. The 12 SW header can only cool the 13, 14, and 15 CFCU's.

The SW system will operate at lower pressure and with less throttling. Specifi-cally, The pump shutoff head will be reduced from 180 psig to 120 psig. The supply header normal operating pressure will be reduced from - 150 psig to

-100 psig. This provides a far greater margin to the piping design pressure, 200 psig and to the design pressure for a number of the SW components, 150 psig.

Winter operation will be reviewed to determine if bypass flow has to be added to compensate for no flow thru the CFCU's. This is required maintain minimum SW pump flow. One option is to increase the bypass flow around the TAC HX.

Note that section 1.3.7, contrary to the above statement, does address SW flow in use in a non-DBA scenario for containment cooling. The basis for providing section 1.3.7 is to answer, proactively, if using SW for non-DBA containment cooling poses an unanalyzed condition to the unit.

1.2.6. Electrical Plant Operation The primary electrical plant change for normal operation is to shift loading from the vital buses to the group buses. Specifically, the normal and accident loading on the vital buses are decreased by destaging the SW pumps. The SW pumps are the single largest loads on the vital buses. The normal load on the group bus is increased by the addition of the new CH pumps and chillers. The total plant electrical load to operate the unit will not significantly change. There will be a small reduction except in the winter time, when there will be a slight increase.

Vital Buses The number of SW pumps in normal operation varies between 2 in the winter and 4 in the summer. This number is not expected to change, but destaging the SW pumps will reduce the vital bus loading by approximately 250 KW per operating SW pump. Since one SW pump is loaded on each diesel on a LOP, this also re-duces the EDG loading by - 250 KW / diesel.

The number of CFCU's in operation varies from 2 in the winter to 4 in the sum-mer. With the chilled water system, 3 CFCU's will be kept operating year-round.

This reduces the summer load by 300 Hp (224 MWe), but increases the winter load by the same amount.

For DBA conditions, the CFCU fans are shifted to low speed operation (100 Hp).

The A diesel is loaded with the 11 CFCU, the B diesel with 12 and 14 CFCU, and the C diesel with 13 and 15 CFCU(This is not a change from the present design).

Non-Vital (Group Buses)

The four chillers and four pumps will be normally split between the 'G" and 'E" buses. In addition, an auctioneered circuit will power the common control panel.

Common l&C, local lighting, and maintenance outlets. Refer to Figure 7 CFCU CH System One Line Electrical on page 17. These non-vital buses have the spare ca-Page 26 of 64

System Description CFCU Chilled Water System Rev 2 04/04/0 pability and breakers as a result of removing the Circ Water Pumps from these buses.

Each of the two 480 VAC CFCU Chilled Water System substations will be able to provide full containment cooling under the bounding conditions discussed in sec-tion 1.3.1 and 1.3.5. These are loss of one or both chillers on the opposite bus.

Each 50% CFCU CH System pump motor is rated at 60 Hp and this load is year-round. Although each 400 ton chiller rated nameplate will be approximately 500 to 550 KW, the normal load, assuming all 4 chillers are in operation, is less than 200 KW/chiller as per the table below.

Chiller Capacity Versus 3 Chiller Operation (each 4 Chiller Operation (each Monthly Ambient 0 Temp and chiller at -350 ton) chiller at -262 ton) 46 F LCWT Mean Dry Capacity KW Total KW Total Month Mean Dr tonsi  % Loaded chiller kW  % Loaded chiller KW BubF chiller k May 82.2 451 77% 307 922 58% 190 757 Jun 86.6 439 80% 330 991 60% 192 766 Jul 89.3 431 81% 345 1038 61% 193 772 Aug 86.8 438 80% 331 994 60% 192 767 Sep 85.0 443 79% 321 965 59% 191 763 Page 27 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 1.3. Abnormal/Emermencv Modes of Operation 1.3.1. Failure of a CFCU CH System Chiller or Pump Electrical failures are addressed in sections 1.3.5 and 1.3.6.

Since the CFCU CH System is required for power operation, it is provided with four 50% pumps and four chillers.

Although the CFCU CH System will not have Technical Specifications mandating a specific number of 'Operable' CFCU Chilled Water System components, there is a containment technical specification on containment peak temperature, which in essence, mandates adequate CFCU CH System performance. Any chiller or pump failure should be addressed in reasonable time to minimize the possibility of cumulative failures that would then impact the system's ability to maintain con-tainment temperature. The project will provide during the implementation phase an analysis showing the consequences of any failure including the impact on the cooling margin. The objective of this analysis is to identify the priority that the re-pair should have.

To mitigate the duration of any major failure, the chillers and pumps are located in an accessible, ground level location. All chiller and pump piping connections are flanged and valved to allow for quick replacement of the defective pump or an entire chiller without impacting the pressure boundary for the rest of the com-ponents. All chillers are provided with single point, lugged electrical lines.

Chillers The cooling requirements and cooling capacity per individual chiller is shown in Figure 1. The cooling requirement/chiller is summarized for three conditions: all chillers available, one chiller lost, and 2 chillers lost. The actual capacity of a chiller is dependent on (1) outside air temperature and (2) LCWT setpoints. The chiller sizing is based on:

1) Assuming 4 chillers are normally on-line, a complete failure of any one chiller will only result in the other three automatically going from -68% to 90% capacity. The remaining three are capable of cooling the containment assuming 105OF outside air and 440F LCWT (keeping containment at less than 900F).

2) On a loss of two chillers, the remaining two are capable of cooling the con-tainment assuming < 900F outside air and 600F LCWT (keeping contain-ment at -1 000F). Under these conditions, the chillers will have zero margin (refer to section 1.3.5).

The chillers include self-diagnostics including screens with problem reports in plain English. In addition, the Vendors offer a maintenance agreement that in-cludes periodical site inspections and repairs.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l A complete loss of a chiller due to a chiller component failure is not likely. Each 400-ton chiller has four separate 100-ton refrigerant circuits'3. Each 100-ton re-frigerant circuit consists of one compressor and multiple condenser fans powered from a separate circuit breaker. Similarly, the refrigerant pressure boundary for each of these circuits has its independent refrigerant piping and condenser cool-ing coils such that a loss of refrigerant will not affect more than one circuit. Thus, the more probable consequence a single refrigerant component failure is loss of 1/16th of the total capacity of 4 chillers, and at least 5 refrigerant circuit failures can be tolerated before chiller capacity becomes limiting.

The above design allows for repairs or routine maintenance to one circuit while keeping the other three circuits available. Furthermore, the compressors are flanged and the physical lay-out specifies that piping shall be run so that it does not interfere with removal of a compressor or prevent fork-lift access to the com-pressor.

An obvious advantage of air-cooled chillers (as opposed to water-cooled) is the simplicity of the refrigerant cooling. As opposed to water cooled chillers, air cooled chillers are immersed in their cooling medium and only require power to the fans to provide adequate cooling even with 105OF outside air. The control scheme is simple. As outside air temperature or chiller loading change, automatic changes in the number of operating fans allow small step changes in the cooling flow rate to maintain optimal refrigerant cooling. Each chiller has 18 or more fans (depending on Vendor). The fan motors are approximately 2 Hp, direct drive, with double sealed, permanently lubricated ball bearings. A fan failure will only affect one circuit and even then a fan failure only results in a proportional reduction in capacity; therefore, in excess of 18 fans would have to fail before containment cooling is impacted.

In addition to the controls on each chiller, a central control panel coordinates the chillers and the pumps. This central control panel provides the following key func-tions:

• It allows for changing any input, e.g. LCWT setpoint, at one location ver-sus individually at each chiller. Similarly, it simplifies obtaining operating data/history from the machines.

• It coordinates the chillers to rotate operating time.

• It coordinates the chillers when chilled water conditions change. This is more important when cooling loads vary. The central control panel will se-quence the chillers to minimize 'over-reaction" to a change in parameter.

• It will start a standby chilled water pump if it senses a pump trip.

13 this is a standard design for York. It would require a customized design from the other vendors.

For example, Trane's standard design has two 200 ton circuits with two 50% compressors/circuit.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l The potential vendors have verbally stated (with verification to be done during the bid selection process) that a failure of the central panel will not disable any equipment. The pumps will remain as before. The running pumps will not be tripped and the standby pumps will not be started. The chillers will operate satis-factorily without the central control panel.

Pumps The chilled water system relies on operation of 2 of 4 fifty (50) % capacity pumps to maintain the containment at less than 900F. A failure of one operating pump will result in a reduced system flow ( b40 1apoati k j) and an upward trend in containment temperature until a standby pump is placed into operation. One pump, however, will keep the containment temperature below 11 0F. To mitigate this concem, the chiller central control panel will auto start a back-up pump when it senses a pump trip (via current transformers on the pump motors).

These pumps will be located inside the 100' level of FHB annex. This is outside of the RCA. This location was provided since it is adjacent to the chillers and it provides ample space, inside an existing concrete building, for optimal layout and access.

1.3.2. Trippina of all CFCU CH System Pumps Refer to section 1.3.6 for a prolonged loss of pumps.

If all on-line chilled water pumps are tripped, the CH AOV's will be automatically shut due to the low CH discharge header signal to these valves14 . The single ac-cumulator then maintains the CFCU's and all SR piping pressurized at nearly normal pressure. If the CFCU CH System pumps are not quickly restarted, the Operators should confirm that these valves are shut (in a DBA, the CH system is also automatically isolated by a Si signal).

CH pumps are not credited for addressing GL96-06 concems.

1.3.3. Failure of a CFCU Containment Normal Temperature Impact:

If operating with CH water to only two CFCU's, the containment temperature will slowly rise due to the thermal inertia inherent in the mass inside containment, but the containment will remain below 110F. The higher temperature differential be-tween CFCU CH chill water and containment temperature then allows the re-maining two CFCU's to remove the required heat load.

