ML17266A520
| ML17266A520 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/29/1981 |
| From: | FLORIDA POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML17212A963 | List: |
| References | |
| 2-0120043, 2-120043, NUDOCS 8111050503 | |
| Download: ML17266A520 (275) | |
Text
Page 1 of 9 Emergency Procedure 2-0120043 Rev 0 ICC pc up (>i.,4)
FLORIDA POWER & LIGHT COMPANY ST+ LUCIE PLANT UNIT 2 EMERGENCY PROCEDURE NUMBER 2-0120043 REVISION 0 INADEQUATE CORE COOLING (ICC)
October 29, 1981 REV FRG Approval Plt Mgr TOTAL NO. OF PAGES 9 Biii050503 811027 PDR ADOCK 05000389
'i A PDR
F I
Page 2 of 9 FLORIDA POWER & LIGHT COMPANY ICC ST LUCIE PLANT UNIT 2 EMERGENCY PROCEDURE NUMBER 2-0120043 ICC REVISION 0 1.0 scopE To'rovide awareness to the operator of degraded core cooling conditions. Assumes all RCP's are stopped.
2~0 SYMPT(MS NOTE: ~An of the following symptoms may be an indication of an approach to inadequate core cooling.
2,1 DNB considerations (alarms) 2.1 Indications/Alarms 2.1 ~ 1 Nuclear Instrument Channel Deviation, erratic L-34, L-40
- 2. l. 2 Variable Overpower (RPS )
L-9, L-17 2.1.3 Hi Local Power Density (RPS )
- 2. 1.6 ZW/f t.
K-17, H-5, H-6, H-7, H-8, L-43 2.1.7 Axial Power L-22, L>>30, L-43
Page 3 of 9 ICC EMERGENCY PROCEDURE NUMBER 2-0120043 ICC) REVISION 0 2~0 SYMPTOMS: (Cont.)
~
2 eat Sink Considerations 2.2 Indications/Alarms 2.2.1 S/G level at or near zero G-'1, G-9 2~2~2 S/G pressure rises to dump valve setpoint, unless a break occurs, in which case pressure would be continually decreasing.
P-17, P-19 2 ~ 2.3 Coincident pressure decrease in the secondary side S/G and the RCS.
P-17, P-19, RTGB203, RTGB206 Th & Tc sub-cooled and decrease, then increase sharply.
H-5, H<<6, H-7, H-8 2.2 ' After approx. constant temperature, the primary coolant temperature increases well above secondary saturation temperature.
K-17 2 ~ 2.5 Opening of PORV's H-12, H-20, H<<9, H-10, H016, H-24
Page 4 of ICC EMERGENCY PROCEDURE NUMBER 2-0120043 (ICC) REVISION 0
2.0 SYMPTOMS
(Cont.)
2 ' LOCA Considerations 2.3 Indications/Alarms 2.3.1 Decreasing motor amps on RCP's or erratic indication 2 3.2 Rapidly decreasing secondary side S/G/RCS 8 P 2.3.3 RCS saturated conditions RTGB203 2.3 ~ 4 RCS Superheated conditions RTGB203, DDPS, core exit thermocouples 2 '.5 Heat transfer from secondary to primary 2 ~ 3.6 Erratic or off-scale przr level indication RTGB203 237 Invalid ex-core nuclear detector indication due to voiding. RPS 2.3.8 Invalid in-core neutron detector indications due to core uncovery. DDPS 2.3 9 Excessive core exi't thermocouple readings.
DDPS 2.4 Plant conditions that could 2.4 Indications/Alarms lead to ICC 2.4.1 Reactor trip (TM/LP) 2.4 ' LOCA 2.4.3 Loss of feedwater 2 '.4 Main Steam line break 2 '.5 S/G tube rupture 2 '.6 Loss of RC flow
Page 6 of 9 ICC EMERGENCY PROCEDURE NUMBER 2-0120043 ICC REVISION 0 IMMEDIATE OPERATOR ACTION 4 ' Ensure control of S/G levels 4 ' With Main or AFW NOTE: If only one S/G is available as a heat.,sink, adequate core cooling can still be maintained.
