ML20083N266
| ML20083N266 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 01/07/1983 |
| From: | Cooke G, Nutt W, Stout R SIEMENS POWER CORP. (FORMERLY SIEMENS NUCLEAR POWER |
| To: | |
| Shared Package | |
| ML17213B024 | List: |
| References | |
| XN-NF-82-99, NUDOCS 8302010605 | |
| Download: ML20083N266 (166) | |
Text
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XN NF 82 99 PLANT TRANSIENT ANALYSIS FOR ST. LUCIE UNIT 1 l
JANUARY 1983 RICHLAND, WA 99352 ERON NUCLEAR COMPANY,Inc.
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XN-NF-82-99 Issue Date: 1/7/83 PLANT TRANSIENT ANALYSIS FOR ST. LUCIE UNIT 1 Prepared by: ////[hw)7
'W.~ T.' Nutt '/ ~
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Plant Transient / Analysis Concur: de, f/, /g3 G. C' Cooke, Manager Plant Transient Analysis Concur: A h Manager, Reload Fuel I/ censing
/ [7, F,il-Tn L Approve:
7 7 A4 f3 F.. 'B. Stout, Manager Licensing & Safety Engineering Approve:
G. A. Sofer, Manager b
Fuel Engineering & Technical Services mb ERON NUCLEAR COMPANY,Inc.
i
NUCLEAR REGULATORY COMMISSION DISCLAIMER IMPORTANT NOTICE REGARTC* aONTENTS AND USE OF THIS DOCUMENT PLE ASE READ CAREFULLY This technical report was rferived through research and development programs sponsored by Exxon Nuclear Company, Inc. it is being sub-mitted by Exxon Nuclear to the USNRC as part of a technical contri-bution to facilitate safety analyses by heensees of the USNRC which utilize Exxon Nuclear fabricated reloarl fuel or other technical services provMed by Exxon Nuclear for liaht water power reactors and it is true and correct to the best of Exxon Nuclear's knowledge, information, 7
and belief. The information contained herein may be used by the USNRC in its review of this report, and by licensees or applicants before the USNRC which are customers of Exxon Nuclear in their demonstration of comoliance with the USN RC's regulatiors.
Without derogating from the foregoing, neither Exxon Nuclear mr any person acting nn its behalf:
A. Makes any warranty, apress or implied, wi*h respect to the accuracy, completeness, or ut.,ulness of the infor-motion contained in this document, or that the use of any information, apparatus, ri.athod, or process disclosed in this document will not infringe privately owned rights; or B. Assumes any liabilities with respect to the u:e of, or for darrages resulting from the use of, any information, ap-paratus, method, or process disclosed in this document.
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i XN- NF- F00,766
1 i XN-NF-82-99 TABLE OF CONTENTS SECTION PAGE-
1.0 INTRODUCTION
AND
SUMMARY
....................................... 1 2.0 CALCULATIONAL METHODS AND INPUT PARAMETERS ..................... 5 2.1' CODE DESCRIPTION .......................................... 5 2.2 MODELING UNCERTAINTIES .................................... 7 2.3 DESIGN PAF.AMLif.P.S ......................................... 8 3.0 TRANSIENT ANALYSIS............................................. 23 3.1 ANTICIPATED OPERATIONAL OCCURRENCES REQUIRING ONLY RPS ACTION ................................ 24 3.2 ANTICIPATED OPERATIONAL OCCURRENCES REQUIRING RPS ACTION AND/0R OBSERVANCE OF THE LCOs .............................................. 26 3.3 POSTULATED ACCIDENTS ...................................... 29 3.4 B0UNDING MODERATOR TEMPERATURE ANALYSIS .................. 33 4.0 DISCUSSION .................................................... 152
5.0 REFERENCES
................................................... 155 I
11 XN-NF-82-99 LIST OF TABLES PAGE TABLE 1.1 Fuel and Vessel Design Limits ...................... 3 4
1.2 Summary of Results ................................
2.1 St. Lucie Unit 1 Trip Functions .................... 10 2.2 St. Lucie Unit 1 Operating Parameters 11 Used in PTSPWR2 Analysis ...........................
2.3 ENC Fuel Design Parameters for St. Lucie Unit 1, Cycle 6 .......................... 12 2.4 Neutronics Parameters for St. Lucie Unit 1, Cycle 6 ............................................ 13 3.1 Transient Events ................................... 34 3.2 Kinetics Parameters for the Loss-of-load Event ..... 35 3.3 Event Table for a Loss-of-load ..................... 36 3.4 Kinetics Parameters for the Evress Load Event ...... 37 3.5 Event Table f or an Excess Load . . . . . . . . . . . . . . . . . . . . . 38 3.6 Kinetics Parameters for the RCS Depressurization Event ............................. 39 Event Table for RCS Depressurization . . . . . . . . . . . . . . . 40 3.7 3.8 Kinetics Parameters for the Loss-of-Coolant Flow Event ......................................... 41 Event Table for a Loss-of-Coolant flow . . . . . . . . . . . . . 42 3.9 3.10 Kinetics Parameters for the CEA Withdrawal Event .............................................. 43 44 3.11 Event Table for CE A Withdrawal . . . . . . . . . . . . . . . . . . . . .
Kinetics Parameters for the CEA-Drop Event ......... 45 3.12
iii ' XN-NF-82-99 LIST OF TABLES (Cont.)
PAGE TABLE 3.13 Event Table for CEA Drop ........................... 46 l
l 3.14 Kinetics Parameters for the Seized-Rotor Event ................................. 47 3.15 Event Table for Seized Rotor (DNB) ................. 48 3.16 Event Table for Seized Rotor (Pressure) ............ 49 3.1/ Event Table for Steam Line Break ................... 50 i
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iv XN-NF-82-99 LIST OF FIGURES FIGURE PAGE 2.1 PTSPWR2 System Model ....................................... 14 2.2 St. Lucie Unit 1 - LSSS Based on LPD ....................... 15 2.3 St. Lucie Unit 1 - TM/LP Correction Function Al ............. 16 2.4 St. Lucie Unit.1 - TM/LP Correction Function QR1 ............ 17 2.5' DNB Limiting Condition of Operation for 18 St. Lucie Unit 1 ......................................... .
2.6 Scram Curves for St. Lucie Uni t 1 - Cycle 6 . . . . . . . . . . . . . . . . . 19 2.7 St. Lucie Unit 1 - Cycle 6 - DNB Limiting Top Peaked Core (ASI = -0.18) ............................... 20 2.8 St. Lucie Unit 1 - Cycle 6 - DNB Limiting Mid-Peaked Core (ASI = 0) ................................... 21 2.9 St. Lucie Unit 1 - Cycle 6 - DNB Limiting Bottom-Peaked Core (ASI = 0.14) ............................. 22 3.1 St. Lucie Unit 1 - Power, Heat Flux and Flow ................ 51 3.2 St. Lucie Unit 1 - S.G. Flows - Loss of Electric Load ....... 52 3.3 St. Lucie Unit 1 - Fuel Temperature Loss of Electric Load ....................................... 53 3.4 St. Lucie Unit 1 - Core Temperature Loss of Electric Load ....................................... 54 3.5 St. Lucie Unit 1 - Loop Temperature Differences Loss of Electric Load ....................................... 55 3.6 St. Lucie Unit 1 - Average Temperatures Loss of Electric Load ....................................... 56 3.7 St. Lucie Unit 1 - Cold Leg Flows Loss of Electric Load ....................................... 57 3.8 St. Lucie Unit 1 - Pressures - Loss of Electric Load ........ 58 3.9 St. Lucie Unit 1 - Water Levels - Loss of Electric Load...... 59 d
v - ,
v XN-NF-82-99 3.10 St. Lucie Unit 1 - DNBR - Loss of Electric Load . . . . . . . . . . . . 60 3.11 St. Lucie Unit 1 - Reactivity - Loss of Electric Load .. .... 61 3.12 St. Lucie Unit 1 - Power, Heat Flux and Flow Loss of Electric Load ...................................... 62 3.13 St. Lucie Unit 1 - S.G. Flows -
Loss of Electric Load ...................................... 63 3.14 St. Lucie Unit 1 - Fuel Temperature - Excess Load .......... 64 )
l 3.15 St. Lucie Unit 1 - Loss of Coolant Flow Excess Load ................................................ 65 3.16 St. Lucie Unit 1 - Loop Temperature Differences Excess Load ................................................ 66 3.17 St. Lucie Unit 1 - Average Temperatures Excess Lead . ............ ................................. 67 l l
3.18 St. Lucie Unit 1 - Cold Leg Flows Excess Load ................................................ 68 3.19 St. Lucie Unit 1 - Pressures - Excess Load ................. 69 3.20 St. Lucie Unit 1 - Water Levels - Excess Load .............. 70 1
3.21 St. Lucie Unit 1 - DNBR - Excess Load ...................... 71 I
1 i
3.22 St. Lucie Unit 1 - Reactivity - Excess Load ................ 72 '
3.23 St. Lucie Unit 1 - Power, Heat Flux and Flow RCS Depressurization ....... ............................... 73 3.24 St. Lucie Unit 1 - S.G. Flows - RCS Depressurization . .. .... 74 l 1
3.25 St. Lucie Unit 1 - Fuel Temperature -
RCS Depressurization ....................................... 75 3.26 St. Lucie Unit 1 - Core Temperatures RCS Depressurization ....................................... 76 l 3.27 St. Lucie Unit 1 - Loop Temperature Differences RCS Depressurization ....................................... 77 l 3.28 St. Lucie Unit 1 - Average Temperatures l
RCS Depressurization ............ .......................... 78 3.29 St. Lucie Unit 1 - Cold Leg Flows RCS Depressurization ....................................... 79 3.30 St. Lucie Unit 1 - Pressures RCS Depressurization ....................................... 80
vi XN-NF-82-99 3.31 St. Lucie Unit 1 - Water Levels R C S De p r e s s u r i z a t i o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 3.32 St. Lucie Unit 1 - DNBR - RCS Depressurization ............. 82 3.33 St. Lucie Unit 1 - Reactivity - RCS Depressurization ....... 83 3.34 St. Lucie Unit 1 - Power, Heat Flux and Flow Loss of Coolant Flow ............ ........ . ............... 84 3.35 St. Lucie Unit 1 - S.G. Flov!s - Loss of Coolant Flow . .. .. .. 85 3.36 St. Lucie Unit 1 - Fuel Temperature Loss of Coolant Flow ....................................... 86 3.37 St. Lucie Unit 1 - Core Temperatures Loss of Coolant Flow .................................... .. 87 3.38 St. Lucie Unit 1 - Loop Temperature Differences Lo s s o f Co o l an t F l ow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 3.39 St. Lucie Unit 1 - Average Temperatres Loss of Coolant Flow ....................................... 89
~
3.40 St. Lucie Unit 1 - Cold Leg Flows Loss of Coolant Flow ....................................... 90 3.41 St. Lucie Unit 1 - Pressures - Loss of Coolant Flow .........~91 3.42 St. Lucie Unit 1 - Water Levels Loss of Coolant Flow ............................... ...... 92 3.43 St. Lucie Unit 1 DNBR - Loss of Coolant Flow .............. 93 3.44 St. Lucie Unit 1 - Reactivity - Loss of Coolant Flow ....... 94 3.45 St. Lucie Unit 1 - Power, Heat Flux and Flow CEA Withdrawal ........ .................................... 95 3.46 St. Lucie Unit 1 - S.G. Flows - CEA Withdrawal ........... . 96 3.47 St. Lucie Unit 1 - Fuel Temperature C E A Wi t hd r awa l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 3.48 St. Lucie Unit 1 - Core Temperatures - CEA Withdrawal....... 98 3.49 St. Lucie Unit 1 - Loop Temperature Differences C E A W i t h d r aw a l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 3.50 St. Lucie Unit 1 - Average Temperatures CEA Withdrawal . ............ .... ....... ................. 100
vii XN-NF-82-99 3.51 St. Lucie Unit 1 - Cold Leg Flows - CEA Withdrawal. 101 3.52 St. Lucie Unit 1 - Pressures - CEA Withdrawal............... 102 3.53 St. Lucie Unit 1 - Water Levels - CEA Withdrawal ........... 103 3.54 St. Lucie Unit 1 - DNBR - CEA Withdrawal ................... 104 3.55 St. Lucie Unit 1 - Reactivity - CEA Withdrawal ............. 105 3.56 St. Lucie Unit 1 - Power, Heat Flux and Flow i CEA Drop ................................................... 106 3.57 St. Lucie Unit 1 - S.G. Flows - CEA Drop . . . . . . . . . . . . . . . . . . 10 7 3.58 St. Lucie Unit 1 - Fuel Temperature - CEA Drop . . . . . . . . . . . . . 108 3.59 lt. Lucie Unit 1 - Core Tempera ures - CEA Drop ............ 109 3.60 St. Lucie Unit 1 - Loop Temperature Differences CEA Drop ................................................... 110 3.61 St. Lucie Unit 1 - Average Temperatures CEA Drop ................................................... 111 3.62 St. Lucie Unit 1 - Cold Leg Flows - CEA Drop ............... 112
. 3.63 St. Lucie Unit 1 - Pressures - CEA Drop .................... 113 3.64 St. Lucie Unit 1 - Water Levels - CEA Drop ................. 114 3.65 St. Luci e Uni t 1 - DNBR - CEA Drop . . . . . . . . . . . . . . . . . . . . . . . . . 115 3.66 St. Lucie Unit 1 - Reactivity - CEA Drop ................... 116 3.67 St. Lucie Unit 1 - Power, Heat Flux and Flow -
- - - - - - - - - - - 117 Sei zed Rotor (DNB-) -
3.68 St. Lucie Unit 1 - 5.G. Flows - Seized Rotor (DNB) ... ..... 118 3.69 St. Lucie Unit 1 - Fuel Temperature - Seized Rotor (DNB) .... lig 3.70 St. Lucie Unit 1 - Core Temperatures Seized Rotor (DNB) ........................... ............. 120 3.71 St. Lucie Unit 1 - Loop Temperature Differences Se i zed R ot or ( DN B ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121 3.72 St. Lucie Unit 1 - Average Temperatures Se i z ed R ot or ( DNB ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 2
viii XN-NF-82-99 3.73 St. Lucie Unit 1 - Cold Leg Flows -
Seized Rotor (DNB) .......................................... 123 3.74 St. Lucie Unit 1 - Pressures - Seized Rotor (DNB) ...........
