ML040680396

Safety Anaysis Transition Program Licensing Report.

ML040680396
Person / Time
Site:	Prairie Island
Issue date:	01/31/2004
From:	Westinghouse
To:	Office of Nuclear Reactor Regulation
References
L-P1-04-014
Download: ML040680396 (388)

Text

Westinghouse Non-Proprietary Class 3 January 2004 Prairie Island Units 1 and 2 Safety Analysis Transition Program Licensing Report Westinghouse

iii TABLE OF CONTENTS LIST OF TABLES ... . . . .

LIST OF FIGURES . ix.....

1 I NTRODUCTION AND

SUMMARY

............................... . 1-1

1.1 INTRODUCTION

.1-1 1.2 PEAKING FACTORS .1-1 1.3 REVISED THERMAL DESIGN PROCEDURES UNCERTAINTIES .1-1 1.4 NUCLEAR STEAM SUPPLY SYSTEM DESIGN PARAMETERS .1-2 1.5 GENERALANALYSIS ASSUMPTIONS .1-2

1.6 CONCLUSION

S .1-3

1.7 REFERENCES

.1-3 2 FUEL ASSEMBLY MECHANICAL DESIGN .. ............................. 2-1 2.1 FUEL ROD PERFORMANCE .. 2-1 2.1.1 Introduction .2-1 2.1.2 Fuel Rod Design Criteria .2-1 2.1.3 Oxide to Metal Ratio .2-5 2.1.4 References .2-6 2.2 SEISMIC/LOCA IMPACT OF FUEL ASSEMBLIES . .2-7 2.2.1 Introduction .2-7 2.2.2 Acceptance Criteria .2-7 2.2.3 Description of Analyses/Evaluations and Results .2-7 3 NUCLEAR DESIGN .. 3-1

3.1 INTRODUCTION

AND

SUMMARY

.3-1 3.2 DESIGN BASIS .3-1 3.3 METHODOLOGY .3-1 3.4 DESIGN EVALUATION - PHYSICS CHARACTERISTICS AND KEY SAFETY PARAMETERS .3-2 3.5 DESIGN EVALUATION - POWER DISTRIBUTIONS AND PEAKING FACTORS .3-2 3.6 NUCLEAR DESIGN EVALUATION CONCLUSIONS .3-2

3.7 REFERENCES

.3-3 4 THERMAL AND HYDRAULIC DESIGN .. 4-1

4.1 INTRODUCTION

AND

SUMMARY

.4-1 4.2 METHODOLOGY .4-1 4.3 EFFECTS OF FUEL ROD BOW ON DNBR .4-3 4.4 FUEL TEMPERATURE/PRESSURE ANALYSIS .4-3 4.5 BYPASS FLOW .4-4 4.6 THERMAL-HYDRAULIC DESIGN PARAMETERS. 4-4

4.7 CONCLUSION

.4-5

4.8 REFERENCES

.4-5 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

iv TABLE OF CONTENTS (cont.)

K-)

5 ACCIDENT ANALYSES .5-1 5.1 NON-LOCAANALYSES .. 5-1 5.1.0 Introduction .5-1 5.1.1 Uncontrolled RCCA Withdrawal from a Subcritical Condition (USAR Section 14.4.1) .. 5-38 5.1.2 Uncontrolled RCCA Withdrawal at Power (USAR Section 14.4.2) .. 5-49 5.1.3 Rod Cluster Control Assembly Misalignment (USAR Section 14.4.3) .. 5-85 5.1.4 Chemical and Volume Control System Malfunction .. 5-93 5.1.5 Startup of an Inactive Reactor Coolant Loop .. 5-100 5.1.6 Excessive Heat Removal Due to Feedwater System Malfunctions (USAR Section 14.4.6) .. 5-101 5.1.7 Excessive Load Increase Incident (USAR Section 14.4.7) .. 5-120 5.1.8 Loss of Reactor Coolant Flow (USAR Section 14.4.8.1) .. 5-131 5.1.9 Locked-Rotor Accident (USAR Section 14.4.8.2) .. 5-153 5.1.10 Loss of External Electrical Load (USAR Section 14.4.9) .. 5-166 5.1.11 Loss of Normal Feedwater (USAR Section 14.4.10) .. 5-185 5.1.12 Loss of All AC Power to the Station Auxiliaries (USAR Section 14.4.11) .. 5-195 5.1.13 Rupture of a Steam Pipe Core Response (USAR Section 14.5.5) .. 5-204 5.1.14 Rupture of a Control Rod Drive Mechanism Housing (RCCA Ejection) (USAR Section 14.5.6) .. 5-257 5.1.15 AMSAC/Diverse Scram System Analyses .. 5-272 \J Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

V LIST OF TABLES Table 1-1 RTDP Uncertainties .................................................. 1-4 Table 1-2 NSSS Design Parameters for Unit with OSG .................................................. 1-5 Table 1-3 NSSS Design Parameters for Unit with RSG .................................................. 1-6 Table 3-1 Key Safety Parameters .................................................. 3-4 Table 4-1 Prairie Island Thermal-Hydraulic Design Parameters Comparison .............................. 4-7 Table 4-2 Peaking Factor Uncertainties .................................................. 4-9 Table 4-3 RTDP Uncertainties .................................................. 4-10 Table 4-4 DNBR Margin Summary .................................................. 4-11 Table 4-5 Limiting Parameter Direction .................................................. 4-12 Table 5.1-1 Non-LOCA Analysis Limits and Analysis Results .................................................. 5-18 Table 5.1-2 Non-LOCA Plant Initial Condition Assumptions .................................................. 5-21 Table 5.1-3 Pressurizer and Main Steam System (MSS) Pressure Relief Assumptions ................ 5-22 Table 5.1-4 Overtemperature and Overpower AT Setpoints ................................. 5-25 Table 5.1-5 Summary of RPS and ESFAS Functions Actuated ................................. 5-26 Table 5.1-6 Core Kinetics Parameters and Reactivity Feedback Coefficients ............................... 5-28 Table 5.1-7 Summary of Initial Conditions and Computer Codes Used ........................................ 5-29 Table 5.1-8 Non-LOCA Transients Evaluated or Analyzed .............................................. 5-31 Table 5.1.1-1 Assumptions and Results - Uncontrolled RCCA Withdrawal from a Subcritical Condition .............................................. 5-42 Table 5.1.1-2 Sequence of Events -Uncontrolled RCCA Withdrawal from a Subcritical Condition................................................................................................. 543 Table 5.1.2-1 Time Sequence of Events for Uncontrolled RCCA Withdrawal at Power (Minimum Feedback) Westinghouse Model 51 SGs ....................................... 5-53 Licensing Report Island Licensing January 2004 Prairie Island Prairie Report January 2004 6296- RNP.doc-01 1604

vi LIST OF TABLES (contL)

Table 5.1.2-2 Limiting Results for RCCA Bank Withdrawal at Power Transient Westinghouse Model 51 SGs ................................................. 5-53 Table 5.1.2-3 Time Sequence of Events for Uncontrolled RCCA Withdrawal at Power (Minimum Feedback) Framatome ANP Model 56/19 SGs ............................. 5-54 Table 5.1.2-4 Limiting Results for RCCA Bank Withdrawal at Power Transient Framatome ANP Model 56/19 SGs ................................................. 5-54 Table 5.1.4-1 Typical Shutdown Margin Requirements ................................................. 5-99 Table 5.1.6-1 Westinghouse Model 51 OSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Automatic Rod Control .......................... 5-106 Table 5.1.6-2 Westinghouse Model 51 OSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Manual Rod Control .............................. 5-107 Table 5.1.6-3 Framatome Model 56/19 RSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Automatic Rod Control .......................... 5-108 Table 5.1.6-4 Framatome Model 56/19 RSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Manual Rod Control .............................. 5-109 Table 5.1.7-1 ELI Summary Results for Westinghouse Model 51 OSGs and Framatome Model 56/19 RSGs ................................................. 5-123 Table 5.1.7-2 Time Sequence of Events for Excessive Load Increase Incident (Westinghouse Model 51 OSGs and Framatome 56/19 RSGs) ................................ 5-124 Table 5.1.8-1 Sequence of Events - Partial Loss of Reactor Coolant Flow ................................... 5-136 Table 5.1.8-2 Sequence of Events - Complete Loss of Reactor Coolant Flow .............................. 5-136 Table 5.1.9-1 Sequence of Events - Reactor Coolant Pump Locked Rotor ................................... 5-157 Table 5.1.10-1 Sequence of Events and Transient Results - Loss of External Electrical Load - with Pressurizer Pressure Control (for Minimum DNBR) ........................... 5-171 Table 5.1.10-2 Sequence of Events and Transient Results - Loss of External Electrical Load - without Pressurizer Pressure Control (for RCS Overpressure) .................... 5-172 Table 5.1.10-3 Sequence of Events and Transient Results - Loss of External Electrical Load - with Pressurizer Pressure Control (for MSS Overpressure) ......................... 5-173 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

vii LIST OF TABLES (cont.)

Table 5.1.11-1 Sequence of Events - Loss of Normal Feedwater ................................................. 5-188 Table 5.1.12-1 Sequence of Events - Loss of All AC Power to the Station Auxiliaries ................... 5-197 Table 5.1.13-1 Summary Results for Steam Line Rupture - Full Power Core Response (0.99 ft2 ) Westinghouse OSGs & Framatorne RSGs ................................ 5-213 Table 5.1.13-2 Sequence of Events - Steam Line Rupture - Full Power Core Response - 0.99 ft2 ................................................. 5-213 Table 5.1.13-3 OSG Steam Line Break Analysis Assumptions and Sequence of Events ................. 5-214 Table 5.1.13-4 RSG Steam Line Break Analysis Assumptions and Sequence of Events ................. 5-215 Table 5.1.14-1 Assumptions and Results - RCCA Ejection ................................................. 5-262 Table 5.1.14-2 Sequence of Events - RCCA Ejection ................................................. 5-263 Table 5.1.15-1 AMSAC/DSS Event Approach ................................................. 5-273 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

ix LIST OF FIGURES Figure 3-1 Typical Cycle Loading Pattern with BOC and EOC Assembly Bumups ..................... 3-5 Figure 3-2 Typical Cycle BOC, MOC and EOC Assembly Power Distribution ............................ 3-6 Figure 3-3 Critical Boron Concentration versus Cycle Burnup, Typical Cycle ............................. 3-7 Figure 3-4 Axial Offset versus Cycle Bumup, Typical Cycle ................................................... 3-8 Figure 3-5 Radial Peaking Factor (FNMH) versus Cycle Bumup ................................................... 3-9 Figure 3-6 Total Peaking Factor (FQ(Z)) versus Cycle Burnup ................................................... 3-10 Figure 4-1 Fuel Average Temperatures ................................................... 4-13 Figure 4-2 Rod Internal Pressure ................................................... 4-14 Figure 4-3 Fuel Surface Temperatures ................................................... 4-15 Figure 4-4 Fuel Centerline Temperatures ................................................... 4-16 Figure 5.1-1 Reactor Core Safety Limits ................................................... 5-32 Figure 5.1-2 Illustration of Overtemperature and Overpower AT Protection .................................. 5-33 Figure 5.1-3 Fractional Rod Insertion versus Time from Release ................................................... 5-34 Figure 5.1-4 Normalized RCCA Reactivity Worth versus Fractional Rod Insertion ...................... 5-35 Figure 5.1-5 Normalized RCCA Reactivity Worth versus Time from Release ............................... 5-36 Figure 5.1-6 Integrated DPC Used in Non-LOCA Transient Analyses ........................................... 5-37 Figure 5.1.1-1 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Reactor Power versus Time ................................................... 5-44 Figure 5.1.1-2 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Heat Flux versus Time................................................... 5-45 Figure 5.1.1-3 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Hot-Spot Fuel Centerline Temperature versus Time ................................................... 5-46 Figure 5.1.1-4 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Hot-Spot Fuel Average Temperature versus Time ................................................... 5-47 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O 1604

x LIST OF FIGURES (cont.)

K>1_

Figure 5.1.1-5 Uncontrolled RCCAWithdrawal from a Subcritical Condition - Hot-Spot Cladding Temperature versus time .................................................... 5-48 Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 1 of 12)

Nuclear Power versus Time .................................................... 5-55 Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 2 of 12)

Nuclear Power versus Time .................................................... 5-56 Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 3 of 12)

Core Heat Flux versus Time .................................................... 5-57 Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 4 of 12)

Core Heat Flux versus Time .................................................... 5-58 Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 5 of 12) I Pressurizer Pressure versus Time .................................................... 5-59 Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 6 of 12)

Pressurizer Pressure versus Time.................................................... 5-60 Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcrm/sec - Full Power), Minimum Feedback (Sheet 7 of 12)

Pressurizer Water Volume versus Time .................................................... 5-61 Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec -Full Power), Minimum Feedback (Sheet 8 of 12)

Pressurizer Water Volume versus Time ..................... ............................... 5-62 Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 9 of 12)

Vessel Average Temperature versus Time .................................................... 5-63 Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 10 of 12)

Vessel Average Temperature versus time .................................................... 5-64 Island Licensing Report January 2004 PrairieIslandLicensingReport Prairie January 2004 6296- RNP.doc-01 1604

xi LIST OF FIGURES (contL)  ;

Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 11 of 12)

DNBR versus Time .................................................... 5-65 Figure 5.1.2-1 Framatome ANP Model 56119 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcn/sec - Full Power), Minimum Feedback (Sheet 12 of 12)

DNBR versus Time .................................................... 5-66 Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcnmsec - Full Power), Minimum Feedback (Sheet 1 of 12)

Nuclear Power versus Time .................................................... 5-67 Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 2 of 12)

Nuclear Power versus Time .................................................... 5-68 Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 3 of 12)

Core Heat Flux versus Time .................................................... 5-69 Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 4 of 12)

Core Heat Flux versus Time .................................................... 5-70 Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcmlsec - Full Power), Minimum Feedback (Sheet 5 of 12)

Pressurizer Pressure versus Time .................................................... 5-71 Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 6 of 12)

Pressurizer Pressure versus Time .................................................... 5-72 Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcmn/sec - Full Power), Minimum Feedback (Sheet 7 of 12)

Pressurizer Water Volume versus Time .................................................... 5-73 Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 8 of 12)

Pressurizer Water Volume versus Time .................................................... 5-74 Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 9 of 12)

Vessel Average Temperature versus Time .................................................... 5-75 January 2004 Praire Licensing Report Island Licensing Prairie Island Report January 2004 62%6 RNP.doc-01 1604

xii LIST OF FIGURES (cont..)

Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 10 of 12)

Vessel Average Temperature versus Time ..................................................... 5-76 Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 11 of 12)

DNBR versus Time ..................................................... 5-77 Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 12 of 12)

DNBR versus Time ..................................................... 5-78 Figure 5.1.2-3 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power, 100% Power (Sheet 1 of 6) ..................................................... 5-79 Figure 5.1.2-3 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power, 60% Power (Sheet 2 of 6) ..................................................... 5-80 Figure 5.1.2-3 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power, 10% Power (Sheet 3 of 6) ..................................................... 5-81 Figure 5.1.2-3 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal K1 at Power, 100% Power (Sheet 4 of 6) ..................................................... 5-82 Figure 5.1.2-3 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power, 60% Power (Sheet 5 of 6) ..................................................... 5-83 Figure 5.1.2-3 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power, 10% Power (Sheet 6 of 6) ..................................................... 5-84 Figure 5.1.3-1 Representative Transient Response to Dropped RCCA - Nuclear Power versus Time ..................................................... 5-89 Figure 5.1.3-2 Representative Transient Response to Dropped RCCA - Core Heat Flux versus Time ..................................................... 5-90 Figure 5.1.3-3 Representative Transient Response to Dropped RCCA - Pressurizer Pressure versus Time ..................................................... 5-91 Figure 5.1.3-4 Representative Transient Response to Dropped RCCA - Vessel Average Temperature versus Time ..................................................... 5-92 Report Licensing Report January 2004 Prairie Island Licensing Prairie Island January 2004 6296-LR-NP-doc-0 11604

xiii LIST OF FIGURES (cont.)

Figures 5.1.6-1 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Reactor Power versus Time ................................................... 5-110 Figures 5.1.6-2 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Pressurizer Pressure versus Time ................................................... 5-111 Figures 5.1.6-3 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Average Temperature versus Time ................................................... 5-112 Figures 5.1.64 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Outlet and Inlet Temperatures versus Time ................................................... 5-113 Figures 5.1.6-5 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: DNBR versus Time .................. 5-114 Figures 5.1.6-6 Framatome Model 56119 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Reactor Power versus Time ................................................... 5-115 Figures 5.1.6-7 Framatome Model 56/19 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Pressurizer Pressure versus Time ................................................... 5-116 Figures 5.1.6-8 Framatome Model 56/19 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Average Temperature versus Time ................................................... 5-117 Figures 5.1.6-9 Framatome Model 56119 RSG -Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Outlet and Inlet Temperatures versus Time ................................................... 5-118 Figures 5.1.6-10 Framatome Model 56119 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: DNBR versus Time .................. 5-119 Figure 5.1.7-1 Nuclear Power: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control ................................................... 5-125 Figure 5.1.7-2 Pressurizer Pressure: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control ................................................... 5-126 Prairie Island Licensing Report st January 2004 6296- RNP.doc-0 11604

xiv LIST OF FIGURES (cont.)

Figure 5.1.7-3 Pressurizer Water Volume: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control ..................................................... 5-127 Figure 5.1.74 Vessel Average Temperature: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control ..................................................... 5-128 Figure 5.1.7-5 DNBR: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control ..................................................... 5-129 Figure 5.1.7-6 Total Steam Flow: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control ..................................................... 5-130 Figure 5.1.8-1 Total Core Inlet Flow versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)..................................................... 5-137 Figure 5.1.8-2 RCS Faulted Loop Flow versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF) ..................................................... 5-138 Figure 5.1.8-3 Nuclear Power versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOP) ..................................................... 5-139 Figure 5.1.84 Core Average Heat Flux versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF) ..................................................... 5-140 Figure 5.1.8-5 Pressurizer Pressure versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)..................................................... 5-141 Figure 5.1.8-6 RCS Faulted Loop Temperature versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)..................................................... 5-142 Figure 5.1.8-7 Hot Channel Heat Flux versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF) ..................................................... 5-143 Figure 5.1.8-8 DNBR versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)..................................................... 5-144 Figure 5.1.8-9 Total Core Inlet Flow versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF) ..................................................... 5-145 Figure 5.1.8-10 RCS Loop Flow versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF) ..................................................... 5-146 Figure 5.1.8-11 Nuclear Power versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF) ..................................................... 5-147 Prairie Island Licensin6 Report January 2004 6296-LR-NP.doc-01 1604

xv LIST OF FIGURES (cont.)

Figure 5.1.8-12 Core Average Heat Flux versus Time - Complete Loss of Flow -

Two Pumps Coasting Down (CLOF) ................................................... 5-148 Figure 5.1.8-13 Pressurizer Pressure versus Til me - Complete Loss of Flow -

Two Pumps Coasting Down (CLOF) ................................................... 5-149 Figure 5.1.8-14 RCS Faulted Loop Temperature versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF) ................................................... 5-150 Figure 5.1.8-15 Hot Channel Heat Flux versus Time - Complete Loss of Flow, Two Pumps Coasting Down (CLOF) ................................................... 5-151 Figure 5.1.8-16 DNBR versus Time - Complete Loss of Flow, Two Pumps Coasting Down (CLOF) ................................................... 5-152 Figure 5.1.9-1 Total Core Inlet Flow versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-158 Figure 5.1.9-2 RCS Loop Flow versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-159 Figure 5.1.9-3 Nuclear Power versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-160 Figure 5.1.9-4 Core Average Heat Flux versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-161 Figure 5.1.9-5 Pressurizer Pressure versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-162 Figure 5.1.9-6 Vessel Lower Plenum Pressure versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-163 Figure 5.1.9-7 RCS Loop Temperature versus Time - Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case ................................................... 5-164 Figure 5.1.9-8 Hot-Spot Cladding Inner Temperature versus Time - Locked Rotor/

Shaft Break - RCS Pressure/Peak Cladding Temperature Case ............................... 5-165 Figure 5.1.10-1 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) - Nuclear Power versus Time ................................................. 5-174 Prairie Island Licensing Report January 2004 6296- RNP.doc-01 1604

xvi LIST OF FIGURES (cont.)

Figure 5.1.10-2 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) - Vessel Core Inlet and Outlet Temperatures versus Time ................................................. 5-175 Figure 5.1.10-3 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) - RCS Pressure versus Time ................................................. 5-176 Figure 5.1.10-4 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) - Pressurizer Water Volume versus Time ................................ 5-177 Figure 5.1.10-5 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) - Steam Generator Pressure versus Time ............................... 5-178 Figure 5.1.10-6 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) - DNBR versus Time ................................................. 5-179 Figure 5.1.10-7 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Nuclear Power versus Time ......................................... 5-180 Figure 5.1.10-8 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Vessel Inlet and Outlet Temperatures versus Time ................................................. 5-181 Figure 5.1.10-9 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - RCS Pressure versus Time ........................................... 5-182 Figure 5.1.10-10 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Pressurizer Water Volume versus Time ....................... 5-183 Figure 5.1.10-11 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Steam Generator Pressure versus Time ....................... 5-184 Figure 5.1. 11-1 Loss of Normal Feedwater- Nuclear Power ................................................. 5-189 Figure 5.1.11-2 Loss of Normal Feedwater - Reactor Coolant Temperatures ................................... 5-190 Figure 5.1.11-3 Loss of Normal Feedwater - Pressurizer Pressure ................................................. 5-191 Figure 5.1.114 Loss of Normal Feedwater - Pressurizer Water Volume .......................................... 5-192 Figure 5.1.11-5 Loss of Normal Feedwater - Steam Generator Pressure .......................................... 5-193 Figure 5.1.11-6 Loss of Normal Feedwater - Steam Generator Mass ............................................... 5-194 Report Licensing Report Island Licensing Prairie Island January 2004 Prairie January 2004 6296- RNP.doc- 11604

xvii LIST OF FIGURES (cont.) " -

Figure 5.1.12-1 Loss of All AC Power to the Station Auxiliaries - Nuclear Power .......................... 5-198 Figure 5.1.12-2 Loss of All AC Power to the Station Auxiliaries - Reactor Coolant Temperatures ..................................................... 5-199 Figure 5.1.12-3 Loss of All AC Power to the Station Auxiliaries - Pressurizer Pressure .................. 5-200 Figure 5.1.12-4 Loss of All AC Power to the Station Auxiliaries - Pressurizer Water Volume ......... 5-201 Figure 5.1.12-5 Loss of All AC Power to the Station Auxiliaries - Steam Generator Pressure ......... 5-202 Figure 5.1.12-6 Loss of All AC Power to the Station Auxiliaries - Steam Generator Mass .............. 5-203 Figure 5.1.13-1 Nuclear Power Steam Line Rupture - Full Power Core Response ........................... 5-216 Figure 5.1.13-2 Core Heat Flux Steam Line Rupture - Full Power Core Response .......................... 5-217 Figure 5.1.13-3 Pressurizer Pressure Steam Line Rupture - Full Power Core Response .................. 5-218 Figure 5.1.134 Pressurizer Water Volume Steam Line Rupture - Full Power Core Response ......... 5-219 Figure 5.1.13-5 Vessel Inlet Temperature Steam Line Rupture - Full Power Core Response ........... 5-220 Figure 5.1.13-6 Steam Generator Pressure Steam Line Rupture - Full Power Core Response ......... 5-221 Figure 5.1.13-7 Loop Steam Flow Steam Line Rupture - Full Power Core Response ...................... 5-222 Figure 5.1.13-8 Doppler-only Power Defect with Stuck RCCA ..................................................... 5-223 Figure 5.1.13-9 Safety Injection Curve ..................................................... 5-224 Figure 5.1.13-10 Main Steam Line Break with OSGs and with Offsite Power - Steam Generator Steam Pressure versus Time .......................... ........................... 5-225 Figure 5.1.13-11 Main Steam Line Break with OSGs and with Offsite Power - Steam Generator Outlet Nozzle Mass Flowrate versus Time .............................................. 5-226 Figure 5.1.13-12 Main Steam Line Break with OSGs and with Offsite Power - Pressurizer Pressure versus Time ..................................................... 5-227 Figure 5.1.13-13 Main Steam Line Break with OSGs and with Offsite Power - Pressurizer Water Volume versus Time ..................................................... 5-228 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

xviii LIST OF FIGURES (cont.)

Figure 5.1.13-14 Main Steam Line Break with OSGs and with Offsite Power - Reactor Vessel Inlet Temperature versus Time .................................................... 5-229 Figure 5.1.13-15 Main Steam Line Break with OSGs and with Offsite Power - Core Heat Flux versus Time .................................................... 5-230 Figure 5.1.13-16 Main Steam Line Break with OSGs and with Offsite Power - Core Averaged Boron Concentration versus Time .................................................... 5-231 Figure 5.1.13-17 Main Steam Line Break with OSGs and with Offsite Power - Reactivity versus Time .................................................... 5 -232 Figure 5.1.13-18 Main Steam Line Break with OSGs and Without Offsite Power -

Steam Pressure versus Time .................................................... 5-233 Figure 5.1.13-19 Main Steam Line Break with OSGs and Without Offsite Power -

Steam Generator Outlet Nozzle Mass Flowrate versus Time ................................... 5-234 Figure 5.1.13-20 Main Steam Line Break with OSGs and Without Offsite Power -

Pressurizer Pressure versus Time .................................................... 5-235 Figure 5.1.13-21 Main Steam Line Break with OSGs and Without Offsite Power -

Pressurizer Water Volume versus Time .................................................... 5-236 Figure 5.1.13-22 Main Steam Line Break with OSGs and Without Offsite Power -

Reactor Vessel Inlet Temperature versus Time .................................................... 5-237 Figure 5.1.13-23 Main Steam Line Break with OSGs and Without Offsite Power -

Core Heat Flux versus Time .................................................... 5-238 Figure 5.1.13-24 Main Steam Line Break with OSGs and Wthout Offsite Power -

Core Averaged Boron Concentration versus Time.................................................... 5-239 Figure 5.1.13-25 Main Steam Line Break with OSGs and Without Offsite Power -

Reactivity versus Time .................................................... 5-240 Figure 5.1.13-26 Main Steam Line Break with RSGs and with Offsite Power -

Steam Generator Steam Pressure versus Time .................................................... 5-241 Figure 5.1.13-27 Main Steam Line Break with RSGs and with Offsite Power -

Steam Generator Outlet Nozzle Mass Flowrate versus Time ................................... 5-242 Figure 5.1.13-28 Main Steam Line Break with RSGs and with Offsite Power -

Pressurizer Pressure versus Time .................................................... 5-243 Report Licensing Report January 2004 Island Licensing Prairie Island January 2004 6296-LR-NP.doc-01 1604

xix LIST OF FIGURES (cont.)

Figure 5.1.13-29 Main Steam Line Break with RSGs and with Offsite Power -

Pressurizer Water Volume versus Time .................................................. 5-244 Figure 5.1.13-30 Main Steam Line Break with RSGs and with Offsite Power -

Reactor Vessel Inlet Temperature versus Time .................................................. 5-245 Figure 5.1.13-31 Main Steam Line Break with RSGs and with Offsite Power -

Core Heat Flux versus Time .................................................. 5-246 Figure 5.1.13-32 Main Steam Line Break with RSGs and with Offsite Power -

Core Averaged Boron Concentration versus Time .................................................. 5-247 Figure 5.1.13-33 Main Steam Line Break with RSGs and with Offsite Power -

Reactivity versus Time .................................................. 5-248 Figure 5.1.13-34 Main Steam Line Break with RSGs and Without Offsite Power -

Steam Pressure versus Time .................................................. 5-249 Figure 5.1.13-35 Main Steam Line Break with RSGs and Without Offsite Power -

Steam Generator Outlet Nozzle Mass Flowrate versus Time ................................... 5-250 Figure 5.1.13-36 Main Steam Line Break with RSGs and Without Offsite Power -

Pressurizer Pressure versus Time..............................................................................5-251 Figure 5.1.13-37 Main Steam Line Break with RSGs and Without Offsite Power -

Pressurizer Water Volume versus Time .................................................. 5-252 Figure 5.1.13-38 Main Steam Line Break with RSGs and Without Offsite Power -

Reactor Vessel Inlet Temperature versus Time .................................................. 5-253 Figure 5.1.13-39 Main Steam Line Break with RSGs and Without Offsite Power -

Core Heat Flux versus Time .................................................. 5-254 Figure 5.1.13-40 Main Steam Line Break with RSGs and Without Offsite Power -

Core Averaged Boron Concentration versus Time .................................................. 5-255 Figure 5.1.13-41 Main Steam Line Break with RSGs and Without Offsite Power -

Reactivity versus Time .................................................. 5-256 Figure 5.1.14-1 RCCA Ejection - BOC Full Power Reactor Power vs. Time ................................... 5-264 Figure 5.1.14-2 RCCA Ejection - BOC Full Power Fuel and Clad Temperatures vs. Time .............. 5-265 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

xx LIST OF FIGURES (cont.)

Figure 5.1.14-3 RCCA Ejection - BOC Zero Power Reactor Power vs. Time .................................. 5-266 Figure 5.1.144 RCCA Ejection - BOC Zero Power Fuel and Clad Temperatures vs. Time ............. 5-267 Figure 5.1.14-5 RCCA Ejection - EOC Full Power Reactor Power vs. Time ................................... 5-268 Figure 5.1.14-6 RCCA Ejection - EOC Full Power Fuel and Clad Temperatures vs. Time .............. 5-269 Figure 5.1.14-7 RCCA Ejection - EOC Zero Power Reactor Power vs. Time .................................. 5-270 Figure 5.1.14-8 RCCA Ejection - EOC Zero Power Fuel and Clad Temperatures vs. Time ............. 5-271 Figure 5.1.15.3-1 RCS Loop Flow versus Time - AMSAC/DSS: Partial Loss of Flow, One Pump Coasting Down ..................................................... 5-277 Figure 5.1.15.3-2 Nuclear Power versusTime - AMSACIDSS: Partial Loss of Flow, One Pump Coasting Down ..................................................... 5-278 Figure 5.1.15.3-3 Pressurizer Pressure versus Time -AMSACtDSS: Partial Loss of Flow, One Pump Coasting Down ..................................................... 5-279 Figure 5.1.15.3-4 RCS Pressure versus Time -AMSACtDSS: Partial Loss of Flow, One Pump Coasting Down ..................................................... 5-280 Figure 5.1.15.3-5 DNBR versus Time -AMSAC/DSS: Partial Loss of Flow, One Pump Coasting Down ..................................................... 5-281 Figure 5.1.15.4-1 AMSAC/DSS: Loss of Normal Feedwater- Nuclear Power .. 5-284 Figure 5.1.15.4-2 AMSAC/DSS: Loss of Normal Feedwater - Reactor Coolant Temperatures .. 5-285 Figure 5.1.15.4-3 AMSACtDSS: Loss of Normal Feedwater- Pressurizer Pressure .. 5-286 Figure 5.1.15.44 AMSAC/DSS: Loss of Normal Feedwater - Pressurizer Water Volume .. 5-287 Figure 5.1.15.4-5 AMSAC/DSS: Loss of Normal Feedwater- RCS Pressure .. 5-288 Figure 5.1.15.4-6 AMSACIDSS: Loss of Normal Feedwater - Steam Generator Pressure .. 5-289 Figure 5.1.15.4-7 AMSAC/DSS: Loss of Normal Feedwater - SG Wide Range Indicated Level .. 5-290 Figure 5.1.15.4-8 AMSAC/DSS: Loss of Normal Feedwater- DNBR .. 5-291 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

xxi LIST OF FIGURES (cont)

Figure 5.1.15.5-1 AMSACIDSS: Loss of All AC Power to the Station Auxiliaries -

Nuclear Power ................................................................ 5-294 Figure 5.1.15.5-2 AMSAC/DSS: Loss of All AC Power to the Station Auxiliaries -

Reactor Coolant Temperatures ................................................................ 5-295 Figure 5.1.15.5-3 AMSAC/DSS: Loss of All AC Power to the Station Auxiliaries -

Pressurizer Pressure ................................................................ 5-296 Figure 5.1.15.54 AMSAC/DSS: Loss of All AC Power to the Station Auxiliaries -

Pressurizer Water Volume ................... ............................................. 5-297 Figure 5.1.15.5-5 AMSAC/DSS: Loss of All AC Power to the Station Auxiliaries -

RCS Pressure ................................................................ 5-298 Figure 5.1.15.5-6 AMSACIDSS: Loss of All AC Power to the Station Auxiliaries -

Steam Generator Pressure ................................................................ 5-299 Figure 5.1.15.5-7 AMSAC(DSS: Loss of All AC Power to the Station Auxiliaries -

SG Wide Range Indicated Level ................................................................ 5-300 Figure 5.1.15.5-8 AMSAC/DSS: Loss of All AC Power to the Station Auxiliaries - DNBR .............. 5-301 Figure 5.1.15.6-1 AMSACIDSS: Loss of External Electrical Load - Nuclear Power versus Time ................................................................ 5-304 Figure 5.1.15.6-2 AMSACIDSS: Loss of External Electrical Load - Reactor Coolant Loop Temperatures versus Time ................................................................ 5-305 Figure 5.1.15.6-3 AMSACIDSS: Loss of Extemal Electrical Load - Pressurizer Pressure versus Time .................. 5-306 Figure 5.1.15.6-4 AMSACIDSS: Loss of External Electrical Load - RCS Pressure versus Time .................. 5-307 Figure 5.1.15.6-5 AMSACIDSS: Loss of External Electrical Load - Steam Generator Pressure versus Time .................. 5-308 Figure 5.1.15.6-6 AMSACIDSS: Loss of External Electrical Load - SG Wide Range Indicated Level versus Time .................. 5-309 Figure 5.1.15.6-7 AMSACIDSS: Loss of External Electrical Load - DNBR versus Time ................. 5-310 January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LRNP.doc-01 1604

xxii LIST OF FIGURES (conL)

Figure 5.1.15.7-1 AMSAC/DSS: Uncontrolled RCCA Bank Withdrawal at Power Nuclear Power versus Time ........................................................... 5-313 Figure 5.1.15.7-2 AMSACIDSS Uncontrolled RCCA Bank Withdrawal at Power Core Reactivity versus Time .................................................... 5-314 Figure 5.1.15.7-3 AMSAC/DSS Uncontrolled RCCA Bank Withdrawal at Power Pressurizer Pressure versus Time .................................................... 5-315 Figure 5.1.15.7-4 AMSAC/DSS Uncontrolled RCCA Bank Withdrawal at Power RCS Pressure versus Time .................................................... 5-316 Figure 5.1.15.7-5 AMSACIDSS Uncontrolled RCCA Bank Withdrawal at Power RCS Loop Temperatures versus Time .................................................... 5-317 Figure 5.1.15.7-6 AMSAC/DSS Uncontrolled RCCA Bank Withdrawal at Power DNBR versus Time .................................................... 5-318 Figure 5.1.15.8-1 AMSAC/DSS: Uncontrolled Boron Dilution Nuclear Power versus Time ............. 5-321 Figure 5.1.15.8-2 AMSAC/DSS: Uncontrolled Boron Dilution Core Reactivity versus Time ............ 5-322 Figure 5.1.15.8-3 AMSAC/DSS: Uncontrolled Boron Dilution Pressurizer Pressure versus Time .................................................... 5-323 Figure 5.1.15.84 AMSAC/DSS: Uncontrolled Boron Dilution RCS Pressure versus Time ............... 5-324 Figure 5.1.15.8-5 AMSAC/DSS: Uncontrolled Boron Dilution RCS Loop Temperatures versus Time .................................................... 5-325 Figure 5.1.15.8-6 AMSAC/DSS: Uncontrolled Boron Dilution DNBR versus Time ......................... 5-326 January 2004 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

I-1 1 INTRODUCTION AND

1.1 INTRODUCTION

The Prairie Island Nuclear Generating Plant (PINGP) plans to transition from its current methodology

[developed by the Nuclear Management Company (NMC)] for performing non-loss-of-coolant accident (LOCA) safety analyses to the Westinghouse methodology for performing these analyses.

This report summarizes the safety evaluations and analyses that were performed to confirm that applicable acceptance criteria are met. Sections 2 through 5.1 of this Safety Analysis Transition Program (SATP) Licensing Report provide the results of the fuel assembly mechanical, nuclear, thermal-hydraulic, and accident analyses, respectively.

This report serves as a reference safety evaluation and analysis report for the transition from the NMC safety analysis methodology to the Westinghouse safety analysis methodology. Thus, this report will be used as a basic reference document in support of future PINGP Reload Safety Evaluations (RSEs) for fuel reloads. Additional references that will be applicable for the'reload designs will be the:

• PINGP Technical Specifications with changes incorporated, and

• The USAR with changes incorporated.

For the analyses, key safety parameters have been chosen to maximize the applicability of the results for future reload cycle evaluations, which will be performed utilizing the Westinghouse standard reload methodology (Reference 1-1). The objective of subsequent cycle-specific RSEs will be to verify that the applicable safety limits are not exceeded based on the reference analyses currently in the USAR (Reference 1-2) or as established in this report.

1.2 PEAKING FACTORS The full-power FNm peaking factor design limit is 1.77 and full powerFQ (Z) peaking factor limit is 2.50.

These will maintain flexibility in developing fuel management schemes for future fuel cycles that will achieve acceptable fuel economy and neutron utilization.

1.3 REVISED THERMAL DESIGN PROCEDURES UNCERTAINTIES An evaluation of the various plant parameter uncertainties is required in order to implement the Revised Thermal Design Procedure [RTDP] (Reference 1-3). This evaluation requires a review of reactor coolant system (RCS) temperature, pressure, power, and flow uncertainties used in the safety analysis. These uncertainties are calculated based on installed plant instrumentation or special test equipment, and on calibration and calorimetric procedures. They are used in the development of the reactor core limits and the departure from nucleate boiling ratio (DNBR) limits. The AT reactor trip setpoints are then developed from the new core limits. NMC has calculated these uncertainties based on their methodology.

Not all analyses use RTDP methodology. For those analyses that do not conform to the RTDP methodology requirements, the Standard Thermal Design Procedure (STDP) is still employed. The January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

1-2 difference between the two methodologies is in the initial conditions used in the analysis and the application of the uncertainties. For the RTDP events, the uncertainties are included in the development of the DNBR limit, and nominal values are assumed for the initial conditions for reactor coolant system (RCS) pressure, RCS temperature, and reactor power. Minimum measured flow (MMF), which is used with the RTDP methodology, is equivalent to the thermal design flow (TDF), which is used with the STDP methodology, plus a flow uncertainty. For those events using the STDP methodology, the uncertainties are directly applied to the nominal values for RCS pressure, RCS temperature, and power to define the initial conditions for the non-LOCA events. For those events using the RTDP methodology, the uncertainties are statistically combined with the DNBR correlation uncertainties to obtain the overall DNBR uncertainty factor used to define the design DNBR limit. Therefore, nominal values for RCS pressure, RCS temperature, and power are used for the initial conditions for the non-LOCA events. The STDP methodology is consistent with the reference licensing basis analyses found in the PINGP USAR (Reference 1-2). Whether positive or negative, uncertainties are applied in a manner that is consistent with the analysis and is in the most conservative direction for a specific event. Analyses that use the STDP methodology and those that use the RTDP methodology are delineated in Section 5 of this report Table 1-1 is a summary of the RTDP uncertainties that were calculated by the NMC. The uncertainties actually used in the safety analysis are larger than what was calculated. The rationale of using slightly larger values for the uncertainties ensures conservatism in the overall analysis.

1.4 NUCLEAR STEAM SUPPLY SYSTEM DESIGN PARAMETERS The analyses for the PINGP SATP use the nuclear steam supply system (NSSS) design parameters shown in Tables 1-2 and 1-3. These parameters are used in all analyses to ensure consistency throughout the program.

Table 1-2 shows the parameters applicable for the unit when the Westinghouse Model 51 original steam generator (OSG) is in place. Two cases are shown: one based on 0 percent steam generator tube plugging; the other based on 25 percent steam generator tube plugging.

Table 1-3 shows the parameters applicable for the unit when the Framatome replacement steam generator (RSG) is in place. Two cases are shown: one based on 0 percent steam generator tube plugging; the other based on 10 percent steam generator tube plugging.

1.5 GENERAL ANALYSIS ASSUMPTIONS Part of the effort involved in performing the analysis is to update and confirm many of the assumptions and inputs. These new or revised assumptions and input parameters form the basis upon which the analyses are performed, and ultimately establish the PINGP licensing basis (that is, Technical Specifications and USAR analysis of record). The process is started by Westinghouse documenting the assumptions and input parameters expected to be used in the analysis. Then the NMC reviews, updates, and approves the list. Once concurrence is achieved, the assumptions and input parameters are documented as final values, which are used in the analysis. The final assumptions and input parameters used in the analysis are contained in the Master Data List, which is maintained separately from this report.

The Master Data List is periodically updated, as necessary.

Report Licensing Report January 2004 Prairie Island Licensing Prairie Island January 2004 6296-LR-NP.doc-01 1604

1-3

1.6 CONCLUSION

S The results of the evaluations and analyses described in this report kad to the following conclusions:

1. Changes in the nuclear characteristics due to the transition to Westinghouse methodology are addressed in Section 3.0 of this report.

2. The core design and safety analysis results documented in this report show the core's capability to operate safely with the conditions that have been assumed for the PINGP,

3. This report establishes a reference upon which to base Westinghouse reload safety evaluations for future reloads.

1.7 REFERENCES

1-1 Davidson, S. L. (Ed.), et al., "Westinghouse Reload Safety Evaluation Methodology,"

WCAP-9272-P-A, July 1985.

1-2 "Prairie Island Updated Safety Analysis Report," Revision 25, May 2003.

1-3 Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-1 1397-P-A, April 1989.

Prairie Island Licensing Report January 2004 6296- RNP.doc-01 1604

1-4 Table 1-1 RTDP Uncertainties Parameter Calculated Uncertainty Power +/-1.62% power no bias Reactor Coolant System Flow +/-2.5% flow no bias Pressure +/-37.2 psi no bias Inlet Temperature +3.21F

-O.5cF (bias)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

1-5 Table 1-2 NSSS Design Parameters for Unit with OSG OWNER UTILITY: Nuclear Management Co.

PLANT NAME: Prairie Island (NSPINRP)

UNIT NUMBER: 1&2 BASIC COMPONENTS Reactor Vessel, ID, in. 132 Isolation Valves No Core Number of Loops 2 Number of Assemblies 121 Steam Generator Rod Array 14x14 OFA Model 51 Rod OD, in. 0.400 Shell Design Pressure, psia 1100 Number of Grids 5Z/21 Reactor Coolant Pump Active Fuel Length, in. 144 Model/Weir 93A/No Number of Control Rods, FL 29 Pump Motor, hp 6000 Internals Type NSP(1) Frequency, Hz 60 THERMAL DESIGN PARAMETERS Case I Case 2 NSSS Power, % 100 100 MWt 1657 1657 106 Btu/hr 5654 5654 Reactor Power, MNVt 1650 1650 106 Btulhr 5630 5630 Thermal Design Flow, Loop gpm 89,000(2) 89,000(2)

Reactor 106 lb/hr 68.8 68.8 Reactor Coolant Pressure, psia 2250 2250 Core Bypass, % 6.0(3) 6.0(3)

Reactor Coolant Temperature, OF Core Outlet 595.8 595.8 Vessel Outlet 592.1 592.1 Core Average 563.2 563.2 Vessel Average 560.0(4) 560.0(4)

Vessel/Core Inlet 527.9 527.9 Steam Generator Outlet 527.7 527.7 Steam Generator Steam Temperature, 'F 506.2 496.4 Steam Pressure, psia 719 659 Steam Flow, 106 lb/hr total 7.19 7.18 Feed Temperature, 'F 434.9 434.9 Moisture, % max. 0.25 0.25 Tube Plugging, % 0 25 Zero Load Temperature, 0F 547 547 HYDRAULIC DESIGN PARAMETERS Pump Design Point, Flow (gpm)/Head (ft.) 89,000/259 Mechanical Design Flow, gpm 103,300 Minimum Measured Flow, gpm total 182,500(5)

Footnotes:

(I) Unique plant, PLA style upper internals; RGE style lower internals.

(2) Customer-specified Thernal Design Flow.

(3) Thimble Plug Removal incorporated.

(4) Customer-specified Tavg.

(5) MMF based on 2.5% flow measurement uncertainty per customer request.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

1-6 Table 1-3 NSSS Design Parameters for Unit with RSG OWNER UTILITY: Nuclear Management Co.

PLANT NAME: Prairie Island (NSP)

UNIT NUMBER: 1 BASIC COMPONENTS Reactor Vessel, ID, in. 132 Isolation Valves No Core Number of Loops 2 Number of Assemblies 121 Steam Generator Rod Array 14x14 OFA Model (2)

Rod OD, in. 0.400 Shell Design Pressure, psia 1100 Number of Grids 5Z721 Reactor Coolant Pump Active Fuel Length, in. 144 Model/Weir 93AINo Number of Control Rods, FL 29 Pump Motor, hp 6000 Internals Type NSP(1) Frequency, Hz 60 THERMAL DESIGN PARAMETERS Case 1 Case 2 NSSS Power, % 100 100 MWt 1657 1657 106 Btu/hr 5654 5654 Reactor Power, MWt 1650 1650 106 Btu/hr 5630 5630 Thermal Design Flow, Loop gpm 89,000(3) 89,000(3)

Reactor 106 lb/hr 68.8 68.8 Reactor Coolant Pressure, psia 2250 2250 Core Bypass, % 6.0(4) 6.0(4)

Reactor Coolant Temperature, 'F Core Outlet 595.8 595.8 Vessel Outlet 592.1 592.1 Core Average 563.2 563.2 Vessel Average 560.0(5) 560.0(5)

Vessel/Core Inlet 527.9 527.9 Steam Generator Outlet 527.7 527.7 Steam Generator Steam Temperature, 'F 514.1 512.0 Steam Pressure, psia 772 758 Steam Flow, 106 lb/hr total 7.20 7.19 Feed Temperature, 'F 434.9 434.9 Moisture, % max. 0.10 0.10 Tube Plugging, % 0 10 Zero Load Temperature, 'F 547 547 HYDRAULIC DESIGN PARAMETERS Pump Design Point, Flow (gpm)fHead (ft.) 89,000/259 Mechanical Design Flow, gpm 103,300 Minimum Measured Flow, gpm total 182,500(6)

Footnotes:

(I) Unique plant, PLA style upper internals; RGE style lower internals.

(2) Parameters reflect Framatome RSG6 Model 56119.

(3) Customer-specified Thermal Design Flow.

(4) Thimble Plug Removal incorporated.

(5) Customer-specified Tavg.

(6) MMF based on 2.5% flow measurement uncertainty per customer request Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

2-1 2 FUEL ASSEMBLY MECHANICAL DESIGN 2.1 FUEL ROD PERFORMANCE 2.1.1 Introduction Fuel rod design evaluations for the Prairie Island VANTAGE+ [14x14 optimized fuel assembly (OFA) rod size] fuel were performed using the Nuclear Regulatory Commission (NRC)-approved models (References 2.1-1 and 2.1-2) and NRC-approved design criteria methods (References 2.1-3, 2.1-4, 2.1-5, and 2.1-6) to demonstrate that all the fuel rod design criteria described in the NRC Standard Review Plan (Reference 2.1-7) are satisfied.

The fuel rod design criteria given below are verified by evaluating the predicted performance of the limiting fuel rod, defined as the rod which gives the minimum margin to the design limit. In general, no single rod is limiting with respect to all the design criteria. Generic evaluations have identified which rods are most likely to be limiting for each criterion, and exhaustive screening of the fuel rod power histories to determine the limiting rod is typically not required.

The NRC-approved performance analysis and design (PAD) models (Reference 2.1-2) for in-reactor behavior are used to calculate the fuel rod performance over its irradiation history. PAD is the principal design tool for evaluating fuel rod performance. PAD iteratively calculates the interrelated effects of temperature, pressure, cladding elastic and plastic behavior, fission gas release, and fuel densification and swelling as a function of time and linear power.

PAD 4.0 is a set of best estimate fuel rod performance models. In most cases, the design criterion evaluations are based on a best estimate plus uncertainty approach. A statistical convolution of individual uncertainties due to design model uncertainties and fabrication dimensional tolerances is used. As-built dimensional uncertainties are measured for some critical inputs, such as, fuel pellet diameter. When available, they can be used in lieu of the fabrication uncertainties.

The COROSN code is used to evaluate cladding and structural component oxidation and hydriding.

COROSN uses the same thermal, corrosion and hydriding models as PAD and is especially adapted for efficient calculations of the oxidation and hydriding design criteria.

2.1.2 Fuel Rod Design Criteria The criteria pertinent to the fuel rod design are as follows:

• Rod internal pressure

• Clad stress and strain

• Oxidation and hydriding

• Fuel temperature

• Clad fatigue

• Clad flattening

• Fuel rod axial growth

• Plenum clad support January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-0 1 1604

2-2

• Clad free standing

• End plug weld integrity The specific assumptions used in the verification of these criteria for the Prairie Island VANTAGE+ fuel include:

• Prairie Island specific operating conditions based on a core power of 1,650 MWth and a +8, -9 relaxed axial offset control (RAOC) strategy.

• Fuel rod duty (steady-state and transient powers, axial power distributions) directly extracted from the neutronic calculations.

Each of these key fuel rod design criteria has been evaluated and it is concluded that each design criterion can be satisfied. The design criteria are described in more details below.

2.1.2.1 Rod Internal Pressure The internal pressure of the lead rod in the reactor will be limited to a value below that which could cause:

• The diametral gap to increase due to outward clad creep during steady-state operation

• Extensive departure from nucleate boiling (DNB) propagation.

The rod internal pressure for the Prairie Island VANTAGE+ fuel rods has been evaluated by modeling the gas inventory, gas temperature, and rod void volumes through the anticipated life of the rod. The resulting rod internal pressure is compared to the design limit on a case by case basis of current operating conditions to end of life (EOL). This evaluation showed that the rod internal pressure satisfies the design limit.