Technical Specification Requirements:

The design is based on the more limiting of the following:

14 The design needs to ensure that the source of this signal is upstream of the CH System supply header check valves. Otherwise, the accumulator pressure will negate this function.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l

1) Any 4 "Operable" CFCU's ensure that two CFCU's operate in a DBA for required containment cooling, including worst postulated SACF, but

2) All 5 CFCU's must be 'Operable" to satisfy the present design basis for iodine scrubbing which requires that 3 CFCU operate in a DBA.

Refer to added discussion in section 1.4:

1.3.4. Failure of a CFCU CH System or CFCU SW Isolation Valve A failure of an isolation valve during testing has been considered. The design provisions are discussed in detail in Section 3.1.

In summary, SW double, in-series isolation is provided only to minimize potential of leakage into chilled water and to allow testing during normal operation; it is not a DBA requirement. One valve per line can be jacked-open and then the stem locked open if the valve testing determines that the Valve would not open in case of an accident.

The chilled water system is provided with dual, parallel flow paths on the isolation valve portions. This allows one of the two parallel paths to be isolated for testing or maintenance without interrupting normal cooling.

The time limitation is imposed only by the need to test the redundant valve or flow path.

A failure in an accident condition has also been considered. The valves required to isolate the non-SR CFCU CH system are redundant, in-series, fail shut valves.

Any single valve failure will not prevent isolation of the CFCU CH System. The SW flow paths consist of two redundant flow paths. A failure of either flow path to unisolate will not prevent the other flow path from providing adequate cooling to three CFCU's.

1.3.5. Partial Loss of Power to CFCU CH System A loss of all power to the system is addresses in Section 1.3.6.

The CFCU CH System pumps and chillers are supplied with non-vital power.

However, the power to the chillers is from two group buses. Each group feeds two chillers and two pumps.

Operating instructions will specify that the preferred mode of operation is to split the operating pumps between the two group buses (assuming both buses are available). This limits a loss of either group bus to (1) a loss of two chillers and (2) a reduction in CFCU CH System flow until the chiller central control panel starts the back-up pump.

If the loss of one circuit is due to a loss of the group bus, the reactor will also be tripped because each group bus supplies one RCP motor. The remaining two chillers should easily suffice due to the reduced heat load.

If the failure is due to the power feed from the 4160 VAC (including the 4160/480 VAC transformer) to one of the two 480 VAC buses, a limited cross-tie can be manually operated. This allows the single remaining 4160 VAC to 480 VAC Page 31 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l power feed to operate three chillers and two pumps provided that no more than one chiller and one pump are powered through the cross-tie.

If the failure is one of the two 480 VAC buses themselves, the two chillers on the opposite bus can provide the required cooling under the following conditions (a) the two chillers can operate at 100% of their capacity, (b) the ambient air is below

- 900F, and (c) the LCWT setpoint is increased to -60 0F. A LCWT of 600F will re-sult in a containment temperature of - 1050F which is still well below the maxi-mum allowable of 1201F.

1.3.6. Total Loss of CFCU CH System Without CH System chillers and/or pumps, containment temperature will rise and will force a shutdown if the chilled water system is not restored reasonably fast.

Provided the CFCU CH System integrity is maintained, there is no immediate safety concern. The CFCU branch lines will remain full since the CFCU CH Sys-tem is a closed loop system and the single accumulator will maintain the CFCU's pressurized. The Operators should verify that the AOV's on the CH return path have isolated (see section 1.3.2).

A loss of both UEf and "G"will cause all CFCU CH System chillers and pumps to stop and is bounded by a total loss of group buses (loss-of-off-site power, LOP).

A LOP by itself will not unisolate the SW isolation valves and initiate SW cooling.

On a loss of the chilled water system following a LOP, it is anticipated that the Operators will initiate SW to the CFCU to prevent a containment transient. In a safe-shutdown earthquake (SSE), chilled-water cooling to CFCU's will remain in service only if off-site power remains available and if pressure boundary integrity is maintained. Any significant loss of pressure boundary integrity will cause the system to fail, but even thought the CFCU Chilled Water System is not designed to Seismic I standards, the design has minimized the risks of seismic failure. The NSR piping is designed to B.31.1 and for the most part, it is supported from Seismic 1 buildings.

1.3.7. Using SW for non-DBA Short Term uAbnormal" Containment Cooling Although highly undesirable, the Project evaluated using SW for non-DBA short term cooling so that if it is ever required, it can be done safely. Assuming an ini-tial containment temperature of 900F and moisture at 20%, it is estimated' 5 that the Operators will have - 14 minutes before containment temperature reaches 120 0F, the Tech Spec limit. The following was performed to support this contin-gency:

1) Physical Modifications:

To address a LOP with SW already in operation, the CFCU SW isolation valves are shut on an undervoltage (UV) signal to the vital buses in order to prevent any 15 This is based on a preliminary Gothic run, by Nuclear Fuels, that has not been formally re-viewed.

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System Description CFCU Chilled Water System Rev 2 04/04/04 water column separation or two phase flow during the SW pump transient. Re-dundant valves provide assurances that all the SW flow path will isolate. In addi-tion, each CFCU SW supply header has a check valve to prevent loss of SW thru the supply side header during SW valve closure. This check valve will be "test-able"; this allows quarterly IST verification that it will open and shut. SW flow will be reestablished after the SW pumps are started as described in Section 1.4, DBA Operation.

2) Analytical Work GL 96-06 evaluation (reference 7.4):

The GL 96-06 evaluation confirms that a 61 psig gas pressure in the accumulator is adequate to keep the CFCU headers full of water and pressurized in the event of a LOP (with or without a simultaneous DBA) The GL 96-06 evaluation credits that (a) the SW return paths are isolated by redundant isolation valves and (b) the SW supply path is initially isolated by the single check valve and then by re-dundant AOV's. AOV closure time is assumed as 10 seconds; however, the valves are anticipated to shut well before 10 seconds since the closure time is only dependent on the sizing of the air operator's exhaust port. These assump-tions are key in justifying the adequacy of one accumulator for keeping the water column on all 5 CFCU's solid. This analysis accounts for two SW outlet paths be-ing initially open.

Fouling:

The revised containment analysis requires two CFCU's post SACF with a 0.0015 CFCU fouling factor. Reference 7.4 estimates that operation with SW cooling to the CFCU's can be maintained for - 4 weeks prior to invalidating the assumption on 0.0015 CFCU HX fouling.

Alternatively, if 5 CFCU's are kept "Operable" so that 3 operate post DBA and SACF, addenda I to reference 7.4 documents that 3 CFCU's with a 0.0032 foul-ing factor still provide greater containment heat removal than two CFCU's with lower fouling. A 0.0032 fouling factor assumes long-term SW cooling.

Added Normal Flow:

The final SW hydraulic calculations will determine if the SW System has the ca-pability to provide continuous SW strainer backwash and CFCU flow during nor-mal power operation. SW strainers may have to be restored to "cycling" mode rather than constant backflush.

3) Station Impact The consequences are fouling of the CFCU HX's and river water contamination of the piping in the penetration and containment (This assumes that the non-SR carbon steel portion of the CFCU Chilled Water System is isolated beforehand).

A review of GL 89-13 program must be done to determine if cleaning, inspection and/or testing have to be performed on the CFCU HX's that had SW flow. It is Page 33 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 anticipated that some testing of the CFCU HX will need to be done, but assuming the testing is acceptable, opening and cleaning would not be required.

1.3.8. CFCU CH System Leaks/Partial Isolation With the revised design, the CFCU piping and headers are isolated from the SW during all anticipated modes of operation. Thus,

• Isolating the CFCU CH System will not impact SW System cooling to other components

• Isolating a SW System header will not impact CFCU cooling by the CH System The safety related portion of the CFCU CH System is classified as a moderate energy system since it will operate at - 110 psig and low temperatures. Leaks, but not breaks, need to be considered.

Since the CFCU CH System is a closed system, any small leak can be easily de-tected by a drop in the head tank level (0.1 gpm leak will drop the tank 4"lday).

Earlier detection allows Operator action while the leak size is manageable. Al-though there is no assurance that the leak will start as a small leak, this is typi-cally the case. On the other hand, the system will have a large volume head tank that will provide a significant make-up volume, and Operator reaction time, to ad-dress leaks before system operation is impacted. This is addressed in Section 1.2.2.

Of particular concern is flooding in the SW valve rooms. A failure in either SW valve room should not affect the components in the opposite SW valve room.

The design will maintain the water tight integrity between the two SW valve rooms and will maintain the same SW header separation.

Preventative Steps Piping failures are considered improbable. All the original carbon SW piping has been replaced in the last - 10 years with AL6N, or other corrosion resistant mate-rials.

As a clean water system with moderate flow velocities and minimal throttling, cor-rosion and erosion are minimized. The system will operate at a lower pressure, approximately 100 psig or about 50 psig below the present operating pressure, and half of the design pressure.

Care was taken to minimize the possibility of damage to the equipment outside the SR buildings. The majority of the CFCU Chilled Water System piping is routed on the outside walls of SR building at - 120' (20' above ground level). The pumps and demineralizer are located inside the FHB annex, a concrete building.

The air-cooled chillers are fenced in.

More recently, the major sources of leaks have been at the CFCU's gasket for the CFCU air cooling HX channel head. Cooling with clean water eliminates the Page 34 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 l need for GL89-13 inspections that require periodical removal of the HX heads.

Refer to section 2.10 for discussions on improved sealing.

Another problem has been failures of the motor cooling tubesheet due to corro-sion at the tube to tubesheet crevice. During anticipated modes of operation, the motor cooler HX's will also see less corrosion and erosion.