124 3.75 St. Lucie Unit 1 - Water Levels Seized Rotor (DNB) .......................................... 125 3.76 St. Lucie Unit 1 - DNBR - Seized Rotor (DNB) ................ 126 3.77 St. Lucie Unit 1 - Reactivity Seized Rotor (DNB) .......................................... 127 3.78 St. Lucie Unit 1 - Power, Heat Flux and Flow Seized Rotor (Pressure) ..................................... 128 3.79 St. Lucie Unit 1 - S.G. Flows - Seized Rotor (Pressure) ..... 129 3.80 St. Lucie Unit 1 - Fuel Temperature Seized Rotor (Pressure) ..................................... 130 3.81 St. Lucie Unit 1 - Core Temperatures 131 Seized Rotor (Pressure) .....................................
3.82 St. Lucie Unit 1 - Loop Temperature Differences 132 Seized Rotor (Pressure) .....................................
3.83 St. Lucie Unit 1 - Average Temperatures 133 Seized Rotor (Pressure) .....................................
3.84 St. Lucie Unit 1 - Cold Leg Flows Seized Rotor (Pressure) ..................................... 134 3.85 St. Lucie Unit 1 - Pressures Seized Rotor (Pressure) ..................................... 135 3.86 St. Lucie Unit 1 - Water Levels -
Seized Rotor (Pressure) .......,.............................. 136 3.87 St. Lucie Unit 1 - DNBR 137 Seized Rotor (Pressure) .....................................
3.88 St. Lucie Unit 1 - Reactivity 138 Seized Rotor (Pressure) .....................................
3.89 RCS Pressure versus HPSI Flow for One Pump .................. 139 3.90 Moderator Temperature Feedback for Steamline Break Analysis .................................... 140 3.91 Doppler Feedback for Power Operation 141 during a Steamline Break ....................................
ix XN-NF-82-99 3.92 St. Lucie Unit 1 - Power, Heat Flux and Flow Steam Line Rupture .......................................... 142 3.93 St. Lucie Unit 1 - S.G. Flows - Steam Line Rupture .......... 143 3.94 St. Lucie Unit 1 - Fuel Temperature Steam Line Rupture ........... .............................. 144 3.95 St. Lucie Unit 1 - Core Temperatures Steam Line Rupture .......................................... 145 3.96 St. Lucie Unit 1 - Loop Temperature Differences Steam Line Rupture .......................................... 146 3.97 St. Lucie Unit 1 - Average Temperatures Steam Line Rupture .......................................... 147 3.98 St. Lucie Unit 1 - Cold Leg Flows i
Steam Line Rupture .......................................... 148 l
l 3.99 St. Lucie Unit 1 - Pressures - Steam Line Rupture . . . . .. . . . . . 149 3.100 St. Lucie Unit 1 - Water Levels Steam Line Rupture .......................................... 150 3.101 St. Lucie Unit 1 - Reactivity Steam Line Rupture .......................................... 151 i
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1 XN-NF-82-99
1.0 INTRODUCTION
AND
SUMMARY
The plant transient analysis reported here was performed to support operation of the St. Lucie Unit 1 nuclear power plant with a mixed core of 84 Exxon Nuclear Company (ENC) assemblies (XN-1) and 133 Combustion Engineering (CE) assemblies.
Because of the higher grid spacer loss associated with the ENC fuel compared to the resident CE fuel, ENC suffers a flow diversion penaety. Since Cycle 6 is the first cycle in which ENC fuel will be loadsd, Cycle 6 will have a lower ratio of ENC to CE fuel assemblies than future cycles, and therefore a larger penalty. Succeeding cycles will experience decreasing penalties until all the fuel in the core is ENC fuel, at which point there will be no flow penalty and the thermal margin for ENC fuel will be significantly improved.
For th s reason, it is anticipated that the Cycle 6 core will be more thermal-hydraulically limiting than future cycles, and thus the present analysis will .
be bounding of for Cycle 7 and subsequent cycles at St. Lucie Unit 1. Cycle-specific safety analyses will be performed to confirm this expectation. The criteria used in the analysis are based on protecting the specified acceptable fuel design limits (SAFDLs), listed in Table 1.1, for anticipated operational occurrences (A00s); and on demonstrating an acceptably low level of fuel damage in the event of a postulated accident (PA).
The purpose of this analysis is to examine core thermal margins for Cicle 6 in St. Lucie Unit 1. Based on thermal-hydraulic considerations alone, NC fuel assemblies in Cycle 6 will be somewhat more thermal-margin limiting than either co-resident CE fuel in Cycle 6 or CE fuel in the all-CE core of '
Cycle 5. Thus verification of adequate thermal margin in Cycle 6 has been a necessity. Because of the importance of the pressure criterion, peak
2 XN-NF-82-99 pressurization transients are addressed, although ENC reload fuel is not expected to significantly impact system pressure response.
The key results of the analysis are summarized in Table 1.2 and confirm that the criteria are met. The lowest value of MDNBR for any A00 is 1.326 for the loss-of-flow event. This va?ue is well above the 95/95 limit for ENC's XNB critical heat flux correlation (l).
Thermal margin results for the locked rotor accident are such that less than 1.0% of the fuel in the core would be expected to experience DNB. A significant return to power did not occur in the analysis for the large steam line break accident using a 3.6% Ao shutdown margin.
The transient events reanalyzed for this cycle are the most limiting events arid comprise an adequate set of simulations to assure safe operation of St. Lucie Unit 1. The events considered for the operation of St. Lucie Unit 1
1 at 2700 MWt are discussed in Section 4.0 and the events analyzed in this report are shown to bound the set discussed in the stretch power submittal (2),
The reactor protection system (RPS) setpoints for Cycle 6 were not changed so the setpoir.ts considered by ENC are the same setpoints taken into account by CE. To ensure conservatism, MDNBRs were calculated using the most limiting axial shapes from the set of 1374 different axial shapes analyzed by ENC.
The analysis of the limiting transients is described in Section 3. The present simulation shows substantially the same plant response to the transients with major differences related to the limiting assembly thermal-hydraulic performance. A description of the transier.t calculational methods and the input parameters is provided in Section 2.
Analysis of the limiting transients has shown that there exists a safe margin to the SAFDLs during A00s and that fuel damage is less than 1% for the pas. The thermal margin for the Cycle 6 reload is sufficient.
1
! 3 XN-NF-82-99 Table 1.1 Fuel end Vessel Design Limits !
Event Class Criteria i
i i
1 Anticipated Operational .- Specified acceptable fuel Occurrences (A00s) designlimits(SAFDLs)-
. MONBR, based on XNB, >l.17 ;
i j . Local power density 21 kW/ft
. Pressure < 2750 psia i '
Postulated Accident (PA) . Fuel damage is limited to a small fraction of the fuel in the core
. Pressure < 2750 psia .
I i
1
)
I i
1
.,.,,.- ~ _ . . - ~ . , - _ . - - .
Table 1.2 Sur. aery of Results Maximum Maximum Core Power Level Average Heat Maximum System MON 8R 2 P_ressure (psia)
Transient (MWt) Flux (BTU /hr-ft ) _ (XNB)
Loss of Load 3446.5 210544 2657 2.035*
Excess Load 3482.7 200512 2250 1.385 RCS Depressurization 40.5 5829 2250 1.389 Loss of Coolant Flow 2735 189766 2401 1.326 CEA Withdrawal 3131.8 199908 2363 1.590 u
CEA drop 2708.5 190301 2250 1.485 Seized Rotor (DNB) i 2757.3 189766 2338 1.189 (Pressure) 2822.2 199753 2397 1.450 Steam Line Rupture i 37.2 9682 2250 >4.5 Steady State Operation 2700 189759 2250 1.72 0
__________________ g ,
- Transient conditions which produce the highest average RCS temperatures for f loss-of-load events were used. g a
t Postulated Accidents
5 XN-NF-82-99 2.0 CALCULATIONAL METHODS AND INPUT PARAMETERS 2.1 CODE DESCRIPTION The transient analysis for St. Lucie Unit I was performed using PTSPWR2(3) the Exxon Nuclear Company plant transient simulation model for pressurized water reactors. The simulation code models the behavior of pressurized water reactors under both normal and abnormal conditions by solving the transient conservation equations for the primary and secondary systems numerically. Core neutronics behavior is modeled using point kinetics, and the transient conduction equation is solved for fuel tempera-tures and heat fluxes. State variables such as flow, pressure, temperature, mass inventory, steam quality, heat flux, reactor power and reactivity are calculated during the transient. Where appropriate the reactor protection system (RPS) ar.d control system are modeled to describe the transients. The departure from nucleate boiling ratio (DNBR) is calculated for the hot channel doring the transients using a hot channel model and the XND(1) correlation.
The system model used by PTSPWR2, shown in Figure 2.1, models the reactor, both primary coolant loops, both steam generators and both steam lines. All major components (pressurizer, coolant pumps, and all major valves) are also modeled.
The present calculations were performed using the NOV76A version of the PTSPWR2 code, along with appropriate updates. These updates include:
(1) An improved pressurizer model, described in Reference 4.
(2) A correction to the mass balance on the secondary side of the steam generator.
(3) A modified set of trip functions to describe a Combustion Engineer-ing plant.
6 XN-NF-87-99 (4) Axial shape-dependent scram curves.
(5) A dynamic flow coastdown model; and (6) Appropriate char.ges to the primary loop, hydraulic behavior to describe the 2 hot leg - 4 cold leg configuration of St. Lucie Unit 1.
Updates 1 and 2 have been included in recent ENC transient analyses. Updates 3-6 were prepared specifically for this analysis.
The trip functions used in this analysis consist of calculated trips set in conjunction with the limiting conditions of operation (LCOs) which protect the specified acceptable fuel design limits (SAFDLs) based on local power density (LPD) and departure from nucleate boiling (DNB) and trips based on single state variables. These latter trip setpoints are listed in Table 2.1 aong with the trip time delay appropriate for all of the RPS trips.
The reactor trip setpoints for Cycle 6 at St. Lucie Unit 1 are unchanged from Cycle 5.
The calculated trips for St. Lucie Unit 1 consist of an LPD trip and a Thermal Margin / Low Pressure (TM/LP) trip. The LPD trip protects against a power excursion exceeding the local power density limit of 21 kW/ft. The trip.
trip is based on core power, Q, defined as the larger of the neutron flux power and the thermal power and on the peripheral axial shape index (ASI); which is defined as, ASI =
Pt ow - PUP , (2.1)
PLOW + PUP where PLOW and PUP are the output from the bottom and top ex-core flux sensors, respectively. Figure 2.2 shows the trip function.
The TM/LP trip is based on the same auctioneered core power as the LPD trip. In addition, it also depends upon the ASI, and the inlet temperature
7 XN-NF-82-99 TIN.
The form of the trip function is, PVAR = 2061 A1 (ASI) QR1 (Q) + 15.85 TIN - 8950, (2.2) where Al and QR1 are shown in Figures 2.3 and 2.4, respectively. Pressurizer pressure is the system variable which is compared to the trip setpcint, PVAR-The TM/LP trip protects the core from the onset of DNB with at least a 95%
probability as long as the plant is operated within the appropriate limiting conditwns of operation (LCO) shown in Figure 2.5.
A set of ASI-dependent scram curves, shown in Figure 2.6, provides a conservative scram curve for each ASI.
Two basic kinds of axial power distributions were considered in the analysis. For transients and accidents where thermal margin (DNB) is the limiting f actor, top peaked axial power distributions were limiting. For peak pressurization transients, bottom peaked power distributions with dela);j scram were limiting. For each of these cases, the scram curve was interpolated from the curves given in Figure 2.6.
The pump response to a loss of power was modeled by setting the shaft rotation speed derivative equal to the pumping torque, divided by the effective inertia. The flow in each of the four cold legs was calculated based on the pump head and the required pressure drop. The effective inertia was then adjusted to provide a good fit to plant data (4).
2.2 MODELING UNCERTAINTIES The present plant transient analysis is basically a deterministic analysis. Thus, steady state measurement and instrumentation errors were taken into account in an additive fashion to ensure conservative calculations of MDNBR. The plant uncertainties related to initial conditions in the MDNBR
8 XN-NF-82-99 calculations are:
Power + 2% for calorimetric error Inlet coolant temperature + 20F.for deadband and measurement error RCS pressure - 22 psi for steady-state measurement errors.
Combined with design flow, these parameter uncertainties minimize the initial minimum DNBR. These uncertainties are not included in the plant system modeling explicitly, rather they are used to establish a conservative bound to the initial minimum DNBR. Table 2.2 is a list of operating parameters used in this analysis.
The trip setpoints are based on Technical Specification Limits (5) and are unchanged from Cycle 5. Statistical verification of the calculated trips (LPD and TM/LP) is presented in the Safety Analysis Report (SAR)(8). These trip setpoints are modeled conservatively in the transient analysis to provide bounding simulations of the plant response.