4 ' Ensure control of steam 4 2 With SBCS or ADS flow 4.3 With steam flow and FW flow, 4.3 'ressure control with maintain Th 20 F below przr heaters or auxiliary saturation temperature spray for existing RCS pressure 4~4 Ensure CVCS can maintain przr level 4 5 Verify natural circulation:
4 5.1 Loop A T less than full power W T (44 F) 4.5.2 Tg constant or decreasing 4 ' ' TP> stable, not steadily increasing 4.5.4 No abnormal differences between Th RTD s and core exit thermocouples 4 ' If natural circulation lost'.6 As indicated by:
4 '.1 RCP motor amps decreasing 4 '.2 Secondary/Primary ih P rapidly decreasing or equal 4.6.3 Th/T essentially equal E
4 6.4 Erratic przr level or off scale 4.'6.5 Erratic excore NIS 4.6.6 Core exit thermocouples ind'icate
-super heated conditions
Page 7 of 9 ICC EMERGENCY PROCEDURE NUMBER 2-0120043 (ICC) REVISION 0 4.0 IMMEDIATE OPERATOR ACTION: . (Cont.)
4.7 Make preparations to supply core cooling with HPSI pumps via cold leg injection, using the PORV's to initiate core coolingo 5~0 SUB S UENT ACTIONS CHECK 5.1 Restart RCP's if possible, using the following starting criteria:
5.1.1 A LOCA does not exist 5 1.2 RCS pressure/temperature permit restart 5.1.3 RCP services (power, oil lift, CCW, etc.) are ava ilab le 5.2 If a steamline or FW line break is indicated, FW should be admitted to the non-affected S/G only 5.3 If condensate is limited, conduct a plant cooldown and initiate SDC prior to running out of water 5.4 Refer back to EP that led to this procedure for further instructions 6 0 PURPOSE/DISCUSSION:
Inadequate core cooling (ICC) is a term that defines a reactor core condition that is degraded beyond that anticipated during normal plant operations. The ICC conditions could result from operator error or a combination of equipment failures. In order to induce ICC, established operating procedures must have been violated or equipment failures greater than considered credible in design criteria have occured This procedure is to be cohsidered as a guide to avoid ICC and not a replacement for procedures which refer to specific accidents or conditions.
Page 8 of 9 ICC EMERGENCY PROCEDURE NUMBER 2-0120043 ICC) REVISION 0 6 0 PURPOSE/DISCUSSION: (Cont.)
On CE plants the core is protected from DNB by either the TM/LP Trip or by the core protection calculators. these systems trip the reactor automatically if the design DNBR is approached, assuring that a lower DNBR, which could lead to ICC, is not reached. A postulated flow blockage in the core support plate or fuel channel would result in a flow maldistribution in the core, that could result in a lower DNBR. Any evidence of core non-symmetry should be investigated.
Loss of feedwater to both S/G during power operation has the potential of producing conditions which could lead to ICC.
break LOCA.
The ~
Compliance with LOCA guidelines assures actions are accomplished.
g.gC~
that the appropriate corrective discussed is synonymous with a small If core parameters violate tech. specs. or are approaching these limits the reactor must be tripped.
Whenever any break results in the release. of high energy fluid to containment, indications associated with containment parameters must be compared and verified.
If a break in the secondary system is suspected feedwater should be provided only to the S/G known to be intact.
Do not exceed 75 F/hr cooldown rate during steam dump operation.
If a SIAS occurs, operate the HPSI pumps until the RCS is at least 50 subcooled, and there is level indication in the przr. Restart HPSI pumps as necessary to maintain this condition.
If RAS occurs assure that flow rates are > minimum HPSI pump flow, (30 gpm). If necessary stop charging pps until one HPSI pp is operating.
,Restart pps as necessary to maintain 50 F subcooling.
If a S/G tube rupture is suspected isolate the faulted S/G. Peed and dump steam from the intact S/G only.
Maximum safety infection flow and PORV operation is, suggested only as an alternative due to multiple malfunctions. It is the least desirable means of inventory and pressure control.
Page 9 of 9 ICC EMERGENCY PROCED URE NUMB ER 2>>0120043 ICC) REVISION 0 7 '
REFERENCES:
7.1 St. Lucie Unit Pl Emergency Procedures 7.2 St. Lucie Unit 81 FSAR Chapter 6 7 3 CE guidelines CEN 152 7~4 'raf t of NUREG 0799 8.1 Normal log entries
~
8.2 Applicable recorder'harts 9 0 APPROVAL:
Reviewed by the Facility Review Group 19 Approved by ,Plant Manager 19 REV Reviewed by the Facility Review Group 19 Approved by ,Plant Manager 19 "LAST PAGE" TOTAL NOe OF PAGES 9
~ ~ ~
q
Attachment to L-81-433 October 6, 1981 A. Response to fire protection questions generated in the September 23, 1981 FPL/NRC meeting B. Revisions to various 440. series questions C. Revised FSAR Chapter 15
/
RESPONSES TO FIRE PROTECTION qUESTTOM GmmMSO 1N THE SE USER P, resl FPX fmC Maar%G 1
'UESTION; State the ability to have the capability to'o to cog shutcbwn van 725cH~5 Df a fKc evert using only o~ powero
'NS%'ER" St. Lucie Unit 4'2 has the capabTiity to poem-aH 8m ecpCprnent necemay to 8o to co@ shutdown utilizin only onsiN power.