On-Line SR Pining Repair Capability:

The design only assumes 3 CFCU's for normal cooling, but it will maintain con-tainment temperature < 11 0F even with 2 CFCU's. Although the CFCU CH Sys-tem design is a single loop system, the single loop branches into two supply and return lines in the SW valve rooms. This allows continued operation of the CFCU Chilled Water System even after isolating any CFCU branch line or many por-tions of the common safety related CFCU supply and return headers to effect re-pairs. In most cases, operation of three CFCU's can be maintained. Removal of a SW52 or SW78 valve would require limiting operations to 2 CFCU's.

l Retain 11-13 CFCU I Retain all but 13 CFCU 12 SW Supply \i\ u West 15 CFCUValve

~

125W2  :~.Room 12W5 1SW212SW78

________ 12SW72 11SW78 East c~12 CFCU VaRoom 11 SW Supply Rtin 13-15 CFCU The CFCU CH supply and retumn flow paths are not redundant with the exception of the active components. The valves are discussed in Section 1.3.4. A failure of piping in a clean, low pressure (100 psig), close loop system is considered highly unlikely. The portions that are safety related, and may see SW in an abnormal or DBA condition, are fabricated from AL6N that has proven highly resistant to SW corrosion.

1.3.9. CFCU CH System Operation at Extreme Cold Weather The chillers and some piping are located outside of buildings; however, to mini-mize exposed piping, piping will be run through the FHB truck bay rather than around the FHB. The pumps and the filter/demineralizer are located in the FHB Page 35 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l annex. This area is heated, and in addition, the pump motors will add heat to the space.

Insulation is required to minimize heat gain in the summer. This insulation will be credited for minimizing heat loss in the winter. The design must determine the optimal insulation thickness to minimize heat gain/heat losses.

The CFCU CH System will operate year-round since the containment heat load is not significantly impacted by outside temperature. Normal operation will keep the recirculated fluid above freezing in the wintertime, but the following will be ad-dressed:

1) The isolation valves for the individual chiller evaporators will be placed at the main headers. If an evaporator has to be isolated in the wintertime, the isolated portion can be drained and the stagnant portion will be negligible length (and remain at main header temperature).

2) Freeze protection of any dead legs and instrument lines exposed to freez-ing weather. External dead legs and external fluid filled instrumentation should be minimized.

3) The evaporators (water side HX) on the chillers include Vendor insulation and heat trace and vent and drain valves.

To address the possibility of a forced, winter outage, with no heat load from the containment, the detailed design will verify that one pump will add sufficient heat/pump work into the main headers to prevent freezing. Refer to section Error! Reference source not found. for a preliminary assessment. In case the flow path to the containment must be isolated in the wintertime, the recirculation path must be opened to allow the pumps to be operated.

The chillers are able to continue to operate in cold weather. Vendors have stated that the cold weather limitation is on "cold start" of the chiller rather than on con-tinuous operation in cold weather. If the chiller is off and the refrigerant cools down to during the low ambient, e.g., 0F, it may not restart. To address this, an option should be included to provide a heater for the refrigerant.

The Vendor/DCP must also document "freezing rain", defined as rain which freezes on contact and causes ice coating. One potential vendor has stated that freezing rain is not a concern since the condenser coils are well above freezing temperature.

1.3.10. SW Inadvertent Initiation During Normal Operation Cooling water to the CFCU's has been designed to minimized inadvertent initia-tion of SWS into the clean CH system by:

1) The normally-closed, fail-closed isolation valves will not inadvertently open as a result of either power failures or pneumatic supply failures.

2) The SW isolation is provided by in series valves. This reduces the prob-ability of an error during testing and/or maintenance from opening a flow path.

Page 36 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04

3) Summarized below are the SI's since 1984. Although Si signal initiation has been reduced in the last 10 years to once per 10 reactor-years, the probability of SW contamination of the CFCU's can be further reduced by blocking the Si signal to these SW valves in modes 5, 6 and undefined.

Mode 6 accounts for 3 of the 9 SI's since 1984 and 2 of the 3 since 1990.

Date Mode Unit Cause (as documented in LER's) 7/13/84 6 1 Personnel error (omitted testing step).

7/25/84 1 2 POP's (PR47) failed open during testing (Valve since removed).

10/7/85 1 2 Vital bus spike, during testing (vital bus recepta-cle polarity wired wrong).

8/26/86 1 2 Technician inadvertently shorted the vital bus.

6/22/88 1 2 2C Vital Inverter failure caused RCP breaker to indicate "open"; unit tripped (this trip since re-moved).

6/09/89 3 1 Inadequate draining of MS lines causing MSV Lifting during plant start-up.

5/01/90 6 2 Personnel error performing DCP wiring changes.

4/15/93 6 2 Si during testing due to SSPS switch design de-fect.

4/07/94 1 1 Circ water rack debris blockage followed by fail-ure to maintain command and control, commu-nications, and priorities at Control Room.

1.3.11. System Flush Following SW Actuation The assumptions herein are the CH side was automatically or remote-manually isolated prior to the SW initiation and that it remains isolated and clean while SW is used for containment cooling.

The purpose of flushing the CFCU side of the system is to minimize the introduc-tion of river water impurities into the carbon steel CH piping and chiller copper tubing.

After the CFCU SW valves can be isolated but before the CH AOV's are opened, the CH side will provide the "feed" water to rinse out the CFCU piping by placing the CH pump in recirc flow and providing DM make-up to the head tank. The 2-inch flush lines in each SW supply and return header are opened to provide a "bleed" path until a reasonable water quality is reached. The supply header side will require much less flush water than the return header because of relative lengths. To minimize the amount of water that has to be drained into the SW valve rooms, the "bleed" path can be to the SW return headers as illustrated be-low. The return header is at very low pressure.

Page 37 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 It is estimated that the water volume in the CFCU side of the piping (that is, the volume that needs to be flushed out) is - 10,000 gallons including 5 CFCU's. As-suming a 50 gpm feed/bleed rate, it would take just under seven hours to do a two volume (20,000 gallons) flush.

Once the majority of the river water contamination has been purged out of the CFCU HX and piping, the CH system can be returned to service. The small amount of remaining impurities will not result in a significant level of impurities on the CH side. In addition, they will be removed over time by the resin in the per-manent CH side stream demineralizer.

SW Su I Header SW Return Header Hose vie Flush Path A Closed Open Open ,r1.fPiDing to CFCU. IClosed Chilled Water Flush Page 38 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 l 1.4. DBA Operation On a DBA, a SI signal will automatically isolate the normally open CH air-operated isolation valves to "bottle-up" the CFCU flow path and then will auto-matically unisolate the normally shut valves on the SW CFCU flow path (section 2.3.1).The sequencing and permissives ensure that the CFCU's remain full of water and pressurized during the transfer from CH System cooling to SWS cool-ing. This sequence, the safety related accumulator, and elimination of SW57 all minimize the pressure fluctuations on the CFCU. The CFCU CH system operates at 110 psig, the accumulator prevents any significant pressure transient, and the SW system pressure will be - 10 psig lower than the chilled water pressure.

If SW was initially in service for cooling the CFCU's, a DBA without a LOP will not cause any flow interruption. Protection on a concurrent LOP against water ham-mer and two phase flow is provided as discussed in Section 2.3.2.

The design ensures that full CFCU SW flow is established within 60 seconds of a DBA. This delay allows initiating the SW flow only after the SW pumps have re-started and the SW flow to non-essential services, e.g. Turbine Building loads, is fully isolated. The accumulator will ensure that the fluid within the CFCU's re-mains pressurized and sub-cooled during the CFCU CH System isolation, SW pump restart, and SW valve flow path opening16.

The CFCU CH System cannot be used for containment DBA cooling even if it remains available post-DBA since the initial containment heat load will cause the chillers to trip out. On a SI Signal the CFCU CH System isolation valves will shut and the CH pumps and chillers will be tripped.

SW flow to the individual CFCU's can be verified by flow indication on the outlet of each CFCU. No flow control valves or modulating valves are used. SW flow is set by fixed resistances. Although the DBA analyses only credits 1200 gpm to each of two CFCU's for heat removal, a significantly higher SW flow is expected.

No credit is taken for any heat removal by the CFCU branch without an operable fan, even though SWS flow is provided.

The system design allows (1) one SW header to fail (i.e. only the 11(21) or the 12(22) headers are assumed to open and initiate SW flow), (2) one CFCU CH System AOV valve fails to shut, and (3) one CFCU CH System check valve fails to shut.

The design incorporates the following licensing basis:

1) Per GDC 17, the a failure of the DC battery is considered a SACF

2) A LOP is considered simultaneously with a DBA (Although a LOP need not be considered after a DBA, the ohysical design for the new system will 16 Check valves on the supply side are credited with immediate closure. In series AOV's on the return side are credited with losure in 3 & . There should be not water loss during the isolation if the non-SR portion remains intact.

Page 39 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 tolerate a LOP anytime the SW system is in use for the reasons discussed in section 2.3.2.

The SW hydraulic model assumes the most limiting conditions. The cases con-sidered are one header providing cooling water to 3 CFCU's and both headers providing cooling water to all 5 CFCU's. Note that check valves SW52 and SW77 prevent the flow from either header from exceeding the flow for 3 CFCU's.

The CFCU containment isolation valves meet GDC 57, closed system inside con-tainment that is required post-DBA. They are shut only if the Operator detects a breach of the piping integrity inside containment. The present containment isola-tion valves and controls for each CFCU can remain as presently designed.

The capability of the operators on these containment isolation valves (SW58 and SW72) to operate under the new system maximum postulated AP is under re-view.

1.4.1. Active Comnonent Failures The two tables below are a simple FMEA to address the key SACF. It shows that 3 CFCU's remain available for containment cooling and iodine scrubbing after any postulated power failure or any header isolation valve failing to open, assum-ing 5 CFCU's were initially "Operable".