The second part of the rod internal pressure design basis precludes extensive DNB propagation and associated fuel failures. The basis for this criterion is that no significant additional fuel failures, due to DNB propagation, will occur in cores that have fuel rods operating with rod internal pressure in excess of system pressure. The design limit for Condition II events is that DNB propagation is not extensive, that is, the process is shown to be self-limiting and the number of additional rods in DNB due to propagation is relatively small. For Condition III/IV events, it is shown that the total number of rods in DNB, including propagation effects is consistent with the assumptions used in radiological dose calculations for the event under consideration. The Condition IIII1V analyses assume a wide range of number of rods in DNB [ Ia'c to cover representative situations.

2.1.2.2 Clad Stress and Strain The design limit for clad stress is that the maximum clad stress intensities excluding pellet clad interaction but accounting for clad corrosion as a loss of load carrying metal, be less than the stress limit defined in Reference 2.1-6, based on the Association of Mechanical Engineers (ASME) code calculations.

The design limit for clad strain during steady-state operation is that the total plastic as well as the total plastic elastic tensile creep strains due to uniform clad creep and uniform cylindrical fuel pellet expansion Licensing Report Island Licensing January 2004 Prairie Island Prairie Report January 2004 6296- RNP.doc-01 1604

2-3 associated with fuel swelling and thermal expansion is less than 1 percent from the unirradiated condition.

The design limit for fuel rod clad strain during Condition II events is that the total tensile strain due to uniform cylindrical pellet thermal expansion is less than 1 percent from the pre-transient value.

The stress and strain criteria have been evaluated for the Prairie Island VANTAGE+ fuel using the PAD and ASME computer codes. These evaluations have shown that the design limits can be met.

2.1.2.3 Oxidation and Hydriding The design criteria related to cladding corrosion require that the ZIRLOQ' clad metal to oxide interface temperature be maintained below specified limits to prevent a condition of accelerated oxidation, which would lead to cladding failure. The calculated ZIRLOTm clad temperature (metal-oxide interface temperature) will be less than [ ]' during steady-state operation, and for Condition II transients, the calculated clad interface temperature will not exceed [ ]'. The clad surface temperatures were evaluated and satisfied the above temperature limits.

The best estimate hydrogen pickup level in ZIRLOrm shall be less than or equal to [ ac on a volumetric average basis at EOL. The hydrogen pickup criterion, which limits the loss of ductility due to hydrogen embrittlement that occurs upon the formation of zirconium hydride platelets, has been met with the current approved model for the Prairie Island VANTAGE+ fuel.

The structural component stresses will be consistent with the ASME Code Section III requirements after accounting for thinning due to corrosion. Generic evaluations have shown that this criterion is met if the structural component metal waste does not exceed [ l This requirement can be met with the Prairie Island VANTAGE+ fuel.

2.1.2.4 Fuel Temperature For Condition I and II events, the fuel and reactor protection system are designed to assure that calculated centerline temperatures do not exceed the fuel melting temperature criterion. The intent of this criterion is to avoid a condition of gross fuel melting, which can result in severe duty on the cladding. The concern here is based on the large volume increase associated with the phase change in the fuel and the potential for loss of cladding integrity as a result of molten fuel/cladding interaction.

The temperature of the fuel pellets was evaluated by modeling the fuel rod geometry, thermal properties, heat fluxes, and temperature differences in order to calculate surface, average, and centerline temperatures of the fuel pellets.

Fuel temperatures have been calculated as a function of local power and burnup. The fuel surface and average temperatures with associated rod internal pressure are then used for accident analysis of the Prairie Island VANTAGE+ fuel design (see Section 4.4 for additional information). The fuel centerline temperature is used to show that fuel melt will not occur in Prairie Island.

Report January 2004 Prairie Island Licensing Prairie Island Licensing Report January 2004 6296- RNP.doc-01 1604

2-4 2.1.2.5 Clad Fatigue The fuel rod design criterion for clad fatigue requires that, for a given strain range, the number of fatigue cycle are less than those required for failure, considering a factor of safety of 2.0 on the stress amplitude and a factor of safety of 20.0 on the number of cycles. The concern of this criterion is the accumulated effects of short-term cyclic clad stress and strain, which result from daily load follow operation.

Clad fatigue for the Prairie Island VANTAGE+ fuel was evaluated by using a limiting fatigue duty cycle consisting of daily load follow maneuvers. The fuel rod fatigue evaluations showed that the cumulative fatigue usage fraction at EOL is less than the design limit of 1.0.

2.1.2.6 Clad Flattening The clad flattening criterion prevent fuel rod failures due to long term creep collapse of the fuel rod clad into axial gaps formed within the fuel stack. Current fuel rod design employing fuel with improved in-pile stability provides adequate assurance that axial gaps large enough to allow clad flattening will not form within the fuel stack.

The NRC-approved WCAP-13589-P-A (Reference 2.14) provides data to confirm that significant axial gaps in the fuel column due to densification (and therefore clad flattening) will not occur in current Westinghouse ammonium diuranate (ADU) fuel designs. Reference 2.1-7 does not apply to gadolinia-doped fuel as these rods are manufactured using the integrated dry route (IDR) process.

However, evaluations have shown that no clad flattening will occur during the anticipated irradiation history of the gadolinia fuel rods. Therefore, the clad flattening criterion is met for the Prairie Island .,

VANTAGE+ fuel.

2.1.2.7 Fuel Rod Axial Growth This criterion assures that sufficient axial space exists to accommodate the maximum expected fuel rod growth without degradation of the assembly function. Fuel rods are designed with adequate clearance between the fuel rod and the top and bottom nozzles to accommodate the differences in growth of the fuel rods and the fuel assembly.

The Prairie Island VANTAGE+ fuel rod growth evaluation demonstrates that there is adequate margin to the fuel rod growth design limit.

2.1.2.8 Plenum Clad Support This criterion assumes that the fuel clad in the plenum region of the fuel rod will not collapse during the normal operation conditions, nor distort so as to degrade fuel rod performance. The helical coil spring used in the Prairie Island VANTAGE+ fuel design prevents potential clad collapse by providing clad support.

~~

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2-5 2.1.2.9 Clad Free Standing The clad free standing criterion requires that the clad shall be short term free standing at beginning of life, at power, and during hot hydrostatic testing. This criterion precludes the instantaneous collapse of the clad onto the fuel pellet caused by the pressure differential that exists across the clad wall.

Evaluations of the clad free standing criteria have shown that instantaneous collapse of the Prairie Island VANTAGE+ fuel cladding will be precluded for differential pressures well in excess of the maximum expected differential pressure across the cladding under operating conditions.

2.1.2.10 End Plug Weld Integrity The fuel rod end plug weld shall maintain its integrity during Condition I and II events and shall not contribute to any additional fuel failures above those already considered for Condition III and IV events.

The intent of this criterion is to assure that fuel rod failures will not occur due to the tensile pressure differential loads that can exist across the weld. The current inspection limits for the end plug weld allows for the existence of small defects within the weld, and under maximum tensile pressure differential, failure of the weld shall not occur.

For Condition I and II events, the methodology is to confirm that the cold and hot internal pressure values of [ 3" and [ ]I, respectively, are bounding for the fuel regions in each reload cycle. For Condition m and IV events, the weld plug integrity methodology is to determine the maximum tensile pressure differential load during the return to power phase of the hot zero power steam line break event. This is done by evaluating the rod internal pressure during the transient to determine the maximum tensile pressure differential. The maximum tensile differential load is compared to the allowable pressure differential load at the minimum transient temperature to determine if the weld integrity criterion is satisfied. For the Prairie Island VANTAGE+ fuel design, the criterion has been shown to be met.

2.1.3 Oxide to Metal Ratio When water reacts with Zirconium-based alloys, the surface of the metal is converted to an oxide. Due to the differences in the densities of the oxide and the base metal, there is a volumetric change from the metal consumed to the oxide generated. This volumetric difference results in a thicker oxide than the metal that was consumed. The ratio of the volume is characterized by the oxide to metal ratio (O/M).

A theoretical O/M ratio of 1.56 is used by Westinghouse. The O/M ratio is used in the fuel rod design calculations to determine the maximum steady-state oxide thickness. It is also used to determine the maximum transient oxide thickness that would occur during a loss-of-coolant accident event. The thickness of these two oxides is added together to ensure that the total localized oxidation does not exceed the Code of Federal Regulations (CFR) Section 10 CFR 50.46 criterion of 17 percent.

For the Prairie Island VANTAGE+ fuel, the 10 CFR 50.46 criterion of 17 percent is not challenged due the low oxidation rates. Factors that could alter this conclusion would be metallurgical changes to the ZIRLOTh" material (i.e., tin level at the high end of the material specification), dramatic plant chemistry changes, significantly reduced primary coolant flow rates, and increased operating temperatures. All of these factors tend to increase the steady-state oxidation, thus reducing margin to the 10 CFR 50.46 total localized oxidation criterion of 17 percent.

Report LicensingReport IslandLicensing January 2004 Prairie Prairie Island January 2004 6296- RNP.doc-0 11604

2-6 2.1.4 References 2.1-1 Davidson, S. L., Nuhfer, D. L. (Eds.), "VANTAGE+ Fuel Assembly Reference Core Report,"

WCAP-12610-P-A, April 1995.

2.1-2 Foster, J. P., Sidener S., "Westinghouse Improved Performance Analysis and Design Model (PAD 4.0)," WCAP-15063-P-A, Revision 1, with Errata, July 2000.

2.1-3 Davidson, S. L. (Ed.), et al., "Extended Burnup Evaluation of Westinghouse Fuel,"

WCAP-10125-P-A (Proprietary), December 1985.

2.1-4 Kersting, P.J., et. al., "Assessment of Clad Flattening and Densification Power Spike Factor Elimination in Westinghouse Nuclear Fuel," WCAP-13589-A, March 1995.

2.1-5 "Revisions to Design Criteria," WCAP-12488-P-A, Addendum 1-A, Revision 1, January 2002.

2.1-6 Slagle, NV. H., "Revisions to Design Criteria," WCAP-10125-P-A, Addendum 1-A, May 2003.

2.1-7 Standard Review Plan, Section 4.2, "Fuel System Design," NUREG-0800, Revision 2, July 1981.

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2-7 2.2 SEISMIC/LOCA IMPACT OF FUELASSEMBLIES For the Prairie Island project, specific seismic and loss-of-coolant-accident (LOCA) analyses of the 14x14 optimized fuel assembly (OFA) homogenous core were performed. The safe shutdown earthquake (SSE) and the LOCA were analyzed using time history integration techniques. The limiting LOCA case [reactor vessel inlet nozzle (RVIN) break] was used for the combined seismic and LOCA analysis for the Prairie Island project. In addition, the top nozzle holddown spring forces were also evaluated.

2.2.1 Introduction Fuel assemblies are designed to perform satisfactorily throughout their lifetime. The combined effects of the design basis loads are considered in evaluating the capability of the fuel assemblies to maintain structural integrity.

2.2.2 Acceptance Criteria The results of the evaluation must support the following:

• The top nozzle holddown springs to provide holddown spring forces exceeding net uplift forces by a defined margin of 100 lbs. per fuel assembly.

• The fuel assembly must be able to maintain structural integrity (coolable geometry) under combined LOCA and SSE loading conditions.

2.2.3 Description of Analyses/Evaluations and Results 2.23.1 Fuel Assembly Seismic/LOCA Evaluation The time histories representing the earthquake motions and the pipe rupture transient were obtained from the reactor vessel and internals system model. The grid impact loads resulting from a combined square root of the sum of the squares (SRSS), SSE, and a limiting LOCA loading condition RVIN are below the allowable grid strengths for a homogeneous core. The results show adequate grid load margin and that the core coolable geometry and control rod insertion requirements are met for combined SSE and LOCA loads. This analysis is discussed in more detail in the following paragraphs.

2.23.1.1 Fuel Assembly and Reactor Core Models Based on the assembly vibrational frequencies and mode shapes, a parametric study was performed using NKMODE. NKMODE calculates a set of equivalent spring-mass elements representing an individual fuel assembly structural system. Based on this model, it has been shown that the mode shapes agree well with the predominate fuel assembly vibration frequencies. The lumped mass-spring fuel assembly model was further verified using the WECAN finite element code.

NWith the appropriate analysis parameters, such as grid impact stiffness and damping, number of fuel assemblies in a planar array, and established gap clearance, the WEGAP reactor core model was used for analyzing transient loadings.

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2-8 2.2.3.1.2 Grid Load Analysis K

The time history motions of the barrel at the upper core plate elevation and the upper and lower core plates are applied simultaneously to the reactor core model. The time histories representing the SSE motion and the pipe rupture transients were obtained from the time history analyses of the reactor vessel and internals finite element model.

Homogenous Core The maximum SSE and LOCA results for the 14x 14 OFA fuel assembly occurs in the X-direction of LOCA. The maximum structural mid-grid loads for the 14x14 OFAZirc-4 fuel assemblies occurred in the peripheral assemblies in the three (3) fuel assembly array. The maximum mid-grid loads obtained from SSE and LOCA loading analyses were combined using the SRSS method. The results of the combined seismic and LOCA analyses indicate that the maximum impact force for the 14x14 OFA assembly design is ( ]' of the respective allowable mid-grid strength. The allowable grid strength is established at the 95 percent confidence level on the true mean from the distribution of experimentally determined grid crush data at temperature.

2.23.13 Seismic/LOCA Impact of Fuel Assemblies Analysis Conclusions The maximum horizontal input motion congruent with the core principal axis is used to determine dynamic fuel responses. The reactor core is analyzed as a de-coupled system with respect to the two lateral directions. The input forcing function is obtained from a separate reactor pressure vessel and reactor internals system analysis.

The evaluation of the homogenous core 14x14 OFA fuel assembly in accordance with NRC requirements as given in SRP 4.2, Appendix A, shows that the 14x14 OFA fuel is structurally acceptable for the Prairie Island reactors. All of the combined mid-grid impact forces of the 14x14 OFA are less than the mid-grid strength limit. The maximum SRSS mid-grid impact force of the 14x14 OFA is [ Iax of the Zirc-4 14x14 OFA mid-grid crush strength. Thus, the core coolable geometry is maintained. The reactor can be safely shut down under the combined faulted condition loads. The results showed that the design criteria are satisfied.

2.23.2 Top Nozzle Holddown Springs Evaluation There are four sets of top nozzle holddown springs for each fuel assembly. Each set of holddown springs consists of two leaves fabricated to form a cantilever leaf spring set. The fixed end of the spring set is held in place. The top nozzle springs are designed to retract within the top nozzle enclosure.

The lift forces for Prairie Island Units I and 2 provided have been evaluated for the impact on the fuel assembly holddown spring capability. The spring evaluation was performed considering a last pump startup (LPS) temperature of 70'F.

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2-9 Top Nozzle Holddown Springs Analysis Conclusions The top nozzle holddown force analysis results show that the holddown spring force requirements are satisfied and the design basis evaluation is still bounding.

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3-1 3 NUCLEAR DESIGN

3.1 INTRODUCTION

AND

SUMMARY

The effects of transitioning the core design to the Westinghouse Alpha Phoenix ANC (Advanced Nodal Code) (APA) code set are evaluated in this section.

The specific values of core safety parameters, e.g., power distributions, peaking factors, rod worths, and reactivity parameters are primarily loading-pattern dependent. The variations in the loading-pattern dependent safety parameters are expected to be typical of the normal cycle-to-cycle variations for the standard fuel reloads. Standard nuclear design analytical models and methods (References 3-1 through 3-3) accurately describe the neutronic behavior of the Prairie Island reactor cores.

In summary, there are no changes anticipated to the fuel product nor to the fundamental strategies in use for the Prairie Island reload cores. The changes related to this program are limited to those resulting from the transition of the core design to the Westinghouse APA code set and associated changes to the Technical Specifications/Core Operating Limit Report (COLR).

3.2 DESIGN BASIS The specific design bases and their relation to the General Design Criteria (GDC) in 10 CFR 50, Appendix A for the optimized fuel assembly (OFA) design are shown in Section 3.1 of Reference 3-4.

OFA fuel is currently licensed to 60,000 MWDJMTU by the Nuclear Regulatory Commission (NRC)

(Reference 34) with extension to 62,000 MWDJMTU on a cycle-specific basis, as delineated in Reference 3-5, Appendix R.

The effects of extended burnup on nuclear design parameters has been previously discussed in Reference 3-6. That discussion is valid for the anticipated OFA design discharge burnup level. In accordance with the NRC recommendation made in their review of Reference 3-6, Westinghouse will continue to monitor predicted versus measured physics parameters for extended burnup applications.

3.3 METHODOLOGY The purpose of this analysis is to determine, prior to the cycle-specific reload design, the required values for the key safety parameters. This will allow the majority of any safety analysis re-evaluations/re-analyses to be completed prior to the cycle-specific design analysis.

No changes to the nuclear design philosophy, methods or models are necessary because of the transition to the Westinghouse APA code set. The reload design philosophy includes the evaluation of the reload core key safety parameters, which comprise the nuclear design-dependent input to the Updated Safety Analysis Report (USAR) safety evaluation for each reload cycle (Reference 3-1). These key safety parameters will be evaluated for each Prairie Island reload cycle. If one or more of the parameters fall outside the bounds assumed in the reference safety analysis, the affected transients will be re-evaluated/re-analyzed using standard methods, and the results will be documented in the Reload Safety Evaluation (RSE) for that cycle.

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3-2 3.4 DESIGN EVALUATION - PHYSICS CHARACTERISTICS AND KEY SAFETY PARAMETERS Multiple cycles of core models were established to model the transition to the Westinghouse APA code set. Actual loading patterns for multiple cycles of depletion were developed, and results benchmarked.

These models were intended to represent typical cycles of operation. They were developed with the intent to show that enough margin exists between typical safety parameter values and the corresponding limits to allow flexibility in designing actual reload cores. Six core models were developed and used for the majority of calculations performed here; where necessary, other models (including current designs) were used to further demonstrate sufficient margin exists between typical safety parameter values and the corresponding limits.

The fuel loading and assembly exposures at beginning of cycle (BOC) and end of cycle (EOC) (including cycle extension) are summarized for a typical core in Figure 3-1. Assembly power distributions at BOC, middle of cycle (MOC) and EOC are provided in Figure 3-2. Key core parameters versus cycle length are provided in Figures 3-3 through 3-6; these include critical boron concentration, axial offset, hot rod (FNm) and total peaking factor (FQ(Z)), respectively.

Table 3-1 provides the key safety parameters ranges. These values are all typical of those seen for other Westinghouse cores.

3.5 DESIGN EVALUATION - POWER DISTRIBUTIONS AND PEAKING FACTORS There are no changes to the radial peaking factor limit foi Prairie Island. The limit for the total peaking factor (Fq(Z)) is raised from a value of 2.4 to 2.5. The current radial peaking factor limit allows the concept of low leakage fuel management to be extended by placing additional burned fuel on the periphery of the core. The reduction in power in the peripheral assemblies is offset by increased power in the remaining assemblies. This increased radial peaking is accommodated by the current radial and total peaking factor limits.

Figure 3-5 shows a summary of radial peaking factors expected for a typical Prairie Island design. The FQ(Z) (total peaking factor) limit is 2.50. A summary of the FQ(Z) versus cycle length for a typical design is provided in Figure 3-6.

Beyond the power distribution impacts already mentioned, other changes to the core power distributions and peaking factors are the result of the normal cycle-to-cycle variations in core loading patterns. The normal methods of feed enrichment variation and insertion of fresh burnable absorbers will be employed to control peaking factors. Compliance with the peaking factor Technical Specifications can be assured using these methods.

3.6 NUCLEAR DESIGN EVALUATION CONCLUSIONS The key safety parameters evaluated for Prairie Island as the methodology transitions to the Westinghouse APA code set show little change relative to the current design. The changes in values of the key safety parameters are typical of the normal cycle-to-cycle variations experienced as loading patterns change.

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3-3 Power distributions and peaking factors will show normal variations experienced with different loading patterns. The usual methods of enrichment and burnable absorber usage w.ill be employed in the Prairie Island cores to ensure compliance with the Peaking Factor Technical Specifications.

3.7 REFERENCES

3-1. Davidson, S. L. (Ed.), et al., "Westinghouse Reload Safety Evaluation Methodology,"

WCAP-9273-NP-A, July 1985.

3-2. Nguyen, T. Q., et al., "Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores," WCAP-11596-P-A, June 1988.

3-3. Liu, Y. S., et al., "ANC: A Westinghouse Advanced Nodal Computer Code," WCAP-10965-P-A, September 1986.

3-4. Davidson, S. L. (Ed.), et al., "VANTAGE + Fuel Assembly Reference Core Report,"

WCAP-12610-P-A, April 1995.

3-5. Davidson, S. L. (Ed.), et al., "Westinghouse Fuel Criteria Evaluation Process," WCAP-12488-A (Proprietary), WCAP-14204-A (Non-Proprietary), October 1994.

3-6. Davidson, S. L. (Ed.), et al., "Extended Burnup Evaluation of Westinghouse Fuel,"

WCAP-10125-P-A (Proprietary), December 1985.

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34 Table 3-1 Key Safety Parameters Safety Parameter Design Values Reactor Core Power (MWt) 1650 Core Average Coolant Temp. HFP (degF) 562.9 Coolant System Pressure (psia) 2250 axc Normal Operation F"AH 1.77 Shutdown Margin (%Ap) 1.70 Normal Operation FQ(Z) 2.5 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

3-5 I 2 3 4 5 6 7 1 0 26315 29330 0 30483 0 48457 25165 49270 52689 28789 52829 24822 56208 2 26315 29208 0 25846 24403 0 49048 49270 51991 29456 50144 48400 24135 55805 3 29330 0 29276 21831 0 0 52689 29432 52628 46551 27976 20604 4 0 25867 21794 29295 0 39696 28789 50151 46517 50655 22438 47026 5 30483 24324 0 0 44387 52829 48341 27973 22455 53139 6 0 0 0 40363 24822 24131 20582 47637 7 48457 49060 BOC Burnup 56208 55811 EOC Burnup Figure 3-1 Typical Cycle Loading Pattern with BOC and EOC Assembly Burnups Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

3-6 2 3 4 5 6 7 K>

1 1 1.125 1.112 1.097 1.239 1.097 1.176 0.328 1.252 1.121 1.136 1.404 1.052 1.159 0.356 1.153 1.021 1.049 1.366 1.034 1.231 0.431 2 1.112 1.087 1.328 1.201 1.209 1.146 0.287 1.121 1.108 1.449 1.168 1.133 1.127 0.311 1.021 1.016 1.348 1.095 1.104 1.196 0.374 3 1.097 1.326 1.164 1.276 1.327 0.977 1.136 1.448 1.117 1.174 1.325 0.964 1.049 1.348 1.037 1.111 1.336 1.031 4 1.239 1.200 1.276 1.069 1.039 0.322 1.404 1.168 1.175 0.995 1.046 0.346 1.366 1.095 1.111 1.001 1.145 0.411 5 1.097 1.210 1.327 1.040 0.379 1.052 1.134 1.325 1.047 0.405 1.034 1.105 1.336 1.146 0.479 6 1.176 1.146 0.976 0.319 V

1.159 1.127 0.963 0.344 1.231 1.196 1.030 0.407 7 0.328 0.287 BOC Power 0.356 0.310 MOC Power 0.431 0.374 EOC Power Figure 3-2 Typical Cycle BOC, MOC and EOC Assembly Power Distribution K>j Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

3-7 Typical Critical Boron Concentration 1800 ~- sI ~

.A Am" 1400 - ' f C 1200 1000 -

800 I 400 -.

t)200 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000 Cycle Bumup (MWD/MTU)

Figure 3-3 Critical Boron Concentration versus Cycle Burnup, Typical Cycle Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

3-8 Axial Offset versus Cycle Burnup 5 - ark

3- 1g,.

2 S 0

I-2000 N -4,6000ti .1000,12000 '-OOO 16S i 2- -

-2 -.-.

-3 N.1 s-4 Cycle Burnup (MWDIMTU)

Figure 3-4 Axial Offset versus Cycle Burnup, Typical Cycle Report January 2004 Licensing Report Prairie Island Licensing January 2004 6296-LR-NP.doc-0 1 1604

3-9 Radial Peaking Factor versus Cycle Burnup 1.7 -

1.65 - Atoiy 'Wp' i~zoh f!-,m 1.655-co

14

21.45 - 2 Xg7

.K' --1-*-",

14 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000 Cycle Bumup (MWDIMTU)

Figure 3-5 Radial Peaking Factor (FNAH) versus Cycle Burnup Prii sadLcnin eotJnay20 January 2004 6296-LR-NP.doc-01 1604

3-10 Total Peaking Factor versus Cycle Burnup 2.1 - Aji; I

.0 2 - e t'~

U 1.95 -

) 1.9 -

.8 W> t*$ 4; 1.785 1.7 -... r W,-.,

..

i I 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000 Cycle Bumup (MWD/MTU)

Figure 3-6 Total Peaking Factor (FQ(Z)) versus Cycle Burnup

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4-1 4 THERMAL AND HYDRAULIC DESIGN

4.1 INTRODUCTION

AND

SUMMARY

This section describes the calculational methods used for the thermal-hydraulic analysis and the departure from nucleate boiling (DNB) performance of the 14x14 optimized fuel assembly (OFA) fuel loaded in the Prairie Island units.

The OFA design allows for 1650 MWt core power conditions at the current FNm limit of 1.77 (discussed in further detail in Section 4.2). Table 4-1 provides the current thermal-hydraulic design parameters that were used in this analysis. A discussion of the thermal-hydraulic parameters is provided in Section 4.6.

The thermal-hydraulic design criteria and methods are the same as those presented in the Point Beach Units 1 and 2 and Kewaunee Reload Transition Safety Report (RTSR) (References 4-1 and 4-2) and the Updated Safety Analysis Report (USAR) (References 4-3 and 4-4) as described in the following sections.

All thermal-hydraulic design criteria are satisfied for the Prairie Island Safety Analysis Transition Program.

4.2 METHODOLOGY The thermal-hydraulic analysis of the 14x14 OFA fuel in the Prairie Island units is based on the Revised Thermal Design Procedure (RTDP) (Reference 4-5) and the WRB-1 DNB correlation (Reference 4-6).

The DNB analysis of the core containing 14x14 OFA fuel assemblies has been shown to be valid with the WRB-1 DNB correlation (References 4-6), RTDP (Reference 4-5), and the VIPRE-W Modeling (Reference 4-7). The W-3 correlation and Standard Thermal Design Procedure (STDP) are still used when any one of the conditions are outside the range of the WRB-1 correlation (that is, pressure, local mass velocity, local quality, heated length, grid spacing, equivalent hydraulic diameter, equivalent heated hydraulic diameter, and distance from last grid to critical heat flux (CHF) site) and RTDP (that is, the statistical variance is exceeded on power, TLy, pressure, flow, bypass, FNM, FE7I, and FEQ).

The WRB-1 DNB correlation is based entirely on rod bundle data and takes credit for the significant improvements in the accuracy of the critical heat flux predictions over previous DNB correlations. The approval, by the Nuclear Regulatory Commission (NRC), that a 95195 correlation limit DNB ratio (DNBR) of 1.17 is appropriate for the 14x14 OFA fuel assemblies has been documented (Reference 4-6).

With RTDP methodology, uncertainties in plant operating parameters, nuclear and thermal parameters, fuel fabrication parameters, computer codes, and DNB correlation predictions are combined statistically to obtain the overall DNB uncertainty factor. This factor is used to define the design limit DNBR that satisfies the DNB design criterion (that is, a plant-specific design limit is that value that accounts for the RTDP uncertainties above the correlation DNBR limit). The criterion is that the probability that DNB will not occur on the most limiting fuel rod is at least 95 percent (at 95 percent confidence level) for any Condition I or II event (that is, normal operation or anticipated operational occurrences). Since the parameter uncertainties are considered in determining the RTDP design limit DNBR values, the plant safety analyses are performed using input parameters at their nominal values. For cases where conditions fall outside the bounds of the RTDP methodology (that is, the statistical variance is exceeded on power, TIN, pressure, flow, bypass, FNAH, FE&H.I, and FEQ), STDP is used and the associated analyses are performed using input parameters with their uncertainties included.

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4-2 The uncertainties included in the combined peaking factor uncertainty are:

• The nuclear enthalpy rise hot channel factor, (FmH)

• The enthalpy rise engineering hot channel factor, (FEm)

• Uncertainties in the VJPRE-W and transient codes

• Uncertainties in effective core flow fraction (that is, bypass flow)

• Uncertainties based on surveillance data associated with vessel coolant flow, core power, coolant temperature, and system pressure.

The increase in DNB margin is realized when nominal values of the peaking and hot channel factors are used in the DNB safety analyses. Table 4-2 provides a listing and description of the peaking factor uncertainties.

Instrumentation uncertainties are documented in Reference 4-8. Both the calculated uncertainties and the uncertainties used in the thermal-hydraulic design analysis, are listed in Table 4-3. The instrumentation uncertainties were used in determining the DNBR design limits. It should be noted that the uncertainties used in the thermal-hydraulic design analysis are slightly larger than what was calculated during the RTDP uncertainty analysis. The rationale of using slightly larger values for the uncertainties ensures conservatism in determining the DNBR design limit and conservatism in the overall analysis.

For the Safety Analysis Transition Program, the design limit DNBR values for the OFA fuel are 1.22/1.22 for typical/thimble cells. For use in the DNB safety analyses, the design limit DNBR is conservatively increased to provide DNB margin to offset the effect of rod bow, instrumentation bias and any other DNB penalties that may occur, and to provide flexibility in design and operation of the plant. This increase in the design limit to account for various penalties and operational issues is the plant-specific margin retained between the design limit and the safety analysis limit. After accounting for the plant-specific margin, the safety analysis limit for the OFA fuel is 1.34/1.34 for typical/thimble cells. These safety analysis limits are employed in the DNB analyses.

With the safety analysis limit set, the core limit lines, axial offset limit lines, and dropped rod limit lines are generated. In generating the various limit lines, the maximum FNAH that yields acceptable results based upon the safety analysis limits is determined. Based on generating these limit lines, the maximum FNAH limit that can be supported is 1.77 (including uncertainties) for the OFA fuel. Included uncertainty that has been accounted for is the measurement uncertainty of 4 percent (Reference 4-9).

FNAH = 1.77 x [I1 + 0.3(1-P)]

Where P = the fraction of full power Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 1604

4-3 Table 4-4 summarizes the available DNBR margin for the Prairie Island units as of the completion of this analysis. It should be noted that the DNBR margin summaries are cycle dependent and may vary from that documented here in future reload designs.

43 EFJECTS OF FUEL ROD BOW ON DNBR The concern with regard to fuel rod bow phenomenon is the potential effects on bundle power distribution and on the margin of fuel rods to DNB. Thus, the phenomenon of fuel rod bowing must be accounted for in the DNBR safety analysis of Condition I and Condition II events. Fuel rod bow is the phenomenon of fuel rods bowing between mid-grids. The effect of the rod bow is to impact the channel spacing between adjacent fuel rods. With a reduced channel spacing, the potential of DNB occurring increases. To determine the impact of rod bow on DNB, Westinghouse conducted tests to determine the impact of rod bow on DNB performance. These tests and subsequent analyses were documented in Reference 4-10.

[

]a. Based on the testing and analyses of various fuel array designs (Reference 4-10), including the 14x14 STANDARD, evaluations have shown that the 14x14 OFA fuel assemblies will have the same rod bow penalty applied to the analysis basis as that used for 14x14 STANDARD fuel assemblies.

For the OFA application, the rod bow penalty will be offset with DNB margin retained between the safety analysis and design DNBR limits (refer to Table 4-4).

4.4 FUEL TEMPERATUREIPRESSURE ANALYSIS Gadolinia (Gd) Rods Limiting Fuel temperatures and associated rod internal pressures have been generated for the OFA Gd fuel. The characteristics of the Gd fuel are such that the Gd rods would exhibit higher fuel temperatures due to an inherent lower thermal conductivity of the Gd-bearing fuel pellet. In addition, increasing gadolinia enrichment results in a corresponding decrease in the fuel melting temperature. The performance criteria employed by Westinghouse for Gd rods is to ensure that these rods are less limiting than the non-Gd rods, throughout life, in terms of fuel temperatures, rod internal pressures, and core stored energy. This is achieved by holding down the U235 enrichment in the Gd rods so that the Gd rods are at sufficiently lower power throughout life. Therefore, the fuel performance parameters for the OFA non-Gd fuel (Reference 4-13) bound those for the OFA Gd fuel. The higher fuel rod average and surface temperatures are conservative for the accident analyses subsequently performed. Refer to Figures 4-1 through 4-4. In addition, minimum fuel average and fuel surface temperatures are required by transient analysis.

Therefore, the OFA non-Gd fuel minimum temperatures are generated, which, with the maximum fuel temperatures, form a consistent basis for transient analysis.

Fuel centerline temperatures were also generated for the OFA fuel in Reference 4-13. These have been developed for future verification during the reload design validation, that fuel melt will not occur. [

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4-4 In addition to the fuel temperatures and pressures, the revised core stored energy for the OFA fuel has been determined for use in containment analysis. Core stored energy is defined as the amount of energy in the fuel rods in the core above the local coolant temperature. The local core stored energy is normalized to the local linear power level. The units for the core stored energy are in full-power seconds (FPS). [ Iax 4.5 BYPASS FLOW Two different bypass flow rates are used in the thermal-hydraulic design analysis-thermal design bypass flow (TDBF) and best-estimate bypass flow (BEBF). These two bypass flows are used in non-statistical and statistical analyses respectively. The TDBF is the conservatively high core bypass flow used in calculations where the results are adversely affected by low core flow. Specifically, TDBF is used with the vessel thermal design flow (TDF) in power capability analyses that use standard (non-statistical) methods. The TDBF is also used with the vessel best-estimate flow (BEF) to calculate core and fuel assembly pressure drops. The BEBF is the flow that would be expected using nominal values for dimensions and operating parameters that affect bypass flow without applying any uncertainty factors.

The BEBF is used in conjunction with the vessel minimum measured flow (MMF) for power capability analyses that use the Improved Thermal Design Procedure (ITDP) or RTDP (statistical methodology). It is also used to calculate fuel assembly lift forces. For the Prairie Island units, the maximum permissible TDBF is 6.0 percent and [ I .

4.6 THERMAL-HYDRAULIC DESIGN PARAMETERS Table 4-1 lists numerous thermal-hydraulic parameters for the current design basis at 1650 MWt with OFA fuel. Some of the parameters listed in Table 4-1 are used in the analysis basis as VIPRE-W input parameters while others are simply provided since they are listed in the USAR. This section will identify those parameters that are used as input parameters to the VIPRE-W model and will also identify the limiting direction of each parameter. The following parameters from Table 4-1 are used in the VIPRE-W model:

• Reactor core heat output (MWt)

• Core pressure for RTDP analyses (psia)

• Heat generated in fuel (%)

• Average heat flux (btulhr-ft 2 )

• Nominal vessel/core inlet temperature (0F)

• FNaH, nuclear enthalpy rise hot-channel factor

• Pressurizer/core pressure (psia)

• TDF for non-RTDP analyses (gpm)

• MMF for RTDP analyses (gpm)

In addition, the average linear power (kW/ft) is used in the PAD analyses for the fuel temperatures and other fuel rod design criteria.

The limiting direction for these parameters is as shown in Table 4-5.

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4-5

4.7 CONCLUSION

The thermal-hydraulic evaluation of the OFA fuel for the Prairie Island units has shown that the DNB margin calculated through use of the RTDP methodology with the WRB-1 DNB correlation is sufficient to allow operation at the power of 1650 MWt. More than sufficient DNBR margin in the safety limit DNBR exists to cover any rod bow and instrumentation bias. All current thermal-hydraulic design criteria are satisfied.

4.8 REFERENCES

4-1 Davidson, S. L., "Reload Transition Safety Report for Point Beach Units 1 and 2,"

September 1983.

4-2 "Reload Transition Safety Report for the Kewaunee Nuclear Power Plant," KEW-RTSR-02-021.

4-3 "Updated Safety Analysis Report - Point Beach Nuclear Power Plant, Units Number 1 and 2,"

Docket Nos. 50-266 and 50-301, June 2001 FSAR Update.

4-4 "Updated Safety Analysis Report - Kewaunee Nuclear Power Plant," Docket Nos. 50-305, December 2000 FSAR Update.

4-5 Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-1 1397-P-A, April 1989.

4-6 Motley, F. E., Hill, K. W., Cadek, F. F., Shefcheck, J., "New Westinghouse Correlation WRB-1 for Predicting Critical Heat Flux in Rod Bundles with Mixing Vane Grids," WCAP-8762-P-A, July 1984.

4-7 Sung, Y.X., et al., "VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCAThermal-Hydraulic Safety Analysis," WCAP-14565-P-A (Proprietary),

October 1999.

4-8 D. A. Rothrock, "Prairie Island: Transmittal of RTDP Input Uncertainties, OTDT and OPDT Parameters and Pressurizer Pressure Low Reactor Trip Analytical Limit Confirmation,"

OC.WES.PX.XX.2003.007, February 2003.

4-9 Spier, E. M., "Evaluation of Nuclear Hot Channel Factor Uncertainties," WCAP-7308-L-P-A, June 1988.

4-10 Skaritka, J., "Fuel Rod Bow Evaluation," WCAP-8691, Revision 1, July 1979.

4-11 Letter from Rahe, E. P., Jr. (Westinghouse) to Miller, J. R. (NRC), "Partial Response to Request Number 1 for Additional Information on WCAP-8691, Revision 1," NS-EPR-2515, October 9, 198 1; and Letter from Rahe, E. P., Jr. (Westinghouse) to Miller, J. R. (NRC),

"Remaining Response to Request Number 1 for Additional Information on WCAP-869 1, Revision 1," NS-EPR-2572, March 16, 1982.

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4-6 4-12 Letter from Berlinger, C. (NRC) to Rahe, E. P., Jr. (Westinghouse), "Request for Reduction in Fuel Assembly Bumup Limit for Calculation of Maximum Rod Bow Penalty," June 18, 1986. u 4-13 Weiner, R. A., "Prairie Island 14x14 OFA VANTAGE+ Generic Fuel Rod," PAC-93-014-0.

Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 1604

4-7 Table 4-1 Prairie Island Thermial-Hydraulic Design Parameters Comparison Thermal-Hydraulic Design Parameters (using RTDP) Analysis Value Reactor Core Heat Output, MWt 1650 Reactor Core Heat Output, 106, Btu/hr 5630 Heat Generated in Fuel, % 97.4 Core Pressure, Nominal - RTDP, psia 2265 Pressurizer Pressure, Nominal, psia 2250 Radial Power Distribution (FN )(l)1.77[1+0.3(1-P)], OFA where p = Thermal Power Rated Thermal Power HFP Nominal Coolant Conditions Vessel MMF Rate (including bypass):

106 Ibrn/hr 70.5 gpm 182,500 Vessel TDF Rate (including bypass):

106 Ibm/hr 68.8 gpm 178,000 Core Flow Rate (excluding Bypass,2) based on TDF):

106 lbm/hr 64.7 gpm 167,320 Core Flow Area, ft2 29.2 (full-core OFA)

Core Inlet Mass Velocity, (excluding bypass, based on TDF):

106 Ibm/hr-ft2 2.19 Notes:

1. Includes 4% measurement uncertainty.

2. Based on design bypass flow of 6% for current design value.

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4-8 Table 4-1 Prairie Island Thermal-Hydraulic Design Parameters Comparison (cont.)

Thermal-Hydraulic Design Parameters (based on TDF) Analysis Value Nominal Vessel/Core Inlet Temperature, 0F 527.9 Vessel Average Temperature, 0F 560.0 Core Average Temperature, 0F 563.2 Vessel Outlet Temperature, IF 592.1 Core Outlet Temperature, 0F 595.8 Average Temperature Rise in Vessel, IF 64.2 Average Temperature Rise in Core, 0F 67.9 Heat Transfer Active Heat Transfer Surface Area, ft* 28,655 Average Heat Flux, Btulhr-ft2 196,475 Average Linear Power, kwlft 6.36 Peak Linear Power for Normal Operation,0 3 kW/ft 15.9 Peak Linear Power for Prevention of Centerline Melt, kW/ft 22.83 Pressure Drop Across Core, psi(4 Full core of OFA 24.056 Notes:

3. Based on maximum FQ of 2.50.

4. Based on best estimate reactor flow rate of 98,500 gpm/loop.

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4-9 Table 4-2 Peaking Factor Uncertainties F&H = FNMx FE where: FNH Nuclear Enthalpy Rise Hot Channel Factor - The ratio of the relative power of the hot rod, which is one of the rods in the hot channel, to the average rod power. The normal operation value of this is given in the plant Technical Specifications or a Core Operating Limit Report (COLR).

FEH Engineering Enthalpy Rise Hot Channel Factor - The nominal enthalpy rise in an isolated hot channel can be calculated by dividing the nominal power into this channel by the core average inlet flow per channel. The engineering enthalpy rise hot channel factor accounts for the effects of flow conditions and fabrication tolerances. It can be written symbolically as:

F f ,H.1F, 62, 1 fA(H maldist, FEH reudist, InHlt FE mixing) where: FEH.1 Accounts for rod-to-rod variations in fuel enrichment and weight FE; -2 Accounts for variations in fuel rod outer diameter, rod pitch, and bowing F AH inlet malist Accounts for the nonuniform flow distribution at the core inlet F AH feist lAccounts for flow redistribution between adjacent channels due to the different thermal-hydraulic conditions between channels FE H mixing Accounts for thermal diffusion energy exchange between adjacent channels caused by both natural turbulence and forced turbulence due to the mixing vane grids The value of these factors and the way in which they are combined depends upon the design methodology used, that is, STDP or RTDP. Note that no actual combined effect value is calculated for FE&H. These factors are accounted for by using the VIPRE-W code.

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4-10 Table 4-3 RTDP Uncertainties Uncertainty Used in Parameter Calculated Uncertainty Thermal-Hydraulic Design Power +/-1.62% power a,c no bias Reactor Coolant System Flow -2.5% flow no bias Pressure +/-37.2 psi no bias Inlet Temperature +/-3.20 F

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4-11 Table 4-4 DNBR Margin Summary'l)

DNB Correlation WRB-1 DNBR Correlation Limit 1.17 DNBR Design Limit (TYP)( 2 ) 1.22 (THM)03) 1.22 DNBR Safety Limit (iTY) 1.34 (THM) 1.34 ac t

Notes:

1. Steam line break is analyzed using the W-3 correlation with STDP. The correlation limit DNBR is 1.45 in the range of 500 to 1000 psia. Rod withdrawal from subcritical is also analyzed using the W-3 correlation (w/o spacer factor) with STDP below the bottom non-mixing vane (NMV) grid. I WRB-I with RTDP is used for rod withdrawal from subcritical above the bottom NMV grid.

2. TYP - Typical Cell

3. THM=ThimbleCell

]

[

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4-12 Table 4-5 Limiting Parameter Direction K>

Parameter Limiting Direction for DNB a,c

\K)

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4-13 aFc Figure 4-1 Fuel Average Temperatures Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

4-14 a,c Figure 4-2 Rod Internal Pressure Prairie Island Licensing Report st January 2004 6296- RNP.doc-0 11 604

4-15 a,c Figure 4-3 Fuel Surface Temperatures Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

4-16 a,c

'F4t m

Figure 4-4 Fuel Centerline Temperatures Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 11604

5-1 5 ACCIDENT ANALYSES 5.1 NON-LOCA ANALYSES This section summarizes the non-LOCA transient analyses and evaluations performed to support the transition to Westinghouse methodology, with consideration for the original Westinghouse Model 51 steam generators and the Framatome Advanced Nuclear Power (ANP) Model 56/19 replacement steam generators at the Prairie Island Nuclear Generating Plant (PINGP).

5.1.0 Introduction 5.1.0.1 Fuel Design Mechanical Features The fuel currently in use at PINGP is the Westinghouse 14x14 Optimized Fuel Assembly (OFA) with Gadolinia as the burnable absorber. Detailed information on the fuel design is provided in Section 2.0.

With respect to the non-loss-of-coolant-accident (LOCA) transient analyses, the effects of fuel design mechanical features are accounted for in fuel-related input assumptions such as fuel and cladding dimensions, cladding material, fuel temperatures, and core bypass flow.

5.1.0.2 Peaking Factors, Kinetics Parameters The power distribution is characterized by a nuclear enthalpy rise hot channel factor (radial peaking, FNAH) of 1.70 for analyses employing the Revised Thermal Design Procedure (RTDP, Reference 5.1.0-1) and 1.77 for non-RTDP analyses, and a full power heat flux hot channel factor (total peaking, FQ) of 2.50.

FNAH is important for transients that are analyzed for departure from nucleate boiling (DNB) concerns (Table 5.1-1 identifies which events are analyzed for DNB concerns, as well as the DNB methodology used, RTDP or non-RTDP). As FN,&H increases with decreasing power level, due to rod insertion, all transients analyzed for DNB concerns are assumed to begin with an FNAH consistent with the FN]H defined in the Technical Specifications Core Operating Limits Report (COLR) for the assumed nominal power level. The FQ, for which the limits are specified in the COLR, is important for transients that are analyzed for overpower concerns, e.g., rod cluster control assembly (RCCA) ejection.

The minimum shutdown margin at hot zero power conditions, with the most reactive RCCA fully withdrawn, is assumed to be 1.7-percent Ak/k. This was assumed in the hot zero power steam line break analysis.

5.1.0.3 Safety Analysis Transition Program Features Key Safety Analysis Transition Program features that were considered in the non-LOCA transient analyses are as follows:

• A nuclear steam supply system (NSSS) power level of 1,657 MWt (includes a guaranteed minimum 7 MWt of pump heat, consistent with the licensed core power of 1,650 MWt).

• A nominal, full power reactor coolant vessel average temperature (Tavg) of 560'F.

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5-2

• A reactor coolant system (RCS) thermal design flow (TDF) of 178,000 gpm.

• Westinghouse Model 51 original steam generators (OSGs) with a maximum steam generator tube plugging (SGTP) of 25 percent, and Framatome ANP Model 56/19 replacement steam generators (RSGs) with a maximum SGTP of 10 percent. A maximum loop-to-loop tube plugging asymmetry of 10 percent has been addressed.

• A nominal operating pressurizer pressure of 2,250 psia.

For most transients that are analyzed for DNB concerns, the RTDP methodology (Reference 5.1.0-1) is employed. With this methodology, nominal values are assumed for the initial conditions of power, temperature, pressure, and flow, and the corresponding uncertainty allowances are accounted for statistically in defining the departure from nucleate boiling ratio (DNBR) safety analysis limit. The nominal RCS flow assumed in RTDP transient analyses is the minimum measured flow (MMF) of 182,500 gpm, and the difference between TDF and MMF is the flow uncertainty.

As discussed in Section 4.0, uncertainties in plant operating parameters, nuclear and thermal parameters, fuel fabrication parameters, computer codes, and DNB correlation predictions are combined statistically to obtain the overall DNB uncertainty factor, which is used to define the design limit DNBR (1.22 for both typical and thimble cells). In other words, the design limit DNBR is a DNBR value that is greater than the WRB-1 DNB correlation limit (1.17) by an amount that accounts for the RTDP uncertainties. To provide DNBR margin to offset various penalties such as those due to rod bow and instrument bias, and to provide flexibility in design and operation of the plant, the design limit DNBR is conservatively increased to a value designated as the safety analysis limit DNBR, to which transient-specific DNBR values are compared. The DNBR safety analysis limit selected for Prairie Island is 1.34 for both typical and thimble cells.

For transient analyses that are not DNB-limited, or for which RTDP is not employed, the initial conditions are obtained by applying the maximum, steady-state uncertainties to the nominal values in the most conservative direction; this is known as Standard Thermal Design Procedure (STDP) or non-RTDP. In these analyses, the RCS flow is assumed to be equal to the TDF, and the following steady-state initial condition uncertainties are applied:

• The NSSS power allowance for calorimetric uncertainty is +/- 2 percent,

• The Tavg allowance for deadband and system measurement uncertainties is + 40 F,

• The pressurizer pressure allowance for steady-state fluctuations and measurement uncertainties is

+/- 40 psi.

5.1.0.4 Other Major Assumptions Table 5.1-2 lists the non-LOCA initial condition assumptions used. Other major assumptions considered in the non-LOCA transient analyses are discussed below:

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5-3

1. A +/- 3-percent setpoint tolerance has been considered in the modeling of the main steam safety valves (MSSVs). Staggered lift setpoints are modeled for the MSSVs using plant-specific Technical Specification setpoints, as shown in Table 5.1-3.

2. The pressurizer safety valves (PSVs) are modeled assuming a + 3-percent setpoint tolerance.

Additionally, when it is conservative to do so (that is, for peak RCS pressure concerns), the effects of the PSV loop seals are explicitly modeled, as discussed in Reference 5.1.0-2. See Table 5.1-3 for more information.

3. Consistent with the PINGP Technical Specifications (COLR), for minimum reactivity feedback, a maximum isothermal temperature coefficient (ITC) of +5 pcm/0 F is applicable for power levels up to 70-percent, and a 0 pcmI0 F ITC is applicable for power levels greater than 70 percent. For maximum reactivity feedback, a maximum moderator density coefficient (MDC) of at least 0.43 Akfglcc was assumed.

4. The fission product contribution to decay heat assumed in the non-LOCA analyses is consistent with the American National Standards Institute/American Nuclear Society standard ANSIIANS-5.1-1979 for decay heat power in light water reactors (Reference 5.1.0-3), including two standard deviations of uncertainty.

5. As PINGP is not licensed to operate at-power with a single reactor coolant pump (RCP) in operation (Technical Specification 3.4.4), the non-LOCA analyses only address two-loop operation.

6. The assumed core bypass flow percentages are 4.5 percent for RTDP analyses and 6.0 percent for STDP analyses.

5.1.0.5 Overtemperature and Overpower AT Reactor Trip Setpoints The overtemperature and overpower AT (OTAT/OPAT) reactor trip setpoints were recalculated using the the methodology described in WCAP-8745-P-A (Reference 5.1.04). Conservative core thermal limits, developed using the RTDP methodology as described in Section 4.0, were assumed. The core limits are applicable to 14x14 OFA fuel, with a norminal core power of 1,650 MWt and nominal RCS pressure of 2,250 psia. The core thermal limits used to calculate the OTAT/OPAT setpoints are provided in Figure 5.1-1 and in the corresponding Technical Specification (COLR) figure. The OTAT and OPAT trip setpoints are illustrated in Figure 5.1-2 and presented in Table 5.14.