Systems necessary to achieve zmd maintain cold shutdovm (one train) from either thcontrol room m emergency corrtrol statlonM will be repaired within 72 hou.s.
Were alternate or dedicated Autdo~m capability is provided for a specific f~ archy ~ ability to &9lleve and main&in coM &utdown coiM1ilons %'LUlln 72 hou s %LEE be provldede QUESTION Ackhess the foHov mg instrumentation recornrnended to be inchx4d on th" hot shutdown paneL a Pressurizer pressure and ievei-
- b. Reactor coolant hot leg temperature and dither coM tcrnperatma or TAVG.
c.Stcam generator pressure and level (wiYierange) cL Source ranEe flux monitor
- c. ActuaI fhw rneasurerne~ for aII pumps used.
- d. Level indication for aD tardes vms (CS'0.
Fi.N5%'ER- The insTrumentation alxf control capabilities of the Hot Shutdov:n Panel (HSDP) can be found in Table 7.0-2 of the FSAR =(copy attacheco a) tent HSDP has indication for both p:esscrizer level and presses.e.
b)The HSDP has'coM keg tengmrature inatcation. Based on past operating experience at St. Lucie Unit P1 arith natu;al circuiations cooÃoem and the control and indication of steam generator parameter~ the utiTization of cold leg tempe. atu.-e indication oMy is deemed achquate.
d The HSOP has steam generator vide range press' indications and narTov. range Lvcl irKEication-reads from 57 in&vs below ~ Th na.-row range Jevei indication sep3rator section of th steam gwerator.
top of t."~ tube bundle to th d) Th HOSP has m~utron I ve.'otors, Ve do however consickr these monitors unneces~y because:
I) The control rods (v:ith on stuck rod) acMs sufficient negative
~~en
~
reactivity to maintain a %utdown margin in hot standby with no bacon
- 2) The two sources h>use hc~
of L
~ter utE1ized fo.- reactor coolant system A!
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'le) AF% fbw mdicatiori. ~ ~ 1 ~
';;, pUAlps EA acMition there is straa
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The HSDP 'presently has pump Am mdicatiqg Bahts for'hese jgiicathgl for each puMp section P, mrna> pre~< and d ~<g '~~ore ~leach indicate Bow tnr~ the purips.:.
V~
~V V
",, CC%'pump Xhw in@mtion 1 ~
~ Ln the event,~t it is necessary to verHy that:~ ha~~ not @st
,I "-:> CC%', there is iocaf mdication for.. suction Maiha s P and pump C ~
- ,'Lscharge press~ %%eh vM incBaite pm'h%'.. 1 1
1
- j.'VpufffklwhMBcation V
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",. Jn the event that it is txxessary to verify that. we have not. ko ~
"'C%'2'here is RmQ fjovr mdication in the CC5'udding Sx.each
". CCRfJCW'hmt exdzange.
~ 1 II 1
- ";", 4 addition, CCV R IG%'forrnance caA be evaheted utiTizhg 1*
<'Rag temperature indication on'the CCV//i'eat exchanga'.'.
I', V 9 CSE hvej=indication bz the, event that it isvri~sary to ~~By the &ver in. AM.
- cond nsate stot age talk,Cere ts a'iocai mecharQcai irNcator.
~ 1, QUEST ON: Discuss the storage and reiMUr of cab& danmged by &'ev and 1
necessary for aoM snutdown.
14 AXSWER: For those areas vzhere reci~daxrt cabL is assumed to be dama~
a alii"rent guanuty of cab'aH be stared on site te Noire by.'ire repair af cab'ecessary for cold shutdown.
& a temporary.rneamrei Xoc expedicious re~ only; sections of cable vAich have, been damaged wiU be, repkacecL Proper testhg1wiil
~ ~ be corduct W ~re that the portions of cabL not.4.in@ repiaced unda~~d. M aU cases th: ~finny of cab'iQ be considered an
~
~ +
ein agency condit"ion only. At the earfiest possibh tinx: e new cabL weal be run from the power suppiy to the equipment for those cabLs
'b.rnaged by fire and necessary Rr coM shutcbwn.