The pressurizer control system was modeled in such a f ashion that it could not ameliorate the effects of transients. The spray system was operable during DNBR transients while the heaters were off, thus tending to minimize DNBR. For pressurization transients, e.g. loss-of-electric load, the spray system and pressurizer relief valves were removed from the simulation.
Additional conservatisms in the pressurization transient include the conservative modeling of the high pressure trip (2422 psia), higher initial power (102%), a conservative choice of kinetics parameters, and a bottom-peaked core to delay termination of the transient as long as possible.
2.3 DESIGN PARAMETERS The ENC fuel design parameters for St. Lucie Unit 1 are summarized in Table 2.3. Table 2.4 lists the neutronics parameters, both nominal and
9 XN-NF-82-99 bounding values for beginning of cycle (80C) and end of cycle (E0C) conditions. The values used in the analysis for the moderator temperature coefficient and shutdown margin are consistent with the new Cycle 6 Technical Specification limits for these parameters. Three axial power distributions, which were found to give minimum steady-state ONBRs, were used along with the radial peaking factor appropriate for each. The radial peaking factors used correspond in each case to the Technical Specification Limit of 1.7 allowing for a 7% uncertainty. The three DNB limiting axial profiles are shown in Figures 2.7 through 2.9. The axial profiles shown in Figures 2.7 through 2.9 are specifically for the hot rod. The quoted AS! is the peripheral ASI and contains the effects of rod shadowing and shape annealing. The ASI one would calculate based on the axia.1 shape would, therefore, not agree with the quoted ASI. However, the local hot rod power is preserved over the entire length of the core.
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Table 2.1 St. Lucie Unit 1 Trip Functions Allowable Values Values Used in tra Analysis Function Setpoint Delay
- Setpoint Delay *
(seconds)
(seconds) )
112 0.9 Variable High Ponor Trip (% of rated) 107 0,9 95 1.15 93 1.15 l
Low Flow Trip (% of design) 2400 1.4 2422 1.4 5 High Pressurizer Pressure (psia)
Low Steam Generator Pressure (psia) 600 1.4 578 1.4 Low Steam Generator Water Level 1.4 31.5 1.4
(% of span) 37
- 0.9 - 0.9 LPD (described in text)
- 1.4 - 1.4 ,
TM/LP (described in text) !
Steam Generator Pressure Difference 185 1.4 (psi) 135 1.4 l E
________________________________________ 4 T l
- includes a 0.5 second allowance for the holding coils to release $
b i
'- ..- - - - - i..-
.m m -
11 XN-NF-82-99 Table 2.2 St. Lucie Unit 1 Operating Parameters used in PTSPWR2 Analysis CORE Total Heat Output (MWt) 2700 Heat generated in fuel (%) 97.5 Coolant Flow Rate (Mlb/hr) 134.8 Unrodded Pin Radial Peaking Factor 1.70 Average Heat Flux (BTV/hr-ft2 ) 189759 REACTOR COOLANT SYSTEM Coolant Flow Rate (Mlb/hr) 139.4 Pressure (psia) 2250 Average Temperature (OF) 572 STEAM GENERATORS Feedwater Enthalpy (Btu /lb) 410.4 Pressure (psia) 860.1 Steam Flow (Mlb/hr) @ 2700 MWt 11.72-
12 XN-NF-82-99 Table 2.3 ENC Fuel Design Parameters for St. Lucie Unit 1, Cycle 6 l
Fuel Pellet Diameter (in) 0.370 Outer Clad Diameter (in) 0.440 Inner Clad Diameter (in) 0.378 Active Fuel Length (in) 136.7 Number of Fuel Rods in the Cere 37,008 i
Table 2.4 Neutronics Parameters for St. Lucie Unit 1, Cycle 6 Bounding Values Cycle 6 Nominal Value E0C BOC E0C 80C Parameter Moderator Temperature Coefficient 0.7 -2.8 0.48 -1.44 (ap/oF x 104 ) HZP 0.2 -2.8 -0.13 -2.07 HFP Doppler Temperature Coefficient
-2.0 -1.2 -2.07 (ApfoF x 105 ) HFP -1.0
-- -1.6 -1.9 HZP Pressure Coefficient
-1.4 5.0 -1.0 4.3 (Ap/ psi x 106 )
Boron Worth Coefficient
-0.8 -0.9 -0.88 -1.07 (op/ ppm x 104 )
0.0045 0.0058 0.0050 Delayed Neutron Fraction (Beta) 0.0071
-0.05078 -0.05671 -0.0649 -0.0/12 Total Rod Worth
-- 0.0355 -- 0.036 Shutdown Margin h
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23 XN-NF-82-99 3.0 TRANSIENT ANALYSIS The transients analyzed for St. Lucie Unit 1 are categorized as either Anticipated Operation.0ccurrences (A00s) or Postulated Accidents (pas). The A00s are further categorized as either requiriag only the action of the reactor protection system (RPS) to meet the Specified Acceptable Fuel Design Limits (SAFDLs) or those requiring RPS action and/or observance of the Limiting Conditions of Operation (LCO).
Table 3.1 lists the transient events censidered and summarizes the disposition of each transient. The Boron dilution event is not analyzed since as a reactivity insertion transient at power, it is bounded by the CEA withdrawal transient. For shutdown modes, there is sufficient shutdown margin to meet applicable operator action time criteria for the boron dilution event. Other transients not re-analyzed include the loss-of-feedwater and excess feedwater flow transients produr.ing heatup and cooldown rates which are less severe than those produced by the loss-of-load and the excess load transients, respectively. Further, the loss-of-A.C.-power event was not considered since it is bounded by the loss-of coolant-flow transient with respect to thermal margin. Asymmetric steam generator events test the effectiveness of the asymmetric steam generator protective trip (ASGPT) in providing a scram signal sufficiently in advance of the time that mismatched cold leg temperatures would reach the core ther1by assuring that highly tilted core power distributions do not occur. Ample margin was demonstrated for -
prior cycles (2) and ENC fuel will not affect the operation of the ASGPT. Hence asymmetric steam generator transients, other than the steam line rupture, have not been re-analyzed. The steam tube rupture is unchanged since the
l 24 XN-NF-82-99 TM/LP trip still protects against fuel damage (8), thus removing any fuel dependence in this transient.
3.1 ANTICIPATED OPERATIONAL OCCURRENCES REQUIRING ONLY RPS ACTION The transients analyzed which f all into this category are: the loss-of-load transient, the excess load transient and the RCS-depres-surization transient.
3.1.1 LOSS OF LOAD EVENT This event was analyzed to simulate plant performance upon a turbine trip without a direct reactor trip. The abrupt loss-of-heat sink results in a rapid rise in the reactor coolant system (RCS) temperature and an expansion of the coolant which produces an insurge of water into the pressurizer and, ultimately, an increase in pressurizer pressure. The criterion employed is that the peak transient pressure must not exceed the ASME code limit of 110% of design pressure (i.e. 2750 psia). The SAFDLs were not approached in this transient siMe power was appreciably less than that required to reach 21 kW/ft and MDNBR occurred at steady state operation at the start of the event. The transient was initiated from 102% power with bounding E0C conditions and the bottom-peaked core shown in Figure 2.9. The pressurizer spray was turned off and the effects of the relief valves were also ignored in order to produce as high a pressure as possible during the simulated transient. The steam dump and bypass were also removed from the model for the same reason. The kinetics parameters used in this analysis are listed in Table 3.2.
Figures 3.1 to 3.11 show the simulated plant response for this event. A higL pressure trip occurred at 4.45 seconds and the peak pressure reached was 2657 peia. The pressure was limited by the operation of the safety valve (See Figure 3.8). The MDNBR, Figure 3.10, did not f all be?ow j
25 XN-NF-82-99 the initial value and the primary teraperature increased by 15.50F. Table 3.3 sumarizes the events during the transient.
3.1.2 Excess Load Event Inadvertent opening of the turbine control valve, steam dump valves and/or the steam bypass valve would result in increased steam flow and increased heat extraction. The resultant cooldown of the RCS would produce a positive reactivity insertion at E0C conditions when a large, negative moderator feedback coefficient exists. Protection against core damage is provided by the variable high power trip (VHPT), the low steam generator pressure trip, and the TM/LP trip.
The mid-plane-peaked axial power shape used in this analysis is shown in Figure 2.8. This particular shape has an ASI of zero and prevents tne local power density (LPD) trip from occurring during the event. A top-peaked axial power shape, such as shown in Figure 2.7, would have provided a lower initial MDNBR, but would have led to a rapid LPD trip, mitigating the transient effects. The pressurizer heaters are assumed to be inoperable to provide a conservative MDNBR calculation. s ne kinetics parameters used in the i
simulation are listed in Table 3.4.
The liriting excess-load transient is the simultaneous opening of steam dump and bypass valves. The plant response to this event was simulated by rapidly ramping steam flow to 143.4% of rated flow. Figures 3.12 l to 3.22 show the simulated plant response. The reactor tripped on the VHPT at 7.42 seconds and the peak power, Figure 3.12, reached 129%. The MDNBR, Figure 3.21, fell to 1.385 at 7.5 seconds. The reactor scram would have occurred much sooner were it not for the 12 second time delay associated with the cold leg RTDs. The IM/LP trip is also nearly simultaneous with the VHP trip. The event sequence is given in Table 3.5.
26 XN-NF-82-99 3.1.3 RCS Depressurization Event The RCS depressurization event was used in assessing the bias term in the TM/LP trip (2). Trip processing delays and measurement uncer-tainties were used to establish the value of that bias.
The event simulated was a failure of both pressurizer relief valves fully open. The kinetics parameters listed in Table 3.6 are bounding B0C values and were used in the simulation. The pressurizer heater capacity was set to zero to allow a more rapid depressurization, and a top-peaked core power distribution, as shown in Figure 2.7, was used to minimize initial MDNBR.
Upon the f ailure of the relief valve, the RCS pressure fell rapidly, as shown in Figure 3.30, and a reactor trip on the LPD functicn occurred at 10.9 seconds. The MDNBR was 1.389 at 10.9 seconds. Figures 3.23 to 3.33 shw the simulated plant response for this event. A summary of the transient events sequence is given in Table 3.7.
The trip uncertainties were treated in a deterministic fashion for this case. Had the TM/LP, the operation of which was verificd statistically (8), been treated statistically, the trip ould have occurred on the TM/LP rather than the LPD trip. Hence, even without the LPD trip, the TM/LP trip would still protect the DNBR limit for the XNB critical heat flux correlation. It is thus concluded that the bias in the TM/LP is sufficient to protect the core during this event.
3.2 ANTICIPATED OPERATIONAL OCCURRENCES REQUIRING RPS ACTION AND/0R OBSERVANCE OF THE LCOs The transients discussed in th_is subsection require the observance of the LCOs for DNB and for linear heat rates in order to protect the SAFDLs,
i 27 XN-NF-82-99 and consist of: the loss-of-coolant flow event, the CEA withdrawal event, and the CEA drop event.
3.2.1 Loss-of-Ccolant-Flow Event Flow reductions result in an increase in enthalpy rise across the core and a subsequent increase in coolant temperature in the hot leg of the RCS. The increased local enthalpy and decreased flow result in a reduction of margin to DNB in the core. The most severe transient, a loss of power to all four RCS pumps simultaneously, was evaluated by simulating a coastdown of all four RCS pumps in the PTSPWR2 model and observing the MDNBR for the transient.
Bounding B0C kinetics, listed in Table 3.8, were used along with the top-peaked axial power distribution shown in Figure 2.7, The event sequence for the transient is summarized i r.
Table 3.9. Figures 3.34 to 3.44 show the simulated plant responses to the four-pump coastdown. The reactor tripped in 2.1 seconds with the minimum DNBR, Figure 3.43 reaching 1.26 in 2.25 seconds. The pressurizer pressure increases to 2401 psia at 5.71 seconds.
3.2.2 CEA-Withdrawal Fvent An inadvertent withdrawal of a bank of CEAs introduces positive reactivity which increases both core power and heat flux. Two potential initiators of this event are: (1) operator error; and (2) a malfunction of either the CEA drive mechenism or of the drive control system which results in aq uncontrolled, continuous withdrawal of a CEA bank. Heat extraction through the steam generator remains constant and the increased power is converted to heat in the RCS. Protection against violation of either of the SAFDLs is provided by the variable high power trip (VHPT), the TM/LP trip, or the LPD trip.
28 XN-NF-82-99 An uncontrolled rod withdrawal was simulated with PTSPWR2 by increasing the reactivity linearly at a rate which conservatively bounds that which can be achieved in the r c-+ r. Bounding B0C kinetics, Table 3.10, were -
used in conjunction with a mid-peak axial shape, Figure 2.8, to provide a conservative estimate of the reactor performance. This choice of shape prevents an almost instantaneous LPD trip from occurring. Further, since slow withdrawals are protci_+.ed by the TM/LP trip, a f ast withdrawal rate was simulated to provide the greatest power overshoot associated with the scram delay.
The simulated plant response for a reactivity insertion, 1.63 x10-4 Ap/sec, from full power is displayed in Figures 3.45 to 3.55. The overpower transient is terminated by the VHPT at 116% power in 3.86 seconds.
The MDNBR falls to 1.59 at 3.6 seconds (see Figure 3.54) and the pressure rises to 2363 psi et 7.3 seconds. The sequence of events for this simulation is sumarized in Table 3.11.
3.2.3 CEA Drop Event A failure in the CEA drive mechanism can result in an inadvertent full-length insertion of a CEA during power operation. Fixed demand from the turbine would cause a cool-off transient in the RCS and, for negative moderator feedback, a return to the original power with a signi -
ficantly greater radial peaking on the core. Since th9 power initially decreases following the dropping of the CEA, no reactor trip occurs and protection of the SAFDLs is provided solely by the LCOs.