Equipment Remaining Available after Electrical Failure 12,13,14,15 CFCU Train A, AC or DC, Fails B & C SW pumps 11 & 12 SW flow path 11,13,15 CFCU Train B, AC or DC, Fails & C SW Pumps 11 & 12 SW Flow path 11,12, 14 CFCU Train C,AC or DC, Fails A & B SW Pumps 11 & 12 SW Flow path Based on the existing design, a loss of DC will prevent the corresponding diesel from providing back-up power in case of a LOP. A loss of a diesel on a LOP will result in a loss of one SW pump and the one or two CFCU's powered from that vital bus. Since the SW CFCU header AOVs have redundant solenoids, each powered from a different DC source, no single AC or DC failure prevents opening and then keeping open both headers (See section 3.3 paragraph 1).

Page 40 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 Equipment Remaining after SW Header Fails to Open (Due to Valve Failure) Or Is Later Isolated 13,14,15 CFCU 11 SWFails A,B&CSWPumps 12 SW flow path 11,12,13 CFCU 12 SW Fails , BP & C SW Pumps 11 SW Flow path Since the revised Westinghouse containment evaluation and the AST design ba-sis both only credit two CFCU's post DBA, the tables also demonstrate that only 4 CFCU's will need be "Operable" at any one time once the AST is approved. In essence, the fifth CFCU will become an installed, redundant CFCU.

1.4.2. Passive (SW Piping) Failure UFSAR SW section 9.2.1 states:

"Failure of one of the nuclear supply headers downstream of the tie valves in the Auxiliary Building will not interrupt the supply of service wa-ter to the equipment required to operate following a LOCA. Each of the two service water loops provides service water to one component cool-ing heat exchanger, one charging pump lube oil cooler, one safety injec-tion pump lube oil cooler, and three containment fan cooler units."

A similar statement also appears in section 6.3 as well as the original SER for Salem provided by the NRC. PSEG licensing has compiled clarifications on this statement. These clarifications are that a SW passive failure is limited to leaks, as opposed to pipe breaks, and furthermore these leaks need not be postulated any earlier than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the DBA, and this passive failure is in lieu of postu-lating a SACF.

The design and licensing basis for SW leaks in a DBA will not be changed. Isola-tion of either header will not prevent the opposite header from providing cooling to three CFCU's. Isolating a SW header is the same as a SW not unisolating, re-fer to the table for section 1.4.1. Even with only 4 CFCU's initially "operable", a minimum of two will continue to provide cooling. Sensitivity analysis performed by Westinghouse demonstrated that only one CFCU is required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into a DBA (however, this sensitivity analysis is not being used to modify the licensing basis).

Page 41 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l

2. DESIGN REQUIREMENTS 2.1. Maior CFCU CH System Components per Salem Unit

1) Four packaged nominal rating of 400 cooling tons capacity, electrically-driven, air-cooled water chillers complete with controls and logic. Each provides -37% of required cooling. This allows 3 chillers to meet 100%

load with an added 10% margin.

2) Four 50% capacity centrifugal pumps, design flow of 1200 gpm each.

3) Power from the "G" and SE" non-vital 4160 VAC buses to two 480 VAC CH System substation. Each substation supply is rated for 2500 KVA and each switchgear is rated for 3200 amps.

4) Local control panels with control room indication, controls and trouble alarms

5) One Accumulator (formerly the 12(22) SW Accumulator)

6) One Head Tank (formerly the 11(21) SW accumulator)

7) A 50 gpm cleanup system consisting of filters and mixed-bed demineral-izers,

8) Automatic valves to isolate the CFCU CH System and unisolate the SWS during a DBA.

9) Associated piping, valves, orifices, instruments and controls.

2.2. Key Desiqn Parameters Key parameters derived in separate documents are summarized in the Table on page 8. These parameters are from References 7.1, 7.2, 7.3, 7.4 and 7.5.

The key parameters for accumulator and head tanks are summarized below.

2.2.1. Accumulator Design Parameters The basis/logic for the key accumulator tank parameters is outlined below. The adequacy of these parameters for accident conditions will be discussed in sec-tion 2.3.

1) Normal CFCU Chilled Water System operating pressure immediately downstream of the SW Supply headers (point "A"on the pictogram in sec-tion 1.2.2) is to be controlled between approximately 105 psig and 110 psig. This allows operating the clean water system at 5 to 10 psid higher than the SW supply pressure to reduce the potential SW leakage into the clean system (Across the normally shut SW AOV's to the CFCU branch lines).

Note: 110 psig was selected using the best estimates from SW pump de-staging and hydraulic runs. These values may be adjusted after further calculations and testing is done to reflect actual values. If destaged SW Page 42 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l pump performance is better than anticipated, the accumulator gas pres-sure will be adjusted upward to maintain the desired range at point "A".

2) Due to redundant, reasonably fast isolation valves in every flow path, the maximum anticipated outflow from the accumulator is - 1000 gallons

3) Since the normal water volume will be between 8,000 and 12,000 gallons, the final water volume will be - 7000 gallons. This provides assurance that no significant amount of N2 will not be introduced into the CFCU headers.

4) The nominal gas pressure will be - 80 psig.

2.2.2. CH Head Tank Design Parameters The head tank N2 gas pressure required to support the nominal 110 psig chilled water system supply pressure is - 65 psig assuming the water level is at its minimum recommended level, 8000 gallons.

Note: these values are selected assuming friction losses from Reference 7.3.

These values may be adjusted after further calculations and testing is done to reflect actual friction losses. If friction losses are less than calculated, the head tank gas pressure will be adjusted downward to maintain the desired range at point 'A'.

Operation at head tank pressures in excess of the above values will only result in a higher CFCU Chilled Water System operating pressure and higher accumulator pressures. The limiting components are (1) the CFCU waterbox with a design pressure of 150 psig and (2) the accumulator head tank with a design pressure of 150 psig. The piping is designed for 200 psig. Since the accumulator is at a lower elevation and closer to the CH pump discharge, it is the limiting compo-nent.

An objective is to keep the accumulator pressure < 135 psig (10% below the re-lief valve setpoint of 150 psig) to prevent the relief valve from lifting. To do so, the head tank gas pressure must be maintained at 135 psig minus the pressure rise between the two tanks. The pressure rise is the CH pump head minus friction losses between the two tanks, 134.7' - (15.6' + 35.1') = 84', or 36 psid. Rounding off, the head tank relief valve should be set at no greater than 100 psig.

2.3. GL 96-06 Design Requirements During the period that the CFCU's are isolated, relief valves vent any thermal ex-pansion to prevent over-pressurization of the isolated piping. A relief valve is physically on located on each CFCU branch line between the CFCU and the CFCU downstream containment isolation valve. These valves are described in Section 3.1, paragraph 18.

Concerns identified in GL 96-06 (reduced heat transfer due to boiling water and hammer loads due to water column separation) are prevented by maintaining the CFCU lines completely full and sufficiently pressurized during any flow interrup-tion including (1) stopping and restarting CH cooling (2) transfer from CH to SW Page 43 of 64

lSystem Description CFCU Chilled Water System Rev 2 04/04/04 flow (3) stopping and restarting SW cooling. Reference 7.4 demonstrates that the revised design satisfies the GL 96-06 concerns.

2.3.1. Postulated Transients - CH System Initially in Operation The CFCU CH System normally has the only open flow paths to the CFCU's. All SW flow paths are normally isolated. Maintaining the CFCU piping water solid during normal operation is achieved by the CFCU CH closed loop system includ-ing the accumulator, head tank, and demineralized water make up. Closed loop cooling with clean water reduces the probability of small leaks, and it allows quicker identification of small leaks. Stopping and then restarting CH flow during normal operation should not pose any GL 96-06 concems.

CH System Piping Failure due to Natural Phenomena:

Switching from CH water to SW does not require any accumulator outflow unless there is a CH system pressure boundary failure.

Since a portion of this closed loop system is non-SR and located outside the rein-forced SR buildings, a loss of CFCU CH system integrity is postulated due to a seismic event or other natural phenomena. To mitigate the consequences of such a failure, the non-SR portion is isolated:

1) On the supply header by in-series, check valves that shut on reverse flow.

2) On the return header by in-series, automatic AOV's. The automatic clo-sure signals for the CH AOV's are discussed in Section 2.7.2. These valves are designed "fail-shut".

Loss of fluid is postulated only during the time delay to initiate closure and then complete AOV closure on the single 10" diameter line CH return header. As shown on the pictogram in section 1.2.2, the SR, seismic 1 criteria for the return line is extended outside of the buildings upwards to elevation 120'. This location is immediately adjacent to and protected by the same missile barriers that were erected for the accumulators. The head tank is likewise protected against exter-nal missiles. The pressurized head tank located downstream of the return header AOV's provides a backpressure that minimizes the flow out of the AOV's during the transient. -

The design still requires one accumulator to make-up for any water losses while the CH System isolates after a pressure boundary failure. However, the required accumulator outflow volume is significantly reduced in comparison with the origi-nal design.

SW unisolation requires that (1) there be no vital bus UV signal present and (2) that the SW supply header is pressurized. Then, the SW supply header valves are opened first to pressurize the CFCU headers with the SW pumps before the SW return header valves are opened. This sequence, along with one accumula-tor tank, ensures the CFCU piping remains pressurized throughout the transition to SW flow.

Page 44 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 DBA:

The CH System is automatically isolated on a Si signal since it is not a SR sys-tem. Since a seismic event and a DBA are not postulated simultaneously, there is no loss of water from the CFCU during the isolation phase. The SW sequence, described above, ensures that the SW supply header is open before the corre-sponding return header begins to open.