~ ' QUESTION
' Supply a fist of eguirnent &at is rmmssary to achieve and mamtain co}d shutdov'n.
V ~
ANS%'ER: 4".coM &utdown fist is attached +hi&,aho indicates the for hot standby. equiprrent'ecessary g,
1'
Page 1 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 1. Diesel Generator g DO Pump 2A MCC 2A7 8 SWGR 2A2 & 2A3 37 g DO Pump 2B MCC 2B7 9 SWGR 2B2 & 2B3 34 II
+DO Storgae Tank 2-A ADO Storage Tank 2-B
+DG-2A Set 4 DG-2B Set Q I-SE-17-1A 6 2A DG-2A Eng Term Blocks 2Al & 2A2 8 (DG Fuel Oil Supply Valves) 120 V-AC PP-211, MCC 2A7 8 SWGR 2A2 & 2A3 37 4 I-SE-17-1B & 2B DG-2B Eng Term Blocks 2B1 & 2B2 9 (DG Fuel Oil Supply Valves) 120 V-AC PP-212, MCC 2B7 9 SWGR 2B2 & 2B3 34 II
+ LS-17-542A, 543A, 552A DG Eng Term Blocks 2A1 & 2A2 8
-550A, 551A, 553A 120 V-AC PP-211, MCC 2A7 8 (DG Day Tank Level Switches) SWGR 2A2 6 2A3 37 ALS-17-542B, 543B, 552B 9 DG Fng Term Block 2Bl & 2B2 9
-550B, 551B, 553B 120 V-AC PP-212, MCC 2B7 9 (DG Day Tank Level Switches) SWGR 2B2 & 2B3 .34 II
Page 2 ST LUCIE UNIT NO. 2.
FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 2. Auxiliary Feedwater 4 AFW Pump 2A SWGR 2A3 37 O'AFW Pump 2B SWGR 2B3 34 II 4AFW Pump 2C Aux Steam & Mech Controller 0 I-MV-09-9 MCC 2A5, SWGR 2A2 & 2A3 37 (AFW Pump 2A Iso Valve)
I-MV-09-10 (AFW Pump 2B Iso Valve)
MCC 2B5$ SWGR 2B2 & 2B3 34 II 4 I-MW-09-11 Local Starter (AFW Pump 2C Iso Valve)
% I-MV-09-12 (AFW Pump 2C Iso Valve) Local Starter 4 I-MV-08-12 125 V-DC 2A Bus (Aux Turbine Steam Supply) 4 I-MV-08-13 125 V-DC 2B Bus (Aux Turbine Steam Supply) 4 I-SE-09-2 125 V-DC 2A Bus (AFW Pump 2A Iso Valve) 0 I-SE-09-3 125 V-DC 2B Bus (AFW Pump 2B Iso Valve) 4 I-SE-09-4 125 V-DC 2B Bus (AFW Pump 2C Iso Valve) 4 I-SE-09-5 125 V-DC 2A Bus (AFW Pump 2C Iso Valve)
I.
Page 3 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE 6 CABLE AREA .