This event was simulated by introducing a step decrease in total reactivity at a steady-state, full power. Bounding E0C kinetics
29 XN-NF-82-99 parameters, Table 3.12, were used and the reactivity insertion was selected to conservatively bound that due to the most reactive CEA being inserted. ,
A radial peaking f actor of 110% was included during the return to power. A top-peaked axial distribution, Figure 2.7, was used to model the hot channel in order to provide a conservative DNBR trace. During the cooldown transient, inlet temperature fell, mass flow rose and pressure, which was not controlled in this transient, fell. The increased radial peaking and reduced pressure tended to decrease the DNBR while the decreased inlet temperature and increased flow tended to increase the DNBR.
Table 3.13 summarizes the event sequence of the transient.
Flow, Figure 3.62, increased due to the cool-off, Figure 3.58, and pressure, Figure 3.63 fell to a minimum of 2215 psia at 20 seconds, and recovers to 2242 psia by 200 seconds. The DNBR fell to 1.485 at 115 seconds and recovered to 1.49 by 200 seconds. Figures 3.56 to 3.66 depict the plant response for the transient.
3.3 POSTULATED ACCIDENTS The events discussed in this subsection are assumed to occur infrequently and are not required to meet the SAFDLs, The ultimate criterion applied to these transients is a radiation exposure limit. In assessing the safety of the XN-1 reload fuel, a comparison. of expected pin failure with prior cycles is used to judge the acceptability of the fuel performance. Fuel failure is conservatively assumed coincident with the occurrence of DNB.
Hence, for the two accidents analyzed in this subsection, the expected number of fuel pins undergoing DNB was used as the evaluation criterion.
3.3.1 Primary-Pump-Seizure Event The instantaneous loss of pumping power caused by disinte-gration of the pump impeller or a complete seizure of the pump shaft would
30 XN-NF-82-99 result in a rapid flow decrease through the affected cold leg, and would cause a rear. tor trip due to low flow in that loop. The flow reduction rate would be more drastic than in a total loss of pumping power and would create a more rapid approach to DNB. The increase in enthalpy of the RCS coolant would also result in a pressure increase. The transient was therefore analyzed once to minimize DNBR and once to maximize RCS pressure. For both analyses, bounding B0C kinetics parameters, Table 3.14, were used to maximize the power excursion and delay the shutdown of the power following the trip.
The transient was first simulated by stopping one of the four pumps at full-power operation, and by using the axial power distribution shown in Figure 2.7. This shape provides the most conservative MDNBR.
Pressuri7er pressure control was retained so that the spray would decrease the pressure transient. The results of the simulation are shown in Figures 3.67 to 3.77. The event sequence is summarized in Table 3.'.5. A minimum DNBR of 1.189 at 1.2 seconds was obtained using the XNB correlation. Fuel damage due to DNB would have been significantly less than 1% for this DNBR. Core average temperature increased 60F and peak pressurizer pressure reached 2338 psia at 3.92 seconds.
The transient was also simulated by stopping one of the four pumps at full power oporation, and by using the axial power distribution shown in Figure 2.9. This shape delays the reactor shutdown since the core power is peaked much lower. The pressurizer spray and relief valves were removed from the model to increase the pressure transient. The results of the simulation are shown in Figures 3.78 to 3.88. The event sequence is summarized in Table 3.16. A minimum DNBR of 1.45 occurred at 1.2 seconds and the core average temperature rose 10.70F resulting in a peak pressure of 2397 psia at 4.6 seconds.
l
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3I XN-NF-82-99 3.3.2 Steam-Line-Break Event A break of a steam line pipe would result in an incre.ase in heat removal which would reduce the RCS soolant temperature as it withdrew more heat than was being produced by the reactor. For a negative moderator temperature coefficient, this cooldown would result in positive reactivity insertion and could lead to a return to criticality following the reactor trip and could result in core damage caused by DNB occurring as a result of the loss of pressure control. A large double-ended guillotine break of the large steam pipe at the steam generator exit at hot zero power (HZP) and E0C. conditions has been shown to be the most limiting accident for a return to power (2). The secondary side of the steam generator is at its highest pressure.(902 psia),
i.e. has the greatest inventory of cold water and.the moderator temperature coefficient is most negative.
For increased conservatism the most reactive CEA was assumed to be stuck fully withdrawn and a conservative radial peaking of 17 was applied to the hot channel for which the top-peaked axial shape shown in Figure 2.9 was used. Boron injection was modeled with one of the 3 injection pumps operating to introduce borated water (1720 ppm) via a safety injection line(volume =12.0cu.ft)whicnwasassumedtobeboron-freeinitially. High Pressure Safety Injection (HPSI) was initiated by a low pressurizer pressure signal and the pump performance curve in Figure 3.89 was used to calculate the injection rate. The initial pressurizer level was set to the HZP level of 33%
of span. The boron makeup tanks were not included in the model.
Passive injection of highly borated water (approximately 15,000 ppm) from the safety injection tanks was also modeled. This protective
32 XN-NF-82-99 feature did not enter since assumed stratification in the reactor head at natural circulation caused the system pressure to remain above the 215 psia maintained in the safety injection tanks.
The transient was initiated from HZP (TAVE=5320F) by intro-ducing a break (6.35 ft2 for S.G. #1 and 2.35 ft2 for S.G. #2) in the steam line. The moderator temperature feedback is given by Figure 3.90 and the Doppler feedback by Figure 3.91. Since Doppler feedback for zero power cannot be calculated from Figure 3.91, because the reactor was subcritical, Doppler feedback was calculated as, -2.3 x 10-3 AT % AP . The break flows were calculated using the Moody curve for critical flow of saturated steam (6). The carry-over fraction at the break was conservatively assumed to be zero to increase the total cooldown. The steam flow from the intact generator, which had to pass through the flow restrictors in both steam lines, was terminated af ter 7 seconds by the action of the main Steam Line Isolation Valves (MSIVs).
The system responses are shown in Figures 3.92 to 3.101 and the transient event sequence is summarized in Table 3.17. Initial steam line flow was 467% of rated. The steam generator with the broken line emptied in 176 seconds. After the pressurizer emptied, the RCS pumps were tripped and, af ter a 3 second delay, the HPSI was initiated. Following pressurizer emptying, pressure control was lost and system pressure fell to hot leg saturation. At 60 seconds flow reversed in the intact loop and the core inlet temperature approached the cold leg temperature of the broken loop. At 188 seconds auxiliary feedwater flow was initiated and a second cooldown transient ensued. The maximum return to power, 37.2 MWt, occurred at 221 seconds. This power level was not sufficient to cause significant fuel or >
coolant heating.
33 XN-NF-82-99 3.4 B0UNDING MODERATOR TEMPERATURE ANALYSIS The bounding moderator temperature coefficient (MTC) for BOC at hot zero power (HZP) described in Table 2.4 was verified by simulating several full-power transients which are sensitive to positive moderator temperature coefficient using 7 x 10-5 Lp for the MTC. The transients are: the derressurization event, the loss-of-coolant-flow event, and the seized-rotor event. Since the MTC decreases from HZP to HFP, the results bound the possible consequences of these events.
For the depressurization transient, peak power was 2843.2 MWt and the MDNBR was 1.377. For the loss-of-coolant-flow transient, the peak power was 2859.5 MWt, and the MDNBR dropped from 1.326 to 1.266. For the seized-rotor transient, the peak power was 1955.3 MWt, and the MDNBR dropped from 1.1.89 to 1.127.
Of these three transients, only the seized-rotor transient produces a measureable probability of DNB occurring in the hot channel. Using conservative statistics for the XNB correlation, less than 1% of the pins would be expected to undergo ONB.
Analysis of transients at HFP indicates that the bounding MTC for HZP is acceptable.
l j
34 XN-NF-82-99 Table 3.1 Transient Events Transient Disposition A00s Requiring Only RPS Action Boron Dilution Not Analyzed Loss of Load Analyzed Loss of Feedwater Not Analyzed Excess Load Analyzed Excess Feedwater Not Analyzed RCS Depressurization Analyzed A00s Requiring RPS Action and/or LC0 Loss of Coolant Flow Analyzed Loss of A.C. Power Not Analyzed CEA Withdrawal Analyzed CEA Drop Analyzed Asymmetric S.G. Transients Not Analyzed pas Seized Rotor Analyzed Steam Line Rupture Analyzed S.G. Tube Ebpture Not Analyzed 7.
I
.- , . .. . - - = . - - ._ . . . . -- ..
t 35 XN-NF-82-99 I I Table 3.2 Aineties Parameter 4 for ttre
' Loss-of-load Event 4
J Parameter Value Moderator Temperature Coefficient 1.6 x 10-4 Ap/0F-Doppler Coefficient -8 x 10-6 Ap/0F Moderator Pressure Coefficient 5'x 10-6 3pfor Beta (effective) 4.5 x 10-3 J
F i
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36 XN-NF-82-99 Table 3.3 Event Table for a Loss-of-load Event Value.
Time (seconds) 2.38 Steam Line Safety Valves Opened ---
3.05 High pressure signal generated 2422 psia 3.86 Pressurizer safety valve opened 2500 psia 3.87 Peak power level occurred 3446.5 MWt j
4.45 Reactor trip occurred (high pressure) ---
I Peak heat flux occurred- 210544 Btu /hr-ft2 7.43 Peak pressurizer pressure occurred 2657 psia i
7.50 Peak average temperature occurred 590.40F 8.62 Peak core average temperature occurred 586.10F 29.52 Peak steam dome pressure occurred 1304 psia ,
I i 37 XN-NF-82-99 Table 3.4 Kinetics Parameters for the l Excess Load Event ,
I i
t Parameter Value Moderator Temperature Coefficient - 2.8 x 10-4 ap/0F Doppler Coefficient
- 8 x 10-6 3pfoF .
Moderator Pr ssure Coefficient 3.6 x 10-6 3p/ psi ;
Beta (effective) 4.5 x 10-3 ;
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n
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38 XN-NF-82 4 Table 3.5 Event Table for an Excess Load Time (seconds) Event Value 0 Op9n steam pump and bypass 43.4% of rated flow '
7.42 Reactor Trip occurred (VHPT) 3482.7 MWt Peak Power Level occurred 7.50 MONBR occurred 1.385 7.51 Peak Average Core Flux occurred 200512 BTU /hr-ft2 12.69 Steam line safety valves opened ---
13.00 Peak steam dome pressure occurred 1004 psia
39 XN-NF-82-99 Table 3.6 Kinetics Parameters for the RCS Depressurization Event Parameter Value Moderator Temperature Coefficient 2 x 10-5 Ap/0F Doppler Coefficient 8 x 10-6 apfor Moderator Pressure Coefficient -1.4 x 10-6 Ap/ psi Beta (effective) 4.5 x 10-3
e .- __ __ - .
43 XN-NF-82-99 Table 3.7 Event Table for RCS Depressurization
~
Time (seconds) Event Value
, O Failure of pressurizer relief valve --
10.90 MDNBR occurred 1.389 i 10.91 Peak power level occurred 2841 MWt Peak core heat flux occurred 195829 Btu /hr-ft2 Reactor trip occurred (LPD) --
4 10.93 Peak core average temperature ,
occurred 572.80F 11.25 Peak average temperature occurred 574.70F 13.84 Steam line safety valves opened --
i i
41 XN-NF-82-99 Table 3.S Ainetics Parameters (Or tne Loss-of-Coolant Flow Event Parameter Value Moderator Temperature Coefficient +2 x-10-5 Ap /0F
- Doppler Coefficient -8 x 10-6 A'p/0F Moderator Pressure Coefficient -1.4 x 10-6 Ap/ psi Beta (effective) 4.5 x 10-3 P
(
l 1 L
f
42 XN-NF-82-99 Table 3.9 Event Table for a Loss-of-Coolant Flow l
Event Value Time (seconds) 0 Loss of pumping power to all four pumps ---
2.10 Reactor trip occurred (low flow) ---
Peak power occurred 2735 MWt Minimum DNBR occurred 1.326 2.25 2.56 Peak core average temperature occurred 576.50F Peak average temperature occurred 577.40F 5.75 Peak pressurizer pressure occurred 2401 psia 5.71 6.76 Steam line safety valves opened ---
43 XN-NF-82-99 Table 3.10 Kinetics Parameters for the CEA Withdrawal Event l
Parameter Value Moderator Temperature Coefficient +2 x 10-5 Ap/0F
- Doppler Coefficient -6 x 10-6 Ap/ F Moderator Pressure Coefficient -6 x 10-7 ap/ psi l
1 Beta (effective) 4.5 x 10-3 9
E
..e-,- - , - ---
44 XN-NF-82-99 Table 3.11 Event Table for CEA Withdrawal Event Value Time (seconds)
O CEA withdrawal initiated 1.63 x 10-4 /second 3.85 Minimum DNBR occurred 1.590 3.86 Power level occurred 3131.8 MWt Peak core heat flux occurred 199908 Btu /hr-ft2 Reactor trip occurred (VHPT) - . -
3.98 Peak core average temperature occurred 574.60F 7.20 Steam line safety valves opened ---
7.25 Peak average temperature occurred 575.60f 7.29 Peak RCS pressure occurred 2363 psia Peak steam dome pressure occurred 1016.6 psia 12.37
45 XN-NF-82-99 Table 3.12 Kinetics Parameters for the
! CEA-Drop Event Parameter Value Moderator Temperature Coefficient -2.8 x 10-5 3p foF Doppler Coefficient -2 x 10-5 3pfoF Moderator Pressure Coefficient ~3.6 x 10-6 3pfp3j Beta (effective) 4.5 x 10-3
I t
l 46 XN-NF-82-99 Table 3.13 Event Table for CEA Drop Time (seconds) Event Value O CEA dropped -0.00105 115 MDNBR occurred 1.485
I 47 XN-NF-82-99 i
r Table 3.14 Kinetics Parameters for the Seized-Rotor Event i
}
Parameter Value Moderator Temperature Coefficient +2 x 10-5 Doppler Coefficient -8 x 10-6 ap/or Moderator Pressure Coefficient -1.4 x 10-6 ap/psj Beta (effective) 4.5 x 10-3 i
s i
n
- - . . . - , - - - ,~.-,,...e . , , - . . . . . - , , . , . - . -y,-W. v, . - , , ,
. - .. . - - - .~ .. - -- . . _ _-___ - .-- _ . . _. -- - . - - ._ - - . ... . ..