After the CFCU headers are isolated, the fans continue to add heat to the stag-nant fluid in the CFCU tubes. The final temperature of this "hot slug" will be above 2120F but below the peak containment temperature. Boiling is not antici-pated because the CFCU piping is isolated, water solid, and the heating transient should maintain the water solid piping pressurized. The opposite, overpressuriza-tion, is the concem. The relief valves should limit the pressurization to the relief valve setpoint. The relief valves will reseat well above the saturation pressure of the fluid. The single accumulator is not critical for keeping the CFCU pressurized and subcooled, but it adds another level of defense.

The release of the "hot-slug" into the low pressure SW outlet header when SW is initiated is addressed analytically. The hot-slug is significantly mitigated by the lower CH operating temperatures.

2.3.2. Postulated Transients - SW System Operation A GL 96-06 evaluation was performed to address the possibility of SW being in operation prior to a postulated DBA. The transients of concern are a LOP by itself and a DBA with a concurrent LOP. The accumulator is required (1) to maintain the piping water solid following a LOP and (2) to maintain the fluid in the CFCU pressurized for a DBA concurrent with a LOP.

A DBA without a concurrent LOP will not interrupt SW flow and therefore there is no water column or two phase flow concern.

To provide protection from a LOP, the SW system flow paths to and from the CFCU's are automatically isolated by vital bus UV signal or by a loss of pressure in the corresponding supply header.

The principal changes to the GL 96-06 evaluations are:

1) Reliance on a single accumulator (but no AOV's that must open)

2) Crediting of in-series fail-shut AOV's so that the required make-up from the accumulator is limited to the water losses before full closure. In addi-tion, the SW supply header has a check valve to prevent backflow.

The CFCU SW valves are "fail-shut" to prevent a DC bus failure from opening the SW headers (see section 2.6).

The Salem DBA licensing basis only requires that the LOP be assumed concur-rent with the DBA. Nevertheless, the control logic isolates the SW flow paths to the CFCU's, if open, any time power to the vital buses are lost. This design fea-ture, along with the check valve on the SW CFCU supply header, provides a greater degree of reliability for the CFCU's in the longer term, post DBA cooling.

Page 45 of 64

I System Description CFCU Chilled Water System Rev 2 04/04/04 However, it is strictly a system design enhancement, and there is no intent or commitment to revise the Salem licensing basis to postulate LOP following a DBA event.

The potential for flashing of the "hot-slug" at the SW return header is addressed analytically.

2.4. GL 89-13 Requirements Normal CFCU CH System operation with demineralized water ensures minimal fouling and improved CFCU thermal performance. Refer to section 2.5 paragraph

2) for credited fouling.

Routine CFCU cleaning and performance monitoring in accordance with Generic Letter 89-13 will no longer be required. This change needs to be reflected in the appropriate program and revised NRC commitments.

The design allows for periodical flushing of the dead legs above the normally shut SW AOV's, and during a SW header outage, inspection to ascertain and remove any build-up of marine growth that may not flush out (section 3.1, para-graph 13).

2.5. Containment Accident Analysis Requirements The revised Westinghouse analyses made several key assumptions. Key as-sumptions include:

1) A cumulative heat transfer rate of 112.8 x 10E6 Btu/hr from the contain-ment atmosphere at the post-accident design conditions, i.e., a saturated air-steam mixture at 47 psig and 271'F.

2) The required cumulative heat transfer is based on 2 CFCU's assuming a fouling factor of 0.0015 (Addenda 1 to reference 7.2 demonstrates that 3 CFCU with maximum fouling from long term SW operation will provide greater cooling than 2 CFCU's with 0.0015 fouling).

3) Rated CFCU SW flow is achieved by t=100 seconds (the design is how-ever based on meeting the present Tech Spec requirements of 60 sec-onds).

4) SW cooling is initiated by the Si signal.

5) Initial containment temperature < 120OF

6) MSLB will credit SGFP trip to reduce feedwater flow if the single failure is a stuck open feedwater regulating valve (this is not a design change; it is only incorporating a Salem design feature that was previously not cred-ited).

7) A passive failure in a CFCU header during the long term phase of a DBA

(> 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) may require isolation of one SW header.

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I System Description CFCU Chilled Water System Rev 2 04/04/04 _

2.6. SW and CFCU CH System Valves Fail Position The failure position for all the CH AOV's and the new CFCU SW header isolation valves is 'shut" to support the GL 96-06 evaluation (section 2.3).

The fail shut mode for the CH valves ensures that these valves isolate and re-main shut on a DBA when the SI signal is received. Since the AOV's have a re-dundant flow path, a spurious failure should not cause inadvertent loss of CH cooling.

The fail mode for the SW valves was selected to ensure that a failure of the DC bus coincident with a SI signal (required by GDC 17) would not cause premature opening of the return lines before the SW pumps restart. This is required to en-sure that the CFCU piping is not partially drained and then subject to water hammer when the SW pumps restart.

The design of the SW valves prevents having to postulate both headers failing to open. Refer to Sections 3.3 paragraphs 1) and 2) for additional information on the l&C design features for these valves to minimize failures.

2.7. SW & CFCU CH Valves. CH Pump. and Chiller Control Signals 2.7.1. SW CFCU Valves See Figure 5 Typical SW Supply Header AOV's Control Logic and Figure 6 Typical SW Return Header AOVs.

The following automatic SW CFCU valve signals are required:

1) On a vital bus undervoltage (UV), shut and/or prevent opening the CFCU SW inlet and outlet header isolation valves. This is required to satisfy GL 96-06 for a LOP that occurs:

• If SW is used for CFCU cooling after a total CH System failure (sec-tion 1.3.7).

• During a DBA alignment.

• After SW is aligned for DBA cooling (section 2.3 paragraph 0).

2) On a loss of SW header pressure, shut and/or prevent opening of the cor-responding CFCU SW supply header isolation valves. The primary pur-pose is to prevent opening of the SW supply header valves after a SI con-current with a LOP until the SW pumps have restarted and restored header pressure. It also addresses the header being tagged out.

3) When the above conditions are met and the CH valves are shut, sequen-tially open the CFCU SW valves on a SI Signal. The SW inlet valve is opened first. When the SW inlet valve is -90% open, the SW outlet valve then opens.

The design automatically initiates SW cooling on any SI except that the signal may be blocked in modes 5, 6 and undefined to avoid inadvertent and undesired SW initiation when not required for plant safety as discussed in section 1.3.10.

Page 47 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l The design allows opening and closing any CFCU SW valve from the control room. This allows for testing one valve at a time for quarterly valve IST.

The signal to manually initiate SW system flow is in parallel with the Si signal.

This is done to ensure that a manual SW initiation meets the same requirements as automatic SW initiation. The primary difference is that the SI signal automati-cally shuts CH whereas a manual SW is blocked until the Operators shuts the CH isolation valves.

The design needs to ensure that the proper SW isolation sequence can be done to prevent inadvertent accumulator discharge. Specifically, the SW return header should be isolated first. Then the SW supply header is isolated.

Caution: If SW system is providing cooling to the CFCU's during normal power operation, only a LOP will automatically isolate the CFCU SW flow path, but a LOP will also trip the high speed fans. For non-automatic transients, e.g. Opera-tor controlled shutdown of SW flow, Station procedures/training should clearly alert the Operators to trip the fans before securing SW flow to that fan since mo-tor cooling is lost.

2.7.2. CH System Valves Refer to Figure 4 Typical CH AOV, page 14.

The CH valves must automatically shut on any of the following conditions:

1) On a SI signal

2) UV on the vital buses (preventative since it is highly likely that the group buses are also affected).

3) The CH discharge header pressure dropping significantly below the antici-pated operating pressure. This is indicative of a pressure boundary failure, pump failure, excess make-up to the SR portion of the design (e.g., leak in the CFCU gasket), or loss of power to all operating CH pumps.

Isolation on low pressure provides protection against a catastrophic pipe break. If the suction is on the suction side of the pumps, the pumps will trip from loss of NPSH or water. If the break is on the supply header, the supply header will de-pressurize. Either way, there will be a significant pressure drop on the supply header. The more likely scenario is a failure that leads to a leak. A tank low wa-ter level alarm and/or low supply header pressure will then alert the Operators. A single CH pump trip will cause the supply header to drop by approximately 10 psig. The resulting pressure remains well above the automatic isolation setpoint.

The CH valves can only be opened if none of the above signals are present, and in addition, the SW supply header isolation valves are shut.

The CH valves will fail shut on a loss of control power or control air since they are fails shut design.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 There are two CH open/shut push buttons in the control room. One operates the two in-series valves from the 11/12/13 CFCU return. The other operates the 13/14/15 return path. Normally, only one path is open to limit CH flow to three CFCU's. However, both flow paths may be open to establish and confirm the flow in the second flow path before isolating the first flow path. Once containment cooling is confirmed on the second flow path, the first flow path should be shut.

Operating with both flow paths open will not result in an unsafe or unacceptable condition. However, the CH flow to the three operating CFCU's will be reduced from 800 gpm to approximately 550 gpm (estimated) and containment tempera-ture will be approximately 70F (estimated) higher. Containment temperature will remain well below the allowable value.

Closure of a CH return path automatically trips the CFCU high-speed breakers for the two CFCU's cooled exclusively by that circuit. The 13 CFCU high-speed breaker is not tripped unless both CH cooling paths are isolated. The tripped sig-nal is not locked-in. This allows the CFCU's to be restarted on SW flow.

An existing SI signal will also trip the high-speed breakers.

Caution: Station procedures/training should clearly alert the Operators to trip a CFCU that has no cooling flow since motor cooling is lost.

2.7.3. CH System Pumps The CH water pumps will automatically trip following a CH valve automatic clo-sure. This signal need not be safety related since its sole function is to prevent the pump from running in a deadhead condition. A trip signal shall not be locked-in. This is to allow restarting the CH pump with the recirculation flow path open.