The adequacy of these setpoints is confirmed by showing that the DNB design basis is met in the analyses of those events that credit these functions for accident mitigation. The revised safety analysis setpoints are based upon the assumption that the reference average temperature (T') used in the OTAT and OPAT setpoint equations is equal to the nominal full power Ta.g of 560'F.

The boundaries of operation defined by the OTAT and OPAT trips are represented as "protection lines" in Figure 5.1-2. The protection lines are drawn to include all adverse instrumentation and setpoint errors so that under nominal conditions, a trip would occur well within the area bounded by these lines. These protection lines are based upon the safety analysis limit OTAT and OPAT setpoint values, which are Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-4 essentially the Technical Specification nominal values with allowances for instrumentation errors and acceptable drift between instrument calibrations. The utility of this diagram is in the fact that the limit imposed by any given DNBR can be represented as a line (AT versus Tad. The DNB lines represent the locus of conditions for which the DNBR equals the limit value (1.34 for both typical and thimble cells).

All points below and to the left of a DNB line for a given pressure have a DNBR greater than the safety analysis limit DNBR value.

The area of permissible operation (power, temperature, and pressure) is bounded by the combination of the high neutron flux (fixed setpoint), high and low pressurizer pressure (fixed setpoints), and OTAT and OPAT (variable setpoints) reactor trips, and the opening of the MSSVs, which limits the maximum RCS average temperature. The adequacy of the OTAT and OPAT setpoints has been confirmed by demonstrating that the DNB design basis is met for those transients analzed for DNB concerns.

As a result of the revised OTAT and OPAT setpoint equations, it is recommended that the temperature ranges provided below be used for the resistance temperature detector (RTD) instrumentation. Also, as appropriate, changes should be made to the applicable setpoints document for the plant.

• Tcod: 500'F - 640'F

• Tho,: 500F - 640'F

• Tvg: 520'F - 620 0 F

• AT: 0 0 F - 100'F 5.1.0.6 RPS and ESFAS Functions Assumed in Analyses Table 5.1-5 contains a list of the different reactor protection system (RPS) and engineered safety features actuation system (ESFAS) functions credited in the non-LOCA transient analyses. The safety analysis setpoints, as well as the time delays associated with each of these functions, are also presented in Table 5.1-5.

5.1.0.7 RCCA Insertion Characteristics The negative reactivity insertion following a reactor trip is a function of the acceleration of the RCCAs and the variation in rod worth as a function of rod position. With respect to the non-LOCA transient analyses, the critical parameter is the time from beginning of RCCA insertion to dashpot entry, or approximately 85 percent of the RCCA travel, although negative reactivity addition continues to be modeled until rods are completely inserted. For the non-LOCA analyses, the assumed insertion time from fully withdrawn to dashpot entry is 2.4 seconds (based on full core flow), which bounds the Technical Specification limit of 1.8 seconds. For the analyses of the loss of reactor coolant flow transients (flow coast down and locked rotor), shorter (but still conservative) rod drop times are assumed, consistent with the reduced core flows at the time of reactor trip.

Three figures relating to RCCA drop time and reactivity worth are presented in this report. The RCCA position (fraction of full insertion) versus the time from release is presented in Figure 5.1-3. The normalized reactivity worth assumed in the safety analyses is shown in Figure 5.1-4 as a function of rod insertion fraction and in Figure 5.1-5 as a function of time.

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5-5 5.1.0.8 Reactivity Coefficients The transient response of the reactor core is dependent on reactivity feedback effects, in particular the ITC and the Doppler power coefficient (DPC). Depending upon event-specific characteristics, conservatism dictates the use of either maximum or minimum reactivity coefficient values. Justification for the use of the reactivity coefficient values is treated on an event-specific basis. Table 5.1-6 presents the core kinetics parameters and reactivity feedback coefficients assumed in the non-LOCA analyses.

The maximum and minimum integrated DPCs assumed in the safety analyses are provided in Figure 5.1-6. Note that the hot zero power steam line break core response analysis uses a different DPC, which is based on an RCCA being stuck out of the core (not shown in Figure 5.1-6 (see Figure 5.1.13-8 in Section 5.1.13)).

5.1.0.9 Computer Codes Utilized Summary descriptions of the principal computer codes used in the non-LOCA transient analyses are provided below. Table 5.1-7 lists the computer codes used in each of the non-LOCA analyses.

FACTRAN FACTRAN calculates the transient temperature distribution in a cross-section of a metal clad U0 2 fuel rod and the transient heat flux at the surface of the cladding, using as input the nuclear power and the time-dependent coolant parameters of pressure, flow, temperature, and density. The code uses a fuel model that simultaneously contains the following features:

• A sufficiently large number of radial space increments to handle fast transients such as a rod ejection accident,

• Material properties that are functions of temperature and a sophisticated fuel-to-cladding gap heat transfer calculation, and

• The necessary calculations to handle post-DNB transients: film boiling heat transfer correlations, Zircaloy-water reaction, and partial melting of the fuel.

The FACTRAN licensing topical report, WCAP-7908-A (Reference 5.1.0-5), was approved by the Nuclear Regulatory Commission (NRC) via a Safety Evaluation Report (SER) from C. E. Rossi (NRC) to E. P.Rahe (Westinghouse), dated September 30, 1986. The FACTRAN SER identifies seven conditions of acceptance, which are summarized below along with justifications for application to Prairie Island.

1. "The fuel volume-averagedtemperatureor surface temperaturecan be chosen at a desired value which includes conservatisms reviewed and approved by the NRC."

Justification The FACTRAN code was used in the analyses of the following transients for Prairie Island:

Uncontrolled RCCA Withdrawal from a Subcritical Condition (USAR 14.4.1) and RCCA January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-6 Ejection (USAR 14.5.6). Initial fuel temperatures used as FACTRAN input in the RCCA Ejection analysis were calculated using the NRC-approved PAD 3.4 computer code, as described in WCAP-1085 1-P-A (Reference 5.1.0-6). As indicated in WCAP-10851-P-A, the NRC has approved the method of determining uncertainties for PAD 3.4 fuel temperatures.

2. "Table 2 presents the guidelines used to select initial temperatures."

Justification In summary, Table 2 of the SER specifies that the initial fuel temperatures assumed in the FACTRAN analyses of the following transients should be "High" and include uncertainties: loss of flow, locked rotor, and rod ejection. As discussed above, fuel temperatures were used as input to the FACTRAN code in the RCCA ejection analysis for Prairie Island. The assumed fuel temperatures, which were calculated using the PAD 3.4 computer code (Reference 5.1.0-6),

include uncertainties and are conservatively high. FACTRAN was not used in the loss of flow and locked rotor analyses.

3. "The gap heat transfercoefficient may be held at the initialconstant value or can be variedas a function of time as specifled in the input."

Justification The gap heat transfer coefficients applied in the FACTRAN analyses are consistent with SER Table 2. For the RCCA withdrawal from a subcritical condition transient, the gap heat transfer coefficient is kept at a conservative constant value throughout the transient; a high constant value is assumed to maximize the peak heat flux (for DNB concerns) and a low constant value is assumed to maximize fuel temperatures. For the RCCA ejection transient, the initial gap heat transfer coefficient is based on the predicted initial fuel surface temperature, and is ramped rapidly to a very high value at the beginning of the transient to simulate clad collapse onto the fuel pellet.

4. ". .. the Bishop-Sandberg-Tong correlationis sufficiently conservative and can be used in the FACTRAN code. It should be cautionedthat since these correlationsare applicablefor local conditions only, it is necessaryto use input to the FACTRAN code which reflects the local conditions. If the input values reflecting average conditions are used, there must be sufficient conservatism in the input values to make the overall method conservative."

Justification Local conditions related to temperature, heat flux, peaking factors and channel information were input to FAC7RAN for each transient analyzed for Prairie Island {RCCA withdrawal from a subcritical condition [Updated Safety Analysis Report (USAR 14.4.1)] and RCCA ejection (USAR 14.5.6)). Therefore, additional justification is not required.

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5-7

5. "Thefuel rod is divided into a number of concentric rings. 'The maximum number of rings used to representthefuel is 10. Based on our audit calculationswe require that the minimum of 6 should be used in the analyses."

Justification At least 6 concentric rings were assumed in FACTRAN for each transient analyzed for Prairie Island (RCCA withdrawal from a subcritical condition (USAR 14.4.1) and RCCA ejection (USAR 14.5.6)).

6. "Although time-independent mechanical behavior (e.g., thermal expansion, elasticdeformation) of the cladding are considered in FACTRAN, time-dependent mechanical behavior (e.g., plastic deformation) is not considered in the code. ...for those events in which the FACTRAN code is applied(see Table 1), significant time-dependent deformation of the cladding is not expected to occur due to the short duration of these events or low cladding temperatures involved (where DNBR Limits apply), or the gap heat transfercoefficient is adjusted to a high value to simulate clad collapse onto the fuel pellet."

Justification The two transients that were analyzed with FACTRAN for Prairie Island (RCCA withdrawal from a subcritical condition (USAR 14.4.1) and RCCA ejection (14.5.6)) are included in the list of transients provided in Table 1 of the SER; each of these transients is of short duration. For the RCCA withdrawal from a subcritical condition transient, relatively low cladding temperatures are involved, and the gap heat transfer coefficient is kept constant throughout the transient. For the RCCA ejection transient, a high gap heat transfer coefficient is applied to simulate clad collapse onto the fuel pellet. The gap heat transfer coefficients applied in the FACTRAN analyses are consistent with SER Table 2.

7. "The one group diffusion theory model in the FACTRAN code slightly overestimates at beginning of life (BOL) and underestimatesat end of life (EOL) the magnitude offiux depression in the fuel when compared to the LASER code predictionsfor the same fuel enrichment. The LASER code uses transporttheory. There is a difference of about 3 percent in the flux depression calculated using these two codes. When [T(centerline) - T(Surface)J is on the order of 3000°F which can occur at the hot spot, the difference between the two codes will give an errorof I000 E When the fuel surface temperature is fixed, this will result in a 100YF lower prediction of the centerline temperaturein FACTRAN. We have indicatedthis apparentnonconservatism to Westinghouse. In the letter NS-TMA -2026, datedJanuary12, 1979, Westinghouse proposed to incorporatethe LASER-calculated power distribution shapes in FACTRAN to eliminate this non-conservatism.

We find the use of the LASER-calculated power distributionin the FACTRAN code acceptable."

Justification The condition of concern (T(centerline) - T(surface) on the order of 3000'F) is expected for transients that reach, or come close to, the fuel melt temperature. As this applies only to the Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-8 RCCA ejection transient, the LASER-calculated power distributions were used in the FACTRAN analysis of the RCCA ejection transient for Prairie Island.

RETRAN RETRAN is used for studies of transient response of a pressurized water reactor (PWR) system to specified perturbations in process parameters. This code simulates a multi-loop system by a lumped parameter model containing the reactor vessel, hot- and cold-leg piping, RCPs, steam generators (tube and shell sides), main steam lines, and the pressurizer. The pressurizer heaters, spray, relief valves, and safety valves may also be modeled. RETRAN includes a point neutron kinetics model and reactivity effects of the moderator, fuel, boron, and control rods. The secondary side of the steam generator uses a detailed nodalization for the thermal transients. The RPS simulated in the code includes reactor trips on high neutron flux, high neutron flux rate, OTAT and OPAT, low RCS flow, high and low pressurizer pressure, high pressurizer level, and low-low steam generator water level. Control systems are also simulated including rod control and pressurizer pressure control. Parts of the safety injection system (SIS), including the accumulators, may also be modeled. RETRAN approximates the transient value of DNBR based on input from the core thermal safety limits.

The RETRAN licensing topical report, WCAP-14882-P-A (Reference 5.1.0-7), was approved by the NRC via an SER from F.Akstulewicz (NRC) to H. Sepp (Westinghouse), dated February 11, 1999. The RETRAN SER identifies three conditions of acceptance, which are summarized below along with justifications for application to Prairie Island.

1. "The transientsand accidents that Westinghouse proposes to analyze with RETRAN are listed in this SER (Table 1) and the NRC staff review of RETRAN usage by Westinghouse was limited to this set. Use of the code for other analyticalpurposes will requireadditionaljustification."

Justification The transients listed in Table 1 of the SER are:

• Feedwater system malfunctions

• Excessive increase in steam flow

• Inadvertent opening of a steam generator relief or safety valve

• Steam line break

• Loss of external load/turbine trip

• Loss of offsite power

• Loss of normal feedwater flow

• Feedwater line rupture

• Loss of forced reactor coolant flow

• Locked reactor coolant pump rotor/sheared shaft

• Control rod cluster withdrawal at power

• Dropped control rod cluster/dropped control bank

• Inadvertent increase in coolant inventory

• Inadvertent opening of a pressurizer relief or safety valve

• Steam generator tube rupture Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-9 The transients analyzed for Prairie Island using RETRAN are:

• Uncontrolled RCCA withdrawal at power (USAR 14.4.1)

• Excessive heat removal due to feedwater system malfunctions (USAR 14.4.6)

• Excessive load increase incident (USAR 14.4.7)

• Loss of reactor coolant flow (flow coast down and locked rotor) (USAR 14.4.8)

• Loss of external electrical load (USAR 14.4.9)

• Loss of normal feedwater (USAR 14.4. 10)

• Loss of all AC power to the station auxiliaries (USAR 14.4.11)

• Steam line break (USAR 14.5.5)

As each transient analyzed for Prairie Island using RETRAN matches one of the transients listed in Table 1 of the SER, additional justification is not required.

2. "WCAP-14882 describes modeling of Westinghouse designed 4-, 3, and 2-loop plants of the type that are currentlyoperating. Use of the code to analyze other designs, including the Westinghouse AP600, will require additionaljustification."

Justification The Prairie Island Nuclear Generating Plant consists of two 2-loop Westinghouse-designed units that were "currently operating" at the time the SER was written (February 11, 1999). Therefore, additional justification is not required.

3. "Conservativesafety analyses using RETRAN are dependent on the selection of conservative input. Acceptable methodologyfordeveloping plant-specific input is discussed in WCAP-14882 and in Reference 14 lWCAP-9272-P-AJ. Licensing applicationsusing RETRAN should include the source of andjustificationfor the input data used in the analysis."

Justification The input data used in the RETRAN analyses performed by Westinghouse came from both NMC and Westinghouse sources. Assurance that the RETRAN input data is conservative for Prairie Island is provided via Westinghouse's use of transient-specific analysis guidance documents.

Each analysis guidance document provides a description of the subject transient, a discussion of the plant protection systems that are expected to function, a list of the applicable event acceptance criteria, a list of the analysis input assumptions (e.g., directions of conservatism for initial condition values), a detailed description of the transient model development method, and a discussion of the expected transient analysis results. Based on the analysis guidance documents, conservative plant-specific input values were requested and collected from the responsible NMC and Westinghouse sources. Consistent with the Westinghouse Reload Evaluation Methodology described in WCAP-9272-P-A (Reference 5.1.0-8), the safety analysis input values used in the Prairie Island analyses were selected to conservatively bound the values expected in subsequent operating cycles.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-IRNPADoc-01 1604

5-10 LOFTRAN Transient response studies of a PWR to specified perturbations in process parameters use the LOFTRAN computer code. This code simulates a multi-loop system by a model containing the reactor vessel, hot-and cold-leg piping, steam generators (tube and shell sides), the pressurizer and the pressurizer heaters, spray, relief valves, and safety valves. LOFTRAN also includes a point neutron kinetics model and reactivity effects of the moderator, fuel, boron, and rods. The secondary side of the steam generator uses a homogeneous, saturated mixture for the thermal transients. The code simulates the RPS, which includes reactor trips on high neutron flux, OTAT and OPAT, high and low pressurizer pressure, low RCS flow, lo-lo steam generator water level, and high pressurizer level. Control systems are also simulated including rod control, steam dump, and pressurizer pressure control. The SIS, including the accumulators, is also modeled. LOFTRAN can also approximate the transient value of DNBR based on input from the core thermal safety limits.

The LOFTRAN licensing topical report, WCAP-7907-P-A (Reference 5.1.0-9), was approved by the NRC via an SER from C. 0. Thomas (NRC) to E. P.Rahe (Westinghouse), dated July 29, 1983. The LOFTRAN SER identifies one condition of acceptance, which is summarized below along with justification for application to Prairie Island.

1. "LOFTRAN is used to simulate plant response to many of the postulated events reportedin Chapter 15 of PSARs and FSARs, to simulate anticipatedtransientswithout scram, for equipment sizing studies, and to define mass/energy releasesforcontainmentpressure analysis. The Chapter 15 events analyzed with LOFTRAN are:

- FeedwaterSystem Malfunction

- Excessive Increase in Steam Flow

- Inadvertent Opening of a Steam GeneratorRelief or Safety Valve

- Steamline Break

- Loss of External Load

- Loss of Offsite Power

- Loss of Normal Feedwater

- FeedwaterLine Rupture

- Loss of Forced Reactor Coolant Flow

- Locked Pump Rotor

- Rod Withdrawal at Power

- Rod Drop

- Startup of an Inactive Pump

- Inadvertent ECCS Actuation

- Inadvertent Opening of a PressurizerRelief or Safety Valve This review is limited to the use of LOFTRANfor the licensee safety analyses of the Chapter15 events listed above, andfor a steam generatortube rupture..."

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-11 Justification For Prairie Island, the LOFTRAN code was only used in the analyses of the dropped rod transient (USAR 14.4.3). As this transient matches one of the transients listed in the SER, additional justification is not required.

TWiNKLE TWINKLE is a multi-dimensional spatial neutron kinetics code. The code uses an implicit finite-difference method to solve the two-group transient neutron diffusion equations in one, two, and three dimensions. The code uses six delayed neutron groups and contains a detailed multi-region fuel-cladding-coolant heat transfer model for calculating pointwise Doppler and moderator feedback effects.

The code handles up to 8,000 spatial points and performs steady-state initialization. Aside from basic cross-section data and thermal-hydraulic parameters, the code accepts as input basic driving functions such as inlet temperature, pressure, flow, boron concentration, control rod motion, and others. The code provides various outputs, such as channelwise power, axial offset, enthalpy, volumetric surge, pointwise power, and fuel temperatures. It also predicts the kinetic behavior of a reactor for transients that cause a major perturbation in the spatial neutron flux distribution.

The TWINKLE licensing topical report, WCAP-7979-P-A (Reference 5.1.0-10), was approved by the U.S. Atomic Energy Commission (AEC) via an SER from D. B. Vassallo (AEC) to R. Salvatori (Westinghouse), dated July 29, 1974. The TWINKLE SER does not identify any conditions, restrictions, or limitations that need to be addressed for application to Prairie Island.

Advanced Nodal Code (ANC)

ANC is an advanced nodal code capable of two-dimensional and three-dimensional neutronics calculations. ANC is the reference model for certain safety analysis calculations, power distributions, peaking factors, critical boron concentrations, control rod worths, reactivity coefficients, etc. In addition, three-dimensional ANC validates one-dimensional and two-dimensional results and provides information about radial (x-y) peaking factors as a function of axial position. It can calculate discrete pin powers from nodal information as well.

The ANC licensing topical report, WCAP-10965-P-A (Reference 5.1.0-11), was approved by the NRC via an SER from C. Berlinger (NRC) to E. P. Rahe (Westinghouse), dated June 23, 1986. The ANC SER does not identify any conditions, restrictions, or limitations that need to be addressed for application to Prairie Island.

VIPRE The VIPRE computer program performs thermal-hydraulic calculations. This code calculates coolant density, mass velocity, enthalpy, void fractions, static pressure, and DNBR distributions along flow channels within a reactor core.

The VIPRE licensing topical report, WCAP-14565-P-A (Reference 5.1.0-12), was approved by the NRC via an SER from T. H. Essig (NRC) to H. Sepp (Westinghouse), dated January 19, 1999. The VIPRE January 2004 Prairie Island Licensing Report island Licensing Report January 2004 6296- RNP.doc-01 1604

5-12 SER identifies four conditions of acceptance, which are summarized below along with justification for application to Prairie Island.

1. "Selection of the appropriateCHFcorrelation, DNBR limit, engineered hot channelfactorsfor enthalpy rise and otherfuel-dependentparametersfora specific plant applicationshould be justified with each submittal" Justification The WRB-I correlation with a 95/95 correlation limit of 1.17 was used in the DNB analyses for the Prairie Island OFA fuel. The use of the WRB-1 DNB correlation for the 14x14 OFA fuel was approved in June 29, 1984 (Letter from C. 0. Thomas (NRC) to E. P.Rahe (Westinghouse), "SER on the Applicability of WRB-1 to Westinghouse 14x14 and 15x15 OFA").

The use of the plant specific hot channel factors and other fuel dependent parameters in the DNB analysis for the Prairie Island OFA fuel were justified using the same methodologies as for previously approved safety evaluations of other Westinghouse two-loop plants using the same fuel design.

2. "Reactor core boundary conditionsdetermined using other computer codes are generally input into VIPREfor reactortransientanalyses. These inputs include core inlet coolantflow and enthalpy, core averagepower, power shape and nuclearpeakingfactors. These inputs should be justified as conservativefor each use of VIPRE."

Justification The core boundary conditions for the VIPRE calculations for the OFA fuel are all generated from NRC-approved codes and analysis methodologies. Conservative reactor core boundary conditions were justified for use as input to VIPRE. Continued applicability of the input assumptions is verified on a cycle-by-cycle basis using the Westinghouse reload methodology described in WCAP-9272-P-A (Reference 5.1.0-8).

3. "The NRC Staff 's genericSER for VIPRE set requirementsfor use of new CHFcorrelationswith VIPRE. Westinghouse has met these requirementsfor using WRB-1, WRB-2 and WRB-2M correlations. The DNBR limitfor WRB-1 and WRB-2 is 1.17. The WRB-2M correlationhas a DNBR limit of 1.14. Use of other CHFcorrelationsnot currently included in VIPRE will require additionaljustification."

Justification As discussed in response to Condition 1,the WRB-1 correlation with a limit of 1.17 was used for the DNB analyses of OFA fuel in Prairie Island. For conditions where WRB-1 is not applicable, the W-3 DNB correlation was used with a limit of 1.30 (1.45, for pressures between 500 psia and 1,000 psia).

Prairie Island Licensing Report January 2004 January 2004 6296-LR-NP.doc-01 1604

5-13

4. "Westinghouse proposes to use the VIPRE code to evaluatefuel performancefollowing postulated design-basisaccidents, including beyond-CHFheat transferconditions. These evaluations are necessary to evaluate the extent of core damage and to ensure that the core maintainsa coolable geometry in the evaluation of certain accidentscenarios. The NRC Staff's generic review of VIPRE did not extend to post CHF calculations. VIPRE does not model the time-dependent physical changes that may occur within the fuel rods at elevated temperatures.

Westinghouse proposes to use conservative input in order to accountfor these effects. The NRC Staff requires that appropriatejustification be submitted with each usage of VIPRE in the post-CHF region to ensure that conservative results are obtained."

Justification For application to Prairie Island safety analysis, the usage of VIPRE in the post-critical heat flux region is limited to the peak clad temperature calculation for the locked rotor transient. The calculation demonstrated that the peak clad temperature in the reactor core is well below the allowable limit to prevent clad embrittlement. VIPRE modeling of the fuel rod is consistent with the model described in WCAP-14565-P-A and included the following conservative assumptions:

- DNB was assumed to occur at the beginning of the transient

- Film boiling was calculated using the Bishop-Sandberg-Tong correlation

- The Baker-Just correlation accounted for heat generation in fuel cladding due to zirconium-water reaction Conservative results were further ensured with the following input:

- Fuel rod input based on the maximum fuel temperature at the given power

- The hot spot power factor was equal to or greater than the design linear heat rate

- Uncertainties were applied to the initial operating conditions in the limiting direction 5.1.0.10 Classification of Events Each of the events listed in Table 5.1-8 is presented in Section 14 of the PINGP USAR (Reference 5.1.0-13). Each non-LOCA event is categorized with respect to its potential consequences.

Most of the transients presented in Section 14.4 of the USAR are events that have no offsite-dose radiation consequences, and are typically expected to occur during a calendar year. The exception to these two criteria is the locked rotor event presented in Section 5.1.9 of this report (Section 14.4.8 of the USAR). The locked rotor event, based on its expected frequency of occurrence and potential radiological consequences, is considered a fault as serious as those presented in Section 14.5 of the USAR. However, because of the similarities between the analysis methodology used for this event and the partial and complete loss-of-reactor-coolant-flow events, which do satisfy both categorization criteria, all three cases are presented together in Section 14.4.8 of the USAR. The design requirements supported by the safety analyses presented in USAR Section 14.4 (except locked rotor) are as follows:

Occurrences are accommodated with, at most, a reactor trip with the plant capable of returning to operation.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-14

• Release of radioactive materials in effluent to unrestricted areas shall be in conformance with the Code of Federal Regulations (CFR) Section 10 CFR 20.

• These incidents shall not generate a more serious incident without other incidents occurring independently.

• There shall be no consequential loss of function of any barrier to the escape of radioactive products (no fuel rod failure or RCS overpressurization).

The transients presented in USAR Section 14.5 and the locked rotor event presented in USAR Section 14.4.8 address faults that are not expected to occur but are postulated because their consequences would include the potential for radioactive releases. These transients are the most drastic design-basis events, and are analyzed to demonstrate compliance with the following requirements:

• Release of radioactive material shall not result in any undue risk to public health and safety, and does not exceed the guidelines of 10 CFR 100.

• There shall be no consequential loss of function of systems needed to cope with the event.

5.1.0.11 Events Evaluated orAnalyzed Each of the USAR transients listed in Table 5.1-1 were evaluated or analyzed as shown in Table 5.1-8 in support of the Safety Analysis Transition Progran. These transient evaluations and analyses demonstrate that all applicable safety analysis acceptance criteria are satisfied for PINGP. Table 5.1-1 summarizes the results obtained for each of the non-LOCA transient analyses. V 5.1.0.12 Analysis Methodology The transient-specific analysis methodologies that were applied to Prairie Island have been reviewed and approved by the NRC via transient-specific topical reports (WCAPs) and/or through the review and approval of plant-specific safety analysis reports. There are only two non-LOCA transients analyzed for Prairie Island that have a transient-specific topical report applicable to Prairie Island: dropped rod (USAR 14.4.3) and RCCA ejection (USAR 14.5.6).

The dropped rod licensing topical report, WCAP-I 1394-P-A (Reference 5.1.0-14), was approved by the NRC via an SER from A. C. Thadani (NRC) to R. A. Newton (Westinghouse Owner's Group), dated October 23, 1989. The dropped rod SER identifies one condition of acceptance, which is summarized below along with justification for application to Prairie Island.

"The Westinghouse analysis, results and comparisonsare reactorand cycle specific. No credit is takenfor any direct reactortrip due to dropped RCCA(s). Also, the analysisassumes no automaticpower reductionfeatures are actuatedby the dropped RCCA(s). A further review by the staff (for each cycle) is not necessary, given the utility assertion that the analysis described by Westinghouse has been performed and the requiredcomparisons have been made withfavorable results."

'KYf January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-0 1 0

5-15 Justification For the reference cycle assumed in the Prairie Island Safety Analysis Transition Program, it is affirmed that the methodology described in WCAP-1 1394-P-A was performed and the required comparisons have been made with acceptable results (DNB limits are not exceeded).

Cycle-specific confirmation will be performed as part of the normal reload evaluation (Reference 5.1.0-8).

The RCCA ejection licensing topical report, WCAP-7588 Rev. 1-A (Reference 5.1.0-15), was approved by the AEC via an SER from D. B. Vassallo (ABC) to R. Salvatori (Westinghouse), dated August 28, 1973. The RCCA ejection SER identifies two conditions of acceptance, which are summarized below along with justification for application to Prairie Island.

1. "The staffposition, as well as that of the reactorvendors over the last several years, has been to limit the averagefuel pellet enthalpy at the hot spotfollowing a rod ejection accident to 280 cal/gm. This was basedprimarilyon the results of the SPERTtests which showed that, in general,fuel failure consequencesfor U02 have been insignificantbelow 300 cal/gm for both irradiatedand unirradiatedfuelrods asfaras rapidfragmentation and dispersaloffuel and cladding into the coolant are concerned. In this report, Westinghouse has decreasedtheir limitingfuelfailure criterionfrom 280 cal/gm (somewhat less than the threshold of significant conversion of thefuel thermal energy to mechanical energy) to 225 caL/gmfor unirradiatedrods and 200 cal/gmfor irradiatedrods. Since this is a conservative revision on the side of safety, the staff concludes that it is an acceptablefuelfailurecriterion."

Justification The maximum fuel pellet enthalpy at the hot spot calculated for each Prairie Island-specific RCCA ejection case is less than 200 cal/gm. These results satisfy the fuel failure criterion accepted by the staff.

2. "Westinghouse proposes a clad temperaturelimitation of 27000 F as the temperatureabove which clad embrittlement may be expected. Although this is several hundred degreesabove the maximum clad temperaturelimitation imposed in the AEC ECCS Interim Acceptance Criteria, this isfelt to be adequate in view of the relatively short time at temperature and the highly localized effect of a reactivity transient."

Justification As discussed in Westinghouse letter NS-NRC-89-3466 written to the NRC (Reference 5.1.0-16),

the 2,700'F clad temperature limit was historically applied by Westinghouse to demonstrate that the core remains in a coolable geometry during an RCCA ejection transient. This limit was never used to demonstrate compliance with fuel failure limits and is no longer used to demonstrate core coolability. The RCCA ejection acceptance criteria applied by Westinghouse to demonstrate long term core coolability and compliance with applicable offsite dose requirements are identified in Section 5.1.14.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc.0I 1604

5-16 5.1.0.13 References 5.1.0-1 WCAP- I1397-P-A, "Revised Thermal Design Procedure," A. J. Friedland and S. Ray, April 1989.

5.1.0-2 WCAP-12910 Rev. 1-A, "Pressurizer Safety Valve Set Pressure Shift," G 0. Barrett, et al.,

May 1993.

5.1.0-3 ANSI/ANS-5.1-1979, "American National Standard for Decay Heat Power In Light Water Reactors," August 29, 1979.

5.1.04 WCAP-8745-P-A, "Design Bases for the Thermal Overpower AT and Thermal Overtemperature AT Trip Functions:' S. L. Ellenberger, et al., September 1986.

5.1.0-5 WCAP-7908-A, "FACTRAN -A FORTRAN IV Code for Thermal Transients in a U0 2 Fuel Rod," H. CG Hargrove, December 1989.

5.1.0-6 WCAP-1085 1-P-A, "Improved Fuel Performance Models for Westinghouse Fuel Rod Design and Safety Evaluations," R. A. Weiner, et al., August 1988 (including Addendum 1 Revison 1 (August 1987) and Addendum 2 (September 1987)).

5.1.0-7 WCAP-14882-P-A, "RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses," D. S. Huegel, et al., April 1999.

5.1.0-8 WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," S. L. Davidson (Ed.), July 1985.

5.1.0-9 WCAP-7907-P-A, "LOFTRAN Code Description," T. W.T. Burnett, et al., April 1984.

5.1.0-10 WCAP-7979-P-A, "TWINKLE - A Multi-Dimensional Neutron Kinetics Computer Code,"

D. H. Risher, Jr. and R. F. Barry, January 1975.

5.1.0-11 WCAP-10965-P-A, "ANC: AWestinghouse Advanced Nodal Computer Code," Y.S. Liu, et al., September 1986.

5.1.0-12 WCAP-14565-P-A, "VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCA Thermal-Hydraulic Safety Analysis," Y. X. Sung, et al., October 1999.

5.1.0-13 "Prairie Island Nuclear Generating Plant Updated Safety Analysis Report," Revision 25.

5.1.0-14 WCAP-1 1394-P-A, "Methodology for the Analysis of the Dropped Rod Event," R. L. Haessler, et al., January 1990.

5.1.0-15 WCAP-7588 Revision 1-A, "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinetics Methods," D. H. Risher, January 1975.

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5-17 5.1.0-16 NS-NRC-89-3466, "Use of 2700'F PCT Acceptance Limitin Non-LOCA Accidents,"

W. J. Johnson (Westinghouse) to R. C. Jones (NRC), October 23, 1989.

January 2004 Prairie Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-18 Table 5.1-1 Non-LOCA Analysis Limits and Analysis Results Analysis Result USAR Analysis Section Event Description Result Parametcr Limit Limiting Case 14.4.1 Uncontrollcd RCCA Withdrawal from a Minimum DNBR below first mixing vane grid 1.428/1.428 1.703/1.849 Subcritical Condition (non-RTDP, W-3 correlation) (thimble/typical) 1.428/1.428 1.703/1.849 Minimum DNBR above first mixing vane grid 1.285/1.285 2.047/2.075 (non-RTDP, WRB-1 correlation) (thimble/ltypical) . 2 Maximum fuel centerline temperature, 'F 4,746(") 2,480 14.4.2 Uncontrolled RCCA Withdrawal at Power Minimum DNBR (RTDP, WRB3-1) 1.34 1.432 Peak RCS pressure, psia 2,748.5 2,572.7 Peak main steam system pressure, psia 1,208.5 1,185.4 14.4.3 RCCA Misalignment Minimum DNBR (RTDP, WRB-I) 1.34 > 1.34 Statically Misaligned RCCAs Peak linear heat generation (kW/ft) 22.54(2) <22.54 Dropped RCCA Peak uniform cladding strain (%) 1.0 < 1.0 14.4.4 Chemical and Volume Control System Malfunction (Boron Dilution)

-Mode I with manual rod control 15 >20 (Mode I with manual)

-Mode I with automatic rod control . 15 >21 (Mode I with auto)

Minimum time to loss of shutdown margin, minutes

-Mode 2 15 >17 (Mode 2)

-Modes 3, 4, 5, and 6 24 >24(3) (Modes 3,4,5,6) 14.4.5 Startup of an Inactive Reactor Coolant Loop No analysis performed (precluded by Tech Specs) N/A N/A 14.4.6 Feedwater Temperature Reduction Incident Maximum feedwater temperature reduction, OF 149.4 70(s) 14.4.6 Excessive Heat Removal Due to Feedwater 1.41 (HFP)

______System Malfunctions Minimum DNBR (RTDP, WRB-I) 1.34 (6) (HZP) 14.4.7 Excessive Load Increase Incident 4 ) Minimum DNBR (RTDP, WRB-I) 1.34 1.49 Peak core heat flux, % 118 117.1 Prairie Island Licensing Report January 9004 6 'NP.doc-01 1604

( Q..

C (6 (I5-19 Table 5.1-1 Non-LOCA Analysis Limits and Analysis Results (cont.)

USAR Analysis Result Section Event Description Result Parameter Analysis Limit Limiting Case 14.4.8 Loss of Reactor Coolant Flow - PLOFt (7 Minimum DNBR (RTDP. WRB-1) (thimble/typical) 1.34/1.34 1.607/1.662 Loss of Reactor Coolant Flow - CLOFS) Minimum DNBR (RTDP, WRB-1) (thimble/typical) 1.34/1.34 1.333(9)/1.344 Loss of Reactor Coolant Flow - Locked Maximum percent rods-in-DNB (RTDP, WRB-1), % 20(10) 18.4 Rotor Peak RCS pressure, psia 2,748.5 2,562 Peak cladding temperature, F 2,700 2,010 Maximum Zirc-water reaction, % 16 0.60 14.4.9 Loss of External Electrical Load Minimum DNBR (RTDP, WRB-I) 1.34 1.77 Peak RCS pressure, psia 2,748.5 2,701 Peak main stream system pressure, psia 1,208.5 1,207.3 14.4.10 Loss of Normal Feedwater Maximum pressurizer mixture volume, ft3 1,010.1 934.1 14.4.11 Loss of All AC Power to the Station Maximum pressurizer mixture volume, ft3 1,010.1 653.0 Auxiliaries 14.5.5 Rupture of a Steam Pipe - Zero Power Minimum DNBR (non-RTDP, W-3) 1.593 2.535 -

(Core response only) .

Rupture of a Steam Pipe - Full Power Minimum DNBR below first mixing vane grid (Core response only) (non-RTDP, W-3 correlation) (thimble/typical) 1.428/1.428 1.448/1.681 Minimum DNBR above first mixing vane grid 1.34/1.34 1537/1578 (RTDP, WRB-I correlation) (thimble/typical) 1.34_1_34_1_ 5 37.1578 Peak linear heat generation (kW/ft) 22.54(1" < 22.54 January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-20 Table 5.1-1 Non-LOCA Analysis Limits and Analysis Results (cont.)

Analysis Result USAR Analysis Section Event Description Result Parameter Limit Limiting Case 14.5.6 Rupture of a Control Rod Drive Mechanism 150.9 (BOC-HZP)( 12 )

Housing (RCCA Ejcction) 168.6 (BOC-HFP)( 13 )

Maximum fucl pellet average cnthalpy, cal/g 200 158.6 (EOC-HZP)(")

160.1 (EOC-HFP)( 15) 0.0 (BOC-HZP)

Maximum fuel melt, % 10 1.94 (BOC-HFP) 0.0 (EOC-HZP) 0.96 (EOC-HFP)

Generically addressed in Peak RCS pressure, psia Rfrne5101 Itefcrence 5.1.0- 15 14.8 Anticipated Transient Without Scram (ATWS) Minimum DNBR (WRB-I) 1.17 > 1.17 Peak RCS pressure, psig 3,200 < 3,200 Notes:

I. Melting tempcraturc corrcsponding to 8-weight-percent Gadolinia-doped U02 fuel.

2. Corrcsponds to a fucl melting temperaturc of 4,700°F.

3. Analysis results define required minimum shutdown margin to meet the analysis limit.

4. Corrcsponds to a 20% load incrcasc.

5. Corrcsponds to thc accidental opening of the fcedwater bypass valvc that diverts flow around the high pressurc fccdwatcr hcatcrs (NMC scope).

6. Boundcd by zero power steam linc brcak.

7. PLOF = partial loss of flow (onc-loop flow coast down).

8. CLOF s complete loss of flow (two-loop flow coast down).

9. Available DNBR margin between the design limit (1.22) and safety analysis limit (1.34) was used to address the DNBR 'violation.'

10. The radiological analysis covers up to 20% of rods-in-DNB.

11. Corresponds to a fuel melting temperature of 4,700°rF

12. Beginning of cycle hot zero power.

13. Beginning of cycle hot full power.

14. End of cycle hot zero power.

15. End of cycle hot full powcr.

Prairie Island Licensing Report January 2004 6 " '-NP.doc-01 1604 C C

5-21 Table 5.1-2 Non-LOCA Plant Initial Condition Assumptions l Parameter RTDP Non-RTDP Notes NSSS Power (MWt) -1,657.0 1,657.0

• 1.02 1 Nominal Total Net RCP Heat (MWO) 7.0 7.0 1,2,3 Full-Power Vessel Tavg (0F) 560.0 560.0 +/- 4.0 1,4 No-Load RCS Temperature (0 F) 547.0 547.0 1,4 Pressurizer Pressure (psia) 2,250 2,250+/-40 1 Steam Flow (Ibm/hir) see Note 5 see Note 5 5 Steam Pressure (psia) see Note 5 see Note 5 5 Feedwater Temperature (0 F) 437.1 437.1 1 Pressurizer Water Level (% span) see Note 6 see Note 6 6 Steam Generator Water Level (% Narrow Range Span) see Note 7 see Note 7 7 Notes:

1. See Tables 1-2 and 1-3 (PCWG-03-17 and PCWG-03-35).

2. Total reactor coolant pump (RCP) heat input minus RCS thermal losses.

3. A maximum net RCP heat of 10 MWt is conservatively assumed in some non-RTDP analyses, e.g., loss of normal feedwater.

4. All analyses assume a programmed no-load Ta., of 5471F. For the events*initiated from a no-load condition [rod withdrawal from subcritical, steam line break, rod ejection, boron dilution], the use of the no-load temperature as the initial temperature bounds the case of startup operations at PINGP being performed at a hot-zero power (HZP) temperature lower than 547°F.

5. The nominal steam flow rate and steam pressure depend on other nominal conditions. See Tables 1-2 and 1-3.

6. The nominal pressurizer water level varies linearly from 21 % of span at a T,,, of 5471F to 33% of span at the full power T.,

of 5600F. An uncertainty of +/-5% of span was applied when conservative.

7. The steam generator water level program modeled in the analyses varies linearly from 33% narrow range span (NRS) at no-load conditions to 44% NRS at 20% load, remaining at 44% NRS for power levels greater than 20%. An uncertainty of

+11 % NRSI-15% NRS was applied when conservative.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 1604

5-22 Table 5.1-3 Pressurizer and Main Steam System (l'ISS) Pressure Relief Assumptions Pressure Relief Model(')

USAR Event Description Pressurizer MSS 14.4.1 Uncontrolled RCCA Withdrawal from a Subcritical Condition 5 5 14.4.2 Uncontrolled RCCA Withdrawal at Power - DNB Case I 3A

- Peak RCS Pressure Case 2B 3A

- Peak MSS Pressure Case I 3B 14.4.3 RCCA Misalignment - Statically Misaligned RCCAs 5 5

- Dropped RCCA 6 6 14.4.4 Chemical and Volume Control System Malfunction (Boron Dilution) 5 5 14.4.5 Startup of an Inactive Reactor Coolant Loop Analysis not required 14.4.6 Feedwater Malfunction - Feedwater Temperature Reduction 5 5

- Feedwater Flow Increase 1 3A 14.4.7 Excessive Load Increase Incident 4 4 14.4.8 Loss of Reactor Coolant Flow - Flow Coast Down 2A 3A

- Locked Rotor 2B 3A 14.4.9 Loss of External Electrical Load - DNB Case 1 3A

- Peak RCS Pressure Case 2B 3A

- Peak MSS Pressure Case 1 3A 14.4.10 Loss of Normal Feedwater 1 3B 14.4.11 Loss of All AC Power to the Station Auxiliaries 1 3B 14.5.5 Rupture of a Steam Pipe (Core Response) 4 4 14.5.6 RCCA Ejection 5 5 14.8 ATWS Case-dependent (see analysis)

Note:

1. The pressure relief models are described on the following pages of this table.

January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-1_1-NP.doc-Ol 1604

5-23 Table 5.1-3 Pressurizer and Main Steam System (CSS)Pressure Relief Assumptions (cont.)

Model 1 (Maximum Pressurizer Pressure Relief)

The setpoint for each of the two pressurizer power-operated relief valves (PORVs) is either 100 psi above the initial pressure or 2,350 psia, whichever is lower. Each PORV has a relief rate of 179,000 Ibm/hr. The pressurizer spray system is actuated when the indicated pressurizer pressure exceeds the initial value by 25 psi. The pressurizer spray valves are full open when the indicated pressurizer pressure exceeds the initial value by 75 psi. A linear increase in the pressurizer spray valve flow area is assumed between these points. The full-open spray valve (PSV) flow area is 0.0376 ft2.

The PSV setpoint is 3% below the nominal setpoint of 2,485 psig. Once the PSVs come open, they do not reseat until the pressure drops 5% below the opening setpoint. No time delay penalty is applied to account for the purging of the water in the PSV loop seals. The PSV relief rate is 360,234 Ibm/hr per valve (2 valves total). Note that for the loss of normal feedwater and loss of all AC power to the station auxiliaries transients, the PSV model is irrelevant because the PORVs and sprays are sufficient to control pressure.

Model 2A (Minimum Pressurizer Pressure Relief)

The pressurizer PORVs and pressurizer sprays are assumed to be unavailable. Although the PSVs are modeled, they do not actuate during the transient.

Model 2B (Minimum Pressurizer Pressure Relief)

The pressurizer PORVs and pressurizer sprays are assumed to be unavailable.

The PSVs setpoint is increased 3% above the nominal set pressure of 2,485 psig to account for set pressure tolerance plus an additional 1% to address the set pressure shift phenomenon associated with PSVs that have water-filled loop seals (see WCAP-12910 (Reference 5.1.0-2)). A maximum time delay of 1.12 seconds is applied to account for the purging of the water in the PSV loop seals. The PSV relief rate is 360,234 Ibm/hr per valve (2 valves total).

Model 3A (Staggered NISSV Setpoints)

There are 5 MSSVs on each loop with a total relief capacity of -2,048 Ibm/sec (total of 10 valves). The assumed setpoints are listed below.

Valve Bank Nominal Setpoint Initial Open Pressure of the MSSVs*

1 1,077 psig 1,158.01 psia 2 1,093 psig 1,174.49 psia 3 1,l10 psig 1,192.00 psia 4 1,120 psig 1,202.30 psia 5 1,131 psig 1,213.63 psia

• Pressure includes +3%for the setpoint tolerance, +34 psi for the pressure drop from the main steam line, at the entrance to the MSSV header, to the MSSVs, and +14.7 psi to convert to atmospheric pressure. The full open pressure for each MSSV is 5 psi above the initial open pressure.

Model 3B (Staggered MSSV Setpoints)

Same as Model 3A, except that instead of a 34-psid pressure drop from the main steam line, at the entrance to the MSSV header, to the MSSVs, a less conservative value of 5 psid was assumed. This reduction in the pressure drop was confirmed by NMC based on a detailed calculation.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-24 Table 5.1-3 Pressurizer and Main Steam System (MSS) Pressure Relief Assumptions (cont.) 'K f Model 4 No specific pressurizer pressure or main steam system relief inputs are modeled. The pressurizer pressure and steam pressure both decrease during this event. Thus, the behavior of the pressurizer spray, relief valves, and safety valves, or the MSSVs, is irrelevant.

Model 5 Pressurizer and main steam system relief is not modeled because either the computer codes used for these analyses do not include pressurizer or steam generator models, or the analysis is a hand calculation that does not involve these plant components. Refer to the accident-specific analyses for additional information.

Model 6 The generic (that is, not plant-specific) analysis performed to address this event assumes that the pressurizer PORVs actuate at 2,350 psia with a total maximum relief capacity of 16.65 ftO/sec. The pressurizer spray valve setpoints assumed are the same as those specified for Model 1, but the total spray capacity is 52.2 Ibm/sec. The PSVs and MSSVs are modeled and assumed to be available, but do not actuate.

Prairie Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-25 Table 5.1-4 Overtemperature and Overpower AT Setpoints Full Power T.,, 5600 F KI (safety analysis value) 1.23 Ki (plant setting) 1.17 K2 0.014PF K3 0.001/psi K4 (safety analysis value) 1.16 K4 (plant setting) 1.11 K5 0.027510F1 K6 0.002/1F a2) iT' 5600 F P 2,250 psia f(AI) Deadband -13% AI a) to +8% AI f(AI) Negative Gain -3.846%/%AlI a) f(AI) Positive Gain +1.73%/%AI High Pressurizer Pressure Reactor Trip Setpoint 2,425 psia Low Pressurizer Pressure Reactor Trip Setpoint 1,850 psia Notes:

1. KS5 = 0.0275/F is valid for increasing T,,,. For decreasing T,,, KS = 0.01OF.

2. K6 = 0.002/F is valid for T.,, > . For T,,, < r, K6 = 0.010F.

3. Based on fuel rod design analysis.

January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR NP.doc-0 11604

5-26 Table 5.1-5 Summary of RPS and ESFAS Functions Actuated USAR Section Event Description RPS or ESFAS Signal(s) Actuated Analysis Setpoint Delay (sec) 14.4.1 Uncontrolled RCCA Withdrawal from a Power-range high neutron flux reactor trip 50% 0.45 Subcritical Condition (low setting) 14.4.2 Uncontrolled RCCA Withdrawal at Power Power-range high neutron flux reactor trip 118% 0.45 (high setting)__ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Overtemperature AT reactor trip Table 5.1-4 6.0(1)

High positive neutron flux rate reactor trip 6.06%,2-second 0.5 time constant IHighi pressurizer pressure reactor trip 2,425 psia 1.0 14.4.3 Statically Misaligned RCCAs N/A N/A N/A Dropped RCCA Low pressurizer pressure reactor trip Note 2 2.0 14.4.4 Chemical and Volume Control System Overtemperature AT reactor trip Table 5.1-4 6.0(s)

Malfunction (Boron Dilution) 14.4.5 Startup of an Inactive Reactor Coolant Loop NIA N/A NIA 14.4.6 Feedwater Temperature Reduction Incident N/A N/A N/A Feedwater Flow Increase Ili-Ili steam generator water level turbine 100% NRS 1.0 (TT) trip (TT), with reactor trip (RT) on turbine 2.0 (RT) trip 14.4.7 Excessive Load Increase Incident None N/A N/A 14.4.8 Loss of Reactor Coolant Flow - Low reactor coolant loop flow reactor trip 87% 1.2 Flow Coast Down Loss of Reactor Coolant Flow - Low reactor coolant loop flow reactor trip 87% 1.2 Locked Rotor 14.4.9 Loss of External Electrical Load High pressurizer pressure reactor trip 2,425 psia 1.0 Overtempcrature AT reactor trip Table 5.1-4 6.0(1_

14.4.10 Loss of Normal Feedwater Lo-Lo steam generator (SG) water level 0% NRS 1.5 reactor trip Lo-Lo SG water level auxiliary feedwater 0% NRS 60.0 l_ (AFW) pump start 14.4.11 Loss of All AC Power to the Station Lo-Lo SG water level reactor trip 0% NRS 1.5 Auxiliaries Lo-Lo SG water level AFW pump start 0% NRS 60.0 Prairie Island Licensing Report JanuaC 1004 6 ' NP.doc-01 1604 (I

C ( c 5-27 Table 5.1-5 Summary of RPS and ESFAS Functions Actuated (cont.)

USAR Event Description RPS or ESFAS Signal(s) Actuated Analysis Setpoint Delay (sec)

Section 14.5.5 Rupture of a Steam Pipe Hi-Hi steam flow setpoint -150% of nominal N/A Lo-Lo steam pressure safety injection (SI) 500 psia setpoint (lead/lag = 12/2) 1.0 Steam line isolation delay from SI coincident N/A 6.0 with Hi-Hi Steam Flow Feedwater isolation delay from SI N/A 51.5 SI pumps at full flow following SI signal N/A 10.0/25.0 (with/without offsite power) ____10.0/25.