I 1
i 48 XN-NF-82-99 1
. v
. Table 3.15 Event Table for Seized Rotor (DNB) i i
Time (seconds) Event Value I.
0 Seizure of Pump la --
1.20 Minimum DNBR 1.189 1
i 1.23 Reactor trip (low flow) occurred- --.
i l 1.39 Peak core average temperature
- occurred 578.20F 1
3.92 Peak pressure occurred 2338 psia 5.95 Steam line safety valve (loop' 2) opened --
! 5.99 Steam line safety valve (loop 1}
opened --
i i
~
w l
1 i
i 1
-- - ,p -- - , v y r mg,,-,eg-~ ww,--,w- , - - , , , - - , - - - - - -
49 XN-NF-82-99 i
i i
Table 3.16 Event Table for Seized Rotor (Pressure)
Event Value Time (seconds) 0 Seizure of Pump 1A --
Minimum DNBR occurred 1.450 1.20 1.23 Reactor trip (low flow) occurred --
1.49 Peak core average temperature occurred 584.10F 4.60 Peak pressurizer pressure occurred 2397 psia 6.39 Steam line safety valve (loop 2) opened 6.45 Steam line safety valve (loop 1) opened
50 XN-NF-82-99 Table 3.17 Event Table for Steam Line Break Event Value Time (seconds) 0 Large steam line break occurred 6.35 ft2 so # 1 2.35 ft2 SG # 2 7.00 Main steam isolation valves closed -----
7.79 Peak core heat flux occurred 9682 Btu /hr-ft2 8.00 Pressurizer emptied -----
HPSI signal generated 1576 psia 8.30 18.30 Operator tripped RCS pumps Boron entered the loop 1720 ppm 44.54 60.0 Flow reversed in intact loop -----
Peak reactivity reached 0.774 % Ap 112.0 Peak power reached 15.1 MWt 124.0 172.0 Flow recovered in intact loop -----
Second peak reactivity reached 0.0817 % ap 176.0 Auxiliary feedwater started 253.6 lbs/sec 188.0 216.0 Flow reversed in intact loop -----
Second peak power reached 37.2 MWt 220.0
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1 Totm. rEEDWATER FLOW 140 - TOTAL STEArt LIPC FLOW
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\
to -
k V 2
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TIME, SEC k 5
Figure 3.2 St. Lucie Unit 1 - S. G. Flow - Loss Of Electric Load
-t,.~.- a c= f,- gg,yg,gg, I
2004 r 1 Ave. REL TEMPERATURE 1804 F 1904 r ts. w w
o 1204P
\
1000-
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800 1
3 1 1 x l I I I -~ I i i l i I z i
6% 4 8 iP_ 16 20 24 28 32' 3G 40 k TIME, SEC a
'?
' Figure 3.3 St. Lucie Unit 1 - Fuel Temperature - Loss Of Electric Load rt .' c "
- s*-- sc.54.44.
-_,.,-.e._.. - . - . -
1 CORE IM.ET TEMPEmpTURE 680l-
- 2. AVE. CORE COOLANT TEMP.
- 3. Ct.90 TEMPERATtJRE i
660 840 3
S20
' T o
=00 -
' s t t s _ _ _s T,A 1
2 E d.-
580
/y 580
- 1 1 I I I E I 1 1 1 I I h,.,
28 32 36 40 54 4 4 8 2 E 20 24 TIME, SEC ln
?'
8 Figure 3.4 St. Lucie Unit 1 - Core Tenperature - Loss Of Electric Load m.s c < ru -
te.st.44.
20 -
1 CHANCE IN TfHOT)-TfCOLD1 LOOP ltLCC 11 2 CHANCE IN Tf HOT >-TI COLD 1 LOOP If LCC 11 3- CHANCC IN Tl HOT i-TT COLO 1 LOOP El LCC 11
- 4. CHANCE IN Tf HOT 1-Tf COLD 1 LOOP 2i LEC t i 10 0
_to -
' 8 o
b
-20 -
4
-30 -
34 1
-40 - 8 8__ 1134 11 x I I I __J i- I i 1 1 1 N
4 8 la 16 20 E4 28 32 36 40 in TIME, SEC k 5
, Figure 3.5 St. Lucie Unit 1 - Loop Temperature Differences - Loss Of Electric Load f
m:v:< wve. tc.cs.ss.
El '- 1 CHANCE IN AVE. PRIMARY C0(M. ANT TEMP. , LOOP 1 2 CHANCE IN AVC. FRIMARY C004.perf TEMP., LOOP t
.1 I
3g j 15 i
1E ts. E o
. s -
t 11 gg g -
3 5
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0 0 4 8 12 16 20 24 28 3a 36 40 T TIME, SEC y 8
l Figure 3.6 St. Lucie Unit 1 - Average Temperatures - Loss Of Electric Load I
j .m' im s
. " f y -- te.5e.44.
FLOV IN COLD LEC f1,1) 106 - 1
- 2. FLOW IN COLD LEC i1.E1
- 3. FLOW IN COLD LEC (t.11
- 4. FLOW IN COLO LEC i 2.,t 1 105 104 Q
w YL E103 -
E 8
e-
- f.
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A.
101 l 100 N O ( 1E1 4 1R34 i P.
x 4 2
- 113 i i I i 1 I i i l I 2 88 0 4 8 12 16 20 24 28 32 3G 40 TIME. SEC k-Figure 3.7 St. Lucie Unit 1 - Cold Leg Flows - Loss Of Electric Load
-T****.* e e f a ., s 9 - tr,eg,4(,
1 STEM DOME PRESSURE CHANCE,t.00P 1 600 --
2.. STEM DONE PRCS90RE CH MCE LOOP t
- 3. PRESSURI2ER PRESSURE CHANGE 500 ie it 1 t_
i 400 1
) '
J 300 m r
h m
O.
\..,
200 I
- 1 100 i
A_ S _ _ . _ . _
'l x ll 1 1 1 I i 1 _ l I ?
!* 1 1 32 36 40 is
!'.I i 4 8 la 16 to TIME, SEC 24 E8 k
b Figure 3.8 St. Lucie Unit 1 - Pressures - Loss Of Electric Load l
l!
i ev in c ic.ss.es.
L
~ 1 CHANCE IN STEAM CEN. VATER LEVEL, Lot 1P 1 60 3 E. CHANCE IN STEAM CEN. WATER LEVEL . LOOP 2 3
CHANGE IN PRESSORITER WATER LEVEL 40 20 It 1
mo H
O ~
g I 40 -
1
-60 - g o
x 2
1 _- l 1 l i I l ! I I ,,_,_
40 in 12 16 20 24 ES 32 3G 4kl_ 4 8
- /g TIME. SEC Figure 3.9 St. Lucie Unit 1 - Water Levels - Loss Of Electric Load
- r. . .., ..... .. tr.!<.ac.
-- ~
4.5 - 1 mwmun uns wuc 4.0 -
3.5 -
C H
F-G ~
at 3.0 -
O t
15 E.0 15 - ,
i i x I I i 1 1 I i I g- 28 32 36 40 [
1 4 12 16 20 E4 TIME, SEC 7
'?
8 Figure 3.10 St. Lucie Unit 1 - DNBR - Loss Of Electric Load "Tf).*.? ? P7/*1/** tc.fl.(1.
~ . . - - - . . _
w..--
1 1900ERATOR REACTIVITY 8 F 2 DOPPLER REACTIVITY I
- 3. BORON REACTIVITY
- 4. TOTAL. REACTIVITY 3
1 _.. _t_ _ t_
g t _
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s , s A . =sr-- ,
0
-3 D us
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f l x I l l
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24 28 32 3G l
4 8 12 18 E0 3 TIME, SEC l0 l 5 Figure 3.11 St. Lucie Unit 1 - Reactivity - Loss Of Electric Load l
! N' .n' ** e. *- - tc.5g,44,
140<- 1 Powet LEVEL
? HEAT Ft.UX
- 3. TOTAL PRIMARY COOLANT FLOW 120 L
1 2 3 3 1 ggg Yk 3 3 1 100
- a r
.: Ego -
E b-O V
Z
$0 -
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40 20
- 1 ** it it 1e x I I I I I I I I i
- i n 0 0 15 20 25 30 35 40 45 50 5 10 TIME, SEC $
h Figure 3.12 St. Lucie 1 - Power, neat Flux and Flow - Excess Load STLUCJ7 14/12/R2 20.35 50.
1 TOTAL FEEDWATER FLOW 17 5 -
- z. TOTat. STEan LINE FLOW 150 t
i 125 O
w
>- cn E0 10 p --
t t t t a z
rp5 -
5 n.
50 25 E.
i 11 11 11 11 11 1 %
I I 0 0 25 30 35 40 45 50 lo 5 10 15 20 TIME, SEC $
e Figure 3.13 St. Lucie 1 - S. G. Flows - Excess Load sTi trJz 14riz/sr 20.35.50.
1801r 1 AVE. FUEL TOFERATIAtE 160tm 1404 r I 1 m
120lP 14 u
me 800
- 1 1 1 1 600 E
i 1 E
I I I I I I I I 50 A N 5 JD 15 20 25 TIME, SEC 30 35 40 45 e
Figure 3.14 St. Lucie 1 - Fuel Temperature - Excess Load STLLC T2 14/12/02 20.35.50.
G60 1 CORE Itt.ET TEMPERATURE Z. AYE. CORE COOLANT TEW.
-v 3. CLAD TErstATURE S40 i
S20 i 600 -
E ta.
o 580 -
s 560 - -
1 d
2 3 ' 8
~
_.a .z 3 540 - - -
i* i*
^~
i s k
5 10 20 35 40 45 TIME. SEC 8 L
Figure 3.15 St. Lucie 1 - Loss Of Coolant Flow - Excess Load
80 - 1 CHANGE IN TtHOT>-T(COLD) LOOP 1(LEC 1) 2 CHANCE IN T( HOT >-T( COLD 1 LOOP 1( LEC E 1
~3 CHANCE IN T( HOT )-T( COLD 1 LOOP t( LEC 11 4 CHANGE IN T( HOT >-T( COLD 1 LOOP t( LEC 1 )
60 40 14 cn E0 u.
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O
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1 4
4 40 -
itse tg3g gg3g gg94 5
f I E I I I I I
( I I 35 40 45 50 [
%. 5 10 1E 20 25 TIMEE, SEC 30 7
e Figure 3.16 St. Lucie 1 - Loop Temperatu e Differencer - Excess Load STLtrJ7 14 /1E/ 82 10.35.50 C _ _ _ _
R 55[7,e I.
0 5
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3 2 ku$
107I- 1. FLOW IN COLD LEC (1 11
- 2. FLOW JN COLD LEC ( 1.11
- 3. FLOW IN COLD LEC ( E.11
- 4. FLOW IN COLD LEC fE.E) 1DG 105 8
E -
2 104 U
6-- .
Z 8 102 E
o.
10E 34 1134 1130 LIII IIS4
- 3 x 101 4 1, 2 3
- i I I I I l J I l I I N 5 10 15 20 25 30 35 40 45 50 h TIMEE SEC Figure 3.18 St. Lucie Unit 1 - Cold Leg Flows Excess Load
300 - 1 STEAM DOME PRESSURE CHANGE, L.00P 1
- t. STEAM DOME PRESSURE CHANCE. LOOP 2
- 3. PRESSURIZER PRESSURE CHANCE 200 1" ~
tt it ie it tg s
G 5
n.
-101F
..pyr-s
-30t& 3 2 s 1 3 5 1 I I I I I I 1 i i a
'4I. 5 10 15 20 25 30 35 40 45 50 ?
TIME, SEC @
Figure 3.19 St. Lucie Unit 1 - Pressures - Excess Load STLtlCJZ 14/12/A? 20.35.50.
t
U E&7$$
i 0
5 3
I 5 1t 4 PP OO S OO LL d
, ,L a LLE I 0 o 4 L EEV VVE s EEL s LL ' e R c RRE x EET E TTA S AAW I
3 -
WW R s
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SSP E W NNN S -
III 5 , 1 EEE 1 2E CGG t NNN M i AAA I n HHH T U CCC e
i
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o !
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z H
z E.0 1
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I I I i 1_ I i ?
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30 35 40 45 50 is 1.%- 5 10 15 20 25 TIME, SEC s
Figure 3.21 St. Lucie Unit 1 - DNBR - Excess Load STLUCJI 14/12/R2 20.35.M
8 2 M000tATOR REACTIVITY 2 DOPPt.ER REACTIVITY
- 3. SORON REACTIVITY
- 4. TOTAL REACTIVITY 5
1 1 1 1 1 - -_ - -
2 17t --t z t t At 2 s s 3 3 3 LJ 8 i 4
-1 -
M I un E;
8-4 O
-7 -
4 4 4 4 4 4
-10 -
2 I I i 1 i g &
1 i 1 1
?
35 40 45 50
_S- 5 .1D 15 20 25 30 TIME, SEC Figure 3.22 St. Lucie Unit 1 - Reactivity - Excess Load STffrJZ 14/t*/82 20.35.50.