- 2. Auxiliary Feedwater g I-HCV-08-1A, 1B (Main Steam Iso Valves) g I-MV-08-1A, lB (Main Steam Iso Bypass Valves)
+Turbine Stop Valves EHC System
Page 4 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE ARFA
- 3. Chemical & Volume +Charging Pump 2A 18I SWGR 2A2 & 2A'5 37 Control 4tCharging Pump 2B 18II SWGR 2B2 & 2B3 34II g Charging Pump 2C 18III SWGR 2AB 28 SWGR 2A2 & 2A3 37 SWGR 2B2 & 2B3 34II 4 Boric Acid Makeup Tank 2A & 2B 17 28 8 V-2553 18 SWOR 2AB (Charging Pump 2C Bypass) 2A2 37 Q V-2554 18 SWGR (Charging Pump 2B Bypass) 4%V-2555 18 SWGR 2B2 34II (Charging Pump 2A Bypass) 9'-2508 & 2509 17 MCC 2B5, SWGR 2B2 & 2B3 34II (BAÃZ Gravity Peed Valves)
Q V-2504 18 MCC 2B5, SWGR 2B2 & 2B3 34II (RWT Supply Valve)
'4 I-SE-02-01 14 RTGB-205 42 (Charging Line Iso Valve) 125 V-DC Bus 2A ~OUI Q I-SE-02<<02 14 RTGB-205 42 (Charging Line Iso Valve) 125 V-DC Bus 2B 34II
+ I-SE-02-03 14 Transfer Control Panel 2A 42 (Aux Spray Iso Valve) 125 V-DC Bus 2A 34II
I 0
0 0
Page 5 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 3. Chemical & Volume 4 I-SE-02-04 Transfer Control Panel 2B 42 Control (Cont'd) (Aux Spray Iso Valve) 125 V-DC Bus 2B 34II
+BAMT 2A Heater Banks 17 MCC 2A5, SWGR 2A2 & 2A3 37 MCC 2B5, SWGR 2B2 & 2B3 34II 4BAMZ 2B Heater Banks 17 MCC 2A6, SWGR 2A2 & 2A3 37 MCC 2B6, SWGR 2B2 & 2B3 34II 4 TIC -2206 17 MCC 2A5, SWGR 2A2 & 2A3 (Temp Controller)'fTIC-2207 17 MCC 2B5, SWGR 2B2 & 2/3 34II (Temp Controller) gTIC-2208 17 MCC 2A6, SWGR 2A2 & 2A3 37 (Temp Controller)
OTIC-2209 17 MCC 2B6, SWGR 2B2 & 2B3 34II
+ Boric Acid Heat Trace Dist Transfer 2A 51 MCC 2A5, SWGR 2A2 & 2A3 37 Dist Transfer 2B 51 MCC 2B5y SWEAR N~Z 4 ZSQ 34II
0 Page 6 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE 6 CABLE AREA
- 4. Reactor Coolant + Pressurizer Heaters 2A 14 Htr Distr Bank Pl Panel 14 (150 KW Proportional) SCR Prop Pvr Controller 2A 34I Press Htr Bus 2A3 34I SWGR 2A3 37
+Pressurizer Heaters 2B Htr Distr Bank P2 Panel 14 05~ lAl f'eopoWtoOQ ) SCR Prop Pwr Controller 2B 34I Press Htr Bus 2B3 34I SWGR 2B3 an%,
Page 7 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 5. HVAC Equipment & Elec Equip Rm Supply Fan (2 HVS-5A) 48 MCC 2A5 SWGR 2A2 & 2A3 37 4 Elec Equip Rm Supply Fan (2HVS-5B) 48 MCC 2B5, SWGR 2B2 & 2B3 34II
+ Elec Equip Room Exh Fan (2HVE-11) 43 MCC 2A6, SWGR 2A2 & 2A3 37
+ Elec Equip Room Exh Fan (2 HVE-12) 43 MCC 2B6i SWGR 2B2 & 2B3 34II
+ Reactor Supports Supply Fan 14 MCC 2A5, SWGR 2A2 & 2A3 37 (2 HVE-3A)
+Reactor Supports Supply Fan MCC 2B5, SWGR 2B2 & 2B3 34II (2 HVS-3B)
+ Q ECCS Area Supply Fan (2 HVS-4A) 39 SWGR 2A2 & 2A3 37
+ QECCS Area Supply Fan (2 HVS-4B) 39 SWGR 2B2 & 2B3 34II gECCS Area Exhaust Fan (2 HVE-9A) 39 MCC 2A6, SWGR 2A2 & 2A3 37 gECCS Area Exhaust Fan (2 HVE-9B) 38 MCC 2B6i SWGR 2B2 & 2B3 34II