Rupture of a Steam Pipe - HFP Overpower AT reactor trip Table 5.1-4 6.0 (1)

Reactor trip from Lo-Lo steam pressure SI 500 psia 1.0 actuation (lead/lag= 12/2) 14.5.6 RCCA Ejection Power-range high neutron flux reactor trip 50% (low setting) 0.45 (low and high settings) 118% (high setting) 0.45 14.8 ATWS Diverse Scram System/ATWS Mitigation System Activation Circuitry (DSS/AMSAC) N/A N/A (case-dependent/see Section 5.1.15)

Notes:

1. The modeling of the OTAT and OPAT reactor trips include a time constant (first order lag) of 1.5 seconds and a filter (lag) of 2.0 seconds for the measurement of the vessel T.,, and AT. These lags account for the response of the RTDs, the RTD electronic filter (if any), the RTD bypass piping fluid transport delay, and the RTD bypass piping heatup thermal lag. In addition, after the ovcrtcmperature or overpower setpoint is reached, a delay of 2.5 seconds is assumed to account for electronic delays, reactor trip breakers opening, and RCCA gripper rcleasc.

2. The generic two-loop dropped RCCA analysis, applicable to PINOP. models the low pressurizer pressure reactor trip setpoint as a "convenience trip." The cases that actuate this function assume dropped rod and control bank worth combinations that arc non-limiting with respect to DNB. Thc fact that the plant-specific low pressurizer pressure setpoint (1,850 psia) is lower than the value assumed in the generic analysis (1,860 psia) does not invalidate the applicability of the generic two-loop statepoints to PINGP. Therefore, the low pressurizer pressure reactor trip setpoint value that is used in the generic two-loop dropped RCCA analysis (1,860 psia) does not represent an analytical limit for this function for PINOP.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-28 Table 5.1-6 Core Kinetics Parameters and Reactivity Feedback Coefficients Beginning of Cycle End of Cycle Parameter (Minimum Feedback) (Maximum Feedback)

Isothermal Temperature Coefficient, pcmI0 F 5.0 (< 70% RTP)(')

N/A 0.0 (> 70% RTP)

Moderator Density Coefficient, Ak/(g/cc) N/A 0.50 Doppler Temperature Coefficient, pcm/0 F -0.91 -2.90 Doppler-Only Power Coefficient, pcm/%power -9.55 + 0.035Q -24.0 + 0.100Q (Q = power in %)

Delayed Neutron Fraction 0.0072 (maximum) 0.0043 (minimum)

Minimum Doppler Power Defect, pcm

- RCCA Ejection 1,000 980

- RCCA Withdrawal from Subcritical 1,100 N/A Note:

1. RTP: Rated Thermal Power K)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

C ( 5-29 Table 5.1-7 Summary of Initial Conditions and Computer Codes Used Vessel Vessel Average Computer DNB Coolant Coolant Temp, RCS Pressure, Accident Codes Used Correlation RTDP Initial Power, % Flow, gpm OF psia Uncontrolled RCCA Withdrawal from a Subcritical Condition TWINKLE FACTRAN VIPRE W0 WRB-1( 2 ) No (1l650

(,5 MWt - core power)

~ oepwr 799922(4) 992~

547 4

2,200 Uncontrolled RCCA Withdrawal 100 (DNB/MSS Pressure) 560.0 (100%-DNJ) 2,250 (DNB) at Powver Yes 6 DB S P ) 182,500 556.0 (100%-Press.)

(DNB) 6 DBMSPesr) (DNB) 554.8 (60%-DNB) 2,210 RETRAN WRB-I 10 (DNBIMSS Pressure) 550.8 (0-Press.) (RCS Press.)

NIA 3 (RCS Pressure) 178,000 548.3 (1O%-DNB)

(Prssre (resue) 544.3 (I0%.P"ress.) 2,290 (Pressure) (1,657 MWt - NSSS power) (Pressure) 551.4 (3%) (MSS Press.)

RCCA Misalignment LOFTRANO3 )

(Dropped Rod) WRB-I Yes 100 182,500 560.0 2,250 VIPRE Chemical and Volume Control 100 (Mode 1) 564.0 (Mode 1) 2,250 System Malfunction NIA N/A N/A 5 (Mode 2) N/A 551.65 (Mode 2) (Modes I and 2)

Startup of an Inactive Reactor Event precluded by the Technical Specifications.

Coolant Loop Feedwater Temperature Reduction Incident Event bounded by the excessive load increase incident.

Feedwvater Flow Increase WRB-I Yes 100 182,500 RETRAN (HFP) MM0 (H-FP) 560.0 (HT 2,250 VIPRE W-3 (HZP) No (HZP) (1,657 MWt - NSSS power) 178,000 547.0 (HZP)

_ _ _ _ _ _ _ __ _ _ _ _ _ _ _(IIZ P) _ _ _ _ _ _

Excessive Load Increase Incident RETRAN WRB-I Yes 100 losfeeoooatlo l______

W

__________ I Y (1,657 MWt - NSSS power) 1 Loss of Reactor Coolant Flow - RETRAN WRB-I Yes 1001850560220 Flow Coast Down VIPRE 1(1,657 MWt - NSSS power) 18,0I6. ,5 Prairie Island Licensing Report January 2004 6296CLR-NP.doc-01 1604

5-30 Table 5.1-7 Sunimnary of Initial Conditions and Computer Codes Used (cont.)

Vessel Vessel Average Computer DNB Coolant Coolant Temp, RCS Pressure, Accident Codes Used Correlation RTDP Initial Power, % Flow, gpin OF psia Loss of Reactor Coolant Flow - N/A (hot 178,000 Locked Rotor RLTRAN spot, 102 (hot spot, pressure) (hot spot, 564.0 (hot spot, 2,290 (hot spot, RE WRB-1 pressure) 100 (DNB) pressure) pressure) pressure)

VIPRE Yes (1,657 MWt - NSSS power) 182,500 560.0 (DNB) 2,250 (DNB)

(DNB) (DNB)

Loss of External Electrical Load N/A 102 (pressure) 178,000 RETRAN WRB-I (pressure) 100 (DNBp) (pressure) 564.0 (pressure) 2,210 (pressure)

Yes (167M t-NS oe) 182,'500 560.0 (DNB) 2,250 (DNB3)

_ __ __ _ __ _ _ _ _ _ _ _ _ _ _ _(D N B) (1 6 7 M t- N S o e ) (D N B) _ _ _ _ _ _ _

Loss of Normal Feedwater RETRAN N/A N/A 102 178,000 556.0 2,290

_________ _ _________(1,657 M W t - NSSS power) 17 , 05 6.2 29 Loss of All AC Power to the RETRAN N/A N/A 102 178,000 556.0 2,290 Station Auxiliaries (1,657 MWt - NSSS power) _____ ______

Rupture of a Steam Pipe - RETRAN W-3(') NoM'1 102('), 100(w) 178,000(2) 564.0(') 2,205"')

Full Power Core Response VIPRE WRB-1t2 ) Yes(2) (1,657 MWt - NSSS power) 182,500(2) 560.0(2) 2,250(2)

Rupturc of a Steam Pipe - RETRAN W-3 No 0 178,000 547.0 2,250 Zero Power Core Response VIPRE (1,657 MWt - NSSS power) 17,054.220 RCCA Ejection 102 (HFP) 178,000 TWINKLE N/A N/A 0 (HZP) (IIF) 564.0 (HFl) 2,210 FACTRAN (1,650 MWt - core power) 79 9224 547.0 (HZP)

ATWSCase-dependenit (see Section 5.1.15)

Notes:

1. Bclow the first mixing vanc grid.

2. Above thc first mixing vanc grid.

3. The LOFTRAN portion of the analysis is generic; the DNB evaluation performed with VIPRE utilizes thc plant-specific values presentcd.

4. Single-loop flow = 0.449

• TDF.

Prairie Island Licensing Report January 2004 62<' R-NP.doc-011604

( (

5-31 Table 5.1-8 Non-LOCA Transients Evaluated or Analyzed Transient Report Section USAR Section Notes Uncontrolled RCCA Withdrawal from a Subcritical Condition 5.1.1 14.4.1 1 Uncontrolled RCCA Withdrawal at Power 5.1.2 14.4.2 1 RCCA Misalignment - Statically Misaligned RCCAs 5.1.3 14.4.3 1 RCCA Misalignment - Dropped RCCA Chemical and Volume Control System Malfunction 5.1.4 14.4.4 1 Startup of an Inactive Reactor Coolant Loop 5.1.5 14.4.5 2 Feedwater Malfunction - Feedwater Temperature Reduction 2 5.1.6 14.4.6 Feedwater Malfunction - Feedwater Flow Increase 1 Excessive Load Increase Incident 5.1.7 14.4.7 1 Loss of Reactor Coolant Flow - Flow Coast Down 5.1.8 14.4.8 1 Loss of Reactor Coolant Flow - Locked Rotor 5.1.9 Loss of External Electrical Load 5.1.10 14.4.9 1 Loss of Normal Feedwater 5.1.11 14.4.10 1 Loss of All AC Power to the Station Auxiliaries 5.1.12 14.4.11 1 Rupture of a Steam Pipe - Zero Power Core Response 5.1.13 14.5.5 1 Rupture of a Steam Pipe - Full Power Core Response RCCA Ejection 5.1.14 14.5.6 1 ATWS 5.1.15 14.8 1 Notes:

1. Complete Analysis

2. Evaluation Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-32 680 660 640 620 0I 3 600 580 560 540 0 0.2 0.4 0.6 0.8 1 1.2 1.4 Fraction of Rated Thermal Power Figure 5.1-1 Reactor Core Safety Limits Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-33 1 si I 800 psia 1850 psia 1900 psia 2000 psia 2250 psia 2425 psia 80 70 60 a) 50 I

40 30 20 Tavg (Deg-F)

Figure 5.1-2 Illustration of Overtemperature and Overpower AT Protection Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-34 1.00 0.80 C

0 0)

Up C

=0.60 IL 0

C 0

0 I..,

C 0

E0.40 U) 1:

0)

U)

C 0

0.20 -

O.0O 0.0 0.5 1.0 1.5 2.0 2.5 3.0 Time From Release (seconds)

Figure 5.1-3 Fractional Rod Insertion versus Time From Release K->

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-35 0

4-U (U

V N

(U 0

z 0.00 0.20 0.40 0.60 0.80 1.00 Rod Insertion (Fraction of Full Insertion)

Figure 5.1-4 Normalized RCCA Reactivity Worth versus Fractional Rod Insertion Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-36

¢ 0.60 C)

M

.N K>

E 0.40 b-0 Z

0.0 0.5 1.0 1.5 2.0 2.5 3.0 Time From Release (seconds)

Figure 5.1-5 Normalized RCCA Reactivity Worth versus Time from Release

<_}

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296- RNP.doc-01 1604

5-37 l- - Minimum Feedback - Maximum Feedback I X

S

_ -0.005 C

0 U

0 0

o .0.010 0

L.

0 IL 0

0. -0.015 O.

0 a

"i -0.020 0

C 0 20 40 60 80 100 120 Power (%/6)

Figure 5.1-6 Integrated DPC Used in Non-LOCA Transient Analyses Prairie Island Licensing Report i aJanuary 2004 6296- RNP.doc-0 11604

5-38 5.1.1 Uncontrolled RCCA Withdrawal from a Subcritical Condition (USAR Section 14.4.1) 5.1.1.1 Accident Description The rod cluster control assembly (RCCA) withdrawal accident is defined as an uncontrolled addition of reactivity to the reactor core caused by withdrawal of RCCA banks resulting in a power excursion. While the occurrence of a transient of this type is unlikely, such a transient could be caused by a malfunction of the reactor control or the control rod drive system. This could occur with the reactor either subcritical, at hot zero power (HZP), or at power. The "at power" case is discussed in Section 5.1.2.

Withdrawal of an RCCA bank adds reactivity at a prescribed and controlled rate to bring the reactor from a subcritical condition to a low power level during startup. Although the initial startup procedure uses the method of boron dilution, the normal startup is with RCCA bank withdrawal. RCCA bank movement can cause much faster changes in reactivity than can be made by changing boron concentration (see Section 5.1.4, Uncontrolled Boron Dilution).

The RCCA drive mechanisms are wired into preselected bank configurations that are not altered during core life. These circuits prevent RCCAs from being withdrawn in other than their respective banks.

Power supplied to the rod banks is controlled so that no more than two banks can be withdrawn at any time and in their proper withdrawal sequence. The RCCA drive mechanisms are of the magnetic latch type; coil actuation is sequenced to provide variable speed travel. The analysis of the maximum reactivity insertion rate includes the assumption of the simultaneous withdrawal of the two sequential banks having the maximum combined worth at maximum speed.

The neutron flux response to a continuous reactivity insertion is characterized by a very fast flux increase terminated by the reactivity feedback effect of the negative Doppler coefficient. This self limitation of the power burst is of primary importance since it limits the power to a tolerable level during the delay time for protective action. Should a continuous control rod assembly withdrawal event occur, the following automatic features of the reactor protection system are available to terminate the transient.

a. The source range high neutron flux reactor trip is actuated when either of two independent source range channels indicates a neutron flux level above a preselected manually adjustable setpoint and provides primary protection below the P-6 permissive. This trip function may be manually bypassed when either intermediate range flux channel indicates a flux level above P-6. It is automatically reinstated when both intermediate-range channels indicate a flux level below P-6.

b. The intermediate range high neutron flux reactor trip is actuated when either of two independent intermediate-range channels indicates a flux level above a preselected manually adjustable setpoint. This trip function may be manually bypassed when two of the four power-range channels give readings above the P-10 permissive (approximately 10 percent of full power) and is automatically reinstated when three of the four channels indicate a power below P-10.

Prairie Licensing Report Island Licensing January 2004 Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-39

c. The power range high neutron flux reactor trip (low settiig) is actuated when two-out-of-four power-range channels indicate a power level above a preselected manually adjustable setpoint (allowable value < 40 percent of full power). This trip function may be manually bypassed when two of the four power-range channels indicate a power level above the P-10 permissive and is automatically reinstated when three of the four channels indicate a power level below P-10.

d. The power range high neutron flux reactor trip (high setting) is actuated when two-out-of-four power-range channels indicate a power level above a preset setpoint (allowable value < 10 percent power). This trip function is always active while the reactor is at power.

In addition, control rod stops on high intermediate range flux (one-out-of-two) and high power-range flux (one-out-of-four) serve to cease rod withdrawal and prevent the need to actuate the intermediate-range flux trip and the power-range flux trip, respectively.

5.1.1.2 Method of Analysis The analysis of the uncontrolled RCCA bank withdrawal from subcritical accident is performed in three stages. First, a spatial neutron kinetics computer code, TVINKLE, is used to calculate the core average nuclear power transient, including the various core feedback effects, i.e., Doppler and moderator reactivity. FACTRAN uses the average nuclear power calculated by TWINKLE and performs a fuel rod transient heat transfer calculation to determine the average heat flux and temperature transients. Finally, the peak core-average heat flux calculated by FACTRAN is used in VIPRE for transient departure from nucleate boiling ratio (DNBR) calculations.

In order to give conservative results for a startup accident, the following assumptions are made.

a. Since the magnitude of the power peak reached during the initial part of the transient for any given rate of reactivity insertion is strongly dependent on the Doppler reactivity coefficient, a conservatively low (absolute magnitude) value for the Doppler power defect is used (1100 pcm).

b. The contribution of the moderator reactivity coefficient is negligible during the initial part of the transient because the heat transfer time constant between the fuel and the moderator is much longer than the neutron flux response time constant. However, after the initial neutron flux peak, the moderator temperature coefficient (MTC) can affect the succeeding rate of power increase. The effect of moderator temperature changes on the rate of nuclear power increase is calculated in TWINKLE based on temperature-dependent moderator cross-sections. An isothermal temperature coefficient (ITC) of 5 pcm/0 F, which accounts for both moderator and Doppler temperature effects, is used in the rod withdrawal from subcritical (RWFS) event analysis.

c. The analysis assumes the reactor to be at HZP nominal temperature of 547°F. This assumption is more conservative than that of a lower initial system temperature (i.e.,

shutdown conditions). The higher initial system temperature yields a larger fuel-to-water Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-40 heat transfer coefficient, a larger specific heat of the water and fuel, and a less-negative (smaller absolute magnitude) Doppler coefficient. The less-negative Doppler coefficient reduces the Doppler feedback effect, thereby increasing the neutron flux peak. The high neutron flux peak combined with a high fuel-specific heat and larger heat transfer coefficient yields a larger peak heat flux. The analysis assumes the initial effective multiplication factor (k~ff) to be 1.0, since this results in the maximum neutron flux peak.

d. Reactor trip is assumed to be initiated by power-range high neutron flux (low setting). The most adverse combination of instrumentation and setpoint errors are accounted for by assuming a 10 percent increase in the power range flux trip setpoint (low setting), raising it from the allowable value of 40 percent to a value of 50 percent. Figure 5.1.1-1 shows that the rise in nuclear flux is so rapid that the effect of error in the trip setpoint on the actual time at which the rods are released is negligible. In addition, the total reactor trip reactivity is based on the assumption that the highest worth rod cluster control assembly is stuck in its fully withdrawn position. Further, the delays for trip signal actuation and control rod assembly release are accounted for in the reactor trip delay time, as shown in Table 5.1-5.

e. The maximum positive reactivity insertion rate assumed (100 pcnlin) is a plant-specific value confirmed for each reload cycle and is greater than that for the simultaneous withdrawal of the two sequential control banks having the greatest combined worth at a conservative speed (45 in/min, which corresponds to 72 steps/min). It should be noted that the assumption of 72 steps/min as the maximum rod withdrawal speed is contingent upon the performance of refueling interval surveillances as recommended in NSAL-01-001 (Reference 5.1.1-1).

f. The departure from nucleate boiling (DNB) analysis assumes the most-limiting axial and radial power shapes possible during the fuel cycle associated with having the two highest combined worth banks in their high worth position.

g. The analysis assumes the initial power level to be below the power level expected for any shutdown condition (10 9 fraction of nominal power). The combination of highest reactivity insertion rate and low initial power produces the highest peak heat flux.

h. Note that the Technical Specifications require that two reactor coolant pumps (RCPs) be in operation for Mode 2 and Mode 3 when capable of rod withdrawal. The analysis is performed at HZP conditions with one RCP in operation, which is conservative, and bounds this accident in lower modes. This assumption also minimizes the resulting DNBR.

i. The accident analysis employs the Standard Thermal Design Procedure (STDP) methodology. Use of the STDP stipulates that the RCS flow rate will be based on the thermal design flow and that the RCS pressure is the nominal pressure minus the uncertainty. Since the event is analyzed from HZP, the steady-state STDP uncertainties on core power and reactor coolant system (RCS) average temperature are not considered in defining the initial conditions.

Licensing Report Island Licensing January 2004 Prairie Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-41

j. A core flow redutioin corresponding to the maximumnpoitntial reactor coolant loop flow asymmetry of 5 percent, associated with a maximum loop-to-loop steam generator tube plugging imbalance of 10 percent, has been applied.

k. The fuel rod heat transfer calculations performed to determine temperature transients during this event assume a total peaking factor or hot channel factor, FQ, that is a function of the axial and radial power distributions. The conservatively high value used in this analysis is presented in Table 5.1.1-1.

1. Westinghouse optimized fuel assembly (OFA) fuel with up to 8 w/o gadolinia content was considered in this analysis and the most bounding results are reported here.

m. Note that different DNBR correlations with different DNBR limits were used for the regions above and below the first mixing vane grid. Both sets of results are listed in Table 5.1.1-1.

5.1.1.3 Results Figures 5.1. 1 -1 through 5.1.1-5 show the transient behavior for a reactivity insertion rate of 75 pcm/sec.

The rate is greater than that calculated for the two highest worth sequential control banks, with both assumed to be in their highest incremental worth region.

Figure 5.1.1-1 shows the neutron flux transient. The neutron flux overshoots the full power nominal value for a very short period of time; therefore, the energy release and fuel temperature increase are relatively small. The heat flux response of interest for the DNB considerations is shown in Figure 5. 1.1-2. The beneficial effect of the inherent thermal lag in the fuel is evidenced by a peak heat flux of much less than the nominal full power value. Figures 5.1.1-3 through 5.1.1-5 show the transient response of the hot spot fuel centerline, fuel average, and cladding temperatures, respectively. DNBR calculations indicate that the minimum DNBR remains above the safety analysis limit value at all times.

Table 5.1.1-1 presents the assumptions and results of the analysis. Table 5.1.1-2 presents the calculated sequence of events. After reactor trip, the plant returns to a stable condition. The plant may subsequently be cooled down further by following normal shutdown procedures.

5.1.1.4 Conclusions In the event of an RCCA withdrawal accident from the subcritical condition, the core and the RCS are not adversely affected since the combination of thermal power and coolant temperature result in a DNBR greater than the limit value. Thus, no fuel or cladding damage is predicted as a result of this transient.

5.1.1.5 References 5.1.1-1 NSP-01-009, "Northem States Power Company Prairie Island Units 1 and 2, NSAL-01-001:

Rod Withdrawal Speed," February 22, 2001.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-42 Table 5.1.1-1 Assumptions and Results - Uncontrolled RCCA Withdrawal from a Subcritical Condition j

Initial Power Level, % 0 Reactivity Insertion Rate, pcmlsec 75 Delayed Neutron Fraction 0.0072 Doppler Power Defect, pcm 1100 Trip Reactivity, % Ak 1.0 Hot Channel Factor 6.64 Number of RCPs Operating 1 Results Calculated Value Limit Peak Fuel Centerline Temperature, IF 2480 4746°'

Peak Fuel Average Temperature, 'F 2009 4746 Below the first mixing vane grid (W-3 Correlation):

Minimum DNBR (Thimble cell) 1.703 1.428 Minimum DNBR (Typical cell) 1.849 1.428 Above the first mixing vane grid (WRB-1 Correlation):

Minimum DNBR (Thimble Cell) 2.047 1.285 Minimum DNBR (Typical Cell) 2.075 1.285 Notes:

1. Limit is for fuel with 8 w/o Gadolinia Report Licensing Report Island Licensing January 2004 Prairie Island Prairie January 2004 6296- RNP.doc-0 1 1604

5-43 Table 5.1.1-2 Sequence of Events - Uncontrolled RCCA Withdrawal from a Subcritical Condition Event Time (seconds)

Initiation of Uncontrolled RCCA Bank Withdrawal 0 Power-Range High Neutron Flux Low Setpoint Reached 10.0 Peak Nuclear Power Occurs 10.1 Rod Motion Begins 10.45 Peak Heat Flux Occurs 12.3 Minimum DNBR Occurs 12.3 Peak Cladding Temperature Occurs 12.6 Peak Fuel Average Temperature Occurs 13.0 Peak Fuel Centerline Temperature Occurs 14.5 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-44 1.4 0

0 0

0 4-j L-j

.4 0

0- I I I , I lii I I I Il 0 5 10 15 20 25 Time [s]

Figure 5.1.1-1 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Reactor Power versus Time Licensing Report January 2004 Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc4011604

545 0

0 C

0 C

0 0

05 10 15 20 25 Time [s]

Figure 5.1.1-2 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Heat Flux versus Time Report January 2004 Prairie Island Licensing Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

546 2500 -

2000 L.L Q) o 1500-E 1000-500 11 I Il l l , l I I l lil 0 5 10 15 20 25 Time [s]

Figure 5.1.1-3 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Hot-Spot Fuel Centerline Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-47 2200 -

2000-1800-LL 1600 -

1400-a)1200-o 1000 800 600 -

400 11 @ l llI I ,

0 5 10 15 20 25 Time [s]

Figure 5.1.1-4 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Hot-Spot Fuel Average Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-48 700 680 -

660 -

~640 ci) 620 -

E600 I.

a) 580 560 540 I i i IIII l i 0 5 10 15 20 25 Time [s]

Figure 5.1.1-5 Uncontrolled RCCA Withdrawal from a Subcritical Condition - Hot-Spot Cladding Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

549 5.1.2 Uncontrolled RCCA Withdrawal at Power (USAR Section 14.4.2) 5.1.2.1 Accident Description The uncontrolled rod cluster control assembly (RCCA) bank withdrawal at power event is defined as the inadvertent addition of reactivity to the core caused by the withdrawal of RCCA banks when the core is above the power defined by the P-10 setpoint. The reactivity insertion resulting from the bank (or banks) withdrawal will cause an increase in the core nuclear power and subsequent increase in the core heat flux.

An RCCA bank withdrawal can occur with the reactor subcritical, at hot zero power (HZP), or at power.

The uncontrolled RCCA bank at power event is analyzed for Mode I (power operation). The uncontrolled RCCA bank withdrawal from a subcritical or low-power condition is considered as an independent event in Section 5.1.1.

The event is simulated by modeling a constant reactivity insertion rate starting at time zero and continuing until a reactor trip occurs. The analysis assumes a spectrum of possible reactivity insertion rates up to a maximum positive reactivity insertion rate greater than that occurring with the simultaneous withdrawal, at maximum speed, of two sequential RCCA banks having the maximum differential rod worth.

Unless the uncontrolled RCCA bank withdrawal transient is terminated by manual or automatic action, the power mismatch and resultant temperature rise could eventually result in departure from nucleate boiling (DNB) and/or fuel centerline melt. Additionally, the increase in RCS temperature caused by this event will increase the reactor coolant system (RCS) pressure, and if left unchecked, could challenge the integrity of the RCS pressure boundary or the main steam system (MSS) pressure boundary.

To avert the core damage that might otherwise result from this event, the reactor protection system (RPS) is designed to automatically terminate any such event before the departure from nucleate boiling ratio (DNBR) falls below the limit value, the fuel rod kWMft limit for fuel centerline melt is reached, the peak primary and secondary pressures exceed their respective limits, or the pressurizer fills. Depending on the initial power level and the rate of reactivity insertion, the RCCA withdrawal is terminated by any of the following trip signals:

• Power-range high neutron flux

• Positive flux rate

• Overtemperature AT

• Overpower AT

• High pressurizer pressure

• High pressurizer water level 5.1.2.2 Method of Analysis The uncontrolled RCCA bank withdrawal at power event is analyzed to show that: (1) the integrity of the core is maintained because the DNBR and peak kW/ft remain within the safety analysis limit values and (2) the peak RCS and MSS pressures remain below 110 percent of the corresponding design limits. Of these, the primary concern is assuring that the DNBR limit is met.

Prairie Island Licensing Report January 2004 6296%LRNP.doc-01 1604

5-50 The RCCA bank withdrawal at power transient is analyzed with the RETRAN computer program (Reference 5.1.2-1). The program simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and steam generator relief and safety valves. The program computes pertinent plant variables including temperatures, pressures, and power level.

To obtain a conservative value for the minimum DNBR, the following analysis assumptions are made:

1. This accident is analyzed with the Revised Thermal Design Procedure (RTDP)

(Reference 5.1.2-2). Therefore, initial reactor power, pressure, and RCS temperatures are assumed to be at their nominal values and the minimum measured RCS flow is assumed.

Uncertainties in initial conditions are included in the limit DNBR.

2. Reactivity coefficients - Two cases are analyzed:

a. Minimum reactivity feedback - A zero isothermal temperature coefficient (ITC) of reactivity (0 pcm/°F) is assumed at full power. For power levels less than or equal to 70-percent power, a positive ITC of reactivity (+5 pcni/0 F) is conservatively assumed, corresponding to the beginning of core life. A conservatively small (in absolute magnitude)

Doppler power coefficient (DPC) is used in the analysis.

b. Maximum reactivity feedback - A conservatively large positive moderator density coefficient and a large (in absolute magnitude) negative DPC are assumed.

3. The reactor trip on high neutron flux is actuated at a conservative value of 118 percent of rated thermal power (RTP). The positive neutron flux rate trip is actuated at a conservative value of 6.06 percent of RTP with a rate lag time constant of 2 seconds. The OTAT trip includes all adverse instrumentation and setpoint errors. The delays for trip actuation are assumed to be at their maximum values. No credit was taken for the other expected trip functions.

4. The RCCA trip insertion characteristic is based on the assumption that the highest worth assembly is stuck in its fully withdrawn position.

5. A large range of reactivity insertion rates is examined. The maximum positive reactivity insertion rate is greater than that which would be obtained from the simultaneous withdrawal of the two control rod banks having the maximum combined differential rod worth at a conservative speed (45 inches/minute, which corresponds to 72 steps/minute).

6. Power levels of 10 percent, 60 percent and 100 percent of RTP are considered. The effect of RCCA movement on the axial core power distribution is accounted for by causing a decrease in the OTAT trip setpoint proportional to a decrease in margin to DNB. The analyses conservatively do not model any reduction in the OTAT trip setpoint which would result in an earlier reactor trip and less limiting results.

The RCCA bank withdrawal at power transient is also analyzed to ensure that the maximum RCS pressure and maximum MSS pressure are less than the corresponding 110 percent of design pressure limits.

Report Licensing Report January 2004 Prairie Island Licensing Prairie Island January 2004 6296-LR-NP.doc-01 1604

5-51 5.1.23 Results The time sequence of events and limiting results for the RCCA bank withdrawal at power transient for both the original steam generator and replacement steam generator models are presented in Tables 5.1.2-1 through 5.1.2-4.

The peak RCS pressure remains below the limit 110 percent of design pressure limit of 2,748.5 psia for all reactivity insertion rates analyzed. In addition, the peak MSS pressure remains below the 110 percent of design pressure limit of 1,208.5 psia.

Figure 5.1.2-1 shows the transient response of nuclear power, core heat flux, pressurizer pressure, pressurizer water volume, RCS temperature, and DNBR to a rapid RCCA withdrawal incident starting from full power with minimum reactivity feedback modeled. A reactor trip on a high neutron flux trip occurs shortly after the start of the accident. Since this transient is rapid with respect to the thermal time constants of the plant, small changes in reactor core Tag and pressurizer pressure result, and a large margin to DNB is maintained as indicated by the resulting minimum DNBR.

The response of nuclear power, core heat flux, pressurizer pressure, pressurizer water volume, RCS temperature, and DNBR for a slow RCCA withdrawal from full power is shown in Figure 5.1.2-2. A reactor trip on an OTAT trip occurs after a longer period of time and the rise in RCS temperature and pressure is consequently larger than for a rapid RCCA withdrawal. Again, the minimum DNBR is greater than the limit value.

Figure 5.1.2-3 shows the minimum DNBR as a function of the reactivity insertion rate for the three initial power levels analyzed (100, 60, and 10 percent) for both minimum and maximum reactivity feedback conditions. This figure shows that the combination of the positive flux rate trip, the high neutron flux and the OTAT trip functions provide protection over the whole range of reactivity insertion rates analyzed as the minimum DNBR remains greater than the limit value.

In Figure 5.1.2-3, the shape of the curves of minimum DNBR versus reactivity insertion rate is due both to the reactor core and coolant system transient response and to the initiating reactor trip.

Referring to the minimum reactivity feedback curve in Figure 5.1.2-3 (sheet 1) for example, it is noted that:

1. For high reactivity insertion rates (that is, between -110 pcmlsecond and -7 pcm/second), reactor trip is initiated by either a high neutron flux trip or a positive flux rate trip. The neutron flux level in the core rises rapidly for these insertion rates, while core heat flux lags behind due to the thermal capacity of the fuel and coolant system fluid. Therefore, the reactor is tripped prior to a significant increase in the heat flux or core water temperature with resultant high minimum DNBRs. Within this range, as the reactivity insertion rate decreases, the core heat flux and coolant temperatures are closer to an equilibrium condition with the neutron flux. Therefore, the minimum DNBR during the transient decreases with decreasing reactivity insertion rate.

2. With a further decrease in the reactivity insertion rate, the OTAT reactor trip becomes effective in terminating the transient.

Report January 2004 Prairie Island Licensing Prairie Island Licensing Report January 2004 6296-LPR-NP.doc-01 1604

5-52

3. The OTAT reactor trip function initiates a reactor trip when the measured AT exceeds the OTAT setpoint, which is based on the measured vessel Tavg and the pressurizer pressure. It is important to note that the contribution of RCS vessel Tavg to the OTAT trip function is lead-lag compensated to compensate for the effect of the thermal capacity of the RCS in response to power increases.

4. For reactivity insertion rates below -7 pcm/second, the effectiveness of the OTAT trip increases, as demonstrated by the increasing minimum DNBR. This is due to the fact that, with lower insertion rates, the power increase rate is slower and the rate of increase of the RCS vessel Tvg is slower, and the system thermal lags and delays become less significant.

5.1.2.4 Conclusions The results for the uncontrolled RCCA bank withdrawal at power transient show that the high neutron flux, the positive flux rate trip and OTAT trip functions provide adequate protection over the entire range of possible reactivity insertion rates as the minimum calculated DNBR is always greater than the safety analysis limit value. In addition, the analysis results show that the peak pressures in the RCS and MSS do not exceed 110 percent of their respective design pressures.

Thus, all pertinent criteria are met for the uncontrolled RCCA bank withdrawal at power transient.

5.1.2.5 References 5.1.2-1 D. S. Huegel, et al., "RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses," WCAP-14882-P-A, April 1999. K.

5.1.2-2 Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-1 1397-P-A, April 1989.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-53 Table 5.1.2-1 Time Sequence of Events for Uncontrolled RCCA Withdrawal at Power (Minimum Feedback) Westinghouse Model 51 SGs Event Time (Seconds)

Case A:

Initiation of Uncontrolled RCCA Withdrawal at Full Power with Minimum 0 Reactivity Feedback (100 pcm/sec)

Positive Flux Rate Trip Initiated 0.564 Rods Begin to Fall into Core 1.064 Minimum DNBR Occurs 1.75 Case B:

Initiation of Uncontrolled RCCA Withdrawal at Full Power with Minimum 0 Reactivity Feedback (I pcm/sec)

OTAT Reactor Trip Signal Initiated 64.7 Rods Begin to Fall into Core 66.7 Minimum DNBR Occurs 67.0 Table 5.1.2-2 Limiting Results for RCCA Bank Withdrawal at Power Transient Westinghouse Model 51 SGs Limiting Analysis Criterion Value Limit Case DNBR 1.43 1.34 Full power, minimum reactivity feedback, 6.6 pcm/second reactivity insertion rate Core Heat Flux (FON) 1.17 1.18 Full power, minimum reactivity feedback 6.6 pcm/second reactivity insertion rate Report January 2004 Prairie Island Licensing Licensing Report January 2004 6296-LRNP.doc-01 1604

5-54 Table 5.1.2-3 Time Sequence of Events for Uncontrolled RCCA Withdrawal at Power (Minimum Feedback) Framatome ANP Model 56/19 SGs Event Time (Seconds)

Case A:

Initiation of Uncontrolled RCCA Withdrawal at Full Power with Minimum 0 Reactivity Feedback (100 pcmlsec)

Positive Flux Rate Trip Initiated 0.564 Rods Begin to Fall into Core 1.064 Minimum DNBR Occurs 1.862 Case B:

Initiation of Uncontrolled RCCA Withdrawal at Full Power with Minimum 0 Reactivity Feedback (1 pcm/sec)

OTAT Reactor Trip Signal Initiated 66.5 Rods Begin to Fall into Core 68.5 Minimum DNBR Occurs 69.0 Table 5.1.2-4 Limiting Results for RCCA Bank Withdrawal at Power Transient Framatome ANP Model 56119 SGs Limiting Analysis Criterion Value Limit Case DNBR 1.43 1.34 Full power, minimum reactivity feedback, 6.2 pcm/second reactivity insertion rate Core Heat Flux (FON) 1.17 1.18 Full power, minimum reactivity feedback l 6.2 pcm/second reactivity insertion rate Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-55 1- .2 a

2 E

0 C

0

-0 C

.8 0

0 L-

.6 3:

.4 0~

0 a,

I-

.2 z

0 10 Time [ s]

Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 1 of 12) Nuclear Power versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-56

~ I .2 0

E 0

C 0

C

.8 0

-0 1._

.6 0R 0

I-a .4 L-U

.2

I z

0 10 20 Time [Is]

Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcni/sec - Full Power), Minimum Feedback (Sheet 2 of 12) Nuclear Power versus Time '--

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 1604

5-57 a

E 0

C 0

a 0

U 0

L.

LA.

.4 0

V

.2 -

V I-0 C.

0- I I , I, l I, I 0 5 10 15 20 Time [s]

Figure 5.1.2- 1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcni/sec - Full Power), Minimum Feedback (Sheet 3 of 12) Core Heat Flux versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

. 5-58

-j .2 c

E 0

0 C .8 0

U.

.6 6-J x

U-0

.2 11-1) 0 0

0 5 10 15 20 Time [s]

Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 4 of 12) Core Heat Flux versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-59 a- 2300 Cn 0.

~2250 Cl)2200 a)

L 0~

L-L 2150 N

2100 En Q)

IL L-2050 50 l l I I' I I ' I ' i I I  ! ,lI 0 5 10 15 20 Time [ s]

Figure 5.1.2-J1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 5 of 12) Pressurizer Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-60 r- 2280 a

C. 2260 -

U-2240 -

, 2220 (n

X 2200 1-m 2180 L..

N') 2160

, 2140 U,

I-I I I I I I I I I I I I I I I I I m 2100 0 110 15 20 Time [ s]

Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 6 of 12) Pressurizer Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-61 380 -

V V

360 -

U M 340 -

320-

>. 300-L.

V c 280-X.4 4t 260-20-V

a. nnn) I I I I I I I I I I I I I I I I I I I LLU 0 10 15 20 Time [ s]

Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 7 of 12) Pressurizer Water Volume versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-62 380 U

a 0

360

. 340 Ca E

' 320 0

U.

X300

' 280 0

= 26 0 K>

0

"-240 0 5 10 15 20 Time [ s]

Figure 5.1.2-1 Framatorne ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 8 of 12) Pressurizer Water Volume versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-63 565 5560 -

I--

555 Cam

,v 545- \

V)4 or

> 50 -

0 5 10 15 20 Time [s]

Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 9 of 12) Vessel Average Temperature versus Time Prairie Island Licensing Report January 2004 6296.LR-NP.doc-01 1604

5-64 565 U.

nI- 560

.2555 0

ca L..

0 cu IC

- 55 o 545 540 0)

U, C,

C, 535 10 Time [Is]

Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcmlsec - Full Power), Minimum Feedback (Sheet 10 of 12) Vessel Average Temperature versus Time Report January 2004 Prairie Licensing Report Prairie Island Licensing January 2004 6296-LR-NP.doc-01 1604

5-65 5

4.5 4

o 3.5 m

z n 3 2.5 2

1.5 0 5 10 15 20 Time [ s]

Figure 5.1.2-1 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 11 of 12) DNBR versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-66

.%I-li; 5

4.5 4

0 3.5 m

z 0 3 25 2

1.5 Time [s]

Figure 5.1.2-1 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (100 pcm/sec - Full Power), Minimum Feedback (Sheet 12 of 12) DNBR versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 I604

5-67 r-9.2 E 1 0

C 0

C

.8 0

L..j 1._

L-

.6 a

0

.4 6-0 0

.2 z

0 0 20 40 60 80 100 Time [ s]

Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcmlsec - Full Power), Minimum Feedback (Sheet 1 of 12) Nuclear Power versus Time January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-68 1.2 -

0 C

E 1-0 C

0 C

.8 -

0 U.

0

. 6-0 60~ .4 -

0 U:

.2 -

K>1 z I i I I I I I I I I I I I I I I I 0- I 1 0 20 40 60 80 100 Time [Is]

Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 2 of 12) Nuclear Power versus Time K>

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 1 1604

5-69 I

,1 .2 I

C E

0 C

4-0 C .8 0

0

.6 Li.

Li.I

.4 0

4)

.2 L..

0 C.)

0 t0 60 Time [ s]

Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 3 of 12) Core Heat Flux versus Time Report January 2004 Prairie Island Licensing Licensing Report January 2004 6296- RNP.doc-01 1604

5-70 0

Cl E

0 0

• 8 0

L.

0 I-

.6 0

.4 x

0 .2 CF.

0 20 40 60 80 100 Time [s]

Figure 5.1.2-:2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 4 of 12) Core Heat Flux versus Tlime '-

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-71

,_ 2300 a

co C) 24250 V

L.

0 en 2200 (I,

Q)

, 2150 Q)

N L-

2100 ton Cn C)

L.

a- 2050 Time [s Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 5 of 12) Pressurizer Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-72 2280 -

01 2260 -

Lcn CL 2240 -

,. 2220-Cn aX' 2200-L-

'L 2180-L-

N 2160 -

, 2140-O 2120-Q a- I I I I I I I I I I I I I I I I I I I L I UU 0 20 40 60 80 100 Time [ s]

Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 6 of 12) Pressurizer Pressure versus Time January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-73

.44 -

V E

4260 - -

420 34 0 - \

. 0 0 20 40 60 80 100 Time [s]

Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (I pcn/sec - Full Power), Minimum Feedback (Sheet 7 of 12) Pressurizer Wlater Volume versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-74 460

_s U

I 440 U

Q420

-0 E

'f 40 0 0

a 360 0

U

, 340 a,

X 320 40 60 Time [ s]

Figure 5.1.2-2 F ramatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (11pcmlsec - Full Power), Minimum Feedback (Sheet 8 of 12) Pressurizer Water Volume versus Tune 'Jo Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-75

_ 570-I.-

n 565-

= 560

> 555-0'

<550-0) 20 40 60 80 100 Time [s]

Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 9 of 12) Vessel Average Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0I 1604

5-76 570 I

ca 565 ci 0I-Ca CL E

ci 0 555 M

a 6-550 ox a,

0a, ci 545 40 60 Time [ s]

Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcm/sec - Full Power), Minimum Feedback (Sheet 10 of 12) Vessel Average Temperature versus Time *EJ Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-77 4.5 4

3.-5 z 3 2.5 2

1.-5 0 60 Time [ s]

Figure 5.1.2-2 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcin/sec - Full Power), Minimum Feedback (Sheet 11 of 12) DNBR versus Time Prairie Island Licensing Report s t January 2004 6296- RNP.doc-01 1604

5-78 3.5 -

m Cy-z 3 2.5 2

0 20 40 60 80 10 0 Time [s]

Figure 5.1.2-2 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power (1 pcnisec - Full Power), Minimum Feedback (Sheet 12 of 12) DNBR versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-79 2

I m)1uTfeedbac m---~ r I rnvromm feedbackI 1.9 PFRTJ 1.8 cr OTDT 9 HNF E 1.7 1.4 1.0E+00 1.0E+01 1.OE+02 1.0E+03 Reactivity Addition Rate [pcrrsec]

Figure 5.1.2-3 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power, 100%

Power (Sheet 1 of 6)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-80 3.2 -

3 Minimum Feedback

[... Maximum Feedback 2.8 PFRT 2.6 z 2.4 E *OTDT E -

1.8 1.6 1.4 I.OE+OO 1.OE+01 1.OE+02 1.OE+03 Reactivity Addtion Rate [pcanVsecl Figure 5.1.2-3 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power, 60 % Power (Sheet 2 of 6)

Report January 2004 Prairie Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 11604

5-81 4.4 3.9 [ Minimum Feedback 3.4 - FI /-"j ci. PiRT- /

z 12.9 .

E '

I, OTDTl 249 ~ ~~..._........._........_--........ ......

1.4 1.OE+00 1.0E+01 i.OE+02 1.OE+03 Reactivity Addition Rate [pCm/sec]

Figure 5.1.2-3 Westinghouse Model 51 SGs Uncontrolled RCCA Bank Withdrawal at Power, 10% Power (Sheet 3 of 6)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-82

---.l. Maximum Feedback r I-MinimumMaximum Feedback Feedback 1.9 PFRT z OTDT E 1.7 HNF E

1.6-1.5 1.4 1.OOE+OO 1.OOE+O1 1.OOE+02 1.OOE+03 Reactivity Addition Rate fpcm/secl Figure 5.1.2-3 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power, 100% Power (Sheet 4 of 6)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-83 3.2 -

-Maximum Feedback Minimum F ck 2.8 -

2.6 PFRT z 2.4 . FI E.

'. OTDT/,

1.6 1.4 1.0E+OO .OE+01 1.OE+02 1.OE+03 Reactivity Addition Rate [pcm/sec]

Figure 5.1.2-3 Framatome ANP Model 56/19 SGs Uncontrolled RCCA Bank Withdrawal at Power, 60% Power (Sheet S of 6)

Prairie Island Licensing Report January---

2004 6296-LR-NP.doc-O 1604

5-84 4.4 r

.Maximum Feedback

-Minimum Feedback 3.9 3.4 cc z

0 E 2.9 E

2 OTOT 2.4 1.9 I'

1.4 -

1.OE+00 1.0E+01 1.OE+02 1.OE+03 Reactivity Addition Rate [pcmlsec]

Figure 5.1.2-3 Framatorne ANP Model 56119 SGs Uncontrolled RCCA Bank Withdrawal at Power, 10 % Power (Sheet 6 of 6)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-85 5.1.3 Rod Cluster Control Assembly Misalignment (USAR Section 14.4.3) 5.1.3.1 Accident Description A Rod Cluster Control Assembly (RCCA) Misalignment Event is a Condition II event that is assumed to be initiated by a single electrical or mechanical failure. The resulting negative reactivity insertion causes nuclear power to rapidly decrease. An increase in the hot channel factor may occur due to skewed power distribution representative of a dropped RCCA configuration. Since this is a Condition II event, it must be shown that the departure from nucleate boiling (DNB) design basis is met for the combination of power, hot channel factor, and other system conditions that exist following an RCCA misalignment event.

The RCCA misalignment accidents include:

• Dropped full-length RCCAs

• Dropped full-length RCCA banks

• Statically misaligned full-length RCCAs Each RCCA has a rod position indicator channel that displays the position of the assembly. The displays of assembly positions are grouped for operator convenience. Fully inserted assemblies are further indicated by rod bottom lights. The full-length assemblies are always moved in pre-selected banks and the banks are always moved in the same pre-selected sequence.

Dropped assemblies or assembly banks are detected by:

• Sudden drop in the core power level (as seen by the nuclear instrumentation system)

• Asymmetric power distribution (as seen on out-of-core neutron detectors or core exit thermocouples)

• Rod bottom light(s)

• Rod deviation alarm (if the plant computer is in operation)

• Rod position indicators Misaligned assemblies are detected by:

• Asymmetric power distribution (as seen on out-of-core neutron detectors or core exit thermocouples)

• Rod deviation alarm (if the plant computer is in operation)

• Rod position indicators Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-86 5.1.3.2 Method of Analysis 5.1.3.2.1 One or More Dropped RCCAs or Dropped RCCA Bank The LOFTRAN computer code calculates transient system responses for the evaluation of a dropped RCCA event. The code simulates the neutron kinetics, reactor coolant system (RCS), pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and main steam safety valves (MSSVs). The code computes pertinent plant variables including temperatures, pressures, and power levels.

Transient RCS statepoints (temperature, pressure, and power) are calculated by LOFTRAN. Nuclear models are used to obtain a hot-channel factor consistent with the primary system conditions and reactor power. By incorporating the primary conditions from the transient analysis and the hot-channel factor from the nuclear analysis, it is shown that the DNB design basis is met using the VIPRE code. The transient response analysis, nuclear peaking factor analysis, and the DNB design basis confirmation are performed in accordance with the approved methodology described in References 5.1.3-1 and 5.1.3-2.

Also note that the analysis does not take credit for the power-range negative flux rate reactor trip.

A generic statepoint analysis for this event, which was performed in 1986 to bound a number of two-loop pressurized water reactors (PWRs), was evaluated and determined to be applicable to the Prairie Island Nuclear Generating Plant (PINGP).

5.13.22 Statically Misaligned RCCA Steady-state power distributions are analyzed using the appropriate nuclear physics computer codes. The peaking factors are then used as input to the VIPRE code to calculate the departure from nucleate boiling ratio (DNBR). The following cases are examined in the analysis assuming the reactor is initially at full power

• The worst rod withdrawn with Bank D inserted at the insertion limit

• The worst rod dropped with Bank D inserted at the insertion limit

• The worst rod dropped with all other rods out It is assumed that the incident occurs at the time in the cycle at which the maximum all-rods-out FwH occurs. This assures a conservative Fm for the misaligned RCCA configuration.

5.1.33 Results 5.13.3.1 One or More Dropped RCCAs Single or multiple dropped RCCAs within the same group result in a negative reactivity insertion. The core is not adversely affected during this period since power is decreasing rapidly.

Power may be re-established either by reactivity feedback or control bank withdrawal. Following a dropped rod event in manual rod control, the plant will establish a new equilibrium condition. The new Report Licensing Report January 2004 Prairie Island Licensing Prairie Island January 2004 6296- RNP.doc-0 11604

5-87 equilibrium condition without control system interaction is relatively steady, thus removing power overshoot concerns and establishing the automatic rod control mode of operation as the limiting case.

For a dropped RCCA event in the automatic rod control mode, the rod control system detects the drop in power and initiates control bank withdrawal. Power overshoot may occur due to this action by the automatic rod controller, after which the control system will insert the control bank to restore nominal power. Figures 5.1.3-1 through 5.1.3-4 show a typical transient response to a dropped RCCA (or RCCAs) event with the reactor in automatic rod control. Uncertainties in the initial conditions are included in the DNB evaluation as described in Reference 5.1.3-1. In all cases, the minimum DNBR remains above the limit value.

Following plant stabilization, the operator may manually retrieve the RCCA(s) by following approved operating procedures.

5.1.3.3.2 Dropped RCCA Bank A dropped RCCA bank typically results in a negative reactivity insertion greater than 500 pcm. The core is not adversely affected during the insertion period, since power is decreasing rapidly. The transient will proceed similar to that described for Section 5.1.3.3.1; however, the return to power will be less due to the greater worth of an entire RCCA bank. Following plant stabilization, normal rod retrieval or shutdown procedures are followed to further cool down the plant.

5.1333 Statically Misaligned RCCA The most severe RCCA misalignment situations with respect to DNB at significant power levels are associated with cases in which one RCCA is fully inserted with either all rods out or Bank D at the insertion limit, or where Bank D is inserted to the insertion limit and one RCCA is fully withdrawn.

Multiple independent alarms, including a bank insertion limit alarm, alert the operator well before the transient approaches the postulated conditions.

The insertion limits in the Technical Specifications may vary from time to time, depending on several limiting criteria. The full-power insertion limits on control Bank D must be chosen to be above the position that meets the minimum DNBR and peaking factors. The full-power insertion limit is usually dictated by other criteria. Detailed results will vary from cycle to cycle depending on fuel arrangements.

For the RCCA misalignment case with one RCCA fully inserted (with either all rods out or Bank D at the insertion limit), the DNBR does not fall below the limit value. The analysis for this case assumes that the initial reactor power, RCS pressure, and RCS temperature are at nominal values and with the increased radial peaking factor associated with the misaligned RCCA.