~
1 POWER LO/EL 140p 2 HEAT FLUX g
- 3. TOTAL PRIMAW: COOLANT FLOW
(
120 1- I' 1 ' '-- '
~* t- --
c-100I**' s O
w W
G x E80 -
- u. O r -
z
$60
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40 N
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(__t 3 g J
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I ' ' ^ ' - I I - =-
8 10 12. 14 16 18 20 &n
' O 0 2 4 6 TIME, SEC &
'?
8 Figure 3.23 St. Lucie Unit 1 - Power, Heat Flux and Flow - RCS Depressurization I
t gv oca, --::.- zo.s2 -
L__
f 160 - 1 TOTAL FEEDWATER FLOW E. TOTAL STEAM LINE FLOW 140 -
120 O i LaJ g 1 1 H 1, 1 c 2 2 G c g c y
E 100 } '
u.
O z -
$80
=
hJ 81.
- 2 z 60 40 5
I I 1 l l l I I I 20 0 6 8 10 12 14 16 18 E'. &
a 4 TIME, SEC .Y e
Figure 3.24 St. Lucie Unit 1 - S. G. Flows - RCS Depressurization en'cne 2.n , p i e 7 on,c3.,a A-
140P 1 Avt. R.T1. Tcw ERATURC 13001 1 t _A - - - ' -
s i
\1 120(&
i
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n 110(P \
k o
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100u- '\ \
\.
N S00 -
\4 x
\,
s N
800 -
N i i ~~~
! 1 1 1 I ~ ,_L i
\ 1 M
7 7% 2 4 G 8 10 12 14 16
~
18 20 f TINE, SEC f8 b
F; cure 3.25 St. Lucie Unit 1 - Fuel Temperature - RCS Depressurization GTLt! COA 20/1?./90 20.53.30.
1 CORE It41.ET TEt@ERATLRE j 680l- 2. avC. CORE COOLANT TEff.
- 3. CLAD TEMPERATURE E60 C40 3 3 3 3 w 3 3
'N~. 5 G20 g
o \
w Q
GOO xk s
a 3 580 g 2 2 2 1 2 _ Nt 2
a 560 -
g g g l l 1 ,_,. 1 .
1 1 .
?
I I I I l ; i I
,g
, EO 54g 8 10 17, 14 $
TINE. SEC S Figure.3.26 St. Lucie Unit 1 - Core Temperatures - RCS Depressurization
"' ' irma snfiere, ,n,y, ,n,
I 30 -
- 1. CHANCE IN Tt HOT }-Tf COLD ) LOOP 1( LEC 11
- 2. CHANCE IN Tt HOT 1-Tf COLD ) LOOP If LEf: 21
- 3. CHANGE IN T! HOT )-Tf COLD ) LOOP Ef LEG 11
- 4. CHANGE IN Tf HOT 1-TI COLD ) LOOP 2f LEC 21
- 20 10 123 4 1234 123 4 1E3 4 its4 123 4 0 0
4 o
2D
-30 7
> E, i 1 1 I ' E I L ~~ I I I
-4% 2 4 G A 10 12 14 16 le 20 k TIME, SEC a e
Figure 3.27 St. Lucie Unit 1 - Loop Temperature Differences - RCS Depressurization FTltr0R 20/U/92 20. F9. ? ".
4 1
CHHNCE IN AVE. PRIt4ARY COOLANT TEMP., LOOP 1
~
E 2 CHANCE IN RVE. PRIMARY COOLANT TEMP,, LOOP 2
-~
1 tz tz S M~
o N,
M
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Q
.-2
-3
-4 -
2 I 1 i 1 a I I -
1 l - _ _
l .___.._1_._. 14 16 18 20 8 10 la 4 - 2 4 6 @
0 TIME, SEC $
Figure 3.28 St. Lucie Unit 1 - Average Temperatures - RCS Depressurization "f!'oOA 20/11/82 P.G . f t . 3 0.
106 ~ 1 FLOW IN COLD LEC ( 1.1 )
2 FLOW IN COLO LEC ( 1,21 3 FLOW IN COLD LEG ( E.11
- 4. FLOW IN COLO LEG ( E.21 105 -
, 104 1 O i w 1 F
\
' G E 103 tt o m e
t-z
$102 x
I w I
i 1 10 1 1E34 123 4 1234 1234 1234 1234 1234 1EM T
' 83 I I i 1 1 I I I I I 5 0 2 6 4 8 10 TIME, SEC 12 14 16 18 20 k i
'F Figure 3.29 St. Lucie Unit 1 - Cold Leg Flows - RCS Depressurization STLIJCOR 2 0 / 1. / 9 ' 20.53.30.
.. _. .y. . . . - .
4
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ll lllltlllil1lli .l ll'1l ll
4 1 CHAT 4CE IN STEAN CEN. WATER LEVEL, LOOP 1 2 CH6NCE IN STEfet CEN. WATER LEVEL, LOOP t
- 3. CHANGE IN PRESSORI2ER WHTER LEVEL 1t 12. 12 gg N, & , , ,
m.
-4 - 'M N.
m -6
~
w s
'I u
z H
\
_a y 1 N
\ N 5
a i l I 1 1 l I J~ l I 7
~Eh 2 7 ~~ G 8 10 12 14 16 18 20 %.
TIME, SEC $
Figure 3.31 St. Lucie Unit 1 - Water Levels - RCS Depressurization P
k 9 O. A9# i9 OO EO OO
i 4.5 -
1 MINIMUM DNS RAT 10 I . /
4.0 -
/
//
3.5 -
/
o H f ct ./
m /
3.0. -
i E V m N
O /
I a
ge.s -
- Z /
n I
E.0 -
1 1 .
1.5 -
% % _/ i
/
x I L -- 1 I I I __. I I I i 1* % a 4 6 8 10 la 14 16 18 20 .
TIME, GEC $
5 Figure 3.32 St. Lucie Unit 1 - DNBR - dCS Depressurization ST'_OrOR 7.0 /1 ?./ 9 U.53.30.
- 1 MODERATOC REACTIVITY E DOPPLER REACTIVITY 2 -
3 BORON REACTIVITY 4 TOTAL REACTIVI 1t34 iz3 4 iz3 4 1z3 4 ,
g -
-4 -.
x tn m
G '
-.s oy .
Q
-8 -
1 4
4_
-10 - 4 I I I I
14 ig 18 20 !?;
4 8 10 12
-12)t 2 TIME. SEC h E
Figure 3.33 St. Lucie Unit 1 - Reactivity - RCS Depressu-ization
-' *0/l'/9? 'A S3 30 m
140 1 POWER LEVEL E. HEAT FLUX
- 3. TOTAL PRI**9RY COOLANT FLOW 120
- 2 '
100 O
w 3 H
- G '
E80 -
- u. 3 %
o 6--
Z 3 d60 2 ,
E g 3 W 3
- n. 3 40 20 1 1 g 1 3 x
I l i I l I I I I I 0 3.0 s.0 8.0 9.0
- 0.0 10 20 40 50 7.0 10.0 TIME. SEC k 5
Figure 3.34 St. Lucie Unit 1 - Power, Heat Flux and Flow - Loss Of Coolant Flow STLUCPJ E0/12/82 C 0. 31.15.
l I
85 XN-NF-82-99 o.
r S
a i 4 el o #
i a tJ e 2 O r>
d -
u-a %
E 2 o
w -
c,
-
- O s o 2 o 2 ao w Y oJ au = 2 k
w -
$ e w
5A ,
ga o w
m x
3E o
ww m -
o u.
wr e
- u. m ~
b a e
I H m
=
-- s oo a v&
~ _
- b An *m C
m
" G) es U
- 3 n a e
a m
Ln m m, m
as L
3 J en e
d o. u-le g
o l ; -
I L I o o . o o g o e *
% % N S *
- 03108 30 IN3383d e # w g,
l l
140(F 1 AVE. FUEL TEMPERATURE 130(q 1 1 l 120(F 110(F o
w O
100(F 900 1
800 -
I I I E
I I I I 70%.0 1
10 I
20 I
3.0 4.0 50 6.0 7.0 8.0 9.0 10.0 k TIME. SEC k
- N Figure 3.36 St. Lucie Unit 1 - Fuel Temperature .- Loss Of Coolant Flow Fil .t 'Cr. f
.~il"/'t 20.'31 15.
l lllI 1l l m *" 5kb 0
I 0 1
s 3 t t 1
, 0 3 I
9 e r
3 w E o
- l
, 0 F I t 8 t s n /
c a t l
' o /
o o 2 t C
t 0 I f
UE 3 o P.
TT L W A
- t L
RT t 0 - T ENE S PAR I 6 s MLU e EOT r TOA C u CR 3 E t T E S a EEP t r LRM t 0 e NOE I
, p ICT 5 E m M e E .D T REA I OVL ' T e CAC E r o
t 0 C I
. . . 4 -
123 1
3 t i
n 1 0 U I
3 i e
c u
3 L t .
0 t I
S 2
7 3
3 M1t 1
I 0
1 i
F e
r u
g 0 -
1 0 0 0 0 0 0 8
0 6
k 4 -
8 6 4 2 0 5 5 5 5 6 6 6 6 E cw l l .l1 lj! lI E
16
- 1 CHANGE IN T( HOT 1-Tt COLO ) LOOP lt LEG 11
- 2. CHANGE IN TlHOT1-T(COLO1 LOOP ifLEC E1
E 3I 1 g 4
3 4
s Po O
z' 1E34 4
-4 -
-8 -
x I I I I ?
l l 20 l
3.0 1
4.0 1
50 60 70 8.0 9.0 10 0 y
-I%. 0 10 TIME, SEC b
Figure 3.38 St. Lucie Unit 1 - Loop Temperature Differences - Loss Of Coolant Flow STLitrPJ 20/1P./Pt :10.31 15
I
- 1 CHANCE IN AVE. PRIMARY COOLANT TEMP.. LOOP 1 7
2.. CHANGE IN AVE. PRIMARY COOLANT TEMP.. LOOP E 6
5 4
u.
1 O
w a
3 E t L
N
' I ' ' ' I 5
- ' ' l g
8.0 9.0 4.0 50 60 7.0 10.0 0
0.0 10 20 3.0 TIME, SEC &
7 8
Figure 3.39 St. Lucie Unit 1 - Average Temperatures - Loss Of Coolant Flow S TL* 'C8'J E0/1?/PC 20. ~31. i' u.
8 Ek$'.8 "
0 I 0 1
4 .
5 1
1 0 3 I O 9 C 4
3 w E l o
0 F I
2 8 t R n /
4 a ?
I l
o /
o 0 2
C 0
I f
7 O 1 1 ) 1 4 s J s
1 E.1 2
. , . 3 o P C
111E L U
( ( ( ( L 0 - T CCCC S EEEE I
6 s LLLL w
- o DDDD C l LLLL E F OOOO S g CCCC 0 e
. L NNNN 1 5 E IIII M d l
WWWW 4 I o OOOO T C LLLL FFFF -
0 1 1
. . . . 4 t
1134 i 4 n U
i e
0 c 1
3 u L
t S
0 0 1
2 4 3
e r
u g
0 i 1
1 F 0
- 0 0 0 0 0 0 0 1 0 0 0 5 4 1 9 8 7 6 1 .
owEE o wz $ xWQ I
o
240 -
1 STEAM DOME PRESSURE CHANCE. LOOP 1 2 STEAM DONE PRESSURE CHANGE LOOP E
- 3. PRESSURIZER PRESSURE CHANGE E00 1E 12 160'- 3 120 a
H un n.
. 80 -
b e I
i E 40 3
3
- '
- iz s 0
t I I i 1 1 I I i 'j E I
-4%.0 10 20 30 4.0 50 6.0 7.0 8.0 9.0 10.0 ki l
TIME, SEC s
'?
8 l Fiaure 3.41 St. Lucie Unit 1 - Pressures - Loss Of Coolant Flow l
S"_ t . CrJ E0/12/Pr 20.31.!!
20 1 CHANGE IN STEON CEN. WATER LEVEL. LOOP 1 2 CHANGE IN STEAM CEN. WATER LEVEL. LOOP E 3 CHANGE IN PRESSURIZER WATER LEVEL 1G 3
3 la N
3 m8 E
E o
3 h -
4 3
3 1E3 11
-4 -
LL 12- Y 2
I I I I I I l 1 I I
-8 00 10 20 30 4.0 50 60 7.0 8.0 90 10.0 in TIME, SEC k 5
Figure 3.42 St. Lucie Unit 1 - Water Levels - Loss Of Coolant Flow STLUCPJ E0/17/90 C0.'i1 15.
4.5 - 1 MINIMUM DNS RATIO i
4.0 -
3.5 -
o H
E ct:
,3. 0 8
E -
E -
Ea.5 2:
E E.0 -
15 -
i i i I I I I E I I 1* k. 0 1
10 20 30 4.0 5.0 6.0 7.0 80 90 10.0 k TIME. SEC g 5
Figure 3.43 St. Lucie Unit 1 - DNBR - Loss Of Coolant Flow ,
Sft.UCPJ 10/12/82. *0.31 i 15.
2 x?y25 0
I 0 1
5 1
1 0 3 I
0 9 2 0 w o
I 8 l "
F /
4 2 t 1 n /
a 0 l 2 0 o I
o 7 C
. f J O P Y C T s U IY s L
/T 0 o T
- IY .
I L S TVT T 6 CII I ATVV C y ECI RATMEC E
S t
i RRAM O EE 0 ,
i t
v TRRD _ I c
AE 5 E a RLN -. .
M e I R DPR T OOO EPOM MDB 0 1 I
4 t i
1E34 n U
?
i e
g c 0 u 1 I 3 L t
S 3
E 4 0 4 1 I E 3 4 e r
3 u 3
t -.