% Po~er Roof Ventilator (2 RV-3) 34I MCC 2A5, SWGR 2A2 & 2A3 37 g Power Roof Ventilator (2 RV-4) 34r MCC 2B5, SWGR 2B2 & 2B3 34I W Control Room AC 2 HVA/ACC-3A) 42II MCC 2A6, SWGR 2A2 & 2A3 37
+ Control Room AC (2 HVA/ACC 3B) 42II. MCC 2B6, SWGR 2B2 & 2B3 34II 4 Control Room AC (2HVA/ACC 3C) 42II MCC 34I 2'WGR 2A2 & 2A3, 2B2 & 2B3 37/34II
I Page 8 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE 6 CABLE AREA
- 6. Makeup Water Primary Water Pump 2A MCC-2A2 Primary Water Pump 2B MCC-2B2
0 Page 9 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 7. Electrical Equipment Emergency Lighting LP 227 42 125 V-DC Bus 2A 34II
+Emergency Lighting LP 228
+Emergency Lighting LP 216 2'IRE 42 42 125 V-DC Bus 2B MCC 2A6, SWGR 2A2 & 2A3 34II 37
+Emergency Lighting LP 226 42 MCC 2B6, SWGR 2B2 & 2B3 34II
+ Station Battery Charger 2A 34XZ MCC 2A5, SWGR 2A2 & 2A3 37 0 Station Battery Charger 2B MCC 2B5, SWGR 2B2 & 2B3 34II 34'4K
+ Station Battery Charger MCC 2AB1 SWGR 2AB 28
Page 10 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 8. Ins trumentation ~ PT<<1102A 14 RTGB-206 42 (Pressurizer Pressure) Inst Bus 2 MA, Static Iny Cab 2A 34Iy 4 PT-1102B 14 RTGB-206 42 (Pressurizer Pressure) Inst Bus 2 'fB, Static Inv Cab 2B 34I 4 PT-1102C 14 RTGB-206 42 (Pressurizer Pressure) Inst Bus 2 MC, Static Inv Cab 2C 34I
+ PT-1102D 14 RTGB-206 42 (Pressurizer Pressure) Inst Bus 2 MC, Static Inv Cab 2D 34I
+ LT-1110X 14 RTGB-203 42 (Pressurizer Level) 120 V-AC PP-201 34I MCC 2A6, SWGR 2A2 & 2AB 37
+ LT-lllOY 14 RTGB 205 42 (Pressurizer Level) 120 V-AC PP-202 34I MCC 2B6, SWGR 2B2 & 2B3 34II 4 TE-1115 14 RTGB-203 42 (RCS Temperature) 120 V-AC PP-201 37 MCC 2A6, SWGR 2A2 & 2A3 37
+ TE-1125 14 RTGB-205 42 (RCS Temperature) 120 V-AC PP-202 34I MCC 2B6, SWGR 2B2 & 2B3 34II
+ PT-08-lA Transfer Control Panel 2A 37 (Steam Gen Pressure) RTGB 202 42 MCC 2A6, SWGR 2A2 & 2A3 37 120 V PP-'201 34I 5 PT-08-1B Transfer Control Panel 2B 34II (Steam Gen Pressure) RTGB 202 42 MCC 2B6, SWGR 2B2 & 2B3 34II 120 V-PP-202 34I
Page ll ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 8. Instrumentation + LT<<9013A, 9023A RTGB 202. 42 (Cont'd) (Steam Gen Level) 125 V-DC Inst Bus MA, Stat 34l; Inv Cab MA MCC 2A5, SWGR 2A2 & 2A3 37 WLT 9013B$ 9023B 14 RTGB-202 42 (Steam Gen Level) 125 V-DC Inst Bus MB, Stat 34I Inv Cab MB MCC 2B5, SWGR 2B2 & 2B3
+ L'g-9013C$ 9023C RTGB"202 42 (Steam Gen Level) 125 V-DC Inst Bus MC, Stat 34I Inv Cab MC MCC 2A5, SWGR 2A2 & 2A3 37 O'LT-9013D$ 9023D 14 RTGB-202 42 (Steam Gen Level 125 V-DC Inst Bus MD, Stat 34I Inv Cab MD MCC 2B5, SWGR 2B2 & 2B3 34II
+ LT-2206 17 MCC 2A6$ SWGR 2A2 & 2A3 37 (BAMT Level) PP-201 34I
+ LT-2206 17 MCC 2B6$ SWGR 2B2 & 2B3 34II (BAMT Level) PP-202 34I