For the RCCA misalignment case with Bank D inserted to the full-power insertion limit and one RCCA fully withdrawn, the DNBR does not fall below the limit value. The analysis for this case assumes that the initial reactor power, RCS pressure, and RCS temperature are at nominal values and with the increased radial peaking factor associated with the misaligned RCCA.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-88 DNB does not occur for the RCCA misalignment incident. Therefore, there is no reduction in the ability of the primary coolant to remove heat from the fuel rod. The peak fuel temperature corresponds to a linear heat generation rate based on the radial peaking factor penalty associated with the misaligned RCCA and the design axial power distribution. The resulting linear heat generation rate is well below that which would cause fuel melting.

After identifying an RCCA group misalignment condition, the operator must take action as required by the plant Technical Specifications and operating procedures.

5.1.3.4 Conclusions The evaluation of the generic statepoints that were obtained using the methodology in Reference 5.1.3-2, for cases of dropped RCCAs or dropped banks encompassing all possible dropped rod worths delineated in Reference 5.1.3-2, concluded that the minimum DNBR remains above the safety analysis limit value.

For all cases of any single RCCA fully inserted, or Bank D inserted to the rod insertion limit and any single RCCA in that bank fully withdrawn (static misalignment), the minimum DNBR remains above the limit value. Therefore, the DNB design criterion is met and the RCCA misalignments do not result in core damage.

5.1.3.5 References 5.1.3-1 Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-11397-P-A, April 1989.

5.1.3-2 Haessler, R. L., et al., "Methodology for the Analysis of the Dropped Rod Event,"

WCAP-1 1394-P-A, January 1990.

Licensing Report Island Licensing Prairie Island January 2004 Prairie Report January 2004 6296-lR-NP.doc-01 1604$

5-89 1.15 0

1.1 0

1.05 0

a B::

0 L.)

To 4-1

.95

.,2L...

0

.9 0~

a, .55 C

.8 -II I I I I I I I I 0 50 100 150 200 Time (seconds)

Figure 5.13-1 Representative Transient Response to Dropped RCCA - Nuclear Power versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-90 1.15-0 E 1.1

.C_

1.05 Lo.95

.9

.85 0 50 100 150 200 Time (seconds)

Figure 5.1.3-2 Representative Transient Response to Dropped RCCA - Core Heat Flux versus Time Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296- RNP.doc-01 1604

5-91 2350 -

• . 2300 a-,

CU C,,

" 2250-CD 2200-0-

2150-0 50 100 150 2 Time (seconds)

Figure 5.13-3 Representative Transient Response to Dropped RCCA - Pressurizer Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-92 590-i-

v588-

'586-C-

E 584 -

o582-a, 580 CO 578-0 50 100 150 Time (seconds)

Figure 5.1.3-4 Representative Transient Response to Dropped RCCA - Vessel Average Temperature versus Time January 2004 Prairie Island Licensing Prairie Report Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-93 5.1.4 Chemical and Volume Control System Malfunction A malfunction of the chemical and volume control system (CVCS) that causes an inadvertent dilution of the reactor coolant system (RCS) could occur at any plant operating mode. The methods used to analyze an event initiated when the reactor is critical are substantially different than those used when the reactor is subcritical. The critical and subcritical cases are evaluated in two separate subsections below.

The major hazard associated with an unmitigated CVCS malfunction is a reduction in the departure from nucleate boiling ratio (DNBR) and/or a complete loss of shutdown margin. The events, therefore, are analyzed in order to demonstrate that the departure from nucleate boiling (DNB) design basis is satisfied or to determine the response time that exists prior to a complete loss of shutdown margin.

5.1.4.1 Critical Reactor Boron Dilution 5.1.4.1.1 Accident Description The accident considered here is the malfunction of the CVCS resulting in the injection of non-borated water at the maximum possible flow rate to the RCS under at-power conditions. With the rod control system in automatic mode, the decrease in the boron concentration will cause the power and temperature to increase, resulting in the insertion of the rod cluster control assemblies (RCCAs) and a decrease in shutdown margin. With the reactor in manual mode, the decrease in the boron concentration will cause the power and temperature to increase. This will eventually result in an overtemperature AT (OTAT) or overpower AT (OPAT) reactor trip if the operator does not intervene.

The boric acid from the boric acid tank is blended with the reactor makeup water in the blender and the composition is determined by the preset flow rates of boric acid and reactor makeup water on the reactor makeup control system. Two separate operations are required. First, the operator must switch from the automatic makeup to the alternate dilution mode or the dilute mode. Second, a control switch must be operated. Omitting either step would prevent dilution. This makes the possibility of inadvertent dilution very small.

Other mechanisms exist that could cause an inadvertent dilution of the RCS. It has been determined that the limiting condition is with the charging pumps. The following discussion evaluates this dilution mechanism.

Reactivity can be added to the core with the CVCS by supplying reactor makeup water from the reactor makeup control system. An intentional boron dilution is a manual operation performed under operator surveillance. For blended additions, a boric acid blend system is provided to permit the operator to match the concentration of reactor coolant makeup water to that existing in the coolant at the time. The CVCS is designed to limit, even under various postulated failure modes, the potential rate of dilution to a value that, after indication through alarms and instrumentation, provides the operator sufficient time to correct the situation in a safe and orderly manner.

The primary source of reactor makeup water for the RCS is the reactor makeup water system. If this is the case, an inadvertent dilution can be readily terminated by isolating this single source. In order for the reactor makeup water to be added to the RCS, the charging pumps must be running in addition to the Prairie Island Licensing Report January 2004 6296-LR-NP.daoc-1 1604

5-94 reactor makeup water pumps. There are other potential dilution sources and mechanisms (e.g., inadvertent valve lineups of ion exchangers, etc.).

Information on the status of the reactor coolant makeup is available to the operator in the control room.

Lights are provided on the control board to indicate the operating conditions of pumps in the CVCS.

Alarms are actuated to warn the operator if boric acid of reactor makeup water flow rates deviate from preset values.

Because of the procedures involved in the dilution process, an erroneous dilution is considered unlikely.

Nevertheless, if an unintentional dilution of boron in the reactor coolant does occur, numerous alarms and indications are available to alert the operator to the condition. The maximum reactivity addition due to the dilution is slow enough to allow the operator to determine the cause of the addition and take corrective action before shutdown margin is lost.

The acceptance criterion for a dilution accident when the reactor is critical is that the time between the initiation of the dilution and a complete loss of shutdown margin must be greater than or equal to 15 minutes. This provides ample time for operator recognition and mitigation of the dilution.

5.1.4.1.2 Method of Analysis The analyses performed for Modes l and 2 are hand calculations designed to identify the amount of time available for operator or automatic mitigation of the boron dilution event prior to the complete loss of shutdown margin.

Dilution at Power (Mode 1)

In this mode, the plant may be operated in either automatic or manual rod control. Conditions assumed for this mode are:

• Dilution flow is the maximum capacity of all three charging pumps, 170 gpm.

• A minimum RCS water volume of 4,348 ft3 at 564 0 R This is a very conservative estimate of the active RCS volume (not including the pressurizer), including the effects of 25 percent steam generator tube plugging (SGTP) in the Westinghouse Model 51 steam generators or 10 percent SGTP in the replacement Framatome Model 56/19 steam generators.

. The maximum critical boron concentration (corresponding to the rods inserted to the insertion limits) and the minimum change in boron concentration from this initial condition to a hot zero power critical condition with all rods inserted are plant-specific values that are confirmed to be valid every cycle as part of the reload verification process. Full rod insertion, minus the most reactive stuck rod, is assumed to occur due to reactor trip.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01I604

5-95 Dilution at Startup (Mode 2)

In this mode, the plant is being taken from one long-term mode of operation, hot standby, to another, power. Typically, the plant is maintained in the startup mode only for the purpose of startup testing at the beginning of each cycle. During this mode of operation, rod control is in manual. All normal actions required to change power level, either up or down, require operator initiation. Conditions assumed for the analysis are as follows:

• Dilution flow is the maximum capacity of all three charging pumps, 170 gpm.

• A minimum RCS water volume of 4,348 ft3 corresponding to the active RCS volume (not including the pressurizer), including the effects of 25 percent SGTP in the Westinghouse Model 51 steam generators or 10 percent SGTP in the Framatome Model 56119 replacement steam generators.

• The maximum critical boron concentration and minimum change in boron concentration from initial to critical conditions during startup are plant-specific values that are confirmed to be valid every cycle as part of the reload verification process.

5.1.4.1.3 Results Dilution during Full-Power Operation (Mode 1)

With the reactor in automatic rod control, the power and temperature increase from the boron dilution results in insertion of the control rods and a decrease in available shutdown margin. The rod insertion limit alarms (low and low-low settings) alert the operator at least 21 minutes prior to loss of shutdown margin. This is sufficient time to determine the cause of dilution, isolate the reactor makeup source, and initiate boration before the available shutdown margin is lost.

With the reactor in manual control, and assuming the operator takes no action, the power and temperature will rise to the OTAT or OPAT reactor trip setpoint. The boron dilution transient in this case is essentially the equivalent to an uncontrolled RCCA bank withdrawal at power. The maximum reactivity insertion rate for a boron dilution is conservatively estimated to be 3.3 pcm/sec, which is within the range of insertion rates analyzed in the RCCA bank withdrawal at power analysis described in Section 5.1.2.

Thus, the effects of dilution prior to reactor trip are bounded by the uncontrolled RCCA bank withdrawal at-power analysis. Following reactor trip, there are greater than 20 minutes prior to criticality. This is sufficient time for the operator to determine the cause of dilution, isolate the reactor water makeup source, and initiate boration before the available shutdown margin is lost.

Dilution at Startup (Mode 2)

The startup mode of operation is a transitory operational mode in which the operator intentionally dilutes and withdraws control rods to take the plant critical. During this mode, the plant is in manual control with the operator required to maintain a high awareness of the plant status. For a normal approach to criticality, the operator must manually initiate a limited dilution and subsequently manually withdraw the control rods, a process that takes several hours. The operating procedures require that the operator determine the estimated critical position of the control rods prior to approaching critically, thus ensuring that the reactor January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-0 1 1604

5-96 does not go critical with the control rods below the insertion limits. Once critical, the power escalation must be sufficiently slow to allow the operator to manually block the source range reactor trip after receiving P-6 from the intermediate range. Too fast of a power escalation (due to an unknown dilution) would result in reaching P-6 unexpectedly, leaving insufficient time to manually block the source range reactor trip, and the reactor would immediately shut down.

However, in the event of an unplanned approach to criticality or dilution during power escalation while in the startup mode, the plant status is such that minimal impact will result. The plant will slowly escalate in power until the power range high neutron flux low setpoint is reached and a reactor trip occurs. From the time of reactor trip, a time period greater than 22 minutes is available for operator action prior to return to criticality.

5.1.4.1.4 Conclusions Because of the procedures involved in the dilution process, an erroneous dilution is considered unlikely.

Nevertheless, if an unintentional dilution of boron in the reactor coolant does occur, numerous alarms and indications are available to alert the operator to the conditions. The maximum reactivity addition due to the dilution is slow enough to allow the operator sufficient time to determine the cause of the addition and take corrective action before shutdown margin is lost.

5.1.4.2 Subcritical Reactor Boron Dilution 5.1.4.2.1 Accident Description Non-borated water may be added to the RCS to increase core reactivity. If this happens inadvertently because of operator error or equipment malfunction, there is an unwanted increase in core reactivity and a decrease in shutdown margin. Termination of the event relies on operator action to stop the unplanned dilution before the shutdown margin is eliminated.

Other mechanisms exist that could cause an inadvertent dilution of the RCS. It has been determined that the limiting condition is with the charging pumps. The following discussion evaluates this mode of dilution.

Reactivity can be added to the core with the CVCS by supplying reactor makeup water from the reactor makeup water system. An intentional boron dilution is a manual operation performed under operator surveillance. For blended injections, a boric acid blend system is provided to permit the operator to match the concentration of reactor coolant makeup water to that existing in the coolant at the time. The CVCS is designed to limit, even under various postulated failure modes, the potential rate of dilution to a value which, after indication through alarms and instrumentation, provides the operator sufficient time to correct the situation in a safe and orderly manner.

The primary source of reactor makeup water for the RCS is the reactor makeup water system. If this is the cause, an inadvertent dilution can be readily terminated by isolating this single source. In order for a significant flow rate of reactor makeup water to be added to the RCS, the charging pumps must be running in addition to the reactor makeup water pumps. There are other potential dilution sources and mechanisms (e.g., inadvertent valve lineups of ion exchangers, etc.).

Licensing Report Island Licensing January 2004 Prairie Island Prairie Report January 2004 6296- RNP.doc-01 1604

5-97 Information on the status of the reactor coolant makeup is available io the operator in the control room.

Lights are provided on the control board to indicate the operating condition of pumps in the CVCS.

Alarms are actuated to warn the operator if boric acid or reactor makeup water flow rates deviate from preset values.

Because of the procedures involved in the dilution process, an erroneous dilution is considered unlikely.

Nevertheless, if an unintentional dilution of boron in the reactor coolant does occur, numerous alarms and indications are available to alert the operator to the condition. The maximum reactivity addition due to the dilution is slow enough to allow the operator to determine the cause of the addition and take corrective action before excessive shutdown margin is lost.

The acceptance criteria for a dilution accident when the reactor is subcritical is that the time between the initiation of the dilution and a complete loss of shutdown margin must be greater than or equal to 24 minutes. This provides ample time for operator recognition and mitigation of the dilution.

5.1.4.2.2 Method of Analysis The methodology, as described in Reference 5.1.4-1, is to determine the minimum required shutdown margin to ensure that the acceptance criteria are satisfied for the specified plant condition and dilution flow rate. The minimum shutdown margin is determined using a relationship for determining the boron concentration as a function of time for a fixed mass and a given dilution rate.

Key assumptions for these analyses are as follows:

a) The mass being diluted remains constant; i.e., there is a letdown flow rate equal in magnitude to the dilution flow rate.

b) The boron concentration is uniform throughout the mass being diluted; i.e., perfect and instantaneous mixing.

c) The methods used in this evaluation determine the minimum shutdown margin requirements necessary to satisfy the acceptance criteria. There are no key physics parameters that need to be reviewed each refueling cycle.

d) The mass being diluted includes all active portions of the RCS and interconnecting systems; i.e., where circulation is occurring. This includes the core, baffle region, downcomer, lower plenum, upper plenum, piping, and pumps. Depending on the system configuration being analyzed, it may also include volumes in the steam generators or in the decay heat removal system. The volumes are determined based on nominal dimensions of the systems.

e) The boron concentrations are determined using approved methodologies and include the appropriate calculational uncertainties. These concentrations are determined for the various plant conditions being analyzed, i.e., core exposure, RCS temperature, Xenon concentration.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-98 f) The boron concentration corresponding to the complete loss of shutdown margin is determined assuming that all available trip reactivity (accounting for the possibility of the most reactive rod being stuck) has been inserted into the core.

g) The dilution flow rate is the maximum flow based on the system configuration, system pressure, and number of pumps running (note that the number of pumps running may be less than the number of pumps available). For the purpose of this input, an additional pump started for a brief period of time to accomplish such operations as pump switching does not constitute an additional pump running.

As the initiation of this event requires multiple system malfunctions and/or operator errors, no additional operator errors are assumed to occur.

The analysis of a CVCS malfunction with the reactor subcritical does not result in a reactor trip or safety injection signal. Therefore, there is no actuation of active safety grade components required for mitigation of the transient. Consequently, no single failure assumption is applied.

5.1.4.23 Results These transients are evaluated each refueling cycle to ensure that proper shutdown margin requirements are specified. Table 5.1.4-1 shows the results of a typical cycle-specific bounding analysis.

Radiological consequences are not evaluated for this transient because a complete loss of shutdown margin and subsequent fuel clad damage are not expected to occur.

5.1.4.2.4 Conclusions Because of the procedures involved in the dilution process, an erroneous dilution is considered unlikely.

Nevertheless, if an unintentional dilution of boron in the reactor coolant does occur, numerous alarms and indications are available to alert the operator to the conditions. The maximum reactivity addition due to the dilution is slow enough to allow the operator sufficient time to determine the cause of the addition and take corrective action before shutdown margin is lost.

5.1.4.2.5 References 5.1.4-1 NSPNAD-8102-P-A, Revision 7, "Prairie Island Nuclear Power Plant Reload Safety Evalaution Methods for Application to PI Units," July 1999.

Licensing Report Island Licensing January 2004 Prairie Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-99 Table 5.1.4-1 Typical Shutdown Margin Requirements Number of Charging Pumps Running Plant Conditions(') 041 Pump 2 Pumps 3 Pumps Mode 1 1.7 1.7 1.7 Mode 2 1.7 1.7 1.7 Mode 3, T.gŽ > 5200 F 2.0 2.0 2.0 Mode 4 2.0 4.5 7.0 Mode 5 25 5.0 7.5 Mode 6, ARI1) 5.129 5.129 7.0 Mode 6, ARO )5.129 6.0 9.0 Notes:

1. The Operational Mode Definitions are located in the Prairie Island Technical Specifications.

2. ARI-All Rods In

3. ARO - All Rods Out Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-100 5.1.5 Startup of an Inactive Reactor Coolant Loop If the plant were to operate with one reactor coolant pump (RCP) out of service, there would be reverse flow through the inactive loop due to the pressure difference across the reactor vessel and the fact that there are no isolation valves or check valves in the reactor coolant loops. The cold-leg temperature in the inactive loop is identical to the cold-leg temperature of the active loop (the reactor core inlet temperature).

If the reactor is operated at power with an inactive loop, and assuming that the secondary side of the steam generator in the inactive loop is not isolated, there is a temperature drop across the steam generator in the inactive loop. Therefore, with the reverse flowv, the hot-leg temperature of the inactive loop would be lower than the reactor core inlet temperature.

Starting the idle RCP without first bringing the hot-leg temperature of the inactive loop close to the core inlet temperature would result in an injection of cold water into the core. This injection of cold water into the core would cause a reactivity insertion, and subsequently a power increase due to the effects of moderator density reactivity feedback.

Sequence of Events and Systems Operation Following the startup of an inactive RCP, flow in the inactive reactor coolant loop will accelerate to full flow in the forward direction over a period of several seconds. The Prairie Island Technical Specifications require that both RCPs be operating when the reactor is in Mode 1 or Mode 2. Therefore, the maximum initial core power level for the. startup of an inactive coolant loop is near 0 MWL Under these conditions, there can be no significant reactivity insertion because the reactor coolant system (RCS) is initially at a nearly uniform temperature. Furthermore, the reactor will initially be subcritical by the Technical Specification requirement. Thus, there will be no increase in core power, and no automatic or manual protective action is required.

Conclusions The startup of an inactive reactor coolant loop event results in an increase in reactor vessel flow while the reactor remains in a subcritical condition. No analysis is required to show that the departure from nucleate boiling limit is satisfied for this event.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-101 5.1.6 Excessive Heat Removal Due to Feedwater System Malfunctions (USAR Section 14.4.6)

A change in steam generator feedwater conditions that results in an increase in feedwater flow or a decrease in feedwater temperature could result in excessive heat removal from the plant primary coolant system. Such changes in feedwater flow or feedwater temperature are a result of a failure of a feedwater control valve or feedwater bypass valve, failure in the feedwater control system, or operator error.

The occurrence of these failures that result in an excessive heat removal from the plant primary coolant system cause the primary-side temperature and pressure to decrease significantly. The existence of a negative moderator and fuel temperature reactivity coefficients, and the actions initiated by the reactor rod control system can cause core reactivity to rise, as the primary-side temperature decreases. In the absence of a reactor protection system (RPS) reactor trip or other protective action, this increase in core power, coupled with the decrease in primary-side pressure, can challenge the core thermal limits.

5.1.6.1 Accident Description Feedwater Temperature Reduction An extreme example of excessive heat removal from the reactor coolant system (RCS) is the transient associated with the accidental opening of the feedwater bypass valve, which diverts flow around the low-pressure feedwater heaters. The function of this valve is to maintain net positive suction head on the main feedwater pump in the event that the heater drain pump flow is lost, such as following a large load reduction. In the event of an accidental opening of the feedwater bypass valve, there is a sudden reduction in feedwater inlet temperature to the steam generators. This increased subcooling would create a greater load demand on the RCS due to the increased heat transfer in the steam generator.

With the plant at no-load conditions, the addition of cold feedwater may cause a decrease in RCS temperature and thus a reactivity insertion due to the effects of the negative moderator temperature coefficient. However, the rate of energy change is reduced as load and feedwater flow decrease, so that the transient is less severe than the full-power case.

The net effect on the RCS due to a reduction in feedwater temperature is similar to the effect of increasing secondary steam flow; that is, the reactor will reach a new equilibrium condition at a power level corresponding to the new steam generator temperature. If the increase in reactor power is large enough, primary RPS trip functions such as high neutron flux, OTAT, and OPAT trips will prevent any power increase that could lead to a departure in nucleate boiling ratio (DNBR) lower than the safety analysis limit value. The RPS trip functions may not actuate if the increase in power is not large enough.

Feedwater Flow Increase Another example of excessive heat removal from the RCS is a common-mode failure in the feedwater control system that leads to the accidental opening of the feedwater regulating valves to the steam generators.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-102 Accidental opening of one or two feedwater regulating valves results in an increase of feedwater flow to one or two steam generators, causing excessive heat removal from the RCS. This also causes a decrease \J in feedwater enthalpy due to the higher velocity of the fluid when passing through the feedwater heaters.

For Prairie Island, the heaters are located before the pipe split between the two steam generators, hence both loops will be affected by the decrease in feedwater enthalpy, even if only one feedwater regulating valve fails.

At power, excess feedwater flow causes a greater load demand on the primary side due to increased subcooling in the steam generator. With the plant at zero-power conditions, the addition of relatively cold feedwater may cause a decrease in primary-side temperature, and, therefore, a reactivity insertion due to the effects of the negative moderator temperature coefficient. The resultant decrease in the average temperature of the core causes an increase in core power due to moderator and control system feedback.

This transient is attenuated by the thermal capacity of the primary and secondary sides. If the increase in reactor power is large enough, primary RPS trip functions such as high neutron flux, OTAT, or OPAT will prevent any power increase that can lead to a DNBR less than the safety analysis limit value. The RPS trip functions may not actuate if the increase in power is not large enough.

Continuous addition of cold feedwater after a reactor trip is prevented since the reduction of RCS temperature, pressure, and pressurizer level leads to the actuation of safety injection on low pressurizer pressure. The safety injection signal trips the main feedwater pumps, closes the feedwater pump discharge valves, and closes the main feedwater control valves.

5.1.6.2 Method of Analysis Feedwater Temperature Reduction An evaluation method was applied that demonstrates the decreased enthalpy caused by the feedwater temperature reduction is bounded by an equivalent enthalpy reduction that results from an excessive load increase incident [see Updated Safety Analysis Report (USAR) Section 14.4.7]. No explicit analysis is performed.

Feedwater Flow Increase The feedwater flow increase analysis is performed to demonstrate that the departure from nucleate boiling (DNB) design basis is satisfied. This is accomplished by showing that the calculated minimum DNBR is greater than the safety analysis limit DNBR. The overall analysis process is described as follows.

The feedwater flow increase transient is analyzed using the RETRAN code. The RETRAN computer code is a flexible, transient thermal-hydraulic digital computer code, that has been reviewed and approved by the U.S. Nuclear Regulatory Commission (NRC) for pressurized water reactor licensing applications (Reference 5.1.6-1). The main features of the program include a point kinetics and one-dimensional kinetics model, one-dimensional homogeneous equilibrium mixture thermal-hydraulic model, control system models, and two-phase natural convection heat transfer correlations. The results from the RETRAN computer code are used to determine if the DNB safety analysis limits for the excessive heat removal due to feedwater malfunction event are met.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-103 Feedwater system failures, inciudidig the accidental opening of the feedwater regulating valves, have the potential of allowing increased feedwater flow to one or two steam generator(s) that will result in excessive heat removal from the RCS. Therefore, it is assumed that one or two feedwater control valves fail in the fully open position, allowing the maximum feedwater flow to one or two steam generator(s).

Cases with and without automatic rod control initiated at hot full-power (HFP) conditions were considered. Also addressed is the initiation of a feedwater malfunction event from a hot zero-power (HZP) condition.

The following assumptions are made for the analysis of the feedwater malfunction event involving the accidental opening of one or two feedwater regulating valves:

• The plant is operating at full-power conditions (and no-load conditions for the HZ? case) with the initial reactor power, pressure, and RCS average temperatures assumed to be at the nominal values.

• Uncertainties in initial conditions are included in the DNBR limit calculated using the Revised Thermal Design Procedure (Reference 5.1.6-2), where applicable (full-power cases).

• The feedwater temperature of 434.90 F for the full-power cases is consistent with normal plant conditions. The no-load feedwater temperature of 100.00 F is assumed in the zero-power case.

• The excessive feedwater flow event assumes accidental opening of the feedwater control valves with the reactor at full power with automatic and manual rod control, and zero power while modeling post reactor trip conditions with minimum shutdown margin. The feedwater flow malfunction results in a step increase to 1,540 Ibm/s for the full-power cases and 1,950 Ibm/s for the zero-power cases.

• Maximum (end of life) reactivity feedback conditions with a minimum Doppler-only power defect is conservatively assumed.

• The heat capacity of the RCS metal and steam generator shell are ignored, thereby maximizing the temperature reduction of the RCS coolant.

The RPS features, including power range high neutron flux, OPAT, and turbine trip/feedwater isolation on hi-hi steam generator water level, are available to provide mitigation of the feedwater system malfunction transient.

5.1.63 Results Feedwater Temperature Reduction The opening of a low-pressure heater bypass valve causes a reduction in feedwater temperature, which increases the thermal load on the primary system. The assumed reduction in feedwater temperature is 700 F, which bounds the expected temperature reduction due to bypassing the low pressure feedwater heaters, and corresponds to an equivalent enthalpy of 338.30 Btu/lbm. The excessive increase in January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- R-P.doc-0 1 0

5-104 secondary steam flow (Section 5.1.7) considers a 20-percent flow increase, which corresponds to an equivalent enthalpy of 256.13 Btullbm. The equivalent enthalpy of the excessive increase in steam flow transient is lower (more limiting) than the equivalent enthalpy calculated for the feedwater temperature reduction. Hence, the excessive increase in steam flow transient bounds the feedwater temperature reduction transient. Therefore, no transient results are presented, as no explicit analysis is performed.

Feedwater Flow Increase The results of the analyses demonstrate that both the HFP cases and HZP case meet the applicable DNBR acceptance criterion.

The most limiting case is the excessive feedwater flow to both loops, from a MI-power initial condition with automatic rod control. This case gives the largest reactivity feedback and results in the greatest power increase. A turbine trip, which results in a reactor trip, is actuated when the steam generator water level in either steam generator reaches the hi-hi water level setpoint. Assuming the reactor to be in manual rod control results in a slightly less severe transient. The rod control system is not required to function for this event. However, assuming that the rod control system is operable yields a slightly more limiting transient.

The excessive feedwater flow from a zero-power condition models a HZP post-trip condition (that is, HZP stuck rod reactivity feedback coefficients, minimum shutdown margin) with maximum reactivity feedback conditions (end of life). The limiting HZP feedwater malfunction conditions were compared to those generated for the steam line break, core response analysis performed at similar, zero-power conditions. The results of the comparison concluded that the zero-power feedwater malfunction event conditions are bounded by the event conditions analyzed for the steam line break, core response analysis performed at zero power. Since the HZ? steam line break core response analysis (documented in Section 5.1.13), is shown to meet the DNBR acceptance criteria, it is concluded that the DNB design basis is met for the feedwater malfunction event (resulting in an increase in feedwater flow) at HZP conditions.

Therefore, no transient results are presented, as no explicit analysis is performed.

The consequence of a feedwater flow increase transient is a turbine trip. Following turbine trip, the reactor will automatically be tripped, either directly due to the turbine trip or due to one of the reactor trip signals discussed in Section 5.1.10, Loss of Extemal Electrical Load. If the reactor was in automatic rod control, the control rods would be inserted at the maximum rate following the turbine trip, and the resulting transient would not be limiting in terms of peak RCS or main steam system pressure.

Tables 5.1.6-1 through 5.1.64 show the time sequence of events for the various cases analyzed for each steam generator type as follows:

Westinghouse - Original Steam Generator (OSG) Model 51

- Table 5.1.6-1 HFP- automatic rod control - single loop failure HFP - automatic rod control - multi loop failure

- Table 5.1.6-2 HFP - manual rod control - single loop failure HFP- manual rod control - multi loop failure Report Licensing Report January 2004 Prairie Island Licensing Prairie Island January 2004 6296-LR-NP.doc-01 1604

5-105 Framatome - Replacemileiti Steam Generator (RSG) Model 56/1i9

- Table 5.1.6-3 HFP - automatic rod control - single loop failure - RSG HFP - automatic rod control - multi loop failure - RSG

- Table 5.1.6-4 HFP - manual rod control - single loop failure - RSG HFP - manual rod control - multi loop failure - RSG Figures 5.1.6-1 through 5.1.6-5 show transient responses with the OSG for various system parameters for the most limiting case, i.e., a feedwater flow increase to both loops, initiated from HBEP conditions with automatic rod control.

Figures 5.1.6-6 through 5.1.6-10 show transient responses with the RSG for various system parameters for the most limiting case, i.e., a feedwater flow' increase to both loops, initiated from HFP conditions with automatic rod control.

5.1.6.4 Conclusions Feedwater system malfunction transients involving a reduction in feedwater temperature or an increase in feedwater flow rate have been analyzed or evaluated. These transients show an increase in reactor power due to the excessive heat removal in the steam generators.

With respect to the feedwater temperature reduction transient (accidental opening of the feedwater bypass valve), it was determined to be less severe than the excessive load increase incident (see USAR Section 14.4.7); no explicit analysis is performed. Based on results for the excessive load increase incident, the applicable acceptance criteria for the feedwater temperature reduction transient have been met.

Analyses of the accidental opening of the feedwater regulating valves were performed from a full-power initial condition with and without automatic rod control, and from a zero-power initial condition. All analyses considered single- and multi-loop failures. The feedwater malfunction event analyzed for an increase in feedwater flow from zero-power initial conditions was determined to be less severe than the steam line break core response analysis presented in Section 5.1.13. Based on the results of the steam line break core response event analysis, the applicable acceptance criteria for the feedwater malfunction event at zero-power resulting in an increase in feedwater flow are met. The feedwater malfunction event analyzed for an increase in feedwater flow from full-power initial conditions has been analyzed to show that the minimum DNBR calculated for all cases meets the safety analysis minimum DNBR limit.

Therefore, the DNB design basis is satisfied and no fuel damage is predicted.

5.1.6.5 References 5.1.6-1 D. S. Huegel, et al., "RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses," WCAP-14882-P-A, April 1999.

5.1.6-2 Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-1 1397-P-A, April 1989.

January 2004 Prairie Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-106 Table 5.1.6-1 Westinghouse Model 51 OSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Automatic Rod Control Event Time (Seconds)

Single Loop Failure Multi Loop Failure Main Feedwater Control Valve(s) Fail Full Open 0.0 0.0 Hi-Hi Steam Generator Water Level Trip Setpoint is Reached 86.4 88.1 Turbine Trip Occurs Due to Hi-Hi Steam Generator Level 87.3 89.0 Minimum DNBR Occurs 88.8 32.0 Reactor Trip Occurs Due to Turbine Trip 89.3 91.0 Feedwater Isolation Valves Fully Closed 111.8 113.5 Results Peak Nuclear Power, Fraction of Initial 1.157 1.180 Peak Core Heat Flux, Fraction of Initial 1.153 1.178 Minimum DNBR 1.54 1.44 Safety Analysis Limit DNBR (WRB-I Correlation) 1.34 1.34 Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 1604

5-107 Table 5.1.6-2 Westinghouse Model 51 OSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Manual Rod Control Time (Seconds)

Event Single Loop Failure Multi Loop Failure Main Feedwater Control Valve(s) Fail Full Open 0.0 0.0 Hi-Hi Steam Generator Water Level Trip Setpoint is Reached 85.7 87.1 Turbine Trip Occurs Due to Hi-Hi Steam Generator Level 86.6 88.0 Minimum DNBR Occurs 88.0 89.3 Reactor Trip Occurs Due to Turbine Trip 88.6 90.1 Feedwater Isolation Valves Fully Closed 111.1 112.5 Results Peak Nuclear Power, Fraction of Initial 1.151 1.158 Peak Core Heat Flux, Fraction of Initial 1.146 1.154 Minimum DNBR 1.56 1.53 Safety Analysis Limit DNBR (WRB-1 Correlation) 1.34 1.34 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-108 Table 5.1.6-3 Framatome Model 56/19 RSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Automatic Rod Control V-Time (Seconds)

Event Single Loop Failure Multi Loop Failure Main Feedwater Control Valve(s) Fail Full Open 0.0 0.0 Minimum DNBR Occurs 83.3 32.0 Hi-Hi Steam Generator Water Level Trip Setpoint is Reached 103.3 98.8 Turbine Trip Occurs Due to Hi-Hi Steam Generator Level 104.2 99.7 Reactor Trip Occurs Due to Turbine Trip 106.2 101.8 Feedwater Isolation Valves Fully Closed 128.7 124.2 Results Peak Nuclear Power, Fraction of Initial 1.166 1.189 Peak Core Heat Flux, Fraction of Initial 1.160 1.187 Minimum DNBR 1.49 1.41 Safety Analysis Limit DNBR (WRB-1 Correlation) 1.34 1.34 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-109 Table 5.1.6-4 Framatome Model 56119 RSG - Sequence of Events for Feedwater System Malfunction Event at Full Power, Manual Rod Control Time (Seconds)

Event Single Loop Failure Multi Loop Failure Main Feedwater Control Valve(s) Fail Full Open 0.0 0.0 Hi-Hi Steam Generator Water Level Trip Setpoint is Reached 102.9 97.9 Turbine Trip Occurs Due to Hi-Hi Steam Generator Level 103.8 98.8 Minimum DNBR Occurs 96.0 100.5 Reactor Trip Occurs Due to Turbine Trip 105.9 100.8 Feedwater Isolation Valves Fully Closed 128.3 123.3 Results Peak Nuclear Power, Fraction of Initial 1.160 1.178 Peak Core Heat Flux, Fraction of Initial 1.155 1.168 Minimum DNBR 1.51 1.47 Safety Analysis Limit DNBR (WRB-I Correlation) 1.34 1.34 Prairie Island Licensing Report January 2004 6296%LR-NP.doc-01 1604

5-110

1. 2 -

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0

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I I I I I I I I I I I 2~~ I

-e I I-I II 0 50 10i0 150 200 250 T i me [Is I Figures 5.1.6-1 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full PowerAutomatic Rod Control Case: Reactor Power versus Time Prairie Island Licensing Report January 2004 6296.LR-NP.doc-01 1604

5-111 2300 0

"f 2250 0.

, 2200 cn 2150 2100 r.,_

a, 2050 0W CV 2000 1 950 0 1 550 Time [ s ]

Figures 5.1.6-2 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Pressurizer Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-112 565 -

U-560 -

555 -

S _ I 0.

V 550 -

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I a 50 150 200 250 T ime [ S I Figures 5.1.6-3 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Average Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-113

_ 580 I-E 560 c-' 540 5200 050 100 150 200 250 Time [s ]

Figures 5.1.6-4 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Outlet and Inlet Temperatures versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-114 Figures 5.1.6-5 Westinghouse Model 51 OSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: DNBR versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-115

1. 2 -

a S 1-0 0

, E-L-

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0 50 16O 1 50 200 25a T ime [ s ]

Figures 5.1.6-6 Framatome Model 56119 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Reactor Power versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-116

, 2300 -

0

= 2250 -

w 2200 -

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X2100-QC

.- 205 0 -

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100 150 Time [s ]

Figures 5.1.6-7 Framatome Model 56/19 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Pressurizer Pressure versus Time Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 1604

5-117 95 9 -

I 560-

- 555 -

.1:

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I I - I I 6 50 i0o 1s ] 200 250 Time [ S I Figures 5.1.6-8 Framatome Model 56119 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case

Vessel Average Temperature versus Time January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 200.4 6296-LR-NP.doc-01 1604

5-118 Ann V V-7 _ "1 VZ Do

_2 580 -

I-cL EV I--

560 -

VI co C-> 54.0-V I %

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= 44V q.,) A - 4 I I I I

III,

. Ie i I I

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Figures 5.1.6-9 Framatome Model 56/19 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: Vessel Outlet and Inlet Temperatures versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-119 6

54 v 4-

. m 3 -

2-I I I I I I I I I I I I I I I a I I I I I 1

0 50O I00 1m50 200 250 T i me [Is I Figures 5.1.6-10 Framatome Model 56119 RSG - Feedwater Flow Increase to Both Loops for Hot Full Power Automatic Rod Control Case: DNBR versus Time January 2004 Prairie Island Prairie Licensing Report Island Licensing Report January 2004 6296- RNP.doc-0 1 1604

5-120 5.1.7 Excessive Load Increase Incident (USAR Section 14.4.7) 5.1.7.1 Accident Description An ELI incident is defined as an event resulting in a rapid increase in the steam generator steam flow that causes a power mismatch between the reactor core power and the steam generator load demand. The reactor control system is typically designed to accommodate a 10-percent step-load increase or a 5-percent per minute ramp load increase (without a reactor trip) in the range of 15 to 95 percent of full power. Any loading rate in excess of these values could cause a reactor trip actuated by the reactor protection system (RPS). The results of the ELI analysis performed for Prairie Island supports a maximum step-load increase of 20 percent during full (100 percent) power operation with either the Westinghouse OSGs or the Framatome ANP RSGs.

This accident could result from either an administrative violation, such as excessive loading by the operator, or an equipment malfunction in the steam dump control or turbine speed control.

During power operation, steam dump to the condenser is controlled by reactor coolant condition signals; that is, a high reactor coolant temperature indicates a need for steam dump. A single controller malfunction does not cause steam dump; an interlock is provided that blocks the opening of the valves unless a large turbine load decrease or turbine trip has occurred.

The possible consequence of this accident (assuming no protective functions) is a departure from nucleate boiling (DNB) with subsequent fuel damage. Note that the accident is typically characterized by an approach of parameter values to the protection setpoints without the setpoints actually being reached.

However, given the large load increase (> 10 percent) assumed for Prairie Island, the reactor trip setpoints (high neutron flux, over-power delta-T, and over-temperature delta-T) could be reached during the analysis of the ELI event. These protection functions are defeated in the analysis to preclude reactor trip, ensure the most severe DNB condition is reached, and demonstrate that the plant reaches a new equilibrium condition at a higher power level corresponding to the increase in steam flow.

5.1.7.2 Method ofAnalysis The excessive load increase transient is analyzed using the RETRAN computer code described in WCAP-14882-P-A (Reference 5.1.7-1). The RETRAN model simulates the reactor coolant system, neutron kinetics, pressurizer, pressurizer relief and safety valves, pressurizer heaters, pressurizer spray, steam generators, feedwater system, and main steam safety valves. The code computes pertinent plant variables including steam generator mass, pressurizer water volume, reactor coolant average temperature, reactor coolant system pressure, and steam generator pressure.

The ELI analysis considers both minimum and maximum reactivity feedback plant conditions with automatic and manual rod control operation. Thus, four cases are analyzed.

The ELI incident is analyzed to show that:

The integrity of the core is maintained without a reactor trip [that is, the minimum departure from nucleate boiling ratio (DNBR) remains above the safety analysis limit value].

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5-121

• The peak reactor coolant system (RCS) and main steam systemi (MSS) pressures remain below 110 percent of the design values.

• The ELI event does not progress from an American Nuclear Society (ANS) Condition II event to a worse classification event.

Of these, the primary concern is ensuring that the core integrity is maintained by ensuring that the minimum DNBR value is maintained above the limit.

Maior Assumptions The following key physics parameter assumptions are made in analyzing the ELI event.

When analyzing cases with maximum reactivity feedback conditions:

a. Moderator Density Coefficient: a most positive value is assumed

b. Doppler Temperature Coefficient: a most negative value is assumed

c. Doppler Power Defect: a most negative value is assumed

d. Effective Delayed Neutron Fraction: a minimum value is assumed When analyzing cases with minimum reactivity feedback conditions:

a. Isothermal Temperature Coefficient: a value of 0.0 pcm/0 F is assumed

b. Doppler Power Defect: a least negative value is assumed

c. Effective Delayed Neutron Fraction: a maximum value is assumed The following key system parameter assumptions are made to ensure the overall results of the analysis bound actual plant operation:

a. Initial conditions of core power, RCS coolant temperature, pressurizer pressure and steam generator level are assumed to be at their nominal values consistent with steady-state full power operation. Uncertainties in the initial conditions of these parameters are not considered, consistent with the application of the Revised Thermal Design Procedure (RTDP) (Reference 5.1.7-2).

b. Minimum measured flow is modeled according to the RTDP methodology (Reference 5.1.7-2).

c. Zero percent steam generator tube plugging level is assumed; this maximizes primary-to-secondary heat transfer and results in a more severe RCS cooldown transient.

d. The pressurizer heaters are not credited.

e. The pressurizer sprays and power-operated relief valves are assumed to be operational.

f. Design mixing is assumed for the vessel inlet and outlet flow.

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5-122

g. Fuel geometry and heat transfer parameters are based on maximum UAs (maximum overall fuel to coolant heat transfer coefficients) consistent with minimum fuel temperatures.

The following reactor protection functions are not credited in the ELI analysis:

a. Power range high neutron flux

b. OPAT

c. OTAT

d. Low reactor coolant loop flow

e. High pressurizer pressure

f. High pressurizer water level

g. Low-low SG water level

h. Safety injection No emergency safety features function is credited in the analysis.

5.1.7.3 Results The results of the ELI analysis, assuming a 20-percent load increase from full power conditions, show that the minimum DNBR remains above the safety analysis limit value for all cases. The cases that model "minimum reactivity feedback conditions with automatic rod control" are the most limiting cases with respect to minimum DNBR. The results are summarized in Table 5.1.7-1. The time sequence of events for each case is provided in Table 5.1.7-2. The transient responses for the limiting case of both the Westinghouse OSGs and Framatome ANP RSGs are shown in Figures 5.1.7-1 through 5.1.7-6. Note that a 10-second steady-state is modeled prior to the event initiation.

5.1.7.4 Conclusions The results of the ELI analysis demonstrate that the minimum DNBR remains above the safety analysis limit value for all cases analyzed assuming a 20-percent step-load increase from full power conditions for both the Westinghouse Model 51 SGs and the Framatome ANP RSGs. Therefore, it is demonstrated that fuel and cladding damage is precluded. The results of the analysis do not challenge the RCS overpressure limit. Moreover, as the event is initiated by an increase in the main steam system flow rate, which results in overcooling the RCS and a decrease in the main steam system pressure, the main steam system overpressure limit is not challenged during the event.

5.1.7.5 References 5.1.7-1 WCAP-14882-P-A, "RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses," April 1999.

5.1.7-2 WCAP-11397-P-A, (Proprietary), WCAP-11397-A, (Non-proprietary), "Revised Thermal Design Procedure," Friedland, A. J. and Ray, S., April 1989.

Prairie Island Licensing Report January 2004 6296.LR-NP.doc-01 1604

5-123 Table 5.1.7-1 ELI Summary Results for Westinghouse Model 51 OSGs and Framatome Model 56/19 RSGs Min DNBR/ Core Heat Flux Time (sec) 1 (fon)/Time (sec)

Limits 1.34 1.18 Westinghouse Model 51 OSG

1) Min Feedback/Auto Rod 1.50/40.25 1.169/40.75

2) Min Feedback/Manual Rod 2.09 /18.25 1.002 / 22.00

3) Max Feedback/Auto Rod 1.62 /42.00 1.132 /43.75

4) Max Feedback/Manual Rod 1.71 /300.00 1.104/106.00 Framatome Model 56/19 RSG

1) Min Feedback/Auto Rod 1.49/40.25 1.171/41.00

2) Min Feedback/Manual Rod 2.09/ 18.25 1.002/ 22.00

3) Max Feedback/Auto Rod 1.60/42.50 1.136/ 44.00

4) Max Feedback/Manual Rod 1.70/300.00 1.108/ 99.00 Notes:

1. Includes 10.0 seconds steady-state prior to event initiation.

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5-124 Table 5.1.7-2 Time Sequence of Events for Excessive Load Increase Incident (Westinghouse Model 51 OSGs and Framatome 56119 RSGs)

Case Event Time (sec)

1. Minimum Reactivity Feedback (automatic rod 20-percent step-load increase 10.0 control) Equilibrium conditions reached 100 (approximate time)

2. Minimum Reactivity Feedback (manual rod control) 20-percent step-load increase 10.0 Equilibrium conditions reached 250 (approximate time)

3. Maximum Reactivity Feedback (automatic rod 20-percent step-load increase 10.0 control) Equilibrium conditions reached 80 (approximate time)

4. Maximum Reactivity Feedback (manual rod control) 20-percent step-load increase 10.0 Equilibrium conditions reached 80 (approximate time)

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5-125

/WestinghouseOSGs

--- - Fromatome ANP RS~s 1.2 0

o 1.15 0

4o C

0

.21.05 0

0~

0 L1 a) z . 95 Time [seconds]

Figure 5.1.7-1 Nuclear Power: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-126 Westinghouse OSGs

- -- - Framatome ANP RSGs 2260 -

-' MU I C)2230 -

D I 23) 2-n w 2230 -

2210 i I Time [seconds]

Figure 5.1.7-2 Pressurizer Pressure: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 11604

5-127 Westinghouse OSGs

- --- Fromratome ANP RSGs 360-S .

Q)355-

-Q 350 -

c) o 345 E

0 340 CD,

~330-325 0 50 100 150 200 250 300 Time [seconds]

Figure 5.1.7-3 Pressurizer Water Volume: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control Report January 2004 Prairie Island Licensing Praire Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-128 Wesestinghouse OSGs

-- -- Framartome ANP RSGs 560M

-11

a. 560

,I a.) 559.5 0

559 Q) a 558.5 558 K>

557.5 a.)

() 557

>)

556.5 150 Time [seconds]

Figure 5.1.7-4 Vessel Average Temperature: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 1604

5-129 Westinghouse OSGs

- -- -Framatome ANP RSGs 2.2 2.1 2

1.9 z 18 1.7 1.6 15 1.4 150 Time [seconds]

Figure 5.1.7-5 DNBR: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control Prairie Island Licensing Report st January 2004 6296- RNP.doc-0 1 1604

5-130

'Wesstinghouse OSGs

--- - Framotome ANP RSGs 2400 a)

U 2300 E

-Q 3¢ 2200 0

E 2100 0

a) i) 2000 0

' I I I I I I I I I I I I I II .I I I I I I II 1900 1 0 50 I0 150 200 250 300 Time [seconds]

Figure 5.1.7-6 Total Steam Flow: 20-Percent Step-Load Increase Minimum Reactivity Feedback/Automatic Rod Control January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296- .NP.doc-0 11604

5-13 1 5.1.8 Loss of Reactor Coolant Flow (USAR Section 14.4.8.1)

The loss of reactor coolant flow events are categorized as follows in the Prairie Island Updated Safety Analysis Report (USAR).

• Flow coastdown accidents

• Locked-rotor accident The first category includes the partial and complete loss of reactor coolant flow events. The second category includes the hypothetical event that addresses an instantaneous seizure of a reactor coolant pump (RCP) rotor.

5.1.8.1 Partial Loss of Reactor Coolant Flow Accident Description The partial loss-of-coolant-flow accident can result from a mechanical or electrical failure in an RCP, or from a fault in the power supply to the RCR If the reactor is at power at the time of the accident, the immediate effect of loss-of-coolant flow is a rapid increase in the coolant temperature. This increase could result in departure from nucleate boiling (DNB) with subsequent fuel damage if the reactor is not tripped promptly.

Normal power for the pumps is supplied through individual buses powered by the main generator. When a generator trip occurs, the buses transfer to a power supply connected to the external power lines, and the pumps continue to supply coolant to the core.

The necessary protection against a partial loss-of-coolant-flow accident is provided by the low primary coolant flow reactor trip signal, which is actuated in any reactor coolant loop by two-out-of-three low flow signals. Above the Permissive 8 setpoint, low flow in either loop will actuate a reactor trip. Above the Permissive 7 setpoint, low flow in both loops will actuate a reactor trip.

Method of Analysis The loss of an RCP with both loops in operation event is analyzed to show that: (1) the integrity of the core is maintained as the departure from nucleate boiling ratio (DNBR) remains above the safety analysis limit value, and (2) the peak reactor coolant system (RCS) and secondary system pressures remain below the design limits. Of these, the primary concern is assuring that the DNBR limit is met.

The loss of an RCP event is analyzed with two computer codes. First, the RETRAN computer code is used to calculate the loop and core flow during the transient, the time of reactor trip based on the calculated flows, the nuclear power transient, and the primary-system pressure and temperature transients.

The VIPRE computer code is then used to calculate the hot-channel heat flux transient and DNBR, based on the nuclear power and RCS temperature (enthalpy), pressure, and flow from RETRAN. The DNBR transients presented represent the minimum of the typical or thimble cell.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O 11 604

5-132 This event is analyzed with the Revised Thermal Design Procedure (RTDP). Initial reactor power, pressurizer pressure, and RCS temperature are assumed to be at their nominal values. Minimum measured flow is also assumed. A conservatively large absolute value of the Doppler-only power coefficient is used, along with the most-positive isothermal temperature coefficient (LTC) limit for full-power operation (0 pcm/0 F). These assumptions maximize the core power during the initial part of the transient when the minimum DNBR is reached.

A limiting end-of-cycle (EOQC) DNB axial power shape is assumed in VIPRE for the calculation of DNBR. This shape provides the most limiting minimum DNBR for the loss-of-flow events.

A conservatively low trip reactivity value (4.0-percent Ap) is used to minimize the effect of rod insertion following reactor trip and maximize the heat flux statepoint used in the DNBR evaluation for this event.

This value is based on the assumption that the highest worth rod cluster control assembly (RCCA) is stuck in its fully withdrawn position. A conservative trip reactivity worth versus rod position was modeled in addition to a rod drop time that is conservative for the reduced core flow at the time of trip.

The flow coastdown analysis is based on a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the continuity equation, a pump momentum balance, and the pump characteristics. Also, it is based on conservative estimates of system pressure losses.