0 F i I 1
4 3
E 0
L - - - - -
E 4 G 8
0 1
N-2 0 - -
m:aGJ. oa i l l' '
s- 1 i;:
3 140
- 1. Powet LEVEL E. HEAT RUX i
- 3. TOTWi PRIMARY C00UWT ROW t
120 2/ t_
Wt* E. 3 \% 3 3 3 3 3 l
g EO S it 5
h0
=
i w CL
-l -
40 l
20 1- 1 1
. x ll 1 I I I I I I I I 1 P 0 0.0 10 20 3.0 40 5.0 6.0 7.0 8.0 9.0 10 0 25 l
l TIME. SEC h Figure 3.45 St. Lucie Unit 1 - Power, Heat Flux and Flow - CEA Withdrawal STLOCIU 15/12/82 20.22.54.
~
' ;!s.- .
eW x?y$5 0
1 0 1
4 5
2 0 2 1
S S P
t N 0
1 2 9 l 8
/
a 2 w 1 a /
r 5 1 j s d h
1 0 t 1 i 7 W W A O E I WO C C OL l LF 0 - L T
F E i s S RN 6 w EI o TL C l A F WM E DA 1 S .
EE 0 G ET ,
FS I .
nL
. . 5E t S
aA I TT T OO 1 TT t 0 i 1
4 n
. . . U 12 e
i c
u t L 0
i 1 .
_3 t S
6 4
t 0 3 t I 2 e r
u g
i F
t 0
a i 1
g
- - - ,0 0
0 0 0 0 0 0 4 2 01 0 0 2 6 1 8 6 4 1 1 awF )g tz$i
.Ea
1500- L AVE. FUEL. TOFERATURE 1400 t
- 1 130(Fg g 1200 ts. 0
'J
,. uw -
\
'l 10(H r-
~
, S00 i
,l 1 l l g 2 i i 1 1 1 1
'l' gN.0 10 20 30 4.0 5.0 6.0 7.0 8.0 S.0 10.0 k TIME, SEC &"
Fioure 3.47 St. Lucie Unit 1 - Fuel Temperature - CEA Withdrawal g
i
'i STLUCIO 15/12/82 20 22 54.
i 680 - 1 CORE INLET TEWERATLRE 7 AVC. CORE COOLANT TEW.
S
- 1. Ct.A0 TEWERATURE 660 1
- 64J 3
1 2 *
.; 3 I sen -
' e u
d -
600 AS ___
580 -
E E e t e
% e as "A0 -
t t 1 1 i 1 .-
t t t_ _
1 1 I I i 1 1 1 I I E l 54%.0 10 a.0 3.0 4.0 50 6.0 7.0 8.0 S.0 10.0$,
TIME, SEC &
'?
8 Figure 3.48 St. Lucie Unit 1 - Core Temperatures - CEA Withdrawal STLUCIlj 15/L2/82 20.22 51.
30 '- 1. CHANCE IN Tt HOT l-Tt COLO 1 LOOP 1( LEC 11 t, CHANCE IN T(HOT ET(COLD 1 LOOP 1(LEC E1
- 3. CHANGE IN TtHOT1-T(COLD 1 LOOP Z(LEC 11
- 4. CHANCE IN T( e40T 1-T( COLO 1 LOOP tt LEC E 1 20 10 1134 - 1_ E .' g 113_4 3 gg3g itS4 E
u.
l o I o
-w -
-to s
i 30 ,
i 5
i 1 1 I i 1 &
l 1 1 I 3.0 4.0 5.0 6.0 70 8.0 90 10.0 ,7 <
-4%.0 10 a.0 TIME. SEC ?
8 Figure 3.49 St. Lucie Unit 1 - Loop Temperature Differences - CEA Withdrawal STLUCTJ 15/ tu 82 20.22 54.
6 1 CHANGE IN AVE. PRIMARY COOLANT TEMP., LOOP 1 2 CHANCE IN AVE. PRIMARY COOLANT TEMP.. LOOP E 5
4 4
3
' 5 u
8 a -
1 1
11 12 11 11 11 0
5 I I i 1 l 1 1 l 1 1 a
-1 0.0 10 20 3.0 4.0 50 6.0 7.0 8.0 9.0 10 0 A TIME, SEC '?
8 Figure 3.50 St. Lucie Unit 1 - Average Temperatures - CEA Withdrawal STttrTU 15/1?/S2 20.P' *4.
i l
r l 106 - 1 FLOW IN COLD LEC ( L.11 l E. FLOW IN COLD LEC i 1.11
- 3. ft.OW IN COLD LEC f 2.11
- 4. FLOW IN COLD LEC r1,11 1D5 l
l l
! 104 O
w 6--
E E103 --
U S z -
i
$10E E
w D.
10 1 34 1EIi 1124 1234 1134 1134 *134 s 111 4 - 1134 1E3 0
' I I I I I I _1 I I I 30 4.0 5.0 8.0 7.0 8.0 9.0 10 0 g
- SS 0.e 10 P. 0 TIME. SEC $
, b Figure 3.51 St. Lucie Unit 1 - Cold Leg Flows - CEA Withdrawal STLLCIU 15/12/82 20 22.54.
4 E~ * " k5 0
I 0 1
N 4 S..
2 0 2 I
0 9 .
2 1t 0 1 2 PP 8 8 OO l
/
OO Y -
a 2 1
LL w /
a 5 r
EE .E
. 1
_ 0 d CCW P NA I 7
h t
AAH i W
HHC U CC A I E E C EER C U RRU L UUS 0 - 1 SSS S SSE 1 6 s EER e RRP r PP C u R E s EEE S s MMZ e OOT DDR 0, . r 1 P U 5 E MerS ApS M -
0 n
- 1 U
. .. - 4 1t3 e i
s c u
g L i 0 .
i t 3 S 2
- 5 t 3 0
a I 2
e r
u g
i s F
. 0 1
1 s
a
- t 0 0
5 1
5 2
1 0
0 1
5 7
0 0u, a. 5 5
2 0 N
) !:'- .
13 1 CHANGE IN STEAN CEN. WATER LEVEL. LOOP 1
- 2. CHANCE IN STEAN CEN. WATER LEVEL. LOOP t
- 3. CHANGE IN PRESSURIZER WATER LEVEL 10 3
7 1
I
~
m4 g
3 "o
U "
z H 3 1 1g? its ses *E= -
i
-E.
U
-5 -
x i i 1. 1 I I I I I I f 4 0.0 10 20 3.0 4.0 50 6.0 7.0 8.0 S.0 10 0 y TIME, SEC $
0
~
Figure 3.53 St. Lucie Unit 1 - Water Levels - CEA Withdrawal CTLUCIO 15/12/92 ?.0.22 54.
4.5 -
1 MINIMUM DP6 MTIO f 4.0 -
) 3.5 -
o H
l w G
i a:
3.0 -
E D
- Ez.s z
H Z
E.0 -
1 1 g 1
15 -
5 1 1 1 1 I l 1 1 1 1 &
8.0 10.0 ?
1* %.0 10 2.0 3.0 40 5.0 6.0 70 S.0 l
TIME. SEC @
Figure 3.54 5t. Lucie Unit 1 - DNBR - CEA Withdrawal STLUCIU 15/12/22 20.22.54.
E "-
1 MOOOtATOR REACTIVITY P DOPPt.ER REACTIVITY
- 3. BORON REACTIVITY
- 4. TOTAL. REACTIVITY s jg34 1114 12 1 4 to 1 4 0 s 4
_g -
i 3
0 4 ..
m -
E 3 0
s l
I
-6 -
, -M -
, e
'l 4 l!
1 x 2
. I I I I I l 1 l l I
-l' o.o 10 a.0 3.0 4.0 5.0 6.0 7.0 8.0 s.0 10.0 E TIME, SEC k 5
Figure 3.55 St. Lucie Unit 1 - Reactivity - CEA Withdrawal l
STLOCIU 15/12/82 20.22 54.
l 102 - 1 POWER LEVEL
? HEAT FLUX
- 3. TOTAL PRIMflRY C00UWT FLOW 3 9 3 s.*
100 34 8
E -
a:S6 g .k 5 e-z -
$$4
$[
Sz -
30 -
5 I I I I ~I I I I I I a 98 0 20 40 60 30 100 120 140 ISO 180 200 ?
m TIME, SEC 7 Figure 3.56 St. Lucie Unit 1 - Power,lieat Flux and Flow - CEA Drop asnmw caanino rasn2L.- _ _ - . - - - _ _ - - - _ _ _
117. ~ 1 TOTW., FEED MTFR FLOW
- t. T01f4. STG.pH LIT FLOW 110 --
108 O
w P-E 106 -
% s~
F-z
$104 -
b v = it 1, 1.-
>_m t_
m t_. t.-
g .,
100 x
I i i l i I I z 1 1 I N 0 m 40 60 80 100 120 140 160 180 2.00 k TIME, SEC k b
Figure 3.57 St. Lucie Unit 1 - S. G. Flows - CEA Drop "T' " v ev tva- f. 3r .n.
gm 5 fyo9 0
I 0 2
2 5
7 0 5 t
I A 7 o G
t 0 p I S o 2 1 r 8 D ?
n A 0 E R C G t 0 -
I 4 1 e r
E u 2 f
t t R a i c
U r T e u A 1 0 p T s
R I 2 m E 1 e P T M C E l T E e S u L 0 F
E i 0 ,
U I 1 E F
M 1
. I t E T i .
V n A U i
I 0 e
. 8 i _
1 c u
L t
g S I 0 6
8 5 .
3 e
1 r I 0 u 4 g i
F i 0 2
r F t e t 4 d' 4 4 n s 4 S 6 4 E 2 P 3
1 3
1 % 1 u u 1 S
.s ut$
, l il
1 CORE INLET TOPERATletE 690'- 2 AVE. CORE C00U WT TEP@.
- 1. CUC TEleERATIRE i
660 640 3 2 3 s s s 3 t 3 3 3 820 ta.
O 5
8 -
s00 590 t t t 1 t a t t e t 560 1 1 E- 1 i s _t t i 1 _
I I I I I I I I l I 140 160 180 200 [
40 60 to 100 120 54% 2.0 TIME. SEC A
'?
8 Figure 3.59 St. Lucie Unit 1 - Core Temperatures - CEA Drop rT .~y er.i.
. iet to.s?.fr m
5 1. CHANCE D T(HOT 1-T(COLD 1 LOOP ltLEC 11 2, CHANGE D T( HOT 1-T( COLD 1 LOOP lt LEC 21
- 3. CHANGE D T( HOT )-T( COLD 1 LOOP tt LEC 11
- 4. (JeNGE IN T(HOT l-T(COLD 1 LOOP tt LEC E1 4
3 t
u.
" b El 1 -
1Z 8 IE38 1E34 1x34 3 4 gg34 gg3g 0 -
3*
4
-1 E,
l l 1 I I I I I I I I 4 4 40 60 80 100 120 140 150 180 200 0 20 $
TIME, SEC a o
l Figure 3.60 St. Lucie Unit 1 - Loop Temperature Differences - CEA Drop l
__ -W. @*
- s ? o t ' M
3 -
L CHANGE IN AVE. PRIMARY C00UWT TEMP., L0tr 1 2, CHANGE IN AVE. PRIMNtY C00LPdi YEF. , t.00P 1 2.
1 o
' I -
u =
8 -
-1
-e -
-3 it 12 l' **
gg g 4
i I I I I I I f I I E 0 20 40 SO 80 100 120 140 1s0 180 200 A TIME, SEC e
Figure 3.61 St. Lucie Unit 1 - Average Temperatures - CEA Drop cfluran nruwurw -
f 107'- 1, FLOW D COLD LEC (1,1) t, F1.0W D COLD LEC (1,t)
- 3. FLOW D COLD LEC ( Z,1)
- 4. FLOW D COLD LEC ( 2,11 108 105 o
W E 104 -
8 =
N i $
gios
, E a -
10 1 sts4 it34 its4 its4 its4 its4 its4 sts4 g its4 I I I I I I i I i 1 i I 200 N .E 3 420 40 60 90 100 120 140 ISO 180 f TIME, SEC b
Figure 3.62 St. Lucie Unit 1 - Cold Leg Flows - CEA Drop
- v. ~ x eu t . *- 10.s .71
- L STEAM DOME PRESSURE CHANGE, LOOP 1 i 30 STEAM DOME PRESSURE CHANCE, LOOP t t,
- 3. PRESSURIZER PRESSADtE CHANGE 20 10 0
C w
M en s s L a.
-10 -
2 e
-to -
21 1t L2--
-30 -
3 x
I I I I I i 1 1 ?
i I 1A0 100 %
160 N 20 40 60 80 100 TIME, SEC 120 140 k
k Figure 3.63 St. Lucie Unit 1 - Pressures - CEA Drop
=r. .
~?.y o s .* ,. .* * - we.
. it . .-
i l
l 4
~
1 CHANGE IN STERN GEN. IfRTER LEVEL, LOOP 1 2 CHANGE IN STEAN CEN. IfRTER LEVEL. LOOP 1
' 3. N IN N R 6 LEVEL
, gg it -
~
- 1. t 1
0 I
m-e Z
H 4 .
s 2 3-3 l 4 -
[
- E L-1 I I I I I I I I I T
~$ 20 40 60 80 100 120 140 180 180 200 $
TIME, SEC $
Figure 3.64 St. Lucie Unit 1 - Water Levels - CEA Drop eaurcu, - o r- ros rn.=p,ste
4.5 - 1 nDanun one anTIo 40 -
3.5 -
O M
t-E 30 -
Ia g .5 M
E.0 -
5- t i 1 t t t t E
i i i 1 i I i I I I k 20 40 60 80 100 220 140 160 180 200 f, 1*%
TITE, SEC $
e Figure 3.65 St. Lucie Unit 1 - DNBR - CEA Drop sTt uCLK Ou tutt .