The chiller control panel will control pump operation. Since check valves are pro-vided in each pump's individual discharge path, the suction and discharge valves can be kept open for the standby pump. All manual butterfly valves shall have clear "open" and 'close" indication. On a low flow or indication of a pump failure, a back-up is automatically started. A signal from the high-low flow switch located in the common discharge header of the pumps indicates that the system flow is abnormal. This signal alarms locally and causes a general trouble alarm in the main control room.

2.7.4. CH Chillers The Vendor will provide all controls for maintaining the chiller outlet temperature at the desired LCWT setpoint (400F to 601F range). The chillers require a flow switch in each chiller branch line. This trips the chiller if there is no-flow in that branch line. This need not be safety related.

2.8. In-Service Testing Requirements All safety related valves that must change position in an accident have redun-dancy to allow for testing without impacting the normal operation of the system.

The CH AOV's and check valves have redundant flow paths as described in sec-tion 3.1 paragraphs 14) and 15). This allows the valves in one flow path to be Page 49 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 l tested for closure. If a valve fails to shut, it can be isolated and removed for re-pairs. The redundant flow path allows the CFCU CH system to remain in service.

Each SW CFCU supply and return header has redundant, in-series AOV's as de-scribed in section 3.1 paragraph 13). This allows the valve to be tested for open-ing without initialing SW flow to the CFCU. This, of course, is predicated on test-ing each valve separately.

2.9. SW Pump Destacjinc Requirements The present requirements for SW pump head is due to the CFCU flow require-ments of 2500 gpm in a DBA coupled with having up to 5 CFCU's post-accident.

The reduction in accident flow/CFCU allows the SW pumps to be destaged from 3 to 2 stages since it eliminates the CFCU as the dominant pressure loop. All normal and accident flows can be met with a 2 stage SW pump.

Destaging the SW pumps is desirable in order to reduce the SW pump electrical power consumption during normal and postulated accident conditions and to lower the SW supply header operating pressure from approximately 150 psig to 100 psig. Since the SW system piping design pressure is 200 psig but a number of SW components have a design pressure of 150 psig, this will provide a significant safety margin. Destaging will require:

1) Physical modification of the SW pump. The simplest method is to remove the last (third) stage and replace it with a spoolpiece with bearing at the same location as third stage bowl bearing.

2) Pump destaging will require destaging all SW pumps for that unit within the same outage. Refer to Section Errorl Reference source not found.

for Outage Planning concems.

3) Upgrading the SW hydraulic model to include a model of the non-nuclear header and then changing the configuration to reflect:

• Reduced pump head (-66% of previous TDH)

• Revised CFCU flows (0 during normal operation and - 7500 gpm total to 5 CFCU's in DBA)

• Revised constant 700 gpm SW strainer backwash

4) Reviewing and revising, as necessary, fixed and variable resistances in all the individual branch lines to determine any changes due to the lower pump head.

5) Reviewing and revising, as necessary, all l&C setpoints that use SW pres-sure as an input.

6) Updating the EDG/vital bus loadings to credit the reduced SW pump Hp requirements.

7) Verifying that the peak diesel loading remains below the continuous allow-able diesel loading (2600 KW), allowing elimination of testing for the 2 Page 50 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 hour and 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> maximum allowable, 2860 KW and 2750 KW, respec-tively.

8) Updating any diesel testing procedures to reflect that the largest single load, the SW pump, has been reduced from 1000 Hp to - 666 Hp and is comparable to the second and third largest loads, the C/SI pump and MD AFW pump. This should be reflected in a quicker frequency and voltage recovery during diesel loading and unloading.

2.10. CFCU Water Box Coating. Sealinag, and Minimization of Leaks The CFCU project scope does not include any modifications to the CFCU water box coating and sealing since these are O&M items. However, it is discussed herein since this a Station concern.

The preliminary assessment is that the tubesheet should continue to be coated as a precautionary measure since crevices tend to accumulate any impurities.

This decision should be finalized by Station and Engineering Design personnel.

However, the coating in the rest of waterbox is unnecessary, and explained be-low, undesirable.

Since the coating is not even, it causes uneven compression of the gasket as il-lustration of the top view showing the components prior to assembly shows. It may be a key contributor to the waterbox leakage problems. Removing the coat-ing on the cover plate and spacer (at least in the mating surfaces) will provide more uniform gasket compression. Removing the coating on the spacer, but not the tubesheet, will provide an even surface on one side of that gasket which nev-ertheless should provide greater sealing reliability.

Coveraalateawith nozzles lMax gasket Soacerl compression _

Minimal gaskt Tuben Shee~t WAlm IcompressionI In addition to allowing the above improvements in sealing, the design minimize the probability of leaks across the gaskets since it (1) will lower the differential Page 51 of 64

[System Description CFCU Chilled Water System Rev 2 04/04/04 l pressure across the sealing surfaces to 2/3 of the present value, and perhaps more importantly, (2) it will greatly reduce the pressure surges. During normal operation, no pressure surges are anticipated since it will operate at constant pressure constant flow. Even if the pumps are all tripped, the accumulator will maintain the pressure essentially unchanged.

Pressure fluctuations during transition to SW flow are also reduced since the flow control valves are eliminated. The CFCU's will first be bottled up by closure of the CFCU CH AOV's and the accumulator will maintain the CFCU's at essentially the same pressure. The SW supply header valves are sequenced to open only after the SW pumps are restarted and SW pressure has stabilized. The SW pressure will be about the same as the CH pressure.

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ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l

3. DISCIPLINE DESIGN REQUIREMENTS This section is primarily a repetition of information from other sections broken down by engineering discipline but with added details.

3.1. Mechanical

1) A constant nominal flow of 2400 gpm chilled water at 400F to 600F supply tem-perature is to be provided by the CFCU CH System to three CFCU's. Each CFCU cooling coil will have approximately 780 gpm and each CFCU motor cool-ing coil will have about 20 gpm.

2) Cooling is provided by four (4) 400 ton nominal capacity, air-cooled chillers.

Since the required containment cooling load is 1074 tons, and each chiller can provide 380 tons even with 105OF ambient outside air, each chiller is rated slightly in excess of 1/3 of the required load. Once the chillers are selected, curves should be provided to show chiller capacity (in cooling tons) versus LCWT and outside ambient air. This will be used to determine any limitations when op-erating with two or three chillers.

3) Chilled water is to be circulated by four (4) 50% capacity centrifugal pumps rated at 1200 gpm each powered from non-vital buses. Automatic pump controls will be kept to an absolute minimum due to the simplicity of the design.

4) The majority of the CFCU CH System, which includes the chillers and CH pumps, shall be non-safety related. Piping will be carbon steel. This piping need not be seismic, but since this non-SR CFCU CH System piping, except the piping on the pad will be supported from SR buildings, the detailed design should de-termine if the piping will resist a seismic event based on SQUG criteria, and/or if the break can be limited as opposed to having to assume a full guillotine break.

5) All other portions of the CFCU CH System, which includes all portions that will be part of the SW pressure boundary following a DBA, will be designed to the same criteria as the present SW piping (Seismic Category I, Safety Class 3). This in-cludes the isolation valves which isolate the non-safety related CFCU CH Sys-tem. All safety related portions will comply with existing SW piping material re-quirements.

6) All safety related piping and components will be designated as "SW" and shown as part of the SW system P&ID. This includes the CFCU CH System isolation valves. All non-safety related portions will be designated as "CH" and shown on the CH system P&ID, but on a separate sheet.

7) Corrosion control will be maintained by keeping a N2 blanket on the CFCU CH System head tank and by maintaining water quality through intermittent use of a mixed bed demineralizer, or for significant SW intrusion events, through feed and bleed followed by use of the demineralizer. To reduce the need to backwash the demineralizer due to non-soluble loading, the demineralizer flow should first pass thru a mechanical strainer/filter. Joint between carbon steel and AL6N will be a flanged joint and include "Maloney" kits.

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I System Description CFCU Chilled Water System Rev 2 04/04/04 l

8) Under normal operating conditions, the CFCU CH System pressure will be main-tained a nominal value (about 10 psid) higher than the normal SW supply header pressure. As discussed later, the normal SW system pressure will be approxi-mately 66% of present pressure since the SW pumps will be converted from a 3 to a 2 stage pump. This requirement is to minimize the possibility of SW to CFCU CH System 'nuisance" leakages. Short-term operation with higher SW pressure due to unusual line-ups is acceptable.

9) Two new 12" SWS AOV butterfly isolation valves in-series on each SWS supply header in addition to retaining one testable check valves. These new valves are seismic category 1,safety related class 3, normally closed, fail shut valves that are automatically opened upon SI initiation or manually opened from the control room to supply SWS to CFCU's during accident conditions.

10)Two new 12" SWS AOV globe valves in-series on each SWS discharge header are seismic category 1,safety related class 3, normally closed, fail shut valves that are automatically opened upon SI initiation or manually sequenced opened from the control room after SWS supply header valves are fully opened under accident conditions.

11)Since the SWS isolation valves are normally shut and fail shut, the hydraulic analysis must account for one of the flow paths failing to open.

12)AII new AOVs will be butterfly valves. The valve body will use the same design concept as the existing SW accumulator isolation valves, SW534 and 535 valves.

The valve body will be carbon steel but is entirely rubber lined. This provides ex-cellent leak tightness and it also protects the valve body. The disc will be se-lected from corrosion resistance materials.

13)The two in-series isolation valves on each SW CFCU supply and return line, de-sign features on the individual AOV's, and additional manual valves allow:

SW Header Flanged Inspection Port Dead Leg - Debris Clean out NC, Outboard Isolation Tell-Tate Drain NC, Inboard Isolation Flush Chilled Water Side

• A greater leakage barrier between the SW system and the CFCU CH System.