The Westinghouse original steam generators were modeled. However, the analysis applies to both the Westinghouse original and Framatome replacement steam generators since this event is not sensitive to the secondary-side modeling. A maximum, uniform, steam generator tube plugging (SGTP) level of K) 25 percent was assumed in the RETRAN analysis. However, a core flow reduction of 1.1 percent, which addresses the potential reactor coolant flow asymmetry associated with a maximum loop-to-loop SGTP imbalance of 10 percent, was applied.

Results Figures 5.1.8-1 through 5.1.8-8 illustrate the transient response for the loss of an RCP with both loops initially in operation. The minimum DNBR is 1.607/1.662 (thimble/typical), which occurred at 4.45 seconds (DNBR limit: 1.34/1.34 (thimble/typical)).

The calculated sequence of events table is shown in Table 5.1.8-1. This event trips on a low primary reactor coolant flow trip setpoint, which is assumed to be 87 percent of loop flow. Following reactor trip, the affected RCP will continue to coast down, and the core flow will reach a new equilibrium value corresponding to the remaining pump still in operation. With the reactor tripped, a stable plant condition will eventually be attained. Normal plant shutdown may then proceed.

Conclusions The analysis performed has demonstrated that for the partial loss-of-coolant event, the DNBR does not decrease below the limit value at any time during the transient. Therefore, no fuel or cladding damage is predicted and all applicable acceptance criteria are met.

Licensing Report Island Licensin6 January 2004 Prairie Island Prairie Report January 2004 6296-LR-NP.doc-01 1604

5-133 5.1.8.2 Complete Loss of Forced Reactor Coolant Flow Accident Description A complete loss of forced reactor coolant flow may result from a simultaneous loss of electrical supplies to all RCPs. If the reactor is at power at the time of the accident, the immediate effect of the loss-of-coolant flow is a rapid increase in the coolant temperature. This increase could result in DNB with subsequent fuel damage if the reactor were not tripped promptly.

Normal power for the pumps is supplied through individual buses powered by the main generator. When a generator trip occurs, the buses transfer to a power supply connected to the external power lines, and the pumps continue to supply coolant to the core.

The following signals provide the necessary protection against a complete loss-of-flow accident:

• RCP power supply undervoltage reactor trip

• Low reactor coolant loop flow reactor trip

• Pump circuit breaker opening (RCP supply underfrequency opens pump circuit breaker, which trips the reactor)

The reactor trip on RCP undervoltage is provided to protect against conditions that can cause a loss of voltage to all RCPs; that is, station blackout. This function is blocked below approximately 10-percent nuclear instrumentation system (NIS) and 10-percent turbine power (Permissive 7).

The reactor trip on low primary coolant flow is provided to protect against loss-of-flow conditions that affect one or both reactor coolant loops. This function is generated by two-out-of-three low flow signals per reactor coolant loop. Above the Permissive 8 setpoint, low flow in either loop will actuate a reactor trip. Above the Permissive 7 setpoint, low flow in both loops will actuate a reactor trip.

The reactor trip on RCP underfrequency (pump circuit breaker opening) is available to trip the reactor for an underfrequency condition, resulting from frequency disturbances on the power grid. However, the analysis conservatively assumes that this function is not available to provide a reactor trip. Therefore, the low primary coolant flow reactor trip function is assumed to provide primary protection against an underfrequency event.

This event is conservatively analyzed to the following acceptance criteria:

• Pressure in the RCS and main steam system (MSS) should be maintained below 110 percent of the design values.

• Fuel cladding integrity shall be maintained by ensuring that the minimum DNBR remains above the limit value.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-134

• An incident of moderate frequency should not generate a more serious plant condition without other faults occurring independently.

Method of Analysis The complete loss-of-flow transient is analyzed as a loss of both RCPs with both loops in operation. The event is analyzed to show that the integrity of the core is maintained as the DNBR remains above the safety analysis limit value. The loss-of-flow events do result in an increase in RCS and MSS pressures, but these pressure increases are generally not severe enough to challenge the integrity of the RCS and MSS. Since the maximum RCS and MSS pressures do not exceed 110 percent of their respective design pressures for the loss-of-load event, it is concluded that the maximum RCS and MSS pressures will also remain below 110 percent of their respective design pressures for the loss-of-flow events.

The transients are analyzed with two computer codes. First, the RETRAN computer code is used to calculate the loop and core flow during the transient, the time of reactor trip based on the calculated flows, the nuclear power transient, and the primary-system pressure and temperature transients. The VIPRE computer code is then used to calculate the heat flux and DNBR transients based on the nuclear power and RCS temperature (enthalpy), pressure, and flow from RETRAN. The DNBR transients presented represent the minimum of the typical or thimble cell for the fuel.

This event is analyzed with RTDP. Initial reactor power, pressurizer pressure and RCS temperature are assumed to be at their nominal values. Minimum measured flow is also assumed. A conservatively large absolute value of the Doppler-only power coefficient is used, along with the most-positive ITC limit for full-power operation (0 pcm/°F). These assumptions maximize the core power during the initial part of K the transient when the minimum DNBR is reached.

A limiting EOC DNB axial power shape is assumed in VIPRE for the calculation of DNBR. This shape provides the most limiting minimum DNBR for the loss-of-flow events.

A conservatively low trip reactivity value (4.0-percent Ap) is used to minimize the effect of rod insertion following reactor trip and maximize the heat flux statepoint used in the DNBR evaluation for this event.

This value is based on the assumption that the highest worth RCCA is stuck in its fully withdrawn position. A conservative trip reactivity worth versus rod position was modeled in addition to a rod drop time that is conservative for the reduced core flow at the time of trip.

The flow coastdown analysis is based on a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the continuity equation, a pump momentum balance, and the pump characteristics. Also, it is based on conservative estimates of system pressure losses.

The Westinghouse original steam generators were modeled. However, the analysis applies to both the Westinghouse original and Framatome replacement steam generators since this event is not sensitive to the secondary side modeling. A maximum, uniform, SGTP level of 25 percent was assumed in the RETRAN analysis. Reactor coolant system loop flow asymmetry due to a loop-to-loop SGTP imbalance does not need to be considered for transients in which both RCPs experience a coastdown.

Licensing Report Island Licensing Prairie Island January 2004 Prairie Report January 2004 6296-L-NP.doc-01 160

5-135 Results Figures 5.1.8-9 through 5.1.8-16 illustrate the transient response for the complete loss of flow associated with a loss of power to both RCPs with both loops in operation. The minimum DNBR is 1.333/1.344 (thimble/typical) which occurred at 4.6 seconds (DNBR limit: 1.34/1.34 (thimble/typical)). Although the thimble cell minimum DNBR is slightly less than the safety analysis limit value, there is sufficient margin available between the DNBR design limit (1.22) and the safety analysis limit (1.34) to ensure that the DNB design basis is satisfied; see Section 4.0 for a discussion on the difference between the DNBR design limit and the safety analysis limit.

The calculated sequence of events for the complete loss-of-flow case is shown on Table 5.1.8-2.

Following reactor trip, the RCPs will continue to coast down, and natural circulation flow will eventually be established. With the reactor tripped, a stable plant condition will eventually be attained. Normal plant shutdown may then proceed.

Conclusions The analysis performed has demonstrated that for the complete loss-of-flow event, the DNBR decreases below the safety analysis limit value for the thimble cell by 0.53 percent. However, sufficient margin still exists to the design limit (1.22) such that no fuel or cladding damage is predicted and all applicable acceptance criteria are met.

Prairie Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-136 Table 5.1.8-1 Sequence of Events - Partial Loss of Reactor Coolant Flow Event Time (seconds)

One Operating RCP Loses Power and Begins Coasting Down 0.0 Low Flow Reactor Trip Setpoint is Reached 1.55 Rods Begin to Drop 2.75 Minimum DNBR Occurs 4.45 Table 5.1.8-2 Sequence of Events - Complete Loss of Reactor Coolant Flow Event Time (seconds)

All Operating RCPs Lose Power and Coastdown Begins 0.0 Low Flow Reactor Trip Setpoint is Reached 1.72 Rods Begin to Drop 2.92 Minimum DNBR Occurs 4.60 i

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-137

.94 -

1=

0 Ua.

.88 4- --- -------

0 U-LL.

ID

.82 4-----------;-----------

r-

.76 ---- -------

I

!K, I I . I

.7 . . I I I I I *

• 2.8 5.6 8.4 14 Time [seconds]

Figure 5.1.8-1 Total Core Inlet Flow versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc- 11604

5-138

.85 ------------

z 0

E

.7 4--_ --

f--

0 0

.5 4--------- - - - -- _- _-_- -

-J E-

.4 ----- _-_____-_

II I

.25 .4. I! I I I I I I 0 I I I 4 4  ! I I I I I I 0 2. 5.6 8.4 1' .2 14 Time [seconds]

Figure 5.1.8-2 RCS Faulted Loop Flow versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

K Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 2004 6296- RNP.doc-0 11604

5-139 1.2 -

.96 - ______ -_ .---

I z

ru, 0 .72 - _ _ _.----

LA-0Btr 0L 3..

I-a CD

.48- __-_--- . -- --- -

'---------l-'-I

.24 - --

- --_ - I- - - - - -- -

0 -._ I

,,,,I I I

• I I

,I I

I I ,I III*

• I *I *I.

• . . . I. I. I I I 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-3 Nuclear Power versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

January 2004 Prairie Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-140 1.2*1 P P

.96 4-----6---

z 0

U-

.2 4------__-. ---------

0 0) 0 0) 0 .48 4- ----_ ----- .

L.

0 C.)

14 ----- ---- x I .. l

,, I I I I II II II I I I 0 1 4 I I P 6 6 6 0 2.8 5.6 I

8.4 I

11.2 14 Time [seconds]

Figure 5.1.84 Core Average Heat Flux versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

Prairie Island Licensing Report r aJanuary 2004 6296-LR-NP.doc-0 11604

5-141 2300 -

I I 2260 -

I ,

F_ _ _ ________I

- +

Q 0.

CL 2220 -___- _-

I...

L-0C o

V) 0 va-2180 -- --- , I----

0 Q)

K11 2140 .- - 4- + __

-__ __ -_ + __ _ _-_-.-

I I I I I I I I I I I I I I I I 2100 .4 .1* 9 9 0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-5 Pressurizer Pressure versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

Prairie Island Licensing Report January 2004 6296-LP-NP.doc-01 1604

5-142 Loop I Hot Leg

-- - -Loop I Co Id Leg 650 620 b..

0 U-590 - ----------- _

oI-a 0

1L E

0

0. 5604- - -

0 en

-J 0

530 -- _ _ __ _ _

I I_

I I II II I I I I I I I I I I 500 -4. I I 4 4 4 I I 4 I I I I 0 2.8 5:6 8:4 11.2 14 Time [seconds]

Figure 5.1.8-6 RCS Faulted Loop Temperature versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296- RNP.doc-01 1604

5-143 1.1

_I----- . --------------- 4---------------____

.9 -______________,

i Ad-----

C-

.8 4----------------

0 U- _.

x0

.7 -----

-4 --------- _________

C-,

CD .6 - ,_______

-6 V

I-

.4 - I---------------

II--- -----

I I

! I I I I

.3 -

0 3 6 9 12 Time (seconds)

Figure 5.1.8-7 Hot Channel Heat Flux versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-144 Transient DNBR

- - - -DNBR Limit 5 -f -

44---------------;-------------- F----------------

3- 1F---------------

/

2 --------------- 1F------------

Il Il I I I It I 10- 4 3

I I 4. I I 9

I I I 12 Time (seconds)

Figure 5.1.8-8 DNBR versus Time - Partial Loss of Flow, One Pump Coasting Down (PLOF)

January 2004 Prairie Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-011604

5-145 I-

.88 - ----------- _

0 3: .76 -

0 L-CD r-L.,

0

.64----------- -- ----------

0

.52 4----------------------- - ---------

I I l l I I . , . II I ,

I

.4 4. ,,

i

• * 4.

I 0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-9 Total Core Inlet Flow versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF)

Prairie Island Licensing Report t January 2004 6296- RNP.doc-0 11604

5-146

'a-I1-7

.88 -

I---

z 0

3r 0 .76-- ___________ ----

La.

0 U

CL 0.

.64-_ - _----------

0 0

-LQI 0:

C I___ _ _ _ _

.52  ! -------

! I

.4.4 L I I I 4

I I I I 4 I I U 4 I I 4 t

0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-10 RCS Loop Flow versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF)

Prairie Island Licensing Report January 2004 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-147 1.2 -

.96 - - - - I z ___________.

0 .72 - - - - - - - - -

LA.

I-0 CL a

.48 -

z

.24 - , _ _ _ _ _ _ _ _

0 _

I I I I i a I. I. o . . I .I .

0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-11 Nuclear Power versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-148 1.2 -

.96 - ,___________-

F-, --- ---

0 LA..

L-j x

.72 - -___________I I------------

.4-a St CD C) 0D .48 84----------------------

L-0 K-)1 C.)

.24 4-----------4-----------,_-----------

0 -4 . ._._._,_.

I I

I I,

a I, .

I

. I , .

0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-12 Core Average Heat Flux versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-149 2400 2340 4----------- -___________. ---- ----- -

a-Iti Ct

-t 2280 - -----

0 I-0 At e) 0~

1t 1.I

2220- _ ---------------------- 4-----------

0 I-At 2160 0----- I I I-----_- - L_- -- -- - - - --

2100 I I I I I I I, I &

I I I I 1

! I I, I 0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-13 Pressurizer Pressure versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-150 Loop 1 Hot Leg

- -Loop 1 Cold Leg 650 -

I------------

620 -

L.

C]

0 a

590 -

4-a ED a

CL E

0.

560 - ___________.

0 0

-J e) 530

_ I _I _ _ _ _.

500 I I I I I I

I I, I I a 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.8-14 RCS Faulted Loop Temperature versus Time - Complete Loss of Flow - Two Pumps Coasting Down (CLOF)

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296- RNP.doc-01 1604

5-151 1.1 I t- -- - .- IId----------------

a- - ---- -- - -

---

t--

0 Z ------------

4I X

I-, .7 4 ----------- +------------

Qa) 4I 0

_c C-.

-1

.X-4-------------+-____________---

.5-4--------------- ; ---------------- A___________

.4 - -----__--_ _

I I I 9 I I I a a I II II

-4 a I

-j I I 12 Time (seconds)

Figure 5.1.8-15 Hot Channel Heat Flux versus Time - Complete Loss or Flow, Two Pumps Coasting Down (CLOF)

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-0 160

5-152

' K Tr Transient DNBR

- - - -DNBR L imi t 4

3.5 3

2 1.5 1

Time (seconds)

Figure 5.1.8-16 DNBR versus Time - Complete Loss of Flow, Two Pumps Coasting Down (CLOF)

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-01 I1604

5-153 5.1.9 Locked-Rotor Accident (USAR Section 14.4.8.2)

Accident Description The postulated locked-rotor accident is an instantaneous seizure of an RCP rotor. Flow through the affected reactor coolant loop is rapidly reduced, leading to an initiation of a reactor trip on a low-flow signal. The consequences of a postulated pump shaft break accident are similar to the locked-rotor event.

With a broken shaft, the impeller is free to spin, as opposed to it being fixed in position during the locked-rotor event. Therefore, the initial rate of reduction in core flow is greater during a locked-rotor event than in a pump shaft break event because the fixed shaft causes greater resistance than a free-spinning impeller early in the transient, when flow through the affected loop is in the positive direction. As the transient continues, the flow direction through the affected loop is reversed. If the impeller is able to spin free, the flow to the core will be less than that available with a fixed-shaft during periods of reverse flow in the affected loop. Because peak pressure, cladding temperature, and DNB occur very early in the transient, the reduction in core flow during the period of forward flow in the affected loop dominates the severity of the results. Consequently, the bounding results for the locked-rotor transients also are applicable to the RCP shaft break.

After the locked rotor, reactor trip is initiated on an RCS low-flow signal. The unaffected RCP is assumed to remain operating throughout the event.

Following initiation of the reactor trip, heat stored in the fuel rods continues to be transferred to the coolant causing the coolant to expand. At the same time, heat transfer to the shell side of the steam generators is reduced. This is because, first, the reduced flow results in a decreased tube-side film coefficient and then because the reactor coolant in the tubes cools down while the shell-side temperature increases (turbine steam flow is reduced to zero upon plant trip). The rapid expansion of the coolant in the reactor core, combined with reduced heat transfer in the steam generators, causes an insurge into the pressurizer and a pressure increase throughout the RCS. The insurge into the pressurizer compresses the steam volume, actuates the automatic spray system, opens the power-operated relief valves (PORVs), and opens the pressurizer safety valves, in that sequence. The two PORVs are designed for reliable operation and would be expected to function properly during the accident. However, for conservatism in the peak-pressure evaluation, their pressure-reducing effect and the pressure-reducing effect of the pressurizer sprays are not included in the analysis.

The locked-rotor event is analyzed to the following criteria:

• Pressure in the RCS should be maintained below the designated limit (see below).

• Coolable core geometry is ensured by showing that the peak cladding temperature and maximum oxidation level for the hot spot are below 2,7000 F and 16.0 percent by weight, respectively.

• Activity release is such that the calculated doses meet 10 CFR Part 100 guidelines.

For Prairie Island, the locked-rotor RCS pressure limit is equal to 110 percent of the design value, or 2,748.5 psia. For the secondary side, the locked-rotor pressure limit is also assumed to be equal to January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-154 110 percent of design pressure, or 1,208.5 psia. Since the loss-of-load analysis bounds the locked rotor, a specific MSS overpressurization analysis is not performed.

A hot-spot evaluation is performed to calculate the peak cladding temperature and maximum oxidation level. Finally, a calculation of the "rods-in-DNB" is performed for input to the radiological dose analysis.

Method of Analysis The locked-rotor transient is analyzed with two primary computer codes. First, the RETRAN computer code is used to calculate the loop and core flow during the transient, the time of reactor trip based on the calculated flows, the nuclear power transient, and the primary-system pressure and temperature transients.

The VIPRE code is then used to calculate the rods-in-DNB and peak cladding temperature using the nuclear power and RCS temperature (enthalpy), pressure, and flow from RETRAN.

For the case analyzed to determine the maximum RCS pressure and peak cladding temperature, the plant is assumed to be in operation under the most adverse steady-state operating conditions; that is, a maximum steady-state thermal power, maximum steady-state pressure, and maximum steady-state coolant average temperature. The case analyzed to determine the rods-in-DNB utilizes the RTDP methodology. Initial reactor power, pressurizer pressure and RCS temperature are assumed to be at their nominal values. Minimum measured flow is also assumed.

The Westinghouse original steam generators were modeled. However, the analysis applies to both the Westinghouse original and Framatome replacement steam generators since this event is not sensitive to the secondary side modeling. A maximum, uniform, SGTP level of 25 percent was assumed in the RETRAN analysis. However, a core flow reduction of 1.1 percent, which addresses the potential reactor coolant flow asymmetry associated with a maximum loop-to-loop SGTP imbalance of 10 percent, was applied.

A conservatively large absolute value of the Doppler-only power coefficient is used, along with the most-positive ITC limit for full-power operation (0 pcm/°F). These assumptions maximize the core power during the initial part of the transient when the peak RCS pressures and hot-spot results are reached.

A conservatively low trip reactivity value (4.0-percent Ap) is used to minimize the effect of rod insertion following reactor trip and maximize the heat flux statepoint used in the DNBR evaluation for this event.

This value is based on the assumption that the highest worth RCCA is stuck in its fully withdrawn position. A conservative trip reactivity worth versus rod position was modeled in addition to a rod drop time that is conservative for the reduced core flow at the time of trip.

For the peak RCS pressure evaluation, the initial pressure is conservatively estimated as 40 psi above the nominal pressure (2,250 psia) to allow for errors in the pressurizer pressure measurement and control channels. This is done to obtain the highest possible rise in the coolant pressure during the transient. The peak RCS pressure occurs in the lower plenum of the vessel. The pressure transient in the lower plenum is shown in Figure 5.1.9-6.

Report Licensing Report January 2004 Prairie Island Licensing Prairie Island January 2004 6296-LR-NP.doc01 1604

5-155 For this accident, an evaluation of the consequences with respect to the fuel rod thermal transient is performed. The evaluation incorporates the assumption of rods going into DNB as a conservative initial condition to determine the cladding temperature and zirconium water reaction resulting from the locked rotor. Results obtained from the analysis of this hot-spot condition represent the upper limit with respect to cladding temperature and zirconium water reaction. In the evaluation, the rod power at the hot spot is assumed to be 2.5 times the average rod power (that is, FQ = 2.5) at the initial core power level.

Film Boiling Coefficient The film boiling coefficient is calculated in the VIPRE code using the Bishop-Sandberg-Tong film boiling correlation. The fluid properties are evaluated at film temperature. The program calculates the film coefficient at every time step based upon the actual heat transfer conditions at the time. The nuclear power, system pressure, bulk density, and RCS flow rate as a function of time are based on the RETRAN results.

Fuel Cladding Gap Coefficient The magnitude and time dependence of the heat transfer coefficient between fuel and cladding (gap coefficient) has a pronounced influence on the thermal results. The larger the value of the gap coefficient, the more heat is transferred between the pellet and cladding. Based on investigations on the effect of the gap coefficient upon the maximum cladding temperature during the transient, the gap coefficient was assumed to increase from a steady-state value consistent with initial fuel temperature to approximately 10,000 Btu/hr-fte-F2 at the initiation of the transient. Therefore, the large amount of energy stored in the fuel because of the small initial value is released to the cladding at the initiation of the transient.

Zirconium-Steam Reaction The zirconium-steam reaction can become significant above 1,800'F (cladding temperature). The Baker-Just parabolic rate equation is used to define the rate of zirconium-steam reaction. The effect of the zirconium-steam reaction is included in the calculation of the hot-spot cladding temperature transient.

Results Figures 5.1.9-1 through 5.1.9-8 illustrate the transient response for the locked-rotor event (peak RCS pressure/peak cladding temperature case). The peak RCS pressure is 2,562 psia and is less than the acceptance criterion of 2,748.5 psia. Also, the peak cladding temperature is 2,010TF, which is considerably less than the limit of 2,700'F. The zirconium-steam reaction at the hotspot is 0.60 percent by weight, which meets the criterion of less than 16-percent zirconium-steam water reaction. For the radiological dose evaluation, the maximum percentage of fuel rods calculated to experience a DNBR less than the limit value is 18.4 percent (rods-in-DNB case). The sequence of events for the peak RCS pressure/peak cladding temperature case is given in Table 5.1.9-1. This transient trips on a low primary reactor coolant flow trip setpoint, which is assumed to be 87 percent.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-156 Conclusions The analysis performed has demonstrated that for the locked-rotor event, the RCS pressure remains below 110 percent of the design pressure and the hot-spot cladding temperature and oxidation levels remain below the limit values. Therefore, all applicable acceptance criteria are met. In addition, the maximum percentage of rods calculated to experience a DNBR less than the limit value is 18.4 percent.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-157 Table 5.1.9-1 Sequence of Events - Reactor Coolant Pump Locked Rotor Event Time (seconds)

Rotor on One Pump Locks 0.00 Low Flow Reactor Trip Setpoint Reached 0.04 Rods Begin to Drop 1.24 Maximum RCS Pressure Occurs 3.30 Maximum Cladding Temperature Occurs 3.40 January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LRNP.doc-01 1604

5-158 i I I ei

.88 - - - , S ________

3.' .76 - ---------- ,-----------------------------------'-------------

.64 --- -- -- -- -- --- -- -- -- -- -- --- -- - - -- -- --

.52 - --- -- -- -- -- -- -- --- -- -- -- -- -- -- --

O 2.8 5.6 8.4 11.2 4 Time [seconds]

Figure 5.1.9-1 Total Core Inlet Flow versus Time - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case Report January 2004 Prairie Island Licensing Report Island Licensing January 200.4 6296- RNP.doc-01 1604

5-159 1.-

.7 - -- --- - - - - I--- - - - - -- - a - -

z 0

3:

.4 -

0 I-C, B.

0 .1 - -- - - - - - - -

0.

-.2 - ------ -- - - - + 4-- - - - - - _

I I I I I I I I ! I I I I I,

-.5 - I I I I I 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.9-2 RCS Loop Flow versus Time - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-160 1.2 '-1

.96 z -__________

0 .72 -

b..

I...

0 0

0 0 ____ _____--

z

.24 ------------

I I I

, ., I  ! ..

, I II

. . I 0_ . . . . ,

I

. I . .-

I

. . I 0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.9-3 Nuclear Power versus Time - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case January 2004 Praire Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-0 11604

5-161 1.2

.96 -j----------- -________

z 0

x .72 4-----------

0 I..

CDl 0

.48 4 - ----- --- - - - - - -- - -

0) 0L)

C-,

14 4 ----------- i------------- ---- ------- f------------ - ----------

I I , I , , I P I , I

,, , , !I ,

0 I I 0 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.9-4 Core Average Heat Flux versus Time - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-162

<2 2700 -

2600 - ___________-

- . AI U) to I

0. aa 2500 - A________+_ _______

Lu U)

I-CD 1.t

2400-2L

/ I 2300 -  : -------- +------

I 2200 -a a I I I . a,. . .

I.

j. . . . I 0 2.8 I 5.6 9 8.4 11.2 14 ri lme [seconds]

Figure 5.1.9-5 Pressurizer Pressure versus Time - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case January 2004 Prairie Island Licensing Report Licensing Report January 2004 6296e.vR-NP.dc-01 1604

5-163 2700 2620 a

Ini a-CL 0

iL-2540 -

E C

L-CD 2460 - F---_____

3r v0

-j 0

2380 - -------------

23D0 I II I , I , .I I I I I,.

I i a 2.8 5.6 8.4 11.2 14 Time [seconds]

Figure 5.1.9-6 Vessel Lower Plenum Pressure versus Time - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-164 K>

Loop 1 Hot Leg

--- Loop 1 Cold Leg 650 620 ------------ _4

,E, L..

0 0L. 590 -

a, tD E

0.

560 . ---------- ------------4----------- F --- J CD CY "IN r- - - - - -

530 - F------------

. I 500 _

I I

I

• I . . .I I

.. . .I .

I

. . . . . I .*

I*

• I I 6 2.8 I

5.6 I

8.4 11.2 14 Time [seconds]

Figure 5.1.9-7 RCS Loop Temperature versus rlme - Locked Rotor/Shaft Break - RCS Pressure/Peak Cladding Temperature Case Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-165 2200 -

2000 - ------- --------

1800 - 7- +

16 a00 ---a -----------

+---------------+---------------t---------------

(I-)

E 1400 - - A----------- ---------------- ---------------- ---------------

1000 --------------+------------------------------------------------

600-4 + +

0 0 3 6 9 1 l1m e (seconds)

Figure 5.1.9-8 Hot-Spot Cladding Inner Temperature versus Time -Locked Rotor/Shaft Break -

RCS Pressure/Peak Cladding Temperature Case Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-166 5.1.10 Loss of External Electrical Load (USAR Section 14.4.9) 5.1.10.1 Accident Description The loss-of-extemal-electrical-load event is defined as a complete loss of steam load or a turbine trip from full power without a direct reactor trip. This anticipated transient is analyzed as a turbine trip from full power because it bounds both the loss of external electrical load event and the turbine trip event. The turbine-trip event is more severe than the total loss-of-external-electrical-load event since it results in a more rapid reduction in steam flow.

For a turbine trip, the reactor would be tripped directly (unless below approximately 10-percent power) from a signal derived from either the turbine auto-stop oil pressure or a closure of the turbine stop valves.

The automatic steam dump system accommodates the excess steam generation. Reactor coolant temperatures and pressures do not significantly increase if the steam dump system and pressurizer pressure control system are functioning properly. If the turbine condenser were not available, the excess steam generation would be dumped to the atmosphere. Additionally, main feedwater flow would be lost if the turbine condenser were not available. For this situation, steam generator level would be maintained by the auxiliary feedwater (AFW) system.

For a loss of external electrical load without subsequent turbine trip, no direct reactor trip signal would be generated. The plant would be expected to trip from the reactor protection system (RPS). A continued steam load of approximately 5 percent would exist after a total loss of external electrical load because of the steam demand of plant auxiliaries.

In the event of a large loss of load in which the steam dump valves fail to open or a complete loss of load with the steam dump operating, the main steam safety valves (MSSVs) may lift and the reactor may be tripped by any of the following signals: high pressurizer pressure, high pressurizer water level, OTAT and OPAT, or low-low steam generator water level. The steam generator shell-side pressure and reactor coolant temperatures will increase rapidly. However, the pressurizer safety valves (PSVs) and MSSVs are sized to protect the reactor coolant system (RCS) and steam generators against overpressure for all load losses without assuming the operation of the steam dump system. The steam dump valves will not be opened for load reductions of 10 percent or less, but may open for larger load reductions. The RCS and main steam system (MSS) steam relieving capacities were designed to ensure safety of the unit without requiring automatic rod control, pressurizer pressure control, steam bypass control systems, or a reactor trip on turbine trip.

5.1.10.2 Method of Analysis The loss-of-load transients are analyzed using the RETRAN computer code. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and MSSVs. The code computes pertinent plant variables including temperatures, pressures, and power levels.

' I Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 200W 6296- RNP.dxo01 1604

5-167 The loss-of-load accident is analyzed for the following:

• To confirm that the PSVs and MSSVs are adequately sized to prevent overpressurization of the primary RCS and MSS, respectively

• To ensure that the increase in RCS temperature does not result in a departure from nucleate boiling (DNB) in the core The RPS is designed to automatically terminate any such transient before the DNBR falls below the limit value.

In this analysis, the behavior of the unit is evaluated for a complete loss-of-steam load from full power with no credit taken for a direct reactor trip on turbine trip. This assumption will delay reactor trip until conditions in the RCS cause a trip on some other signal. Therefore, the analysis assumes a worst-case transient and demonstrates the adequacy of the pressure-relieving devices and plant-specific RPS setpoints assumed in the analysis for this event.

Three cases are analyzed:

1. The first is performed to address DNB concerns. For this case, automatic pressurizer pressure control is assumed; therefore, full credit is taken for the effect of the pressurizer spray and power-operated relief valves (PORVs) in reducing or limiting the primary coolant pressure. Safety valves are also available and are modeled assuming a percent setpoint tolerance. This case analysis is performed to demonstrate that the core thermal limits are adequately protected

[beginning of cycle (BOC) reactivity feedback conditions with automatic pressurizer pressure-control]; the loss-of-load accident is analyzed using the Revised Thermal Design Procedure (RTDP) (Reference 5.1.10-1). For this case, initial core power, reactor coolant temperature, and reactor coolant pressure are assumed to be at the nominal values consistent with steady-state full-power operation. Uncertainties in initial conditions are included in determining the DNBR limit value (Reference 5.1.10-1).

2. The second case ensures that the peak primary RCS pressure remains below the design limit (2748.5 psia). For the primary RCS overpressure analysis, it is assumed that automatic pressurizer pressure control is not available; therefore, no credit is taken for the effect of the pressurizer spray or PORVs in reducing or limiting the primary coolant pressure. Safety valves are assumed operable, but are modeled assuming a +3-percent setpoint tolerance and a +1-percent shift (Reference 5.1.10-2). The effects of the PSV loop seals are conservatively modeled in the analysis. This case analysis is performed to demonstrate the adequacy of the primary pressure-relieving devices (BOC reactivity feedback conditions without automatic pressurizer pressure control); the loss-of-load accident is analyzed using the Standard Thermal Design Procedure (STDP). For this case, initial core power and reactor coolant temperature are assumed at the maximum values consistent with steady-state full-power operation, including allowances for calibration and instrument errors. Initial pressurizer pressure is assumed at the minimum value for this case, since it delays reactor trip on high pressurizer pressure and results in more severe primary-side temperature and pressure transients. This results in the maximum power difference for the loss of load.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-168

3. The final case confirms that the peak MSS pressure remains below 110 percent of the steam generator shell design pressure (1208.5 psia). This third case is provided for additional information, but is not included in the USAR. Similar to the primary RCS overpressurization case, the MSS overpressurization case is analyzed assuming the STDP assumptions with respect to initial conditions and uncertainties and also assumes BOC reactivity feedback conditions.

However, the MSS overpressurization case differs from the primary RCS overpressurization case in that automatic pressurizer pressure control is assumed in order to delay reactor trip and maximize the heat transfer to the secondary side. Credit is taken for the effect of the pressurizer spray and PORVs in reducing or limiting the primary coolant pressure; therefore, conservatively delaying the actuation of the RPS until an OTAT reactor trip signal is generated. Delaying the reactor trip ensures that the energy input to the secondary system, and subsequently the MSS pressure, is maximized.

The major assumptions and features of these cases are summarized as follows:

a. The loss-of-load event results in a primary-system heatup and, therefore, is conservatively analyzed assuming minimum reactivity feedback consistent with BOC conditions. This includes assuming an isothermal temperature coefficient (lTC) value consistent with BOC hot full power (HFP) conditions (that is, zero pcmn/F).

b. It is conservative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and reduce the severity of the transient.

c. No credit is taken for the operation of the steam dump system or steam generator PORVs.

The steam generator pressure rises to the safety valve setpoints, where steam release through the MSSV limits the secondary-side steam pressure to the setpoint values. The MSSV was explicitly modeled in the loss-of-load licensing basis analysis assuming a

+3.0-percent tolerance. Note that by maximizing the pressure transient in the MSS, the saturation temperature in the steam generators is maximized, resulting in limiting pressure and temperature conditions in the RCS.

d. Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for AFW flow since a stabilized plant condition will be reached before AFW initiation is normally assumed to occur for full-power cases. However, the AFW pumps would be expected to start on a trip of the main feedwater pumps. The AFW flow would remove core decay heat following plant stabilization.

e. In the loss-of-load event analysis documented herein, both the Westinghouse OSGs and the Framatome ANP RSGs are addressed.

f. A maximum SGTP level of 25 percent for the Westinghouse OSGs and of 10 percent for the Framatome RSGs is modeled. SGTP imbalances do not adversely affect this transient.

Report Licensing Report Island Licensing January 2004 Prairie Island Prairie January 2004 6296- RNP.doc-01 1604

5-169 5.1.103 Results ¢ The transient responses for a total loss of load from full-power operation are shown in Figures 5.1.10-1 through 5.1.10-11 for the DNB and RCS overpressure cases assuming BOC reactivity feedback conditions with and without automatic pressurizer pressure control (pressurizer spray and PORVs).

Results for both the Westinghouse OSGs and Framatome RSGs are provided. The different steam generators have only a limited impact on the loss-of-load event.

Figures 5.1.10-1 through 5.1.10-6 show the transient responses for the total loss of steam load at BOC (minimum feedback reactivity coefficients) assuming full credit for the pressurizer spray and PORVs to calculate the transient DNBR response. Following event initiation, the pressurizer pressure and average RCS temperature increase due to the rapidly reduced steam flow and heat removal capacity of the secondary side. The peak pressurizer pressure and water volume and RCS average temperature are reached shortly after the reactor is tripped by the OTAT trip function. The DNBR initially increases slightly, then decreases until the reactor trip is tripped. Finally, following reactor trip, it increases rapidly.

The minimum DNBR remains well above the safety analysis limit value. The MSSVs actuate to limit the MSS pressure below 110 percent of the steam generator shell design pressure. Table 5.1.10-1 summarizes the sequence of events and limiting conditions for this case.

The total loss-of-load event was also analyzed assuming the plant to be initially operating at full power at BOC with no credit taken for the pressurizer spray or PORVs to maximize the primary RCS pressure response. Figures 5.1.10-7 through 5.1.10-11 show the transients for this case. Pressurizer pressure, pressurizer water volume, and RCS average temperature increase due to the sudden reduction in primary to secondary heat transfer. The reactor is tripped on the high pressurizer pressure trip signal. In this case, the PSVs are actuated and maintain the primary RCS pressure below 110 percent of the design value. The MSSVs actuate to limit the MSS pressure below 110 percent of the steam generator shell design pressure.

Table 5.1.10-2 summarizes the sequence of events and limiting conditions for this case.

The transient responses for the total loss of steam load at BOC (minimum feedback reactivity coefficients) assuming full credit for the pressurizer spray and PORVs to maximize the MSS pressure response are very similar to those of the first case discussed above and thus are not discussed in detail.

Table 5.1.10-3 summarizes the sequence of events and limiting conditions for this case.

5.1.10.4 Conclusions The results of the analyses show that the plant design is such that a total loss of external electrical load without a direct or immediate reactor trip presents no hazard to the integrity of the primary RCS or MSS.

Pressure-relieving devices that have been incorporated into the plant design are adequate to limit the maximum pressures to within the safety analysis limits; that is, 2748.5 psia for the primary RCS and 1208.5 psia for the MSS.

The integrity of the core is maintained by operation of the RPS; that is, the minimum DNBR is maintained above the safety analysis limit value of 1.34. Therefore, no core safety limit will be violated.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-170 5.1.10.5 References 5.1.10-1 Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-11397-P-A, April 1989.

5.1.10-2 Barrett, G O., et al., "Pressurizer Safety Valve Set Pressure Shift," WCAP-12910, Rev. 1-A, May 1993.

Report Licensing Report January 2004 Prairie Island Licensing Prairie Isand January 2004 6296-LR-NP.doc-01 1604

5-171 Table 5.1.10-1 Sequence of Events and Transient Results - Loss of External Electrical Load - with Pressurizer Pressure Control (for Minimum DNBR)

Westinghouse OSGs Framatome RSGs Event Time (seconds) Time (seconds)

Turbine Trip 20.0 20.0 Reactor Trip on OTAT 30.0 30.2 Rod Motion Begins 32.5 32.7 Time of Minimum DNBR 33.1 33.3 Time of Peak MSS Pressure 47.4 40.7 Minimum DNBR Value 1.77 1.80 DNBR Limit 1.34 1.34 Peak MSS Pressure (psia) 1,176.9 1,184.9 MSS Pressure Limit (psia) 1,208.5 1,208.5 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-172 Table 5.1.10-2 Sequence of Events and Transient Results - Loss of External Electrical Load - without Pressurizer Pressure Control (for RCS Overpressure)

Westinghouse OSGs Framatorme RSGs Event Time (seconds) Time (seconds)

Turbine Trip 20.0 20.0 Reactor Trip on High Pressurizer Pressure 28.1 27.7 Rod Motion Begins 29.1 28.7 Time of Peak RCS Pressure 32.3 31.8 Time of Peak MSS Pressure 48.1 38.7 Peak RCS Pressure (psia) 2,684.1 2,701.0 RCS Pressure Limit (psia) 2,748.5 2,748.5 Peak MSS Pressure (psia) 1,167.0 1,178.3 MSS Pressure Limit (psia) 1,208.5 1,208.5 K)

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-173 Table 5.1.10-3 Sequence of Events and Transient Results - Loss of External Electrical Load - with Pressurizer Pressure Control (for MSS Overpressure)

Westinghouse OSGs Framatome RSGs Event Time (seconds) Time (seconds)

Turbine Trip 20.0 20.0 Reactor Trip on OTAT 27.8 28.2 Rod Motion Begins 30.3 30.7 Time of Peak RCS Pressure 32.4 32.9 Time of Peak MSS Pressure 38.2 37.9 Peak RCS Pressure (psia) 2,380.8 2,408.9 RCS Pressure Limit (psia) 2,748.5 2,748.5 Peak MSS Pressure (psia) 1,183.5(') 1,197.6(2 MSS Pressure Limit (psia) 1,208.5 1,208.5 Notes:

1. Pressure in the Steam Dome is provided in the table, but it was also confirmed that the maximum pressure in the MSS was below the MSS pressure limit. Maximum pressure in the MSS is 1192.0 psia.

2. Pressure in the Steam Dome is provided in the table, but it was also confirmed that the maximum pressure in the MSS was below the MSS pressure limit. Maximum pressure in the MSS is 1207.3 psia.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-174 Fraortome RSGs F

--- - Westinghouse OSGs 1.2

.8 0

0 U

0 U-.

.6 I.-

0-Cal

. .4

.2 0

Figure 5.1.10-1 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) -

Nuclear Power versus Time 'K_,

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-175 Fromotome RSGs. Vessel Inlet Temperature

- - - -Fromatome RSGs. Vessel Outlet Temperature Westinghouse OSGs. Vessel Inlet Temperature

--- Westinghouse OSGs. Vessel Outlet Temperature 620 -

600- / AAt

• 580-E 560 540 520 Figure 5.1.10-2 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) -

Vessel Core Inlet and Outlet Temperatures versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-176 Fromotome RSGs

--- -Westinghouse OSGs 2500-2400 T 2300 -

0n CL CD)

C 2200 2100 2000- I I 0 20 40 60 80 100 120 Time(seconds)

Figure 5.1.10-3 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) -

RCS Pressure versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP.doc-0 1 1604

5-177 Frarmotome RSGs

---

Westinghouse OSGs 650-600 /0-

- I 1-11'

-550 C,3 0 -

E 0

L..

L-..

C,,

Cn a,I L.

0X 450-400 350 Time(seconds)

Figure 5.1.10-4 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) -

Pressurizer Water Volume versus Time January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc01 1604

5-178

'1 fFrmarctome RSGs

---

Westinghouse OSGs 1200 1100 1000 M._

W

, 900 co, 0-

'2 Coo 800 700 600 Figure 5.1.10-5 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) -

Steam Generator Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-179 Fromotorne RSGs

---

Westinghouse OSGs 5-4.5-4 /1 3

2.5 2

1.5 Figure 5.1.10-6 Loss of External Electrical Load with Automatic Pressure Control (DNB Case) -

DNBR versus Time Prairie Island Licensing Report r LJanuary 2004 6296- RNP.doc-01 1604

5-180 Fromatome RSGs

---

Westinghouse OSGs 1.2 l

V 0

C>

0 0

.- W_

TC .6 ao 0

I.-

Ui V

W

.4

.2 0

Time (seconds)

Figure 5.1.10-7 Loss of External Electrical Load WithoutAutomatic Pressure Control (RCS Overpressure Case) - Nuclear Power versus Time Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296- RNP.doc-0 11604

5-181 Fromatome RSGs. Vessel Inlet Temperature

- - - - Fromatome RSGs. Vessel Outlet Temperature

- Westinghouse OSGs. Vessel Inlet Temperature

--- Westtinighouse OSGs. Vessel Outlet Tempercture 620 -

600-- _M /5 U' 5M - _;

M-.

560 E, -

540 520 Time (seconds)

Figure 5.1.10-8 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Vessel Inlet and Outlet Temperatures versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-OI 1604

5-182 Fromortome RSGs

---

Westinghouse OSGs 2800 2700 2600

.co 0-

= 2500 CO, Cl-2400 2300 2200 Time (seconds)

Figure 5.1.10-9 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - RCS Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc.01 160t

5-183 Framotorne RSGs

---

Westinghouse OSGs 500 -

480 -

E 440-Cn cn X 420-400-380- I I 0 20 40 60 80 100 120 Time (seconds)

Figure 5.1.10-10 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Pressurizer Water Volume versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-184 Fromotome RSGs

-- -- Westinghouse OSGs 1200 1100 1000 0-L.

C',

cn a-D Li, 800 700 600 Time (seconds)

Figure 5.1.10-11 Loss of External Electrical Load Without Automatic Pressure Control (RCS Overpressure Case) - Steam Generator Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-185 5.1.11 Loss of Normal Feedwater (USAR Section 14.4.10) 5.1.11.1 Accident Description A loss of normal feedwater (from a pipe break, pump failure, or valve malfunction) results in a reduction of the ability of the secondary system to remove the heat generated in the reactor core. If the reactor were not tripped during this accident, core damage could possibly occur from a sudden loss of heat sink. If an alternate supply of feedwater were not supplied to the steam generators, residual heat following reactor trip and reactor coolant pump (RCP) heat would cause the primary system water to expand to the point where water relief from the pressurizer would occur. A significant loss of water from the RCS could conceivably lead to core damage. Since the reactor is tripped well before the steam generator heat transfer capability is reduced, the primary system never approaches a condition where the departure from nucleate boiling ratio (DNBR) limit may be violated.

The following features provide protection against a loss of normal feedwater:

1. Reactor trip on low-low water level in either steam generator

2. Automatic start of one motor-driven auxiliary feedwater (AFW) pump and one turbine-driven AFW pump (via opening of the steam admission control valve) per unit on low-low water level in either steam generator The analysis shows that following a loss of normal feedwater, the AFW system is capable of removing the stored energy, residual decay heat, and RCP heat. The pressurizer is prevented from becoming water-solid, which could lead to a more serious plant condition without other faults occurring independently.

5.1.11.2 Method of Analysis The loss of normal feedwater transient is analyzed using the RETRAN computer code. The RETRAN model simulates the RCS, neutron kinetics, pressurizer, pressurizer relief and safety valves, pressurizer heaters, pressurizer spray, steam generators, feedwater system, and main steam safety valves (MSSVs).

The code computes pertinent plant variables including steam generator mass, pressurizer water volume, and reactor coolant average temperature.

Separate analyses were performed for the Westinghouse original steam generators (OSGs) and the Framatome replacement steam generators (RSGs) scheduled to be installed in Prairie Island Unit 1 during the fall 2004 outage. The major assumptions are summarized below.

1. The plant is initially operating at 102 percent of the nominal nuclear steam supply system (NSSS) power of 1,657 MWt. The RCP heat is a maximum constant value of 10 M'Wt (5 MWt per pump). The RCPs run throughout the transient.

2. The initial reactor coolant vessel average temperature is assumed to be 5560 F (the nominal full-power value of 560TF minus 40 F uncertainty). Sensitivity analyses demonstrated that a low initial coolant temperature is conservative.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-186

3. The initial pressurizer pressure is assumed to be 2,290 psia (the nominal value of 2,250 psia plus 40 psi uncertainty). Sensitivity analyses demonstrated that a high initial pressurizer pressure is conservative.

4. The initial pressurizer water level is assumed to be 38 percent level span (the programmed full-power value of 33 percent span based on the nominal full-power vessel. average temperature of 560'F plus 5 percent span uncertainty). A high initial pressurizer water level is conservative because it minimizes the initial margin to filling the pressurizer water-solid.

5. The initial steam generator water level is assumed to be 55 percent of narrow range span (NRS)

(the programmed full-power value of 44 percent plus 11 percent NRS uncertainty). A high initial steam generator water level is conservative because it maximizes the time to reach the steam generator low-low water level, thus increasing the primary system heat input.

6. The transient is simulated by terminating main feedwater flow at 20 seconds.

7. Reactor trip occurs on steam generator low-low water level at 0 percent NRS. Turbine trip occurs as a result of reactor trip.

8. One minute after the low-low steam generator water level setpoint is reached, a minimum constant AFW flow of 190 gpm is initiated from one AFW pump, with flow split equally between the two steam generators (equal flow split is the limiting case). This assumption considers the limiting single failure of one AFW pump. The AFW enthalpy is assumed to be 70.9 Btullbm (I00°F at 1100 psia).

9. Secondary system steam relief is achieved through the main steam safety valves (MSSVs). The MSSV opening pressures are the nominal settings plus a 3 percent tolerance.

10. Normal reactor control systems are not assumed to be operable if their operation leads to less limiting analysis results. However, the pressurizer power-operated relief valves (PORVs),

pressurizer heaters, and pressurizer sprays are assumed to operate normally, since this results in a conservative transient with respect to the peak pressurizer water volume. If these control systems did not operate, the pressurizer safety valves would maintain peak RCS pressure below 110 percent of the design value.

11. A conservative core residual heat generation is assumed based on the American Nuclear Society (ANS) 5.1-1979 decay heat model plus 2-sigma (Reference 5.1.11-1).

The loss of normal feedwater analysis is performed to demonstrate the adequacy of the reactor protection system to trip the reactor and AFW system to remove long-term decay heat, stored energy, and RCP heat.

This prevents excessive heatup or overpressurization of the RCS. As such, the assumptions used in the analysis are designed to maximize the time to reactor trip and to minimize the energy removal capability of the AFW system. These assumptions maximize the possibility of water relief from the RCS by maximizing the expansion of the RCS inventory, as noted in the assumptions listed above.

Licensing Report Island Licensing January 2004 Prairie Prairie Island Report January 2004 6296- RNP.doc-0 11604

5-187 5.1.113 Results -

Figures 5.1.11-1 through 5.1.11-6 show the significant plant responses following a loss of normal feedwater. The calculated sequence of events and results are listed in Table 5.1.11-1.

Following the reactor and turbine trip from full load, the water level in each steam generator falls due to the reduction of the steam generator void fraction, and because steam flow through the steam generator MSSVs continues to dissipate the stored and generated heat. One minute after the initiation of the low-low level trip, flow from the available motor-driven AFW pump begins, thus reducing the rate of water level decrease in the steam generators.

The capacity of one AFW pump is sufficient to dissipate core residual heat, stored energy, and RCP heat such that the pressurizer does not become water-solid, demonstrating the adequacy of the AFW system to provide long-term core cooling. Figure 5.1.11-4 shows the pressurizer water volume transients; the calculated peak pressurizer water volume is 878.1 ft3 for the Westinghouse OSGs and 934.1 ft3 for the Framatome RSGs, compared to the total pressurizer volume limit of 1,010.1 ft3 . Plant procedures may be followed to further cool down the plant.

The maximum RCS and main steam system pressures for this event are bounded by the loss of external electrical load analysis, which demonstrates that the peak pressures remain below 110 percent of the respective design limit values. The DNBR is not evaluated for this analysis since it is bounded by the loss of external load analysis, for which the initial reactor coolant heatup is more severe.

5.1.11.4 Conclusions The results of the loss of normal feedwater analysis show that all applicable acceptance criteria are satisfied. The AFW capacity is sufficient to dissipate core residual heat, stored energy, and RCP heat such that reactor coolant water is not relieved through the pressurizer relief or safety valves.