10.57.5t.
Ca Ekkae 0
i 0 2
4 1 w I p 1 0 a 8
I 1 n r
4 1
E 1 0 I 6 e 1 p m 4 o -
r t 1 D -
1 A e 1 0 E I 4 C 1
4 t y r Y 1 t T
IY E i
v n
VT 1 0 i L IIYY TVTT I 2 1
t c 4 CIII a ATVV 4 e ECII RATT C R ECC 1 E -
RRRA 1 S O EE 1 0 1 TRRR 0 ,
AE .
I 1 E t t
LN . i 0POM 0PRT 4 M I U n
0O0O 3 T e nD8T 1 i 1 c I 0 u
. . . . 8 L 1Z34 .
4 t
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a I
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1
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o S
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r t 0 o c t
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O I 6 n C a Y C x R E u L A s l E M S F VXI 0 EUR .
. t LLP l 5E a F e R L M H ETA I ,
WAT T OEO PHT s
k 1 l
0 4 P r
e w
o 123 -
1 3
, t i
. 0 n l
3 U i
e c
s u L
0 .
l t 2 S 7
3 6 t 3 l 0 t l 1 e r
u
_ i F
g a 0
- - 0 0 0 0
4 1
2 1
0 1
0 8
0 6
0 4 a 0 OwEE 1O $ $aw(
4 L
M i
a 160 1 TOTAL FEEDWATER FLOW 2 TOTAL STEAM LINE FLOW i
l 140 -
l 120 O
W 1 c
E100 14 O
F-z -
$80 g z co w
D.
80 e t = e g
t
- e s
40 -
N t 1 J l l I I I I I I 5 20 0.0 1.0 2.0 3.0 4.0 S.0 G.0 7.0 9.0 9.0 10.0 k TIME. SEC lo
'?
8 Figure 3.68 St. Lucie Unit 1 - S. G. Flows - Seized Rotor (DNB)
. . . . . , , . . , . . . . . ......3,
l l ll l 5 5a[?8 0
I 0 1
n .
0 .
I 9 a
)
B N
D 0 (
I 8 r -
o t
o R -
d 0 e I
z i
7 e S
E .-
R -
U T e A 0 r -
R u E I 6 t f a r
O C e p
T E m
. S e G 0 T U I F 5 E l e
M u E I F V
A .
N' T -
0 1 I t
. 4 1 i n
U i
e 0 c I
u 3 L t
S 0 9 6
I 2 3
_ e r
u g
_ i 0 F s_ I 1
0
(
m
(
q r
(
m
( (
F - -
0 0 0 0 0 0 0 1 0 0 0 0 4 3 2 1 9 8 7 1 1 1 1 08 ll ll l
f) l1jl jl, l l 5ga~
0 I 0
- 1 s
S _ s.
t t 1 0 n.
I t 9 -
)
3 B t N D
g 0 (
~
I 8 r ~
o .
t .
o -
s R e t d -
0 e I z 7 i
. e EP S R1 UD TT s - m A t s v.
RT 1 0 e v-ENE I r fAR 6 u LU t OOT C a
r TOA e CR 2 E p T E S n EEP 0 e LRM 1 T
NOE I ICT 5 E e M r E .O I o R
Ovt E A. T C CAC -
1 0 1
I
. . . 4 123 t i
n U
i e
1 0 c
I 3 u L
t S
1 O 0 I
L 7 3
s e r
_ e u g
1 0 i 1
1 F s
1 0 0 0 0 0 0 0 0 %
4 6 4 2 0 8 6 9 6 5 5 5 6 6 6 6 u OO llll 1l
30 -
1 CHANCE IN TtHOTi-TtCOLD1 LOOP'IfLEC 1) i 2. CHANCE IN Tf HOT i-Tf COLO 1 LOOP if LEC 2 )
J. CHANCE IN TI HOT l-Tt COLD 1 LOOP 2f LEC 11
- 4. CHANCE IN TrHOT1-TtCOLD1 LOOP EtLEC 21 20 -
10 1 ES ' *E 3 4 3 E 4
teS
- u.
- O Q
4
-20 -
x
-30 -
8
'4 x
1 1 I I I I I I I I ?
-4k.0 1.0 2.0 3.0 4.0 5.0 6.0 70 !8.0 9.0 10.0 %
TIME, SEC k 5
Figure 3.71 St. Lucie Unit 1 - Loop Temperature Differences - Seizecl Rotor (DNB)
-. . . ye . . . . . . . ,
..g,33,
8 -
1 CHANCE IN AVE. PRIMARY COOLANT TEEP. , LOOP 1
- 2. CHANCE IN AVE. PRIMARY COOLANT TEMP. . LOOP t 5 -
e e I "w i 1
-- . NQ
) E
-1 N
, u.
1 o M
~
! w
-4 -
N N
-7 -
\
-10 -
i i I I I I E i I I 1
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?
Figure 3.72 St. Lucie Unit 1 - Average Temperatures - Seized Rotor (DNB)
...... r . . . . - . . . -..a..,..
1 FLOW IN COLD LEC ( 1,1 )
E 8.; -
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'F Figure 3.73 St. Lucie Unit 1 - Cold Leg Flows - Seized Rotor (DNB)
-- e r. -
3 f,* '. t . a t . ' * .
i __
200 - t. STEM 00ME PRESSURE CHANCE. LOOP 1
- 2. STEAN DONE PRESSURE CHANCE. LOOP 2 y
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Fiaure 3.78 St. Lucie Unit 1 - Power, Heat, Flux and Flow - Seized Rotor (Pressure)
STLUCND 03/12/ A1 21 32 51
s i
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l 00 '?
TIME. SEC $
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[ smuuas emine n s s t.n .s t.
140(m 1 ave. FUEL TEMPERATURE 1
t --
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10 E.0 3.0 4.0 50 60 70 9.0 90 10 0 k TIME. SEC '
k i Figure 3.79 St. Lucie Unit 1 - Fuel Temperature - Seized Rotor (Pressure)
STLt!CND E3/12/82 21 32.51
680 -
1 CORE INLET TEMPERATURE
, 2 AVE. CORE COOLANT TEMP.
- 3. CLAO TEMPERATURE 680 -
3 3
I 640 -
620 -
L9 W to "
600 -
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m TIME. SEC ?'
8 Figure 3.81 St. Lucie Unit 1 - Core Temperatures - Seized Rotor (Pressure)
STLt.?CND 23/12/92 21 32.S1
30 -
1 CHANGE IN T( HOT 1-T( COLD 1 LOOP .it LEG 1) 2 CHANCE IN Tt HOT 1-Tt COLD 1 LOOP 1( LEC 21
- 3. CHANGE IN TTHOT1-TCCOLD) LOOP afLEC 1)
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?
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STLUCND r.3 / ir / 9 2 E 1 3 E. 51 L . . . . .
J 1 CHANGE IN AVE. PRIMARY COOLANT TEMP., LOOP 1
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I STLtfCND 23/12/A2 21 32.51
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' .. . . - om mc ., /
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STLUCND E3/12/AE E 1. ? 2 51
40 -
1 CHANGE IN STEAM CEN. WATER LEVEL. LOOP L
- t. CHANCE IN STEAM CEN. WATER LEVEL. LOOP a 3 CHGNGE IN PRESSURIZER WATER LEVEL 30 20 10 3
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i Figure 3.86 St. Lucie Unit 1 - Water Levels - Seized Rotor (Pressure)
STI.l'Ct40 23/'t/P? 21 32.51
- - _= -. - __- .
- 4.5 -
1 MINIMUM DN8 RATIO 40 -
35 -
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TINE. SEC y 8
Figure 3.87 St. Lucie Unit 1 - DN3R - Seized Rotor (Pressure)
,.,m.,.. . _ _ _ . . . _ _
" ' ' ~
2.
1 MODERATOR REACTIVITY E. DOPPt.ER REACTIVITY 3 BORON REACTIVITY
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Figure 3.88 St. Lucie Unit 1 - React.vity - Seized Rotor (Pressure)
STll'CND 23 /12/ 9 C .L.32.5; b _
139 XN-NF-82-99
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CORE POWER (FRACTION Of 2700 MWT)
Figure 3.91 Doppler Feedback For Power Operation During A Steam 1ine Break
1 POWER LEVEL 140' - 1 WAT FLUX
- 3. TOTAL. PRIMARY COOLAPfi flow 120 100 d
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152 .XN-NF-82-99 4.0 DISCUSSION The ENC transient analysis performed for St. Lucie Unit I nuclear power plant demonstrates adequate margin to fuel and vessel design limits for a mixed core of ENC /CE fuel under normal operation, anticipated transients and postulated accidents The transients analyzed in Section 3 were selected because they were shown in the stretch power submittsl and the FSAR(7) to have less margin than the transients not analyzed.
The loss-of-load event was analyzed as an overpressurization transient and as such, bounds events such as the loss-of-feedwater or a loss-of-heat-sink in one steani gener stor. The action of the pressurizer safety valve in controlling the overpressurization is sufficient to demonstrate the accept-ability of the plant for overpressurization transients.
The excess-load event was analyzed as the limiting cooldown A00. The action of the variable high power trip in terminating the transient without a significant degradation in DNBR was sufficient to bound the results of an excess-feedwater transient.
The RCS depressurization transient represents the most pressure trans-ient in the A00 category and was used to test the TM/LP oias. As a test of the TM/LP bias, it was found to be more limiting than the CEA-withdrawal event.
The loss-of-coolant flow event is a limiting A00 for flow reduction and bounds the loss of A.C. power. Further, it provided one of the two transients which was analyzed to set the LCO for DNB.
The CEA-withdrawal event provides a bounding analysis for reactivity insertion transients at full power. The chemical and volume control malfunct ions all introduce smaller reactivity ramp rates than this event.
This transient is not limiting for the TM/LP bias, since it trips on variable
153 XN-NF-82-99 high power significantly before reaching the TM/LP trip setpoint. This occurs primarily because the LPD trip prevents analysis of this transient with a top-peaked core, which would have been far more limiting.
The CEA drop was analyzed for two reasons: (1) it is not protected by a trip; and (2) it was used to verify the LC0 based on DNB. The transient simulation supports the existsing LCO.
The seized-rotor event was analyzed as both a DNB transient and as a pressure transient. It was found to be a limiting pressure transient, and it does produce an MDNBR which is essentially at the 95:95 limit for the XNB critical heat flux correlation. The expected pin damage is, however, significantly less than 1%, and thus meets the criterion for radiation release.
The asymmet-ic steam generator transients were not analyzed since the analyses for prior cycles demonstrated that the ASGPT provided for a reactor scram before the asymmetric reactor inlet flow condition, against which it was designed to protect, could occur. ,The limiting event, a loss-of-load to one steam geno ator, results in a trip signal within 2.5 seconds. A cooldown heatup transient initiated in the steam generators requires about 5 seconds to reach the core inlet. Allowing 1.4 seconds from the time the trip condition exists until the CFAs begin to f all leaves 1.1 seconds for the rods to f all before the asymmetry develops.
The steam generator tube rupture transient was not reanalyzed expli-citly. The adequacy of the TM/LP trip to protect against a rapid depressuri-zation transient was demonstrated for the bounding case, a f ailure of all pressurizer relief valves to open, which resulted in an acceptable MDNBR. The steam generator tube rupture event results in a less severe d'e pressurization
_ _ _ _ _ ~ _ . _ _ _ _ _ _ _
154 XN-NF-82-99 transient, and thts the TM/LP trip protects against fuel damage for the mixed core. Since this protection removes the fuel dependency of the analysis, it is therefore anticipated that the accident analysis would progress exactly as described in analyses for prior cycles.
In summary, the analysis presented in this report shows acceptable results for core thermal margin during A00s or pas for Cycle 6 at St. Lucie Unit 1.
155 XN-NF-82-99
5.0 REFERENCES
- 1. "ExxonNuclearDNBCorrelationforPWRFuelDesign,"XN-NF-621(P1,'
Rev. 1, Exxon Nuclear Company, Inc., Richland, Washington 99352, April 1982.
- 2. " Design and Safety P.eport for St. Ltcie Unit 1 Cycle 4 at 2700 MWt,"
Attachment 3 to Operating License DPR-67, November 14, 1980.
- 3. " Description of the Exxon Nuc' ear Plant Transient Simulation Model for Pressurized Water Reactors (PTSPWR)," XN-74-5, Rev. 1, Exxon Nuclear Company, Inc., Richland, Washington 99352, M?v 1975.
- 4. Letter, T. P. Gates to C. G. O'Farrill (FPL), " Transmittal of St.
Lucie Unit 1 Flow Coastdown Data," F-CE-7775, October 25, 1982.
- 5. St. Lucie Unit 1 Technical Specifications, Appendix A to License
- DPR-67, as per Amendment 45. Noi.cmber 3, 1981.
- 6. Moody, F. J., ASME Transactions, p.134, February 1965.
- 7. Florida Power & Light Company, St. Lucie Plant, Unit No. 7, Updated Final Safety Analysis Report.
- 8. "St. Lucie Unit 1 Safety Analysis Report," XN-NF-82-81, Exxon Nuclear Company, Inc., Richland, Washington 99352, December 1982.
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1/7/83 l
PLANT TRANSIENT ANALYSIS FOR ST. LUCIE UNIT 1 DISTRIBUTION F.T. Adams G.C. Cooke N.F. Fausz T.J. Helbling J.S. Holm J.D. Kahn R.H. Kelley M.R. Killgore T.R. Lindquist J.N. Morgan W.I. Nutt F.B. Skogen G.A. Sofer R.B. Stout G.N. Ward P.D. Wimpy C.H. Wu USNRC/J.C., Chandler (25)
FPL/C.G. O'Carrill (10)
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