The valves shall be rubber seated to provide greater leakage tightness. Metal seats are not required since these valves will not see SW flow except in a DBA, and leak tightness is not then required. In addition, metal seats would require larger operators that would be extremely difficult to install in the SW valve rooms.

Page 54 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/0

• Cycling one valve at a time for quarterly IST without introducing SW flow to the CFCU flow path.

• In case an AOV fails to open during testing, the valve will be provided with features to allow it to be jacked-open, the stem locked in the open position, and the valve operator removed/replaced/repaired. Although this increases the risk of SW contamination of the CFCU CH System, it maintains the sys-tem in an "operable" status17.

• A flush valve (labeled dead leg - debris clean out) allows blow down of the vertical, dead-headed piping between the main SW header and the first SW isolation valve before stroking the SW valves. Flushing this dead leg prevents long-term accumulation of silt and debris in the dead-headed portion of the line (and it avoids having that debris drop into the clean areas during AOV testing).

• An inspection port in the "dead leg" allows inspections and removal of any marine life, such as mussels, which would not flush out but which could over time cause flow reductions.

• When testing the outboard SW isolation valve (outboard refers to the AOV closest to the main SW header), a small, manual by-pass around the "in-board" SW isolation valve is opened. This "flush" valve keeps the volume be-tween the two valves pressurized with the higher pressure, clean chilled wa-ter. Flow when testing the outboard isolation valve will then be into the SW header.

• A tell-tale valve between the two AOV's can be periodically opened to deter-mine if either AOV is leaking. The water quality of the leak determines which valve is leaking. The object is to detect a single valve leaking, and repair it at a convenient time, and to minimize the probability of both valves leaking at the same time.

• Removal of the SW AOV is anticipated to be an infrequent outage activity.

Manual valves allow for the SW AOV's in one header to be removed while maintaining CH to 3 CFCU's. For example, the 11 SW header valves can be removed and CH can be maintained to the 13, 14, and 15 CFCU's by shutting 11SW52, 11SW78, 11SW54 and SW76, 12SW54 and SW76, and the CH manual valves to the 11 SW header.

14)The CFCU CH System supply header is a single flow path. However, to allow for testing and to minimize the risk and consequences of an isolation check valve failure incapacitating the system, the isolation header portion will have two re-dundant parallel flow paths, each with redundant in-series check valves. One of the two paths can be removed from service to allow testing, and if the check 17 The limitation is that this valve is required to be returned to service prior to testing the other iso-lation valve.

Page 55 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 valve fails to shut on reverse flow, it can be kept out of service without entry into any Technical Specifications Action Statement' .

Non-SR, SR, non-seismic Seismic I I'nk To CFCU's 15)Likewise, the CFCU CH System return header is a single flow path and it's isola-tion header portion will also have two redundant parallel flow paths each with in-series fast closure AOVs. These 10" nominal diameter AOV's will "recycle" the present SW accumulator isolation valves (SW534 and 535's) except that they will be modified from normally shut, fail open to normally open, fail shut.

Non-SR, SR, Seismic 1 non-seismic 44W From CFCU return header

0. 4 -

Flow Direction 16)The present CFCU control valves, SW57 and SW65 will be deleted. SW223, will be converted to a manual valve, locked in a specific throttle positions. This will entail determining the extent of demolition for all associated controls (including control switches, logics, wires, pneumatics, etc).

17)The SW53 and SW77 check valves will be retained. These valves prevent the 11(21) SW header from cooling the 14(24) and 15(25) CFCU and, similarly the la The limitation is that this flow path is required to be returned to service prior to testing the other flow path valve.

19 Refer to SH.OP-AP.ZZ-01 03, Attachment 4 "Locked Valve Validation Criteria", Criterion 5, SR Throttle valves. Manual valves that are throttled to balance flow in a system or regulate flow to a component shall be locked In the required position. When incorrectly positioned these valves could affect system or component operability". Criterion 4 also applies.

Page 56 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l 12(22) SW header from cooling the 11(21) and 12(22) CFCU. These valves al-low the SW headers to be separated to address the possibility of a passive fail-ure, resulting in a leak, in a CFCU line during a DBA. This passive failure need only be postulated 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the start of a DBA. The CH supply line into each SW valve room will is provided with a check valve in each room branch line.

These check valves are required for the same reason as SW53, maintain SW header separation.

18)Since the maximum anticipated operating pressure at the CFCU's will be ap-proximately 95 psig (about 55 psid below the CFCU design pressure) and the system will be operating with clean water except on a DBA, a thermal relief valve will be added to each CFCU branch line to address isolation of the CFCU's. The existing bypasses to the SW223 valves will be eliminated. The setpoint will be 150 psig which provides a significant margin to prevent leakage and spurious opening. The design shall include a bellows so that the set pressure is not raised during a containment DBA.

19)The 12(22) SWS accumulator will be retained to ensure the CFCU's remain full and pressurized, as discussed earlier, during a transition from normal cooling to SW cooling. The N2 pressure will be reduced from 150 psig to - 80 psig. The AOV's on its discharge path are removed (used elsewhere).

20)The 11(21) SWS accumulator be converted to a head/surge tank for the CFCU CH System. The N2 blanket will be maintained but pressure will be significantly reduced. The pressure will be determined by how much pressure has to be added to the CFCU CH System pumps, during normal operation, to maintain the chilled water pressure slightly higher than the SW supply header pressure (measured at the point where the SW headers enter the Mechanical Pen Area).

21)A make-up line from the Demineralized Water (DM) System to the CFCU CH System is required. The detailed design will determine if the DM System can make up directly to the suction side of the CFCU CH System without requiring added pumps. If so, the present SW accumulator pumps will be deleted.

22)During anticipated operations, CH water is aligned to three CFCU's. To prevent CH flow to the other 2 CFCU's but maintain the SW flow path operable, the CH return line AOV's from either the east SW valve room or the west SW valve room are shut.

23)No changes are required to existing CFCU containment isolation valves, SW58 and SW72. However, their capability to isolate must be reviewed to ensure ade-quate closure assuming the following changes (1) lower SW pressure but (2) clo-sure against full SW flow. Presently, valve closure credits prior SW223 closure.

24)The SW System hydraulic model will be revised to confirm satisfactory flow to all components during normal and accident conditions incorporating the changes in flow to the CFCU's and SW strainer backwash and the reduction in SW pump TDH. This may require a review of control valve Cv's and/or fixed orifices in the individual branch lines.

Page 57 of 64

[System Description CFCU Chilled Water System Rev 2 04/04/04 25)SW minimum flow must be reviewed during winter operation. Presently, SW flow to the major loads (TAC and CCHX) is significantly throttled with low river tem-peratures. Eliminating the CFCU flow may require increasing the flow on an existing bypass line to ensure that the minimum SW pump flow can be 26)000flfilf added HVAC is required in the FHB annex due to normal operation of two, 60 Hp motors for the CFCU CH System pumps. This includes added ven-tilation during the summer and added heat during the winter. Note that the heater used in the wintertime is unreliable because the hot water line to it has tended to freeze.

27)Determine impact on Control Air System loads. This assessment should credit per Salem unit (a) deletion of fifteen valves AOV's (SW57, SW65, and SW223 in each CFCU) (b) addition of 8 SW header isolation valves (c) conversion of the 4 SW accumulator valves to 4 CH isolation valves and (d) changes in instrumenta-tion.

3.2. Electrical The electrical one line is Figure 7 CFCU CH System One Line Electrical.

1) Two chillers and 2 CH pumps will be powered from the "E" group bus and 2 chill-ers and 2 CH pump will be powered from the 'G' group bus as shown on Figure 7 CFCU CH System One Line Electrical. This design allows for over full cooling with the limitations described in the next paragraph) and full flow on a single group bus (note that all four group buses are required to operate the unit since Salem is not licensed to operate with less than 4 RCP's).

2) If there is failure of one of the two CFCU Chilled Water System buses, which causes a loss of power to 2 pumps and 2 chillers, the remaining bus should be capable of providing the required power one chiller and one pump on the oppo-site bus through the cross-tie, as discussed in Section 1.3.5.

3) Miscellaneous power to the area including lights, receptacles for power tools, in-strumentation, and heat tracing.

4) Run two (2) cables from the Turbine Building (TB) E and G buses to the outside of the FHB. The cable will be 4KV. Use the breaker location vacated by the CW pumps.

The routing of the cable shall be determined by cost considerations.

Each cable will feed one 4160V to 480V transformer mounted by the FHB.

5) No changes are required in the 'fan" side of the CFCU's. Normal, high speed is required during normal operation, and low speed is required during DBA. The Project considered the option of a single speed fan speed, but determined that it was not desirable. Reducing the speed during normal operation would invalidate much of the temperature gains achievable by the use of CH water; increasing the speed during DBA would require a much higher SW flow and would negate the goal of replacing the control valves with fixed resistances.

Page 58 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04 l 3.3. I&C The l&C control logic for the valves are shown on Figure 4 Typical CH AOV Control Logic, Figure 5 Typical SW Supply Header AOV's Control Logic, and Figure 6 Typical SW Return Header AOV's Control Logic. Refer to section 2.7, SW & CFCU CH Valves, CH Pump, and Chiller Control Signals. Additional information:

1) The new SW System CFCU air operated isolation valves are required to open for DBA's but they are normally shut, fail shut (see section 2.6). Therefore, all control air and electrical power will be from safety related sources and will re-quire careful design (e.g., provide accumulators to ensure no common mode air failures and use DC solenoid valves, powered from a vital power supply to ad-dress a diesel SACF). Spurious opening of both in-series SW isolation valves due to a single component failure or testing error is highly undesirable. The de-sign needs to consider to the extent reasonable how to minimize spurious simul-taneous openings while at the same time providing reliable opening when an ac-tuation signal is received.