+ LT-12-11 10 RTGB-202 42 (CST Level) 120 V-AC PP-201 34I MCC 2A6, SWGR 2A6 & 2A3 37 O'T-12-11B 10 RTGB-202 42 (CST Level) 120 V-AC PP-202 34I MCC 2B6, SWGR 2B6 & 2B3 34II
4 Page 12 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 8. Instrumentation + FT-09-2A2 (Cont'd) (AFW Pump 2A Flow)
$ FT-09-2B2 (AFW Pump 2B Flow)
+ FT-09-2C2 (AFW Pump 2C Flow) 4 Q FI-14-1A PP-201 34I (CCW Pump 2A Flow) MCC 2A6, SWGR 2A2 & 2A3 37 5 FI-14-1B PP-202 34I (CCW Pump 2B Flow) MCC 2B6, SWGR 2B2 & 2B3 34II 0 FIS-21-9A 13 PP-201 34I (ICW Pump 2A Flow) MCC 2A67 SWGR 2A2 & 2A3 37
+ FIS-21-9B 13 PP-202 34I (ICW Pump 2B Flow) MCC 2B6, SWGR 2B2 & 2B3 34II
+ % FT-25-21A1 39 (ECCS Exh Fan 9A Flow) 44 FT-25-21-Bl 38 ECCS Exh Fan 9B Flow 9 4 FT-3306 16I (LPSI Pump 2A Flow) 5 4 FT-3301 16II (LPSI Pump 2B Flow)
Page 13 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 9. Miscellaneous Valves PCV-1100E & 1100F 14 (Pressurizer Spray)
(Valves whose spurious opera- V-1460 14 tion could (RCS Vent Iso Valve) prevent safe plant shutdown) V-1461 14 (RCS Vent Iso Valve)
V-1462 (RCS Vent Iso Valve)
V-1463 14 (RCS Vent Iso Valve)
V-1464 (RCS Vent Iso Valve)
V-1465 14 (RCS Vent Iso Valve)
V-1466 14 (RCS Vent Iso Valve)
V-2515 14 (Letdown Iso Valve)
V-2516 14 (Letdown Iso Valve)
.V-2522 24 (Letdown Iso Valve)
(ARVea~n Eo<V<P) 2g V-1474 14 (PORV)
Page 14 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 9. Miscellaneous Valves V-1475 (Cont'd) (PORV)
V-1476 14 (PORV Iso Valve)
V-1477 14 (PORV Iso Valve)
I-MV-08-14 & 16 Local Starters (ADV Iso Valve)
I-MV-08-15 & 17 Local Starters (ADV Iso Valve)
PCV-8801, 8802, 8803, 8804, 8805 47 (Condenser Dump Valves)
Page 15 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE ARFA
- 10. Safety Infection + Refueling Water Tank
+ 4 LPSI Pump 2A 16X SWGR 2A3 37 Q4 LPSX Pump 2B 161r SWGR 2B3 34II
+ V-3480 MCC 2B5, SWGR 2B2- & 2B3 34II (SDC Xso Valve) 40 V-3481 14XX MCC 2AS,,SWOR 2A2 & 2A3 37 (SDC Xso Valve) g V-3651 14XZ MCC 2B6, SWGR 2B2 & 2B3 34II (SDC Iso Valve)
+ + V-3652 14Xr MCC 2A5, SWGR 2A2 & 2A3 37 (SDC Xso Valve)
)}f + V-3545 14XX MCC 2A9, 34I (SDC Crosstie) SWGR. 2A2/'2B2 & 2A3/'2B3 37/34II 4 V-3664 24 MCC 2A6, SWGR, 2A2 & 2A3 37 (SDC Xso Valve)
Q V-3665 24 MCC 2B5, SWGR 2B2 & 2B3 34II (SDC Xso Valve)
Q + FCV-3306 16I MCC 2A5, SWGR 2A2 & 2A3 37 (SDC Control)
+ 'g FCV-3301 16I'I MCC 2B6, SWGR 2B2 & 2B3 34XX (SDC Contxol) 4 g HCV 3657 16I MCC 2A5, SWGR 2A2 & 2A3 37 (SDC Control)
Page 16 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS
.,ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE YSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA 10 Safety Injection g $ HCV-3512 MCC 2B5, SWGR 2B2 .& 2B3 34II (Cont'd) (SDC Control)
'f +V-3456 16I MCC 2A5, SWGR 2A2 & 2A3 37 (SDC Block Valve)
+ V-3457 16II MCC 2B5, SWGR 2B2 & 2B3 34II (SDC Block Valve)
Q V-3517 16I MCC 2A5, SWGR 2A2 & 2A3 37.