5.1.11.5 References 5.1.11-1 ANSTIANS-5.1-1979, "Decay Heat Power in Light Water Reactors," August 29, 1979.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-188 Table 5.1.11-1 Sequence of Events - Loss of Normal Feedwater Time (seconds)

Westinghouse Framatome Event OSG RSG Main Feedwater Flow Stops 20.0 20.0 Low-Low Steam Generator Water Level Trip Setpoint Reached 54.5 59.1 Rods Begin to Drop 56.0 60.6 Both Steam Generators Begin to Receive AFW Flow from One Pump 114.5 119.1 Peak Water Volume in the Pressurizer Occurs*,

Core Decay Heat (plus RCP Heat) Decreases to AFW Heat Removal - 8,000 - 7,800 Capacity

• Peak Pressurizer Water Volume, ft3 878.1 934.1 Pressurizer Water Volume Limit, ft3 1,010.1 1,010.1 Licensing Report Island Licensing January 2004 Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-189 K>

Fromotome RSGs

-- -- Westinghouse OSGs 1.20-1.00 - I I

I I

I I

.E I

.80 - I I

I 0

I I

I

.60 - I C)

C.> I 0 I

. II 0~ I 0- I a) .40 - I I

I I

I I

.20 -

I I

I I t r f I t f I I

.00 -t 2 31 4 10 10 10 10 Time (seconds)

Figure 5.1.11-1 Loss of Normal Feedwater - Nuclear Power Prairie Island Licensing Report r LJanuary 2004 6296- ,NP.doc-011604

5-190 Framatome RSGs. Vessel Inlet Temperature

- - -- Framatome RSGs. Vessel Outlet Temperature

--- Westinghouse OSGs. Vessel Inlet Temperature

- - Westinghouse OSGs. Vessel Outlet Temperature 600 590 580 U-c-,

3 s 570 0~

qa, E

Ca_

560 0

0 C-,

L 550 o

C-l 0

a) 540 530 520 Time (seconds)

Figure 5.1.11-2 Loss of Normal Feedwater - Reactor Coolant Temperatures

'Kf Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-191 Fromaotome RSGs F

---

Westinghouse OSGs 2400 2350

-1 ~

U)

Cn a)

.=

U) a)

CL-2250 2200 14 Time (seconds)

Figure 5.1.11-3 Loss of Normal Feedwater - Pressurizer Pressure Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-192 Framatome RSGs

---

Westinghouse OSGs 1000 900 800

-5 700 a) cii, 600

=3 cn co) an  ;.

500 400 300 Time (seconds)

Figure 5.1.11-4 Loss of Normal Feedwater - Pressurizer Water Volume Licensing Report January 2004 Prairie Island Licensing Prairie Island Report January 200.4 6296- RNP.doc-01 1604

5-193 Framotome RSGs

- --- Westinghouse OSGs 1200-1100 - I I

I_

_2 I

- 1000 -

a, L-Cl, Cf) /

Qa, L- 900-o 0

L.

I CD ra CD E) 800 -

V)

/

_ ,1 700 -

_ I I I I_

600 2 3 4 I0 10 10 10 Time (seconds)

Figure 5.1.11-5 Loss of Normal Feedwater - Steam Generator Pressure January 2004 Prairie Licensing Report Island Licensing Prairie Island Report Jantuay2004 6296-lR-NP.doc-01 1604

5-194 Framotome RSGs

---

Westinghouse OSGs 120000 100000 80000

-o cn C)

-M 00 60000 ca a,

0 40000 Ki 20000 0

Time (seconds)

Figure 5.1.11-6 Loss of Normal Feedwater - Steam Generator Mass Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-195 5.1.12 Loss of All AC Power to the Station Auxiliaries (USAR Section 14.4.11) 5.1.12.1 Accident Description A complete loss of non-emergency AC power results in the loss of all power to the plant auxiliaries; such as the reactor coolant pumps (RCPs), main feedwater and condensate pumps, etc. The loss of power may be caused by a complete loss of the offsite grid accompanied by a turbine generator trip at the station, or by a loss of the onsite AC distribution system.

The events following a loss of AC power are described in Updated Safety Analysis Report (USAR)

Section 14.4.11. The auxiliary feedwater (AFW) system is started automatically, as discussed for the loss of normal feedwater analysis (Section 5.1.11).

Upon the loss of power to the RCPs, coolant flow necessary for core cooling and the removal of residual heat is maintained by natural circulation in the reactor coolant loops. Following the RCP coastdown caused by the loss of AC power, the natural circulation capability of the RCS removes residual and decay heat from the core, aided by the AFW in the secondary system.

5.1.12.2 Method of Analysis The loss of all AC power to the station auxiliaries transient is analyzed using the RETRAN computer code. The code simulates the neutron kinetics, RCS including natural circulation, pressurizer, pressurizer relief and safety valves, pressurizer heaters, pressurizer spray, steam generators, feedwater system, and main steam safety valves (MSSVs). The code computes pertinent plant variables including steam generator mass, pressurizer water volume, and reactor coolant average temperature.

The analysis does not assume that power is lost as the initiating event. Rather, the analysis conservatively models a loss of normal feedwater with a subsequent loss of offsite power following the reactor trip on low-low steam generator water level. This bounds the case of an immediate loss of all AC power as the initiating event, which would result in an immediate reactor trip.

Major assumptions made in the loss of all auxiliary AC power analysis are the same as those made in the loss of normal feedwater analysis (Section 5. 1. I), with the following exceptions.

1. The RCPs are assumed to lose power and begin coasting down 2 seconds following the reactor trip on low-low steam generator water level. Following the loss of power to the RCPs, coolant flow necessary for core cooling and removal of residual heat is maintained by natural circulation flow in the coolant loops. Heat addition from the RCPs to the primary coolant ceases.

2. Pressurizer sprays are lost when forced reactor coolant flow ceases as a result of RCP coastdown.

5.1.123 Results Figures 5.1.12-1 through 5.1.12-6 show the significant plant responses following a loss of all AC to the station auxiliaries. The calculated sequence of events and results are listed in Table 5.1.12-1.

Prairie Island Licensing Report January 2004 6296-LRNP.doc-01 1604

5-196 Following the reactor and turbine trip from full load, the water level in each steam generator falls due to the reduction of the steam generator void fraction, and because steam flow through the steam generator V MSSVs continues to dissipate the stored and generated heat. One minute after the initiation of the low-low level trip, flow from the available motor-driven AFW pump begins, thus reducing the rate of water level decrease in the steam generators.

The capacity of one AFW pump is sufficient to dissipate core residual heat and stored energy such that the pressurizer does not fill water-solid, with natural circulation flow conditions in the reactor coolant system (RCS). Figure 5.1.124 shows the pressurizer water volume transients; the calculated peak pressurizer water volume is 639.2 ft3 for the Westinghouse original steam generators (OSGs) and 653.0 ft3 for the Framatome replacement steam generators (RSGs), compared to the total pressurizer volume limit of 1,0L0. ft3 . The results are less limiting than those obtained for the loss of normal feedwater transient due to the loss of RCP heat addition. Plant procedures may be followed to further cool down the plant.

The maximum RCS and main steam system pressures for this event are bounded by the loss of external electrical load analysis, which demonstrates that the peak pressures remain below 110 percent of the respective design limit values. In the case where a loss of all AC power is the initiating event, the first few seconds of the transient will closely resemble the simulation of the complete loss of reactor coolant flow event (USAR Section 14.4.8), where departure from nucleate boiling (DNB) and core damage due to rapidly increasing core temperature is prevented by promptly tripping the reactor. For the specific scenario analyzed, the departure from nucleate boiling ratio (DNBR) results are less limiting since the reactor is already tripped when RCP coastdown begins. Thus, the DNBR is not evaluated for this analysis since it is bounded by the loss of reactor coolant flow analysis.

5.1.12.4 Conclusions The results of the loss of all AC power to the station auxiliaries analysis show that all applicable acceptance criteria are satisfied. The AFW capacity is sufficient to dissipate core residual heat and stored energy such that reactor coolant water is not relieved through the pressurizer relief or safety valves.

Report Licensing Report Island Licensing January 2004 Prairie Island January 2004 6296- RNP.doc-0 11 60S

5-197 Table 5.1.12-1 Sequence of Events - Loss of All AC Power to the Station Auxiliaries Time (seconds)

Westinghouse Framatome Event OSG RSG Main Feedwater Flow Stops 20.0 20.0 Low-Low Steam Generator Water Level Trip Setpoint Reached 54.5 59.1 Rods Begin to Drop 56.0 60.6 RCPs Begin to Coast Down 58.0 62.6 Both Steam Generators Begin to Receive AFW Flow from One Pump 114.5 119.1 Peak Water Volume in the Pressurizer Occurs*,

Core Decay Heat Decreases to AFW Heat Removal Capacity - 1650 - 1560

• Peak Pressurizer Water Volume, ft3 639.2 653.0 Pressurizer Water Volume Limit, ft3 1,010.1 1,010.1 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-198

- .Framotome RSGs

---

Westinghouse OSGs 1.20 -

100 I I

I I

I 0 I I

E .80 I 0

C: I I-0 I

I C> I ca 0 I I

-)

.60 I 3 I I

I- I I

0 I

.40 I -

D.c)

I

=3 I I

I I

I

.20 I I I I I I I I II I 2l 3 4 10 10 10 10 Time (seconds)

Figure 5.1.12-1 Loss of AU AC Power to the Station Auxiliaries - Nuclear Power Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-199 Frrmatome RSGs. Vessel Inlet Temperature

- --- Fromotome RSGs. Vessel Outlet Temperature

- Westinghouse OSGs. Vessel Inlet Temperature

- - Westinghouse OSGs. Vessel Outlet Temperature 620 600 Ltz, 0

L 580 E0-0 0

cat 560 0

0 Q.)

540 520 Time (seconds)

Figure 5.1.12-2 Loss of All AC Power to the Station Auxiliaries - Reactor Coolant Temperatures January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-200 V

FFromaotome RSGs Westinghouse OSGs 2400 2350 C,,

Cn X 2300 as U)

Qn 0-L-

Cn a,

2250 2200 Time (seconds)

Figure 5.1.12-3 Loss of All AC Power to the Station Auxiliaries - Pressurizer Pressure Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-201 Framotome RSGs

- -- - Westinghouse OSGs 1000 900 800 re) 0, E

1- 700 a)

.=

a) 0, 09_

600 C,,

500 400 300 Time (seconds)

Figure 5.1.12-4 Loss of All AC Power to the Station Auxiliaries - Pressurizer Water Volume Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-202 Fromatome RSGs

- -- - Westinghouse OSGs 1200-1100

_/

• 1000- _

C/,

Q_

a, 900-  ?

-0 CD

/I.

700 -_ _ _

600- 1" ' I I I I lXll 2 l 43 10 10 10 10 Time (seconds)

Figure 5.1.12-5 Loss of All AC Power to the Station Auxiliaries - Steam Generator Pressure Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-203

-~ Froamatome RSGs

---

Westinghouse OSGs 120000 100000 E

-M C-,

Vt) 80000 0

co 0

0 L-ac CZD 60000 E

0 CD) 40000 20000 Time (seconds)

Figure 5.1.12-6 Loss of All AC Power to the Station Auxiliaries - Steam Generator Mass Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-204 5.1.13 Rupture of a Steam Pipe Core Response (USAR Section 14.5.5)

Introduction The steam pipe rupture - core response transient is analyzed at both full-power and zero-power conditions. The analysis of the steam pipe rupture core response transient typically found in safety analysis reports assumes zero-power (Mode 2) conditions. The greatest cooldown, and therefore the greatest reactivity excursion, would occur from a Mode 2 condition, where the decay heat level is low and the steam generator shell-side inventory and pressure is high. For a number of years, this was the only steam line rupture core response event analyzed by Westinghouse. In the mid-70s, Westinghouse issued WCAP-9226 for the steam line rupture event in which examinations of the effects of power level, break size, plant variations, and single failures were documented. This WCAP document contained the conclusion that "... the largestdouble-ended steamline rupture at end of life, hot shutdown conditions with the most reactiverod cluster control assembly (RCCA) in thefully ivithdraivnposition is a limiting and sufficiently conservative licensing basis to demonstrate that the Westinghouse PWR is in compliance with 10CFRJOOcriteriaforCondition II, III and IVsteamline break transients." However, plant modifications may have been made over the years which challenge the applicability of the assumptions that went into the original WCAP, such as the overtemperature and overpower AT response times, lead/lag time constants, etc. As a result, both the zero-power and the full-power steam line break events have been analyzed to demonstrate that the applicable acceptance criteria continue to be satisfied. The core response analysis of a rupture of a steam pipe from full-power conditions is presented in Section 5.1.13. 1, and the core response analysis of a rupture of a steam pipe from zero-power conditions is presented in Section 5.1.13.2.

5.1.13.1 Rupture of a Steam Pipe - Full Power Core Response Accident Description The analysis of the steam line rupture - full power core response event addresses both the current Westinghouse Model 51 original steam generators (OSGs) and Framatome Advanced Nuclear Power (ANP) Model 56/19 replacement steam generators (RSGs).

A steam line rupture - full power core response transient is defined as a "break" that results in an increase in steam flow from one or both steam generators. A steam line rupture can result from:

• An inadvertent opening of a steam generator safety or relief valve

• A rupture of the main steam piping Increased steam flow from the steam generators causes an increase in the heat extraction rate from the reactor coolant system (RCS), resulting in a reduction of primary coolant temperature and pressure.

Because negative moderator temperature and Doppler fuel temperature reactivity coefficients are a characteristic of Westinghouse core designs, the core power will inherently seek a level bounded by the steam load demand, assuming no intervention of control, protection, or engineered safeguards systems.

The rate at which the pressurized water reactor (PWR) approaches equilibrium power with the secondary load is greatest when the reactivity coefficients are the most negative, which corresponds to end-of-life in Licensing Report January 2004 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-205 a fuel cycle. Thus, in the absenrce of any protective actions, a reactor power level dictated by steam flow rate could be established.

Method of Analysis The steam line rupture - full power core response event is analyzed with a Westinghouse version of the RETRAN-02 code (Reference 5.1.13-1).

The RETRAN-02 computer code is a digital computer code, developed to simulate transient behavior in light water reactor systems. The main features of the program include a point kinetics and one-dimensional kinetics model, one-dimensional homogeneous equilibrium mixture thermal-hydraulic model, control system models, two-phase natural convection heat transfer correlations, and a non-equilibrium pressurizer model.

The aim of the analysis is to demonstrate that a reactor trip occurs in adequate time to ensure fuel and cladding damage is precluded. Breaks of various sizes are postulated to occur in the steam line upstream of the main steam isolation valve (MSIV).

The range of break sizes analyzed covers up to a 1.4 ft2 break. The larger break sizes generate reactor trips on the low steam line pressure - safety injection - reactor trip function while smaller breaks trip on the overpower AT reactor trip function. The most limiting break size is typically the largest break case that results in a reactor trip on the overpower AT reactor trip function.

Major Assumptions The following key physics parameter assumptions are made in analyzing the steam line rupture - full power core response event:

1. Moderator density coefficient: a most positive value is assumed

2. Doppler temperature coefficient: a most negative value is assumed

3. Doppler power defect: a least negative value is assumed

4. Effective delayed neutron fraction: a minimum value is assumed The following key system parameter assumptions are made to ensure the overall results of the analysis bound actual plant operation:

1. Initial conditions of core power, RCS coolant temperature and pressurizer pressure are assumed to be at their nominal values consistent with steady-state full power operation. Uncertainties in the initial conditions of these parameters are not considered, consistent with the application of the Revised Thermal Design Procedure (RTDP) Methodology (Reference 5.1.13-2). Steam generator water level is assumed to be at its nominal value.

2. Minimum measured flow is modeled according to the RTDP methodology (Reference 5.1.13-2).

3. Zero percent steam generator tube plugging (SGTP) level is assumed; this maximizes primary-to-secondary heat transfer and results in a more severe RCS cooldown transient.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-206

4. Pressurizer heaters are not credited.

5. Pressurizer sprays and power-operated relief valves are assumed to be operational.

6. Manual rod control is assumed.

The protection functions assumed for this event are the low steam pressure - safety injection - reactor trip function and the overpower AT reactor trip function. Long-term consequences of this event (i.e., post-reactor trip) are bounded by the hot zero power hypothetical steam line break that is analyzed in Section 5.1.13.2.

Results The results of the steam line rupture - full power core response analysis show that the minimum departure from nucleate boiling (DNBR) remains above the limit value and the peak linear heat generation rate remains below the limit value. The results show that the limiting case is the 0.99 ft2 break size. The results are summarized in Table 5.1.13-1. The time sequence of events for the limiting cases is provided in Table 5.1.13-2. The transient responses for the limiting case of both the Westinghouse OSGs and FramatomeANPRSGs are shown in Figures 5.1.13-1 through 5.1.13-7.

Conclusions Based on the results of this analysis, it is concluded that fuel and cladding damage will not occur from a steam line rupture full power core response event for either the Westinghouse Model 51 OSGs and the Framatome ANP Model 56/19 RSGs. Since the event results in overcooling the RCS and a decrease in the main steam system pressure, neither the reactor coolant system nor the main steam system pressure limits is challenged during the event.

5.1.13.2 Rupture of a Steam Pipe - Zero-Power Core Response Accident Description A steam line break transient would result in an uncontrolled increase in steam flow release from the steam generators, with the flow decreasing as the steam pressure drops. This steam flow release increases the heat removal from the RCS, which decreases the RCS temperature and pressure. With the existence of a negative moderator temperature coefficient (MTC), the RCS cooldown results in a positive reactivity insertion, and consequently a reduction of the core shutdown margin. If the most reactive RCCA is assumed stuck in its fully withdrawn position after reactor trip, the possibility is increased that the core will become critical and return to power. A return to power following a steam line break is a concern with the high-power peaking factors that may exist when the most reactive RCCA is stuck in its fully withdrawn position. Following a steam line break, the core is ultimately shut down by the boric acid, which is injected into the RCS by the emergency core cooling system (safety injection).

The steam line break analysis discussed herein was performed to demonstrate that there is no consequential damage to the primary system and that the core remains in place and intact. Assuming the most reactive RCCA is stuck in its fully withdrawn position, and applying the most limiting single failure Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 1 604

5-207 of one safety injection train, steam line break core response cases were examined for the OSGs and the RSGs with and without offsite power available. Although departure from nucleate boiling (DNB) and fuel cladding damage are not necessarily unacceptable consequences of a steam line break transient, the analysis described herein demonstrates that there is no consequential damage to the primary system, and that the core remains in place and intact, by showing that the DNB design basis is satisfied following a steam line break.

The systems and components that provide the necessary protection against a steam line break are listed below.

• Safety injection system actuation by any of the following:

- Two-out-of-three pressurizer pressure channels with low signals

- Two-out-of-three steam line pressure channels on either loop with lo-lo signals

- Two-out-of-three containment pressure channels with high signals

• The overpower reactor trips (neutron flux and AT) and the reactor trip occurring from the receipt of the safety injection signal.

• Redundant isolation of the main feedwater lines; sustained high feedwater flow would cause additional cooldown. In addition to normal control action that isolates main feedwater following a reactor trip, a safety injection signal will rapidly close all feedwater control valves, trip the main feedwater pumps, and close the feedwater pump discharge valves.

• Closure of the MSIVs. These valves are designed to close after receipt of any of the following:

- A safety injection signal coincident with one-out-of-two steam flow channels on Loop A with a hi-hi signal (isolates Loop A)

- A safety injection signal coincident with one-out-of-two steam flow channels on Loop B with a hi-hi signal (isolates Loop B)

- A safety injection signal coincident with one-out-of-two steam flow channels on Loop A with a high signal AND two-out-of-four Tavg channels with lo-lo signals (isolates Loop A)

- A safety injection signal coincident with one-out-of-two steam flow channels on Loop B with a high signal AND two-out-of-four Tavg channels with lo-lo signals (isolates Loop B)

- Two-out-of-three containment pressure channels with hi-hi signals The main steam system (MSS) conducts steam in 30-inch piping from each of the two steam generators within the reactor containment, through a swing-disc type isolation valve (MSIV) and a swing-disc type non-return check valve to the turbine stop and control valves. The isolation and non-return check valves are located outside of the containment, and an equalizing line downstream of the isolation valves interconnects the two steam lines. The non-retum check valves prevent reverse flow of steam. Therefore, if a break occurs between a non-return check valve and a steam generator, only the affected steam Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-208 generator would blow down. The steam generator blowdown from a steam line break located downstream of a non-return check valve would be terminated upon closure of both MSIVs.

Each main steam line contains a 16-inch diameter Venturi-type flow restrictor located upstream of the MSIV and inside containment. These flow restrictors serve to limit the steam release rate for any steam line break transient downstream of the Venturi. Additional flow restrictors that are an integral part of the outlet nozzles for the RSGs serve to limit the steam release rate during any steam line break transient.

Method of Analysis The analysis of the steam line break transient has been performed to demonstrate that the DNB design basis is satisfied. This is accomplished by showing that the calculated minimum DNBR is greater than the safety analysis limit DNBR of 1.593 (which corresponds to the W-3 low pressure DNB correlation limit of 1.45 plus appropriate allowances for rod bow, etc.). The overall analysis process is described in this section.

Using the RETRAN code (Reference 5.1.13-1), transient values of key plant parameters identified as statepoints (core average heat flux, core pressure, core inlet temperature, RCS flow rate, and core boron concentration) were calculated first. Next, the advanced nodal code (ANC) core design code (Reference 5.1.13-3) was used to:

• Evaluate the nuclear response to the RCS cooldown so as to justify the RETRAN transient prediction of the average core power/reactivity

• Determine the peaking factors associated with the return to power in the region of the stuck rod control cluster assembly (RCCA)

Finally, using the RETRAN-calculated statepoints and the ANC-calculated peaking factors, the detailed thermal and hydraulic computer code VIPRE (Reference 5.1.13-4) was used to calculate the minimum DNBR based on the W-3 DNB correlation.

The following assumptions were made in the analysis of the main steam line break:

1. A hypothetical double-ended rupture (DER) of a main steam line was postulated at hot zero power (HZP)/hot shutdown conditions. For the OSGs, the maximum break size is effectively limited to the flow area of the steam generator outlet nozzle (4.6 ft2 ) in the faulted loop and the area of the Venturi flow restrictor in the intact loop (1.4 ft 2). For the RSGs, the maximum break size is effectively limited to the flow area of the steam generator outlet nozzle flow restrictors (1.4 ft2 per steam generator). The assumed conditions correspond to a subcritical reactor, an initial vessel average temperature at the no-load value of 5470 F, and no core decay heat. These conditions are conservative for a steam line break transient because the resultant RCS cooldown does not have to remove any latent heat. Also, the steam generator water inventory is greatest at no-load conditions, which increases the capability for cooling the RCS.

2. In total, four DER cases were considered. Two DER cases were considered for both the OSGs and RSGs: with offsite power and with a loss-of-offsite power. The difference being that both Prairie Island Licensing Report January 2004 January 2004 6296-J.PRNP.doc-01 1604

5-209 reactor coolant pumps (RCPs) begin coasting down three seconds after the steam line break initiation for the cases without offsite power. Note that steam line break transients associated with the inadvertent opening of a steam dump or relief valve were not analyzed because the resultant RCS cooldown, and thus the minimum DNBR, would be less limiting compared to the DER cases.

3. Perfect moisture separation within the steam generators was conservatively assumed.

4. An end-of-life shutdown margin of 1.7-percent Ak/k corresponding to no-load, equilibrium xenon conditions, with the most reactive RCCA stuck in its fully withdrawn position was assumed. The stuck RCCA was assumed to be in the core location exposed to the greatest cooldown; that is, related to the faulted loop. The reactivity feedback model included a positive moderator density coefficient (MDC) corresponding to an end-of-life rodded core with the most reactive RCCA in its fully withdrawn position. The variation of the MDC due to changes in temperature and pressure was accounted for in the model. The Doppler reactivity defect associated with power, assuming the stuck RCCA, was also accounted for in the model. The Doppler-only power defect assumed in the model is presented in Figure 5.1.13-8.

The reactivity and power predicted by RETRAN were compared to those predicted by the ANC core design code. The ANC core analysis considered the following:

- Doppler reactivity feedback from the high fuel temperature near the stuck RCCA

- Moderator feedback from the high water enthalpy near the stuck RCCA

- Power redistribution effects

- Non-uniform core inlet temperature effects The ANC core analysis confirmed that the RETRAN-predicted reactivity is acceptable.

5. Assuming no frictional losses, the Moody critical flow curve was applied to conservatively maximize the break flow rate.

6. The non-return check valves were neglected to conservatively allow blowdown from both steam generators up to the time of MSIV closure. This assumption was made, along with not crediting containment protection signals, to assure that any postulated break location or single failure assumption is bounded by a single analysis.

7. The closure of the MSIV in the faulted loop was conservatively modeled to be complete at 6.0 seconds after conditions reach the hi-hi steam flow rate setpoint (approximately 150 percent of nominal full-power steam flow) coincident with reaching the lo-lo steam line pressure setpoint (500 psia, lead/lag = 12/2) in the same loop.

8. The safety injection pumps were assumed to provide flow to the RCS at 10 seconds after receipt of a safety injection signal for the case with offsite power available, and at 25 seconds after a safety injection signal for the case without offsite power available. These delays account for signal processing and pump startup delays, and, as applicable, diesel generator startup time.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LP-NP.doc-0 1604

5-210

9. The minimum capability for the injection of highly concentrated boric acid solution, corresponding to the most restrictive single active failure in the safety injection system (SIS), was assumed. The assumed safety injection flow (see Figure 5.1.13-9) corresponds to the operation of one high-head safety injection pump. Boric acid solution from the refueling water storage tank (RWST), with a minimum concentration of 2,600 ppm and a minimum temperature of 60'F, was the assumed source of the safety injection flow. The safety injection lines downstream of the RWST were assumed to initially contain unborated water to conservatively maximize the time it takes to deliver the highly concentrated RWST boric acid solution to the reactor coolant loops.

10. The safety injection accumulator tanks (one per loop) provide a passive injection of up to 1,270 ft3 of borated water into the RCS. However, the accumulators were only assumed for the purposes of maintaining RCS pressure, and were not credited as a source of borated water. The accumulators were assumed to have a boron concentration of 0 ppm, a minimum temperature of 70'F, and an initial gas pressure of 699.7 psia.

11. Main feedwater flow equal to the nominal (100-percent power) value was assumed to initiate coincident with the postulated break, and was maintained until feedwater isolation occurs. The feedwater isolation was assumed to be complete at 51.5 seconds after the steam line pressure in the faulted loop reaches the lo-lo setpoint that generates the safety injection signal.

12. A minimum SGTP level of 0 percent was assumed to maximize the cooldown of the RCS.

13. Maximum (1,000 gpm) auxiliary feedwater at a minimum temperature of 35 0 F was assumed to initiate coincident with the postulated break to maximize the cooldown of the RCS. The auxiliary feedwater was conservatively assumed to be delivered asymmetrically, with all flow being delivered to the faulted steam generator, to further maximize the RCS cooldown.

Results The results of the statepoint evaluation demonstrate that all four cases analyzed (two with the OSGs and two with the RSGs) meet the applicable DNBR acceptance criterion. The most limiting case is the OSG case in which offsite power was assumed to be available. The time sequence of events is presented in Table 5.1.13-3 for the OSG cases and Table 5.1.13-4 for the RSG cases.

Double-Ended Rupture With OSGs and With Offsite Power Available Figures 5.1.13-10 through 5.1.13-17 show the steam pressure, steam flow, pressurizer pressure, pressurizer water volume, reactor vessel inlet temperature, core heat flux, core boron concentration, and core reactivity following a double-ended rupture of a main steam line with the OSGs at initial no-load conditions and with offsite power available (full reactor coolant flow). The effective break size was limited to the area of the steam generator outlet nozzle (4.6 ft2 ) in the faulted loop and the area of the Venturi flow restrictor in the intact loop (1.4 ft2 ), and both steam generators were assumed to discharge through the break until steam line isolation had occurred.

Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LLR-NP.doc-01 1604

5-211 Double-Ended Rupture With OSGs and Without Offsite Power Available Figures 5.1.13-18 through 5.1.13-25 show the steam pressure, steam flow, pressurizer pressure, pressurizer water volume, reactor vessel inlet temperature, core heat flux, core boron concentration, and core reactivity following a double-ended rupture of a main steam line with the OSGs at initial no-load conditions and with a loss-of-offsite power (RCPs begin coasting down 3 seconds after break initiation).

The effective break size was limited to the area of the steam generator outlet nozzle (4.6 ft2 ) in the faulted loop and the area of the Venturi flow restrictor in the intact loop (1.4 ft2 ), and both steam generators were assumed to discharge through the break until steam line isolation had occurred.

Double-Ended Rupture With RSGs and With Offsite Power Available Figures 5.1.13-26 through 5.1.13-33 show the steam pressure, steam flow, pressurizer pressure, pressurizer water volume, reactor vessel inlet temperature, core heat flux, core boron concentration, and core reactivity following a double-ended rupture of a main steam line with the RSGs at initial no-load conditions and with offsite power available (full reactor coolant flow). The effective break size was limited to 1.4 ft2 per steam generator by the flow area of the-steam generator outlet nozzles, and both steam generators were assumed to discharge through the break until steam line isolation had occurred. It is important to note that at approximately 57 seconds the faulted loop (Loop 1) break (outlet nozzle) mass flow rate spikes (see Figure 5.1.13-27) as a result of the upper steam generator node becoming water-solid. This spike occurs long before the peak heat flux is reached and does not invalidate the results.

Double-Ended Rupture With RSGs and Without Offsite Power Available Figures 5.1.13-34 through 5.1.13-41 show the steam pressure, steam flow, pressurizer pressure, pressurizer water volume, reactor vessel inlet temperature, core heat flux, core boron concentration, and core reactivity following a double-ended rupture of a main steam line with the RSGs at initial no-load conditions and with a loss-of-offsite power (RCPs begin coasting down 3 seconds after break initiation).

The effective break size was limited to 1.4 ft2 per steam generator by the flow area of the steam generator outlet nozzles, and both steam generators were assumed to discharge through the break until steam line isolation had occurred. It is important to note that at approximately 27 seconds the faulted loop (Loop 1) break (outlet nozzle) mass flow rate spikes (see Figure 5.1.13-35) as a result of the upper steam generator node becoming water-solid. This spike occurs long before the peak heat flux is reached and does not invalidate the results.

Conclusions The main steam line break transient was conservatively analyzed with respect to the reactor core response. Key analysis assumptions were made to conservatively maximize the cooldown of the RCS, so as to maximize the positive reactivity insertion, and thus maximize the peak return to power. Other key assumptions include: end-of-life shutdown margin with the most-reactive RCCA stuck in its fully withdrawn position, maximum delays in actuating engineered safeguard features such as safety injection, main steam isolation and feedwater isolation, and minimum safety injection flow with a minimum boron concentration.

January 2004 Prairie Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP~doc- 116W

= ---

5-212 A DNBR statepoint analysis was performed for the four DER cases considered: OSG and RSG cases both with and without offsite power. The case with the OSGs and offsite power available, i.e., the OSG case with full reactor coolant flow, was found to be the limiting case. The minimum DNBR for each case was determined to be greater than the DNBR safety analysis limit, and thus the DNBR design basis is met.

References 5.1.13-1 D. S. Huegel, et al., "RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses," WCAP-14882-P-A, April 1999.

5.1.13-2 WCAP-1 1397-P-A, (Proprietary), WCAP-1 1397-A, (Non-proprietary), "Revised Thermal Design Procedure," Friedland, A.J. and Ray, S., April 1989.

5.1.13-3 Liu, Y. S., et al., "ANC: AWestinghouse Advanced Nodal Computer Code,"

WCAP-10965-P-A, September 1986.

5.1.134 Sung, Y.X., et al., "VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCA Thermal-Hydraulic Safety Analysis," WCAP-14565-P-A (Proprietary),

October 1999.

)'

Licensing Report Island Licensing January 2004 Prairie Island Prairie Report January 2004 6296-LR-NP.doc-01 1604

5-213 Table 5.1.13-1 Summary Results for Steam Line Rupture - Full Power Core Response (0.99 ft2)

Westinghouse OSGs & Framatome RSGs Criteria Limit Calculated Value Minimum DNBR (W-3 correlation)() 1.A28 thimble/typical 1.448 thimble/1.681 typical Minimum DNBR (WRB-1 correlation)(2 1.34 thimble/typical 1.537 thimble/1.578 typical Peak Linear Heat Generation Rate - 22.54 kW/ft < 22.54 kW/ft Notes:

1. Below first mixing grid.

2. Above first mixing grid.

Table 5.1.13-2 Sequence of Events - Steam Line Rupture - Full Power Core Response - 0.99 ft 2 Westinghouse OSGs Framatome RSGs Time Event Time (seconds) (seconds)

Break Initiation with Reactor at Full Power 20.01 20.01 Overpower AT Condition Reached in Loop 1 33.23 31.74 Overpower AT Condition Reached in Loop 2 35.35 33.44 Overpower AT Reactor Trip 37.85 35.94 Minimum DNBR Reached 38.25 36.25 Maximum Core Heat Flux Reached 38.25 36.25 Turbine Trip Following Reactor Trip 38.85 36.94 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-214 Table 5.1.13-3 OSG Steam Line Break Analysis Assumptions and Sequence of Events K>

Double-Ended Rupture Double-Ended Rupture with Offsite Power Without Offsite Power Steam Generator Model Westinghouse Model 51 Westinghouse Model 51 Loss-of-Offsite Power No Yes Time of Main Steam Line Rupture, seconds 10.01 10.01 Time Maximum AFW (1,000 gpm to the faulted loop) 10.01 10.01 Initiated, seconds Time Faulted Loop Steam Flow Reaches Hi-Hi 10.01 10.01 Setpoint (-150% of Nominal), seconds Time Faulted Loop Steam Pressure Reaches Lo-Lo 10.17 10.17 Setpoint (500 psia)

Time of SI Signal Actuation Due to Coincidence of . 11.19 11.19 Hi-Hi Steam Flow and Lo-Lo Steam Pressure, seconds Time of RCP Trip (Loss-of-Offsite-Power), seconds N/A 13.01 Time of Steam Line Isolation (MSIV Closure) Due to 16.19 16.19 SI Signal Actuation, seconds Time SI Pump Reaches Full Speed, seconds 21.19 36.19 Time Core Returns to Criticality, seconds 38.25 44.75 Time of Feedwater Isolation (Main Feedwater Isolation 61.69 61.69 Valve Closure) Due to SI Signal Actuation, seconds Time of Peak Heat Flux, seconds 83.00 100.00 Time of Minimum DNBR, seconds 83.00 -100.00 Peak Heat Flux, fraction of nominal 0.227 0.043 Minimum DNBR 2.535 Bounded by other case Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-215 Table 5.1.13-4 RSG Steam Line Break Analysis Assumptions and Sequence of Events Double-Ended Rupture Double-Ended Rupture with Offsite Power Without Offsite Power Steam Generator Model Framatome Model 56119 Framatome Model 56119 Loss-of-Offsite Power No Yes Time of Main Steam Line Rupture, seconds 10.01 20.01 Time Maximum AFW (1,000 gpm to the faulted loop) 10.01 20.01 Initiated, seconds Time Faulted Loop Steam Flow Reaches Hi-Hi 10.01 20.01 Setpoint (-150% of Nominal), seconds Time Faulted Loop Steam Pressure Reaches Lo-Lo 10.65 20.61 Setpoint (500 psia)

Time of SI Signal Actuation Due to Coincidence of 11.67 21.63 Hi-Hi Steam Flow and Lo-Lo Steam Pressure, seconds Time of RCP Trip (Loss-of-Offsite-Power), seconds N/A 23.01 Time of Steam Line Isolation (MSIV Closure) Due to 16.67 26.63 SI Signal Actuation, seconds Time SI Pump Reaches Full Speed, seconds 21.67 46.63 Time Core Returns to Criticality, seconds 50.75 71.00 Time of Feedwater Isolation (Main Feedwater Isolation 62.17 72.13 Valve Closure) Due to SI Signal Actuation, seconds Time of Peak Heat Flux, seconds 114.00 112.00 Time of Minimum DNBR, seconds -114.00 -112.00 Peak Heat Flux, fraction of nominal 0.113 0.016 Minimum DNBR Bounded by other case Bounded by other case January2004 Prairie Island Licensing Report Island Licensing Report

• January 2004 6296-LR-NP.doc-01 1604

5-216

-~ Westinghouse OSGs

--- - Frarnatome ANP RSGs 1.4-0 E 1.2 0C-4-

0 c-o

.8 0

0 L-4-_

.6 Q) 0 .4 L-0 .2 3

z 0 Time [seconds]

Figure 5.1.13-1 Nuclear Power Steam Line Rupture - Full Power Core Response Prii sadLcnin eotJnay20 Prairie Island Licensing Report January 2004 6296-LR-N'P.dc-01 1604

5-217 Westinghouse OSGs

--- - Framortome ANP RSGs r_1 1.4 -

0 E 12 4-0 I I

. I 0

4-

_ _ \I 0

_. I I I II . I I I I . I I I I . I I I I 0) 0)

0L l l U 10 20 30 40 50 Time [seconds]

Figure 5.1.13-2 Core Heat Flux Steam Line Rupture - Full Power Core Response Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-218 Weestinghouse OSGs

---

Framatome ANP RSGs 2300 -

2OO i 2250-Q)

L-D 2200 -

a) i 2150-N a 2100-2050-0 10 20 30 40 50 Time [seconds]

Figure 5.1.13-3 Pressurizer Pressure Steam Line Rupture - Full Power Core Response Report Licensing Report Island Licensing January 2004 Prairie Island January 2004 6296-LR-NP.doc-0 11604

5-219

/Westinghouse OSGs

- --- Framatome ANP RSGs r-- uvvv IM a) a)

360 0

340 320

> 300 O 280

°N 260 co 240 L)

L-0 non.

LIN 20 30 Time [seconds]

Figure 5.1.13-4 Pressurizer Water Volume Steam Line Rupture - Full Power Core Response Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-220 NWestinghouse OSGs (Faulted Loop)

---

Westinghouse OSGs (Intact Loop)

---

Fromatome ANP RSGs (Faulted Loop)

--- Fromatome ANP RSGs (Intact Loop) r, 530 LL

- 525 0 520 Q) 0-K)

E

_ 515 j

a)

- 510 co

> 5)

> 505 Time [seconds]

Figure 5.1.13-5 Vessel Inlet Temperature Steam Line Rupture - Full Power Core Response Report Licensing Report January 2004 Praire Island Prairie sland Licensing January 2004 6296-LR-NP.doc-0 1 1604

5-221 Westinghouse OSGs (Faulted Loop)

---

Westinghouse OSGs ( Intact Loop)

---

Fromatome ANP RSGs (Faulted Loop)

---Framatome ANP RSGs (Intact Loop) 800 -

' 750 L-j 15-  %

Q)

L 650-0 600-C)

E550-0n lllll Time [seconds]

Figure 5.1.13-6 Steam Generator Pressure Steam Line Rupture - Full Power Core Response Licensing Report January 2004 Prairie Island Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 1 1604

5-222 Westinghouse OSGs (Faulted Loop)

- Westinghouse OSGs (Intact Loop)

---

Framutome ANP RSGs (Faulted Loop)

---Framutome ANP RSGs (Intact Loop) 1800-U\

0)1600-E 1400 -

-Q 1200-o E1 1000-E 800 T Q)I n600-

° 0 a00 400 -" e I,,I1, ,,I 20-J 0 10 20 30 40 lime [seconds]

Figure 5.1.13-7 Loop Steam Flow Steam Line Rupture - Full Power Core Response Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 1 604

5-223 0

-0.002

2 -0.004 0

X) a)

0 -0.006 0

IL Z%

C 0

IL la.

CL -0.008

-0.01

-0.012 0 0.1 0.2 0.3 0.4 Power (fraction)

Figure 5.1.13-8 Doppler-only Power Defect with Stuck RCCA Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-224 2250 2000 1750

'U

`. 1500 0

I-0

(&1250O E

0 (A

U, E5 1000

'U 0

C.)

03 0

500 250 0

0 25 50 75 100 SI Flow Rate (Ibmlsec)

Figure 5.1.13-9 Safety Injection Curve Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-225

-- Loop I

_ __ Loop 2 1200 1000 C-"

a,

,)_

0) a)

a)

Time [seconds]

Figure 5.1.13-10 Main Steam Line Break Steam Pressure versus with OSGs and with Offsite Power - Steam Time Generator Prairie island icensiganuary 6296-t*-NP.do-0 11604 2004

5-226 Loop 1 Loop 2 10000 -

C)_

C.,

2_

8000-0)

'a 6000-a 4000-W C-D-02000-E 2-0 l Time [seconds]

Figure 5.1.13-11 Main Steam Line Break with OSGs and with Offsite Power- Steam Generator Outlet Nozzle Mass Flowrate versus Tune January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-0 11604

5-227 2500 -

2000 -

Cl) 0n Cl)

CD)

L1500 100-0n Cl) 1000 0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-12 Main Steam Line Break with OSGs and with Offsite Power- Pressurizer Pressure versus Time Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 62936-LR-NP.dto-1 1604

5-228 300 250 -

200 E

150 150 a) 50 50 0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-13 Main Steam Line Break with OSGs and with Offsite Power- Pressurizer Vater Volume versus mime Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-229 Loop 1

--- - Loop 2 550-r,500

-450-a) 40 -I' Qa, 0~

E c,) 350 -

= 300 250 300 Time [seconds]

Figure 5.1.13-14 Main Steam Line Break with OSGs and with Offsite Power- Reactor Vessel Inlet Temperature versus TIme January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-230

.25 -

.2 E

.15 C>

C--)

05-0 00 Time [seconds]

Figure 5.1.13-15 Main Steam Line Break with OSGs and with Offsite Powfer- Core Heat Flux versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-231 400 300 -

C)

CL 0

IC-,

CD20 -) 020304050610 200102030 0 0 Time [seconds]

Figure5S.1.13-16 Main Steam Line Break with OSGs and with Offsite Power- Core Averaged Boron Concentration versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-232 0

-4.

0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-17 Nlain Steam Line Break with OSGs and with Offsite Power- Reactivity versus Time January 2004 Prairie L6cens4ng Report Island Licensing raiP Island Report January 2004 6296-LR-NP.doc-01 1604

5-233 Loop 1

- - -- Loop 2 1200 -

1000- _ H

_ IX o-- 800  %

CL) co 600-CD E

0 0-

1) 400 200 0

Time [seconds]

Figure 5.1.13-18 Main Steam Line Break with OSGs and Without Offsite Power - Steam Pressure versus Time IK January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296 LRNP.doc-01 1604

5-234 Loop 1

- - -- Loop 2 10000 CI a)

En

-o ok, 8000 Q>

U us 6000 U-NJ 0

a, a) 4000 CD i 0

L-0 t 2000 a)

U) ca, (D L-Time [seconds]

Figure 5.1.13-19 Main Steam Line Break with OSGs and Without Offsite Power- Steam Generator Outlet Nozzle Mass Flowrate versus Time Report January 2004 Prairie Island Prairie Licensing Report Island Lice6sing January 2004 6296- RNP.doc-0 1 1604

5-235 2500 2000 -

0 0-C',

inI C',

1000 -

500 0 50 100 150 200 Time [seconds]

Figure 5.1.13-20 Main Steam Line Break with OSGs and Without Offsite Power - Pressurizer Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0I 1604

5-236 300 250 -

D 200-C-)

> 150-C I CL.

.N 100-C,,

50 0 50 100 l50 200 Time [seconds]

Figure 5.1.13-21 Main Steam Line Break with OSGs and Without Offsite Power - Pressurizer Water Volume versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-237 Loop 1

- - - _Loop 2 550 500 L-CO 450 0

L..

Q- 400 E

Ca Ca

= 350 co Cn I.. 300 0

C.)

0Toi 250 200 Figure 5.1.13-22 Main Steam Line Break with OSGs and Without Offsite Power - Reactor Vessel Inlet Temperature versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-238

.5E-01

.E-O C..

0 .2E-01

, E-0D1 -

C)

.1E-01 0

0 50 100 150 200 Time [seconds]

Figure 5.1.13-23 Main Steam Line Break with OSGs and Without Offsite Power- Core Heat Flux versus Time Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 11604

5-239 120 100 -

0 /

0~

CL m 0 /

0 40-20-ll 5 100 150 26 Time [seconds]

Figure5S.1.13-24 Main Steam Line Break with OSGs and Without Offsite Power- Core Averaged Boron Concentration versus Time January 2004 Prairie Island Licensing Report Island Licensing Report Januar 2004 6296-LR-NP.doc-01 1604

5-240 0

.5 a.I CD,

- -2 C-,

-3 0 50 100 150 200 Time [seconds]

Figure 5.1.13-25 Main Steam Line Break with OSGs and Without Offsite Power- Reactivity versus Thme Prairie Island Licensing Report January 2004 6296.LR-NP.doc-O1 1604

5-241 Loop 1

- - - _Loop 2 1200 1000 c-,- 800 a)

'° a) 600 0c Con400 200 0

Time [seconds]

Figure 5.1.13-26 Main Steam Line Break with RSGs and with Offsite Power- Steam Generator Steam Pressure versus Time January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-242

'I Loop 1

- - - _Loop 2 5000 an

-CFE a)-4000 c' 3000 a) 0

-, 2000 0 I L-a)

= 1000 CD a,

Ew 0

Figure 5.1.13-27 Main Steam Line Break with RSGs and with Offsite Power- Steam Generator Outlet Nozzle Mass Flowrate versus Time Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 2004 6296- RNP.doc-01 1604

5-243 2500 -

2000 -

C,,

to C,,

A 1500-C, C)_

1000 -

500- ,

0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-28 Main Steam Line Break with RSGs and with Offsite Power - Pressurizer Pressure versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296- RNP.doc-01 1604

5-244 300*

250 -

a) 200-E

>- 150-0 100102030 coo 0 0 0 Time [seconds]

Figure 5.1.13-29 Main Steam Line Break with RSGs and with Offsite Power- Pressurizer Seater Volume versus Eime <

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-245 Loop 1

- - - -Loop 2 550

..- 500 0)

L.. 450 E

C-a, I-E 400 a_

C,,

cn 350 0

C-)

a)

= 300 250 Figure 5.1.13-30 Main Steam Line Break with RSGs and with Offsite Power - Reactor Vessel Inlet Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-246

.12-

.1E+00 E

z .8E 0

, .6E Q .4E-01

.2E 0-0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-31 Main Steam Line Break with RSGs and with Offsite Power- Core Heat Flux versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-247 400 -

- 300 -

cor 0

I..-

C an c

C=

0 C 200 -

0 0

m a) 0 a),

w 100-0 C-D

. . I I 0- 4.-I 0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-32 Main Steam Line Break with RSGs and mith Offsite Power- Core Averaged Boron Concentration versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-248 1*

0 0

C--)

-3 0 100 200 300 400 500 600 Time [seconds]

Figure 5.1.13-33 Main Steam Line Break with RSGs and with Offsite Power- Reactivity versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-249

- Loop 1

- - - _Loop 2 1200 1000 CI_

800 0O L.

a)

CD 0n 600 a)

CL-E U) 400 200 0

Time [seconds]

Figure 5.1.13-34 Main Steam Line Break with RSGs and Without Offsite Power - Steam Pressure versus Time January 2004 Prairie Island Prairie Licensing Report Island Licensing Report January 2004 6296 lRNP.doc-01 1604

5-250 Loop 1

- - - _Loop 2 5000 C),

a)

U, E

-o

--- 4000 0

0 Cal gn 3000 a) rN

-a 2000 0

0

= 1000 a)

CD:

ca)

U) 0 0o Time [seconds]

Figure 5.1.13-35 Main Steam Line Break with RSGs and Without Offsite Power - Steam Generator Outlet Nozzle Mass Flowrate versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-251 2500 2000-C-

0.)

to 0) 1500 -

500 0 50 100 150 200

-Time [seconds]

Figure S.1.13-36 Main Steam Line Break with RSGs and Without Offsite Power- Pressurizer Pressure versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-252 300 -

250 -

. 200-E 10 0

50 l 0 50 100 150 200 Time [seconds]

Figure 5.1.13-37 Main Steam Line Break with RSGs and Without Offsite Power - Pressurizer Wlater Volume versus Time J Prairie Island Licensing Repo1ts t January 2004 6296-LR-NP.doc01 1604

5-25 3 Loop 1

- - - - Loop 2 550 -

. 500 -\

- \

, 450 CL_

E

-EI-400-Cn 3 350-300 250 Ti'me [seconds]

Figure 5.1.13-38 Main Steam Line Break with RSGs and Without Offsite Power - Reactor Vessel Inlet Temperature versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-254

.2E-01

.- .15E-01

.f_

0

'- 0C)

" .5E-01 U-II CD o .5E-02 0

Time Figure 5.1.13-39 MIain Steam Line Break with RSGs and Without Offsite Power- Core Heat Flux versus Time ,.I Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-255 100 -

E 80 Q-C c ,

0~

0 -

0 cc: 20 -/

0 50 100 150 200 Time [seconds]

Figure5S.1.13o40 Main Steam Line Break with RSGs and Without Offsite Power- Core Averaged Boron Concentration versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-256 0 5 C..)

050 100 150 200 Time [seconds]

Figure 5.1.1341 Main Steam Line Break with RSGs and Without Offsite Power- Reactivity versus Time Licensing Report Island Licensing January 2004 Prairie Island Prairie Report January 2004 6296- RNP.doc-01 1604

5-257 5.1.14 Rupture of a Control Rod Drive Mechanism Housing (RCCA Ejection) (USAR Section 14.5.6) 5.1.14.1 Accident Description This accident is the result of the extremely unlikely mechanical failure of a control rod drive mechanism pressure housing such that the reactor coolant system (RCS) pressure would eject the rod cluster control assembly (RCCA) and drive shaft. The consequences of this mechanical failure, in addition to being a minor loss-of-coolant accident (LOCA), may also be a rapid reactivity insertion together with an adverse core power distribution, possibly leading to localized fuel rod damage.

Certain features in Westinghouse pressurized water reactors are intended to preclude the possibility of a rod ejection accident, or to limit the consequences if the accident were to occur. These include a sound, conservative mechanical design of the rod housings, along with a thorough quality control (testing) program during assembly, and a nuclear design which lessens the potential ejection worth of control rod assemblies and minimizes the number of assemblies inserted at high power levels.

The mechanical design is discussed in Section 3 of the USAR. A failure of the full length control rod mechanism housing, sufficient to allow a control rod to be rapidly ejected from the core, is not considered credible for the following reasons:

• Each control rod drive mechanism housing is completely assembled and shop-tested at 4100 psi.

• The mechanism housings are individually hydrotested as they are installed on the reactor vessel head to the head adapters, and checked during the hydrotest of the completed RCS.

• Stress levels in the mechanism are not affected by system transients at power, or by the thermal movement of the coolant loops. Movements induced by the design earthquake can be accepted within the allowable primary working stress range specified by the American Society of Mechanical Engineers (ASME) Code, Section HI, for Class A components.