The SW AOV's require air to open and the solenoid valves that control air to these valves will be normally shut, fail shut. However, each SW AOV will be provided with redundant air thru redundant, parallel path solenoid valves pow-ered from separate DC sources. Thus, any single DC failure will not prevent any SW AOV from automatically opening when required.

Note: although automatic actuation energizes both redundant solenoids and both headers, remote-manual unisolation from the control allows the Operator to select one or both headers, but it only energizes the "primary" solenoid for a header.

2) The new CFCU CH System air operated isolation valves are normally open and must shut on a SI signal. Two in series valves are provided to ensure that no failure keeps both valves remaining open. The design should however minimize the inadvertent isolation of both return paths.

3) In addition to automatic signals, remote-manual controls for both the CFCU CH System and SWS isolation valves are to be located in the main control room.

This is in keeping with FSAR commitments to provide controls in the control room for all key SW isolation valves.

4) Presently, the CFCU's have inlet and outlet flow measurements to detect signifi-cant leaks. Flow measurement is required to verify normal and accident flow.

Flow deviation is not critical for normal operation, but must be retained for DBA.

5) The Project must delete the l&C for SW57, SW65 and SW223. These valves presently control flow in the CFCU branch lines. They are being removed or converted to manual valves.

6) Review, and as necessary, modify all the instrumentation and controls on the SW system that are affected by destaging the SW pump and operating the SW system at approximately 66% of present pressure.

Page 59 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04

7) The design should allow testing of the SI signal to the CH and SW valves; how-ever, the design should allow this tests to be performed without actually opening the SW valves. Testing of the SI signal to these valves is anticipated as part of the safeguard test performed during a refueling outage.

8) To minimize SW initiation due to spurious SI signals, the design should allow blocking the SI initiation signal to the CFCU SW isolation valves when CFCU accident cooling is not required by Technical Specifications (during modes 4, 5, 6 and defueled).

9) Chillers Controls, indication, and alarms for the chillers are located on local vendor sup-plied chiller control panels. Any alarm actuation on the local panel will also cause a trouble alarm the main control room panel. Chiller controls will be pro-grammed to add or drop compressor loading as necessary to maintain chilled water in the control band (around 460F), as heat load in the containment in-creases or decreases.

Controls and instrumentation for each chiller include:

• Vendor-furnished, equipment-mounted control package and control pan-els that include chiller outlet water low flow switch, flow indicator, local pressure indicator, temperature indicator, temperature switch, and tem-perature high-low alarm,

• Local chiller inlet water pressure indicator,

• Computer input for compressor motor winding temperature,

• Computer input for compressor motor bearing temperature.

10) Centrifugal Pumps The pumps shall trip following any CH System isolation signal.

Controls and alarms for chilled-water pumps are located on the local vendor supplied control panel. Any alarm actuation on the local panel will also cause a trouble alarm the main control room.

Controls and instrumentation for each chilled-water pump include:

• A chilled-water flow transmitter and indicator, flow displayed on the local control panel.

• A chilled-water flow high-low switch which alarms at the local control panel and cause a trouble alarm the main control room.

• Pump suction and discharge pressure indicators.

• Computer input for chilled water discharge pressure.

Page 60 of 64

System Description CFCU Chilled Water System Rev 2 04/04/04 3.4. Corrosion/WaterChemistry Control Due to the possibility of SW initiation and discharge of the CFCU CH System fluid into the river, no chemicals will be used.

Corrosion will be controlled by maintaining a N2 blanket on the accumulator and head tank and using demineralized water as make-up.

To maintain water quality a fifty (50) gpm, or 2%of the total chilled-water flow, will be filtered through a filter and then treated thru a mixed bed demineralizer. The fil-ter/mixed-bed demineralizer skid is a preassembled unit with the following instru-ments:

1. An in-line, turbine type flow element with digital indicator and totalizer for monitoring skid flow and total usage.

2. Several local pressure gauges for monitoring differential pressure across the media beds and across the outlet resin trap.

3. An outlet flow conductivity element with digital, local indication and high alarm for monitoring demineralizer performance.

The filter minimizes the insoluble loadings added to the resins and minimizes the need for backwashing resins.

Since this skid may not be in constant use, it will be located indoors to provide freeze protection.

3.5. Civil/Structural Civil/Structural is required to support installation of the new equipment and activities as described elsewhere and briefly summarized below:

1. Provide a support pad for the chillers and switchgear located by the FHB. The supports shall raise the components above ground to minimize the risk from a nominal flood and/or from snow accumulation. The bottom of the chillers shall be a nominal 3' above grade.

2. Civil work for piping, conduits, etc including core bores

3. Relocation of fences and other commodities located in the yard

4. Any modifications required in the FHB "Annex" to support installation of the CFCU CH System pumps and demineralizer skid. This includes re-opening of the floor drain that was plugged during the re-rack work.

3.6. Design Snecialties

1) Radiation Monitoring on the SW return lines will be addressed by a separate project. The present R13A monitors are located on a tubing bypass around the SW223 valves. There is one per CFCU branch line, and their design function is to detect for any containment leakage thru a failed CFCU tube that, if unde-tected, would result in releases to the river. These monitors are not adversely impacted by the CFCU CH System.

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System Description CFCU Chilled Water System Rev 2 04/04/04

• During CFCU CH System operation, chilled water pressure will be at -

100 psig whereas containment pressure will be at - 0 psig. Any CFCU pressure boundary leakage will result in demineralized water leaking into the containment and be detectable by a decreasing level in the head tank. A 0.1 gpm leak will result in a 4"/day level drop. Even if the chilled water pumps were all lost, the accumulator tank would maintain chilled water pressure well above containment design pressure.

• In the event of a DBA, the CFCU CH System is isolated and SW is initi-ated. SW pressure on all lines inside containment will remain higher than containment pressure even with destaged SW pumps. Nevertheless, if one were to postulate a containment leak into the SW system water, the lower SW flow (reduced from - 2500 gpm to - 1500 gpm/CFCU) would reduce the dilution making detection easier.

2) The CFCU CH System is subject to moderate line break evaluations. Specific concerns are leaks/flooding of the SW valve rooms.

3) Pipe whip protection is not required for components located outside of contain-ment.

4) No environmental qualification is required except for the added SW and CFCU CH System isolation valves and related controls or instrumentation.

5) No new tornado missile protection is required. Although much of the CFCU CH System equipment is outdoors, the only new safety-related components that are outside the present buildings are the portions that are in or immediately adjacent to the accumulator building. This piping should be protected by the same shields originally installed to protect the accumulator building..

6) EQ of components inside the containment needs to be reviewed against the new DBA temperature and pressure profiles. In addition, once the modification is implemented, the EQ program should credit a normal containment ambient temperature of -90 0 F when computing EQ component replacements.

3.7. Licensing

1) Technical Specification changes to change number of CFCU's required to be

'Operable" from 5 to 4 (depending on the source term/CR dose calculation, may have to require 5 CFCU's Operable until AST is approved), reduce required SW flow from 2500 gpm to -1200 gpm, revised SW accumulator requirements, and as required to support the licensing change process.

2) Provide revised FSAR analysis and text changes.

3) Permits may be required for the chiller foundations and for discharging the heat to the atmosphere.

4) Coordinate above effort with Licensing for AST Project Page 62 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04

4. KEY PROJECT DOCUMENTS All calculations are retrievable thru DCRM. All memo's, position papers, evaluations, and studies are located in the CFCU Project S-Drive under the folder labeled "906 Reports StudiesEvaluations".

7.1. Westinghouse WCAP, Containment Analysis for Revised CFCU Cooling 7.2. S-C-SWS-MDC-1968, Revision 1, Post-Modification CFCU Heat Removal Capacity 7.3. S-C-CH-MDC-1 970, CFCU Chilled Water System Design Basis Parameters 7.4. S-C-SW-MDC-1 969, SWS System Requirements for Post-Accident Contain-ment Cooling (also called GL96-06 calculation) 7.5. S-C-SW-MEE-1821 SW System Hydraulic Performance with 2-Stage Pumps 7.6. Johnston Pump Preliminary Data (letter Dated 9/30/02) 7.7. Johnston Pump Test Data on Destaged Pump (After Testing) 7.8. Final Proto-Flow SW Hydraulic Analysis for Destaged Pumps and 5 CFCU's (includes Turbine Bldg Loads) 7.9. DBA Dose Calculation (Need document #)

7.10. Basis for Selection of Air Cooled Chillers Memo 08 08 03 7.11. CFCU Reliability White Paper 7 22 03 7.12. CLCWC Piping and Corrosion Control Options 07 10 03 7.13. Revised Plot Plan Showing Location of Major Equipment (Approved by Sta-tion Management) 7 14 03 7.14. Isolation Signals Requirements 08 11 03 7.15. Marked Up SW P&ID's Showing Changes 7.16. CFCU CH Simplified P&ID, SR 7.17. CFCU CH Simplified P&ID, non-SR 7.18. Conceptual Piping and Equipment Layout for Pumps and Chillers 7.19. Conceptual Layout of Piping in SW Valve Rooms 7.20. CFCU Chilled Water System Substation Electrical One-Line 7.21. Control Logic Drawings for All New Power Valves 7.22. Control Logic Drawings for CH Pumps 7.23. Chiller Specification Page 63 of 64

ISystem Description CFCU Chilled Water System Rev 2 04/04/04

24. CFCU CH Pump Specification20

!5. Filter/Demineralizer Specification

26. Switchgear Specification 7.227. SR Valve Specification 7.2le28. NSR Valve Specification 7.2e29. Chiller Vendor Data

30. CFCU Pump Vendor Data

31. Filter/Demineralizer Vendor Data 7.2

12. Switchgear Vendor Data 7.2

13. SR Valve Vendor Data

14. NSR Valve Vendor Data 20 The conceptual layout was done assuming a Goulds Model 3410, 6x8-13 Page 64 of 64