• The latch mechanism housing and rod travel housing are each a single length of forged Type 304 stainless steel. This material exhibits excellent notch toughness at all temperatures that are encountered.

A significant margin of strength in the elastic range, together with the large energy absorption capability in the plastic range, gives additional assurance that gross failure of the housing will not occur. The joints between the latch mechanism housing and rod travel housing are threaded and reinforced by canopy-type rod welds. Administrative regulations require periodic inspections of those (and other) welds.

Even if a rupture of the control rod mechanism housing is postulated, the operation of a chemical shim plant is such that the severity of an ejected rod is inherently limited. In general, the reactor is operated with control rods inserted only far enough to permit load follow. Reactivity changes caused by core depletion and xenon transients are compensated by boron changes. Further, the location and groupings of control rod banks are selected during the core nuclear design to lessen the severity of an ejected control rod assembly. Therefore, should an RCCA be ejected from the reactor vessel during normal operation, Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-258 there would probably be no reactivity excursion since most of the control rods are fully withdrawn from the core, or a minor reactivity excursion if an inserted RCCA is ejected from its normal position.

However, it may occasionally be desirable to operate with larger control rod insertions. For this reason, rod insertion limits are defined in the Technical Specifications as a function of power level. Operation with the RCCAs above this limit guarantees adequate shutdown capability and acceptable power distribution. The position of all RCCAs is continuously indicated in the control room. An alarm will occur if a bank of RCCAs approaches its insertion limit or if one RCCA deviates from its bank. There are low and low-low level insertion monitors with visual and audio signals. Operating instructions require boration when receiving either alarm.

If an RCCA ejection accident were to occur, a fuel rod thermal transient that could cause departure from nucleate boiling (DNB) may occur together with limited fuel damage. The amount of fuel damage that can result from such an accident will be governed mainly by the worth of the ejected RCCA and the power distribution attained with the remaining control rod pattern. The transient is limited by the Doppler reactivity effects of the increase in fuel temperature and is terminated by a reactor trip which is actuated by neutron flux signals. The reactor trip will occur before conditions are reached that can result in damage to the reactor coolant pressure boundary or significant disturbances in the core, its support structures or other reactor pressure vessel internals that would impair the capability to cool the core.

The neutron flux response to a continuous reactivity insertion is characterized by a very fast flux increase terminated by the reactivity feedback effect of the negative Doppler coefficient. This self-limitation of the power burst is of primary importance since it limits the power to a tolerable level during the delay time for protective action. Should an RCCA ejection accident occur, the following automatic features of the reactor protection system are available to terminate the transient.

a. The source-range high neutron flux reactor trip is actuated when either of two independent source-range channels indicates a neutron flux level above a preselected manually adjustable setpoint. This trip function may be manually bypassed when either intermediate-range flux channel indicates a flux level above a specified level. It is automatically reinstated when both intermediate-range channels indicate a flux level below a specified level.

a. The intermediate-range high neutron flux reactor trip is actuated when either of two independent intermediate-range channels indicates a flux level above a preselected manually adjustable setpoint. This trip function may be manually bypassed when two-out-of-four power-range channels give readings above approximately 10 percent of full power and is automatically reinstated when three-out-of-four channels indicate a power below this value.

b. The power-range high neutron flux reactor trip (low setting) is actuated when two-out-of-four power-range channels indicate a power level above a preselected manually adjustable setpoint (allowable value, < 40 percent power). This trip function may be manually bypassed when two-out-of-four power-range channels indicate a power level above approximately 10 percent of full power and is automatically reinstated when three-out-of-four channels indicate a power level below this value.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-259

g. The power-range high neutron flux reactor trip (high setting) is actuated when two-out-of-four power-range channels indicate a power level above a preset setpoint (allowable value, < 110 percent power). This trip function is always active when the reactor is at power.

h. The high nuclear flux rate reactor trip is actuated when the positive rate of change of neutron flux on two-out-of-four nuclear power-range channels indicates a rate above the preset setpoint. This trip function is always active.

The ultimate acceptance criteria for this event is that any consequential damage to either the core or the RCS must not prevent long-term core cooling, and that any offsite dose consequences must be within the guidelines of 10 CFR 100. To demonstrate compliance with these requirements, it is sufficient to show that the RCS pressure boundary remains intact, and that no fuel dispersal in the coolant, gross lattice distortions, or severe shock waves will occur in the core. Therefore, the following acceptance criteria are applied to the RCCA ejection accident:

a. Maximum average fuel pellet enthalpy at the hot spot must remain below 200 callg (360 Btu/lbm).

b. Peak RCS pressure must remain below that which would cause the stresses in the RCS to exceed the faulted condition stress limits.

c. Maximum fuel melting must be limited to the innermost 10 percent of the fuel pellet at the hot spot, independent of the above pellet enthalpy limit.

5.1.14.2 Method of Analysis The calculation of the RCCA ejection transient is performed in two stages: a neutron kinetic analysis and a hotspot fuel heat transfer analysis. The spatial neutron kinetics code TWINKLE (Reference 5.1.14-1) is used in a 1-D axial kinetics model to calculate the core nuclear power including the various total core feedback effects, i.e., Doppler reactivity and moderator reactivity. The average core nuclear power is multiplied by the post-ejection hot channel factor, and the fuel enthalpy and temperature transients at the hotspot are calculated with the detailed fuel and cladding transient heat transfer computer code, FACTRAN (Reference 5.1.14-2). The power distribution calculated without feedback is pessimistically assumed to persist throughout the transient. Additional details of the methodology are provided in WCAP-7588 (Reference 5.1.14-3).

The overpressurization of the RCS and number of rods in DNB, as a result of a postulated ejected rod, have both been analyzed on a generic basis for Westinghouse pressurized water reactors as detailed in Reference 5.1.14-3.

If the safety limits for fuel damage are not exceeded, there is little likelihood of fuel dispersal into the coolant or a sudden pressure increase from thermal-to-kinetic energy conversion. The pressure surge for this analysis can, therefore, be calculated on the basis of conventional heat transfer from the fuel and prompt heat generation in the coolant.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-260 A detailed calculation of the pressure surge for an ejection worth of one dollar at beginning of life (BOL),

hot full power, indicates that the peak pressure does not exceed that which would cause stresses in the RCS to exceed their faulted condition stress limits. Since the severity of the Prairie Island analysis does not exceed this worst case analysis, the RCCA ejection accident will not result in an excessive pressure rise or further damage to the RCS.

Reference 5.1.14-3 also documents a detailed multi-channel thermal-hydraulics code calculation, which demonstrates an upper limit to the number of rods in DNB for the RCCA ejection accident as 10 percent.

Since the severity of the Prairie Island analysis does not exceed this worst case analysis, the maximum number of rods in DNB following an RCCA ejection will be less than 10 percent, which is well within the value used in the radiological dose evaluation. The most limiting break size resulting from an RCCA ejection will not be sufficient to uncover the core or cause DNB at any later time. Since the maximum number of fuel rods experiencing DNB is limited to 10 percent, the fission product release will not exceed that associated with the guidelines of 10 CFR 100.

In calculating the nuclear power and hot spot fuel rod transients following RCCA ejection, the following conservative assumptions are made:

a. The Standard Thermal Design Procedure (STDP) (maximum uncertainties in initial conditions) is employed. The analysis assumes uncertainties of +2.0 percent in nominal core power, +4.00 F in nominal vessel Tvg, and .40 psi in nominal pressurizer pressure.

b. A minimum value for the delayed neutron fraction for beginning of cycle (BOC) and end of cycle (EOC) conditions is assumed which increases the rate at which the nuclear power K>

increases following an RCCA ejection accident.

c. A minimum value of the Doppler power defect which conservatively results in the maximum amount of energy deposited in the fuel following an RCCA ejection accident is assumed. A minimum value of the moderator feedback is also assumed. A positive moderator temperature coefficient is assumed for the BOC, zero-power case.

d. Maximum values of ejected RCCA worth and post-ejection total hot channel factors are assumed for all cases considered. These parameters are calculated using standard nuclear design codes for the maximum allowed bank insertion at a given power level, as determined by the rod insertion limits. No credit is taken for the flux flattening effects of reactivity feedback.

e. The start of rod motion occurs 0.45 seconds after the high neutron flux trip point is reached.

The analysis is performed to bound operation with Westinghouse fuel (UO2 and up to 8 w/o gadolinia-doped U0 2 ) and a maximum loop-to-loop steam generator tube plugging imbalance of 10 percent.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-011604

5-261 5.1.143 Results Figures 5.1.14-1 through 5.1.14-8 are representative nuclear power and hot spot fuel rod thermal transients following an RCCA ejection accident. The transient results of the analysis are summarized in Table 5.1.14-1. A time sequence of events is provided in Table 5.1.14-2. For all cases, the maximum fuel pellet enthalpy remained below 200 cal/g. 'For the hot full power cases, the peak hot spot fuel centerline temperature reached the fuel melting temperature (4900'F at BOL and 48000 F at end of life for U0 2 fuel);

however, melting was restricted to less than 10 percent of the pellet. For the hot zero power cases, no fuel melting was predicted. The U0 2 cases are bounding for all fuel types, including gadolinia-doped fuel.

5.1.14.4 Conclusions Even on the most pessimistic basis, the analyses indicate that the fuel and clad limits are not exceeded. It is concluded that there is no danger of sudden fuel dispersal into the coolant. Since the pressure does not exceed that which would cause stresses to exceed the faulted condition stress limits, it is concluded that there is no danger of further consequential damage to the primary coolant system. The amount of fission products released as a result of the assumed failure of fuel rods entering into DNB will not exceed the guidelines of 10 CFR 100.

5.1.14.5 References 5.1.14-1 WCAP-7979-P-A (Proprietary) and WCAP-8028-A (Non-Proprietary), 'TWINKLE -A Multi-Dimensional Neutron Kinetics Computer Code," Barry, R.F. and Risher, D.H., Jr.,

January 1975.

5.1.14-2 WCAP-7908-A, 'FACTRAN - A FORTRAN-TV Code for Thermal Transients in a U02 Fuel Rod," Hargrove, H.G, December 1989.

5.1.14-3 WCAP-7588, Revision 1-A, "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinetics Methods," Risher, D.H., Jr., January 1975.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-262 Table 5.1.14-1 Assumptions and Results - RCCA Ejection Beginning of Cycle Full Power Zero Power Initial Power Level, % 102 0 Ejected RCCA Worth, % Ak 0.380 0.770 Delayed Neutron Fraction 0.0049 0.0049 Doppler Power Defect, % Ak 1.000 1.000 Feedback Reactivity Weighting 1.139 2.008 Trip Reactivity, % Ak 4.0 1.0 FQ Before Ejection 2.5 NIA FQ After Ejection 4.2 11.0 Number of RCPs Operating 2 1 Maximum Fuel Pellet Enthalpy, caL/g 168.6 150.9 Maximum Fuel Melted, % 1.94 None End of Cycle Full Power Zero Power Initial Power Level, % 102 0 Ejected RCCA Worth, % Ak 0.30 0.954 Delayed Neutron Fraction 0.0047 0.0047 Doppler Power Defect, % Ak 0.980 0.980 Feedback Reactivity Weighting 1.316 2.755 Trip Reactivity, % Ak 4.0 1.0 FQ Before Ejection 2.5 N/A FQ After Ejection 5.69 18.42 Number of RCPs Operating 2 1 Maximum Fuel Pellet Enthalpy, cal/g 160.1 158.6 Maximum Fuel Melted, % 0.96 None Prairie Island Licensing Report January 2004 6296-LR-NP.doc.0I 1604

5-263 Table 5.1.14-2 Sequence of Events - RCCA Ejection Beginning of Cycle - Hot Zero Power Time (seconds)

RCCA Ejection Occurs 0.000 High Neutron Flux Setpoint (Low Setting) is Reached 0.211 Peak Nuclear Power Occurs 0.252 Rods Begin to Fall Into the Core 0.661 Peak Cladding Average Temperature Occurs 2.297 Peak Fuel Average Temperature Occurs 2.463 Beginning of Cycle - Hot Full Power Time (seconds)

RCCA Ejection Occurs 0.000 High Neutron Flux Setpoint (High Setting) is Reached 0.030 Peak Nuclear Power Occurs 0.135 Rods Begin to Fall Into the Core 0.480 Peak Fuel Average Temperature Occurs 1.962 Peak Cladding Average Temperature Occurs 2.106 End of Cycle - Hot Zero Power Time (seconds)

RCCA Ejection Occurs 0.000 High Neutron Flux Setpoint (Low Setting) is Reached 0.156 Peak Nuclear Power Occurs 0.183 Rods Begin to Fall Into the Core 0.606 Peak Cladding Average Temperature Occurs 1.723 Peak Fuel Average Temperature Occurs 1.956 End of Cycle - Hot Full Power Time (seconds)

RCCA Ejection Occurs 0.000 High Neutron Flux Setpoint (High Setting) is Reached 0.035 Peak Nuclear Power Occurs 0.130 Rods Begin to Fall Into the Core 0.485 Peak Fuel Average Temperature Occurs 2.002 Peak Cladding Average Temperature Occurs 2.165 January 2004 Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-0 1160>4

5-264 4

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Figure 5.1.14-1 RCCA Ejection - BOC Full Power Reactor Power vs. lime January 2004 Prairie Island Praire Report Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 11 604

5-265 5000 - ,

- A __ __ - -_ - _ _ _ _ __ - - - -

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Figure 5.1.14-2 RCCA Ejection - BOC Full Power Fuel and Clad Temperatures vs. Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-266 10- I c 1 -_0 __ _ _ 4_ _ _ __

6 __ _ _ . _ _ _ _

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Figure 5.1.14-3 RCCA Ejection - BOC Zero Power Reactor Power vs. Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-267 5000- _ _-_____ ---

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5-269 5000*

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Figure 5.1.14-6 RCCA Ejection - EOC Full Power Fuel and Clad Temperatures vs. Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-270 10 2 a a

- I - I E l l 2 . 'Io ' ' ' i ' ' ' i I I '

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Figure 5.1.14-7 RCCA Ejection - EOC Zero Power Reactor Power vs. EMue Report January 2004 Prairie Island Licensing Report Island Licensing January 2004 6296-LR-NP.doc-0 11604

5-271 5000-Fuel Melting - 4800°F

_ ~~Fuel Centeriii Temperature l 4000- ------

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Fiur RCAEetoS O eoPwrFeladCa I..- eprtrsv.Tm Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-272 5.1.15 AMSAC/Diverse Scram System Analyses As defined in 10 CFR 50.62 (Reference 5.1.15-1), an anticipated transient without scram (ATWS) is an expected operational transient that is accompanied by a failure of the reactor protection system to shutdown the reactor. Initial NRC staff guidance on ATWS was provided in WASH-1270, "Technical Report on Anticipated Transients Without Scram for Water-Cooled Power Reactors" (Reference 5.1.15-2).

Westinghouse responded to WASH-1270 with a series of generic ATWS studies that are summarized in WCAP-8330 (Reference 5.1.15-3). Additional studies, which conformed to the guidance provided in NUREG-0460 (Reference 5.1.154), were also performed by Westinghouse at the request of the NRC.

The results of these studies showed that the analyzed ATWS events would have acceptable consequences, provided the turbine is tripped and auxiliary feedwater flow is initiated in a timely manner.

The final ATWS rule, 10 CFR 50.62, was published by the NRC on July 26, 1984. For Westinghouse plants, this rule required the installation of an ATWS mitigating system actuation circuitry (AMSAC) system to initiate a turbine trip and actuate auxiliary feedwater flow independent of the normal reactor protection system. This requirement is based on the analyses performed by Westinghouse and documented in letter NS-TMA-2182 (Reference 5.1.15-5) in response to WASH-1270 and NUREG-0460.

An AMSAC system was therefore installed at Prairie Island in 1989.

A diverse scram system (DSS) was subsequently installed at Prairie Island in 1996 to address concerns regarding the operability of the AFW pumps during an ATWS transient. The DSS installed in Prairie Island provides a reactor trip signal on a low steam generator wide range level signal and on RCP breaker position signal. The AFW pump operability concerns arose as a result of changes that had been made to the AFW system for pump runout protection. The licensing amendment request for the installation of the DSS was submitted to the NRC in 1998 (Reference 5.1.15-6). Included in this licensing amendment request was a summary of new analyses completed by Northern States Power (NSP) to demonstrate that the DSS would indeed provide adequate protection for ATWS events. Explicit analyses were performed for the uncontrolled boron dilution, loss of external load/turbine trip, loss of normal feedwater flow, loss of reactor coolant flow (one-half pump trip), loss of AC power to the station auxiliaries, and isolation of the main condenser ATWS events.

The analyses performed by NSP demonstrated that the DSS provides protection for the ATWS events, such that all of the applicable acceptance criteria are met. As part of the Safety Analysis Transition Program for Prairie Island, Westinghouse has reanalyzed several of these ATWS events to reconfirm that the DSS provides adequate protection. These reanalyses are summarized in this section of the report.

5.1.15.1 Selection of Transients to be Reanalyzed The transient selection originally performed by NSP in Reference 5.1.15-6 was reviewed. Based on the Westinghouse analysis methods and the existing analyses completed by NSP, it was determined that the ATWS events would be addressed as described in Table 5.1.15-1 below.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-273 Table 5.1.15-1 AMSAC/IDSS Event Approach Condition II Event Approach Uncontrolled RCCA Withdrawal from a The only operation mode considered for the AMSACIDSS Subcritical Condition events is full-power operation. Therefore, this event is not analyzed.

Uncontrolled RCCA Bank Withdrawal at Power Analyze. No reactor trip is credited from either the normal RPS or the AMSACIDSS.

Dropped Rod/Control Rod Misalignment Bounded by RWAP and uncontrolled boron dilution since the reactivity insertion from those events is larger.

Uncontrolled Boron Dilution Analyze. No reactor trip is credited from either the normal RPS or the AMSAC/DSS.

Startup of an Inactive Loop Reactor trip not required in Westinghouse methodology.

Feedwater System Malfunction Reactor trip not required in Westinghouse analysis methodology.

Excessive Load Increase Reactor trip not required in Westinghouse analysis methodology.

Loss of External Load/Turbine Trip Analyze. Credit SG wide range level DSS reactor trip.()

Loss of Normal Feedwater Flow Analyze. DNBR results bounded by LOLrTT event. Credit SG wide range level DSS reactor trip.

Loss of AC Power to the Station Auxiliaries Analyze. DNBR results bounded by LOLrTT. Credit SG wide range level DSS reactor trip.

Loss of Reactor Coolant Flow - 1/2 Pump Trip Analyze. Credit RCP breaker DSS reactor trip.

Isolation of Main Condenser Bounded by loss of external load/turbine trip.(l)

Note:

1. In the Westinghouse methodology, all normal feedwater is assumed to be lost coincident with the Loss of Load/Turbine trip, and the steam dump system is assumed to be unavailable. Therefore, the Westinghouse LOL/TT analysis bounds the Isolation of Main Condenser event.

January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-274 5.1.15.2 AMSAC/DSS Trips and Acceptance Criteria The DSS installed in Prairie Island provides a reactor trip on low steam generator wide range level (WRL) signal and on a RCP breaker position signal. The DSS will provide a trip signal when two-out-of-two wide range signals (per steam generator) indicate a level of less than 40 percent in either steam generator. For the AMSAC/DSS analyses performed by Westinghouse, a trip setpoint of 35 percent WRL was assumed based on input provided by NMC. The DSS will also provide a trip signal after receiving an RCP breaker open position signal.

The following key assumptions regarding the DSS functionality were made for these analyses:

• The AMSAC/DSS steam generator wide range level trip safety analysis setpoint is 35 percent WRL.

• The AMSACIDSS output signal is generated within 5 seconds.

• The AMSACIDSS AFW start delay is 65 seconds from the time that the AMSAC/DSS setpoint is reached, or 60 seconds from the time that the AMSAC/DSS output signal is generated.

• The AMSAC/DSS turbine trip delay is 10 seconds from the time that the AMSAC/DSS setpoint is reached, or 5 seconds from the time that the AMSACIDSS output signal is generated.

The AMSAC/DSS analyses completed by Westinghouse are based on the following acceptance criteria, which are consistent with those used by NSP in the AMSACIDSS analyses documented in Reference 5.1.15-6:

1. The analytical limit for the MDNBR will be 1.17 throughout any AMSAC/DSS event. This is the WRB-1 DNB correlation DNBR limit value.

2. The analytical limit for the RCS maximum pressure will be 3,200 psig throughout any AMSAC/DSS event.

5.1.153 AMSACIDSS: Partial Loss of Reactor Coolant Flow, One-half RCP Trip Accident Description The partial loss-of-coolant-flow accident can result from a mechanical or electrical failure in an RCP, or from a fault in the power supply to the RCP. If the reactor is at power at the time of the accident, the immediate effect of the loss-of-coolant flow is a rapid increase in the coolant temperature. This increase could result in DNB with subsequent fuel damage if the reactor is not tripped promptly.

The normal protection against a partial loss-of-coolant-flow accident is provided by the low primary coolant flow reactor trip signal, which is actuated in any reactor coolant loop by two-out-of-three low flow signals. For this event, the low coolant flow reactor trip is not modeled, and the AMSACIDSS is assumed to actuate a diverse reactor trip after receiving a RCP breaker open position signal.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-275 Method of Analysis The loss of an RCP with both loops in operation event is analyzed to show that: (1) the integrity of the core is maintained as the DNBR remains above the correlation limit value of 1.17, and (2) the peak RCS pressure remains below 3,200 psig.

The loss of an RCP event is analyzed with two computer codes. First, the RETRAN computer code is used to calculate the loop and core flow during the transient, the time of reactor trip based on the calculated flows, the nuclear power transient, and the primary system pressure and temperature transients.

The VIPRE computer code is then used to calculate the hot-channel heat flux transient and DNBR, based on the nuclear power and RCS temperature (enthalpy), pressure, and flow from RETRAN. The DNBR results presented represent the minimum of the typical or thimble cell.

The following key analysis assumptions are made:

1. The AMSAC/DSS system is functional and activated by an opening of the RCP breaker at 0 seconds. A 5 second delay is assumed to actuate the DSS signal, plus another 3 seconds for rod motion to begin. The total delay from transient initiation to the start of rod motion is therefore 8 seconds.

2. Initial reactor power, pressurizer pressure, and RCS temperature are assumed to be at their nominal values. Minimum measured flow is also assumed.

3. A conservatively large absolute value of the Doppler-only power coefficient is used, along with the most-positive MTC limit for full-power operation (0 pcmn/F). These assumptions maximize the core power during the initial part of the transient when the minimum DNBR is reached.

4. A conservatively low trip reactivity value (4.0-percent Ap) is used to minimize the effect of rod insertion following reactor trip and maximize the heat flux statepoint used in the DNBR evaluation for this event. This value is based on the assumption that the highest worth RCCA is stuck in its fully withdrawn position.

5. A conservative trip reactivity worth versus rod position was modeled in addition to a conservative rod drop time (2.4 seconds to dashpot).

6. The Framatome replacement steam generators were modeled. However, the analysis applies to both the original and replacement steam generators since this event is not sensitive to the secondary-side modeling.

7. A maximum, uniform, SGTP level of 10 percent was assumed in the RETRAN analysis.

Results Figures 5.1.15.3-1 through 5.1.15.3-5 illustrate the transient response for the loss of an RCP with both loops in operation. The minimum DNBR is 1.45, which occurred at 8.8 seconds. The maximum RCS pressure calculated is 2,388 psia.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-UNP.doc-01 1604

5-276 Conclusions The analysis performed has demonstrated that for the partial loss-of-coolant flow event, the DNBR does not decrease below the AMSACIDSS limit value at any time during the transient. Additionally, the peak RCS pressure remains below the AMSACIDSS limit of 3,200 psig. Therefore, the AMSAC/DSS adequately protects the reactor.

Report Licensing Report Island Licensing January 2004 Prairie Island Prairie January 2004 6296-LR-NP.doc-01 1604

5-277 Unfoulted Loop

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Figure 5.1.153-1 RCS Loop Flow versus Time - AMSAC/DSS: Partial Loss of Flow, One Pump Coasting Down January 2004 Prairie Island Licensing Report January2004 6296-LR-NP.doc-0 11604

5-278 1.2 a - ---- -

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Figure 5.1.153-2 Nuclear Power versus Time - AMSACIDSS: Partial Loss of Flow, One Pump Coasting Down MU Prairie Island Licensing Report January 2004+

6296-LR-NP.doc-01 1604

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Figure 5.1.15.3-3 Pressurizer Pressure versus Time - AMSAC/DSS: Partial Loss of Flow, One Pump Coasting Down Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

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Figure 5.1.15.3-4 RCS Pressure versus Thie -AMSACIDSS: Partial Loss of Flow, One Pump Coasting Down Licensing Report January 2004 Prairie Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-281 Transient DNBR

--- - DNBR Limit 4

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Figure 5.1.153-5 DNTBR versus Time - AMSAC/DSS: Partial Loss of Flow, One Pump Coasting Down Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-282 5.1.15.4 AMISAC/DSS: Loss of Normal Feedwater Flow Accident Description A loss of normal feedwater (from a pipe break, pump failure, or valve malfunction) results in a reduction of the ability of the secondary system to remove the heat generated in the reactor core. If the reactor were not tripped during this accident, core damage could possibly occur from a sudden loss of heat sink. If an alternate supply of feedwater were not supplied to the steam generators, residual heat following reactor trip and reactor coolant pump (RCP) heat would cause the primary system water to expand to the point where water relief from the pressurizer would occur. A significant loss of water from the RCS could conceivably lead to core damage.

The following features provide normal protection against a loss of normal feedwater

1. Reactor trip on low-low water level in either steam generator

2. Reactor trip on steam flow-feedwater flow mismatch coincident with low water level in either steam generator

3. Automatic start of one motor-driven auxiliary feedwater (AFW) pump and one turbine-driven AFW pump (via opening of the steam admission control valve) per unit on low-low water level in either steam generator For the AMSACIDSS LONF event, it is assumed that these protection functions are unavailable. The AMSAC/DSS is assumed to start the AFW pumps, actuate a turbine trip, and actuate a diverse reactor trip after receiving a steam generator wide range level < 35 percent signal (safety analysis value).

Method of Analysis The loss of normal feedwater transient is analyzed using the RETRAN computer code, which is described in Section 5.1.0.9.

The Framatome replacement steam generators (RSGs) are modeled in this analysis since they are limiting with respect to peak pressurizer water volume (based on the analyses described in Section 5.1.11). The major assumptions are summarized below.

1. The plant is initially operating at 100 percent of the nominal NSSS power of 1,657 MWt. The RCP heat is a nominal constant value of 7 MWt. The RCPs run throughout the transient.

2. The initial reactor coolant vessel average temperature is assumed to be 560'F, the nominal full-power value.

3. The initial pressurizer pressure is assumed to be 2,250 psia, the nominal value.

4. The initial pressurizer water level is assumed to be 33 percent level span, the programmed full-power value.

Licensing Report Island Licensing January 2004 Prairie Island Report January 2004 6296- RNP.doc-01 1604

5-283

5. The initial steam generator water level is assumed to be 44 percent of narrow range span (NRS)

(the programmed full-power value).

6. The transient is simulated by terminating main feedwater flow at 20 seconds.

7. A reactor trip signal is generated 5 seconds after the steam generator wide range level reaches 35 percent WRL. The rods begin to drop after an additional delay of 3 seconds. No credit is taken for any other reactor trip functions. Turbine trip occurs 5 seconds after the reactor trip signal (or 10 seconds after the steam generator wide range level reaches 35 percent WRL).

8. Both the turbine- and motor-driven AFW pumps are operable. Sixty-five seconds after the AMSAC/DSS wide range steam generator water level setpoint is reached, a constant AFW flow of 160 gpm is initiated from each AFW pump, with flow split equally between the two steam generators. The AFW enthalpy is assumed to be 44.7 Btu/lbm (73.60 F at 1,100 psia).

9. Secondary system steam relief is achieved through the main steam safety valves (MSSVs). The MSSV opening pressures are the nominal settings plus 3 percent tolerance.

10. The pressurizer power-operated relief valves (PORVs), pressurizer heaters, and pressurizer sprays are assumed to operate normally.

11. A conservative core residual heat generation is assumed based on the ANS 5.1 1979 decay heat model with no additional uncertainty.

Results Figures 5.1.15.4-1 through 5.1.15.4-8 show the significant plant responses following a loss of normal feedwater.

The capacity of the AFW pumps together with the AMSAC/DSS trip function are sufficient to dissipate core residual heat, stored energy, and RCP heat demonstrating the adequacy of the AFW system to provide long-term core cooling. The maximum RCS pressure for this event, 2,352 psia, is well below the peak pressure limit of 3,200 psig. The minimum DNBR is calculated is 1.87, which is above the correlation limit of 1.17.

Conclusions The results of the loss of normal feedwater analysis show that the AMSAC/DSS criteria are met. The AFW capacity and AMSACIDSS reactor trip are sufficient to dissipate core residual heat, stored energy, and RCP heat such that reactor coolant water is not relieved through the pressurizer relief or safety valves, and the AMSAC/DSS maximum RCS pressure and MDNBR criteria are met.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 160W

5-284 1-2, 1.2 -

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Figure 5.1.15.4-2 AMSACIDSS: Loss of Normal Feedwater - Reactor Coolant Temperatures Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

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Figure 5.1.15.4-3 AMSACIDSS: Loss of Normal Feedwater - Pressurizer Pressure Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

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Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

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Figure 5.1.15.4-5 AMISACIDSS: Loss of Normal Feedwater - RCS Pressure Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

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5-292 5.1.15.5 ANISAC/DSS: Loss of AC Power Accident Description A complete loss of non-emergency AC power results in the loss of all power to the plant auxiliaries, such as the RCPs, main feedwater and condensate pumps, etc. The loss of power may be caused by a complete loss of the offsite grid accompanied by a turbine generator trip at the station, or by a loss of the onsite AC distribution system.

Upon the loss of power to the RCPs, coolant flow necessary for core cooling and the removal of residual heat is maintained by natural circulation in the reactor coolant loops. Following the RCP coastdown caused by the loss of AC power, the natural circulation capability of the RCS removes residual and decay heat from the core, aided by the AFW in the secondary system.

The AMSAC/DSS is assumed to start the AFW pumps, actuate a turbine trip, and actuate a diverse reactor trip after receiving a steam generator wide range level < 35 percent signal (safety analysis value).

Method of Analysis The loss of all AC power to the station auxiliaries transient is analyzed using the RETRAN computer code, which is described in Section 5.1.0.9.

The analysis does not assume that power is lost as the initiating event. Rather, the analysis conservatively models a loss of normal feedwater with a subsequent loss of offsite power following the reactor trip on the wide range steam generator water level AMSACIDSS setpoint.

Major assumptions made in the loss of all auxiliary AC power analysis are the same as those made in the AMSACIDSS loss of normal feedwater analysis (Section 5.1.15.4), with the following exceptions.

1. The RCPs are assumed to lose power and begin coasting down 2 seconds following the reactor trip on the wide range steam generator water level AMSACJDSS trip function. Following the loss of power to the RCPs, coolant flow necessary for core cooling and removal of residual heat is maintained by natural circulation flow in the coolant loops. Heat addition from the RCPs to the primary coolant ceases.

2. Pressurizer sprays are lost when forced reactor coolant flow ceases as a result of RCP coastdown.

Results Figures 5.1.15.5-1 through 5.1.15.5-8 show the significant plant responses following a loss of all AC to the station auxiliaries.

The capacity of the AFW pumps together with the AMSACIDSS trip function are sufficient to dissipate core residual heat, stored energy, and RCP heat demonstrating the adequacy of the AFW system to provide long-term core cooling. The maximum RCS pressure for this event, 2,366 psia, is well below Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-293 the peak pressure limit of 3,200 psig. The DNBR is calculated is 1.87, which is above the correlation limit of 1.17.

Conclusions The results of the loss of all AC power to the station auxiliaries AMSAC/DSS analysis show that the AMSAC/DSS acceptance criteria are satisfied. The AFW capacity and AMSAC/DSS reactor trip are sufficient to dissipate core residual heat and stored energy such that reactor coolant water is not relieved through the pressurizer relief or safety valves, and the AMSAC/DSS maximum RCS pressure and MDNBR criteria are met.

Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 2004 6296- RNP.doc-01 1604

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%1s' Prairie Island Licensing Report t January 2004 6296-lR-NP.doc-01 1604

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5-302 5.1.15.6 AMSACIDSS: Loss of Load/Turbine Trip Accident Description The loss-of-extemal-electrical-load event is defined as a complete loss of steam load or a turbine trip from full power without a direct reactor trip. This anticipated transient is analyzed as a turbine trip from full power because it bounds both events-the loss of external electrical load and turbine trip. The turbine trip event is more severe than the total loss of external electrical load event since it results in a more rapid reduction in steam flow.

If the reactor were not tripped during this event, the mismatch between heat production and heat removal would eventually boil the steam generators dry leading to consequences identical to those in the AMSAC loss of normal feedwater flow transient.

The AMSACIDSS is assumed to start the AFW pumps and actuate a diverse reactor trip after receiving a steam generator wide range level < 35 percent signal (safety analysis value).

Method of Analysis This event is analyzed using the RETRAN computer code, which is described in Section 5.1.0.9.

In this analysis, the behavior of the unit is evaluated for a complete loss of steam load from full power with no credit taken for a direct reactor trip on turbine trip or for the normal reactor protection system functions. This assumption will delay reactor trip until conditions in the RCS cause a trip on the K AMSACIDSS steam generator wide range level setpoint. Therefore, the analysis assumes a worst case transient and demonstrates the adequacy of the pressure relieving devices and AMSACIDSS setpoint assumed in the analysis for this event.

One case is performed to confirm that both the AMSACIDSS DNBR and peak primary RCS pressure limits are met. The major assumptions for these cases are summarized as follows:

1. The AMSAC/DSS is assumed to initiate a reactor trip signal when the steam generator wide range level reaches 35 percent WRL. A reactor trip signal is generated 5 seconds after this AMSAC/DSS setpoint is reached. The rods begin to drop after an additional 3-second delay.

2. Initial core power, reactor coolant temperature, and reactor coolant pressure are assumed to be at the nominal values consistent with steady-state full-power operation.

3. The loss of load event results in a primary system heatup and, therefore, is conservatively analyzed assuming minimum reactivity feedback consistent with BOC conditions. An MTC of 4.1 pcm/F was assumed. This value bounds the 95 percent MTC (MTC that is more positive than 95 percent of those for a representative cycle).

4. It is conservative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and reduce the severity of the transient.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-303

5. No credit is taken for the operation of the steam dump system or steam generator power-operated relief valves (PORVs). The steam generator pressure rises to the safety valve setpoints, where steam release through the MSSV limits the secondary side steam pressure to the setpoint values.

The MSSV was explicitly modeled in the loss-of-load licensing basis analysis assuming a zero percent tolerance with a 5 psi pop to full open. The MSSV model also assumed a 5 psi pressure drop from the main steam line entrance to the MSSV header in determining the opening setpoints.

6. Automatic pressurizer pressure control is assumed. Therefore, full credit is taken for the effect of the pressurizer spray and PORVs in reducing or limiting the primary coolant pressure. Safety valves are also available and are modeled assuming a zero percent setpoint tolerance.

7. Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip.

Results The transient responses for a total loss of load from full-power operation are shown in Figures 5.1.15.6-1 through 5.1.15.6-7.

The reactor is tripped on the AMSAC/DSS steam generator wide range level trip signal. The PORVs and PSVs are actuated and maintain the primary RCS pressure below 3,200 psig. The peak RCS pressure calculated in the transient is 2,445 psia.

The calculated DNBR for this case is 1.80, which is well above the AMSAC/DSS limit of 1.17.

Conclusions The results of the analysis show that the plant design is such that a total loss of external electrical load without a direct or immediate reactor trip does not result in a violation of the AMSAC/DSS criteria.

Pressure relieving devices that have been incorporated into the plant design are adequate to limit the maximum pressures.

The integrity of the core is maintained by operation of the AMSAC/DSS; that is, the minimum DNBR is maintained above the correlation limit value of 1.17.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-304

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+ __ _

--- __ _ __ __ __ _+ _ __ _+ 4 __ __ +

4 __ __ +_ __ _

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_- III

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a 150 300 Time (seconds)

Figure 5.1.15.6-1 AMSAC/DSS: Loss of External Electrical Load - Nuclear Power versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-305 Cold Leg Temperature Hot Leg Temperature 640

, I I S I I I I I S I I I I I I I I S I

-- I a----i------------------------

-_ _ I _ _Sj ______-- I _----- +__-------------

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560 - -- -------------------------------------------

C.)c)560 + 4 +1 ---------------

I i i i i i ii I I I I I I I I 540 ----------------- --------------------- ----- 4------- ------

I 520-0 150 300 Time (seconds)

Figure 5.1.15.6-2 AMSAC/DSS: Loss of External Electrical Load - Reactor Coolant Loop Temperatures versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-306 2400

__ L

- -_--_-- i - - - - -

--+- +- -- _--

-- _- +- -- -- -- -- +- - - - --_--_--

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, a

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, ,4.,

a a - F - -a_ _ _ _ a_ _ _ _ _ a_ __ _ _a-- _ __ _ _a _

1900 ai a_.aa 1800 0 150 300 Time (seconds)

Figure 5.1.15.6-3 ANISACIDSS: Loss of External Electrical Load - Pressurizer Pressure versus Time K>

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-307 2500

- +------------------ ----------------------- ___

I I

• a . a a

~ ~~

_~~~~ _-._______4 - - - - - - ._______+_______4 a a I * *

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a a 2000 1900 0 150 300 Time (seconds)

Figure 5.1.15.6-4 AMSAC/DSS: Loss of External Electrical Load - RCS Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-308 i-1200

- +

I I . Is I - - I

---

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640

. . IIII

• I IA I II 500 U 300 Time (seconds)

Figure 5.1.15.6-5 AMSAC/DSS: Loss of External Electrical Load - Steam Generator Pressure versus Time KU}

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-309 70

- - - 4I -- - - 4I--- -- -

4I --

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-+ 4 4 4 F------+-------+-------+-------+-------+--_____+_______+_______-

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++ 4 4 B=

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+ + 4 +- --- +--______+____+___

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, + + 4 4

+ + + ,

4+

+ 4 + 4 4 4 0

0 150 jUg Time (seconds)

Figure 5.1.15.6-6 ANMSACIDSS: Loss of External Electrical Load - SG Wide Range Indicated Level versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.do-Oc1 1604

5-310

-- ------------- ++

5-

+ -+ -+ + +

---

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3- ______ +_____ _ +____--+- -------

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---

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_______ + __ ____-_____-_ +-- - -- - -- -- - - - --- -- - - -- -- - -____ -----

2.5 -

_______+ ______+_ __-__-__ ____+_- ------- --- ----- ------- ___

2-1.5 -I 0 150 300 Time (seconds)

Figure 5.1.15.6-7 AMSACIDSS: Loss of External Electrical Load - DNBR versus Time K1-'

Report January 2004 Prairie Island Prairie Licensing Report Island Licensing January 200W 6296-LR-NP.doe-01 160

5-311 5.1.15.7 AMSACIDSS: RCCA Bank Withdrawal at Power Accident Description The uncontrolled RCCA bank withdrawal at power event is defined as the inadvertent addition of reactivity to the core caused by the withdrawal of RCCA banks when the core is above the power defined by the P-10 setpoint. The reactivity insertion resulting from the bank (or banks) withdrawal will cause an increase in the core nuclear power and subsequent increase in the core heat flux. An RCCA bank withdrawal can occur with the reactor subcritical, at HZP, or at power. The AMSAC/DSS uncontrolled RCCA bank at power event is analyzed for Mode 1 (power operation).

The event is simulated by modeling a constant reactivity insertion rate starting at time zero and continuing until the rods are fully withdrawn, based on a withdrawal rate of 72 steps/min. The D-bank of control rods is assumed to be at the nominal full-power position of 218 steps.

For this AMSAC/DSS event, a total reactivity of 100 pcm is assumed to be inserted by the rod withdrawal. This value is intended to bound typical cycle-specific values for the rod worth of D-bank at 218 steps.

No reactor trip is modeled in this analysis.

Method of Analysis The AMSAC/DSS RCCA bank withdrawal at-power transient is analyzed to ensure that the AMSAC/DSS maximum RCS pressure and MDNBR criteria are met.

This event is analyzed with the RETRAN computer program, which is described in Section 5.1.0.9.

The following analysis assumptions are made:

• Initial reactor power, pressure, and RCS temperatures are assumed to be at their nominal values and the minimum measured RCS flow is assumed.

• A -2 pcm/F MTC is assumed at full power. This value is more conservative than a best-estimate MTC. A conservatively small (in absolute magnitude) Doppler power coefficient (DPC) is used in the analysis.

• The transient is initiated with D-bank at 218 steps. A withdrawal rate of 72 steps/min is modeled from 218 steps to the maximum all-rods-out position (228 steps). The total reactivity inserted is 100 pcm.

Results Figures 5.1.15.7-1 through 5.1.15.7-6 show the transient response of nuclear power, core reactivity, pressurizer pressure, RCS pressure, RCS loop temperatures, and DNBR to a RCCA withdrawal incident starting from full power, with no reactor trip.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296-LR-NP.doc-01 1604

5-312 The peak RCS pressure calculated, 2,313 psia, remains below the ATWS limit of 3,200 psig. In addition, the minimum DNBR of 1.29 remains above the AMSAC/DSS limit of 1.17.

Conclusions The AMSACIDSS criteria are met for the RCCA bank withdrawal at-power event in support of the Prairie Island Safety Analysis Transition Program.

Ki Report Licensing Report January 2004 Island Licensing Prairie Island January 2004 6296-LR-NP.doc-01 1604

5-313 1.12

\ + + 4 4 4 4 I \ I I I I I I I I I , . .

1.1 I I . . . .

+ + + + - - +4 a * * .I .

1.08 - - - - - - - - - - - - - - - - - -_4- - - - - - - - - - - - - - --F - -_- +-- -- -

I I a I I I a

I I V I I I I

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II I I I I I 0 I I a Ia a I 1.06 I I I II I I I I I I I I I C1 I I I xI I I I I I I a I I I U-I I I Ia I I I I I I I I I I L. I I I I I I I 1.04 - --

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-a - - - I

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- - - - - - - - A_--

.98 U 130 26i0

'Time (seconds)

Figure 5.1.15.7-1. AMSAC/DSS: Uncontrolled RCCA Bank Withdrawal at Power Nuclear Power versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-314 SE-01 -

_ t * - ------ * ---- - - -- -------_ +---_-_--_--_--_-__-__--_-_--_--_-

-- -4E-01 -.--------- _-

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.+

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5-315 2300 a a a t I S I I a I S + I I I -+-------+-----

l l l l l+l a a a a a a a

+ a a a a a I

+ a a a I I I

+ + + -+- --- + -- 4 2280 + a a a I I I s +o a a a a a I I a ~ SI ~~ I I I

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_ 4 4 __ _ __ 4 _ __ __ 4__ _ __ _ + __ _ + 4_ __ __

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__ _ __ _ _ _ __ _ __ _ +_ _ __ + __ _ _ + _ __ _ __ _ __ _ __ _

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_ _ _ + _

_ _ + 4 _ __ 4__ _ __ _ + 4 _4___

a)

L.

In 2240 0-

_ I I I I I I

_ + 4 + 44 A 222 2200 0 130 260 Time (seconds)

Figure 5.1.15.7-3 AMSAC/DSS Uncontrolled RCCA Bank Withdrawal at Power Pressurizer Pressure versus Time January 2004 6296-LR-NP.doc-01 1604

5-316 2350 _ . . . _

i l l l l l l l l l l l l l

_ _ _ + _

_ _ + 4._+__ __ + ____ +_ 4. __

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4. _ __ _ __ __4.___

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Figure 5.1.15.7-4 AMSACIDSS Uncontrolled RCCA Bank Withdrawal at Power RCS Pressure versus Tmne Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-317 Cold Leg Temperature Hot Leg Temperature 640-I I a I , I I I S I I I I _ _I 620 - ---- -- -- a----

a--- -- ----- + ------- a

-a ' -i a , a --- -- I - --- -- -' -- - --I -- - --I - -- -

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---

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I I I 3 I I

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52

--- ------ --- ------ F---------- ------- _______+_______+_______ 26 Tie(ecns 50 _____+_ 260___+____________+__

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5-3 18 2.2

- - - - -a--- -- - - --

- -I - - -- - - - - -

-- -- -- -- -- - -a---a--- -- -- --

- - --- a - -- - - -a 2 -a-- - -- - -- - -- - - - - -- - -- - -- - -- - -- - -- - -- -

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-- .4 .4 .4 .------ --- --- --- --- --- -

1.6 1.4 1.2 0 260 Time (seconds)

Figure 5.1.15.7-6 AMvSAC/DSS Uncontrolled RCCA Bank Withdrawal at Power DNBR versus r-ue K>

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 11604

5-319 5.1.15.8 AMSAC/DSS: Uncontrolled Boron Dilution Accident Description The uncontrolled boron dilution event is defined as the inadvertent addition of reactivity to the core caused by the addition of unborated water into the RCS. The reactivity insertion resulting from this dilution will cause an increase in the core nuclear power and subsequent increase in the core heat flux.

The AMSAC/DSS uncontrolled boron dilution event is analyzed for Mode 1 (power operation).

The event is simulated by modeling a constant reactivity insertion rate starting at time zero and continuing until operator action terminates the boron dilution at 10 minutes. The AMSAC/DSS does not actuate for this event.

For this event, a total reactivity of 214 pcm is assumed to be inserted by the boron dilution. This value is based on a maximum dilution flow of 60.5 gpm from one charging pump, and a boron worth of

-7 pcm/ppm.

No reactor trip is modeled in this analysis. The event is assumed to be terminated by operator action after 10 minutes.

Method of Analysis The AMSAC/DSS uncontrolled boron dilution event is analyzed to ensure that the AMSACIDSS maximum RCS pressure and MDNBR criteria are met. Since this event is a slow gradual increase in power, RCS overpressurization is unlikely.

This event is analyzed with the RETRAN computer program, which is described in Section 5.1.0.9.

The following analysis assumptions are made:

• Initial reactor power, pressure, and RCS temperatures are assumed to be at their nominal values and the minimum measured RCS flow is assumed.

• A -4.2 pcmP/F MTC is assumed at full power. This value represents a 95 percent MTC (bounds 95 percent of MTCs for a representative cycle). Best-estimate values for the Doppler power and temperature coefficients are used in the analysis.

• A maximum dilution rate of 60.5 gpm from one charging pump is modeled. The fluid conditions are calculated based on a temperature of 125 0 F and a pressure of 2,250 psia.

• A boron worth of-7 pcm/ppm is assumed.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 160>4

5-320 Results Figures 5.1.15.8-1 through 5.1.15.8-6 show the transient response of nuclear power, core reactivity, pressurizer pressure, RCS pressure, RCS loop temperatures, and DNBR to a uncontrolled boron dilution incident starting from full power, with no reactor trip.

The peak RCS pressure, 2,306 psia, remains below the AMSACIDSS limit of 3,200 psig. In addition, the minimum DNBR of 1.18 remains above the AMSAC/DSS limit of 1.17.

Conclusions The AMSAC/IDSS criteria are met for the uncontrolled boron dilution event in support of the Prairie Island Safety Analysis Transition Program.

Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-321 1.03 - _ . .

I I I - I I I

- +4 - - - - - - - - - - - - _,

- 4-- - - -- 4-4-- 4 -- 4-- -- -- - - + --- -

I I/ 1 _ I I I 1.025 -

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-- -- -- - - - - - I- - - -I- - - - - - - - - I- - - - - --

1.02 -

0

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4 4 _ __ 4 __ _ ___4 __ ___ 4 __ ___ 4____ _

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__ _ 4 4 __4 4 4__ __ _ __ __ 4 _ __ __ 4__ _ __ _

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1- __ _ 4 4 4 4 __ _ __4 _

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, 4444444

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.995 _.4..

0 300 600 Time (seconds)

Figure 5.1.15.8-1 AMSAC/DSS: Uncontrolled Boron Dilution Nuclear Power versus Time January 2004 Prairie Island Licensing Report Island Licensing Report January 2004 6296-LR-NP.doc-01 160

5-322

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Figure 5.1.15.8-3 AMSAC/DSS: Uncontrolled Boron Dilution Pressurizer Pressure versus rhne Praiie slanR Liensng por Jan ary200 Prairie Island Licensing Report January 2004 6296-LR-NP.doc-0 1 1604

5-324 2350 a . . . . E . a l l l l l l l a a a a a a a a a a a a a a a a a a a a a 2320 2290 a a a a a a a a a 0 S a a a a a a C.F5 a a a a

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Figure 5.1.15.8-4 AMSACIDSS: Uncontrolled Boron Dilution RCS Pressure versus Time Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-325

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Figure 5.1.15.8-5 AMSAC/DSS: Uncontrolled Boron Dilution RCS Loop Temperatures versus Tnme Prairie Island Licensing Report January 2004 6296-LR-NP.doc-01 1604

5-326 K) 2.2

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Figure 5.1.15.8-6 AMSACIDSS: Uncontrolled Boron Dilution DNBR versus Tine K-Prairie Island Licensing Report January 2004 6296-LR-NP.doc-O1 1604

5-327 5.1.15.9 References 5.1.15-1 Code of Federal Regulations, Title 10, Part 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants."

5.1.15-2 WASH-1270, "Anticipated Transients Without Scram for Water-Cooled Reactors," U.S.

Nuclear Regulatory Commission, September 1973.

5.1.15-3 WCAP-8330, "Westinghouse Anticipated Transients Without Trip Analysis," August, 1974.

5.1.154 NUREG 0460, "Anticipated Transients Without Scram for Light Water Reactors," December 1978.

5.1.15-5 Letter NS-TMA-2182, Letter from T. M. Anderson (Westinghouse) to Dr. S. H. Hanauer (NRC) dated December 30, 1979, "ATWS Submittal."

5.1.15-6 Letter from J. P. Sorensen of Northern States Power Company to the U.S. NRC Document Control Desk, "License Amendment Request Dated February 27, 1998, ATWS Mitigating System Actuating Circuitry/Diverse Scram System," February 27, 1998.

January 2004 Prairie Licensing Report Island Licensing Prairie Island Report January 2004 6296- RNP.doc-01 1604