(SDC Block Valve)
+ V-3658 16II MCC 2B6$ SWGR 2B2 & 2B3 34II (SDC Block Valve) 4 V-3444 (SDC Block Valve)
+ V<<3432 (SDC Block Valve)
+ 2I-V7161 (1514) 24 (CS Block Valve)
+ 2I-V7164 (1514) 24 (CS Block Valve)
+ HCV-3615 16I MCC 2A5 SWGR 2A2 & 2A3 37 (SIS Block Valve)
+ $ HCV-3635 16II MCC 2B6, SWGR 2B2 & 2B3 34II (SIS Block Valve)
Page 17 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 10. Safety (Cont')
Injection + V-3733, 3735, 3737 &3739 14 (SIT Vents) 44 V-3734, 3736, 3738 & 3740 14 (SIT Vents)
Page 18 ST.LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA ll. Main Steam I-MV l8+ g NQ 6 (Atmospheric Dump Valves)
'+ I-MV-08-18B & 19B (Atmospheric Dump Valves)
U
~
Page 19 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 12. Component Cooling W +CCV Pump 2A SWGR 2A3 37 Water
+ QCCW Pump 2B SWGR 283 34II
Page 20 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE & CABLE AREA
- 13. Intake Cooling + + ICW Pump 2A SWGR 2A3 37 13'3 Water S.ICW Pump 2B SWOR 2B3 3411
Page 21 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM E UIPMENT RE UIRED AREA POWER SOURCE 6 CABLE AREA
- 14. Hot Shutdown Panel + %SIAS "A" Block 34II (Only items not listed above) + +SIAS "B" Block 34II
+LI-9113 (Steam Gen Level)
+LI-9123 (Steam Gen Level)
+ PI-8113 (Steam Gen Pressure)
'+ PI-8123 (Steam Gen Pressure)
+ PI-1108 (Pressurizer Pressure)
+PI-1107 14 (Pressurizer Pressure)
+ LI-1105 (Pressurizer Level) 14
+ LI-1106 (Pressurizer Level)
+ TI-1145 (RCS Temperature)
+ TI-1125-1 14 (RCS Temperature)
+ + TI-3351Y 16I (SDC Temperature)
Page 22 ST LUCIE UNIT NO. 2 FIRE HAZARD ANALYSIS ESSENTIAL E UIPMENT LIST BY SYSTEM NORMAL MODE FIRE FIRE SYSTEM AREA POWER SOURCE 6 CABLE AREA
- 14. Hot Shutdown Panel +,+ TI-3352Y 16II (Cont'd) (SDC Temperature)
VM-1606-1 (Diesel Gen 2A Volts)
VM-1616-1 (Diesel Gen 2B Volts)
WM-1606-1 (Diesel Gen 2A Watts)
WM-1616-1 (Diesel Gen 2B Watts)
JI-001A1 (Neutron Flux)
JI-001B1 (Neutron Flux)
- Equipment Required for Hut Standby.
- Equipment Required for Cold Shutdown.
C-E Pov~er Systems Tei. 203/688-1911 Combustion Engineering, Inc. Teiex: 99297 1000 Prospect Hill Road Windsor, Connecticut 06095 IR% SYSTEMS St. Lucie Plant Vnit No. 2 - 1978-890 MW Extension Mr. K. N. Chow Ebasco Services, Inc.
2 World Trade Center 80th Floor New York, NY 10048
Subject:
Revisions to NRC/RSB (440.X) Responses
Dear Mr. Chow:
Revisions to the responses for the following NRC questions are attached:
1.~ Question 440.7: Revised to include effects
~ ~ ~
of moderate energy line break on core cooling. ~
- 2. guestion 440. 18: Revised to confirm commitment to redundant pressurizer heater cutoff on low level.
- 3. guestion 440.25: Re iseg.to reflect final locked rotor analysis.
4.
+go-@v gueftion 440.81(d: Revised td provide additional*discussion on the single failure for the feedwater line break analysis.
- 5. guestion 440.81(f): Revised to include a discussion of conservatisms in the feedwater 'Line break methodology.
If you have any questions on these revisions, please call S. E. Ritterbusch.
Very truly yours, J. C. Moulton Project Manager JCM/SER/cw cc: E. Z. Zuchman L. Tsakiris L. V. Pelosi E. W. Dotson W. B. Derrickson W. H. Rogers, Jr.
C. Wethy K. N. Harris B. D. Escue G. E. Crowell M. Floyd R. E. Havner C. E. Waddell E. R. Bottrill G. Boissy
f L2/2907 1/80 "SAR/ER CHANGE REOVEST" Change '.<unbar By PLE/EPL (1) To: Ebasco.
(2) Frcn C-E (3) pro]cct: St. Luci e 2 (A) subject: NRC uesti ons (5) Change Affec s:
(6) The Affected Areas is: Sections(s) Page(s)
(7) Reconncndcd change and reascn(s) for requesting change: (voce: Attach narked uo copy of all affected pages).
Revisions to 440..7 and 440.81 f to fu1fil t commitments (8) Change will inpact the following: ie. Specs, Dwgs, Other Disciplines/Organi"at'ons None (9) To:
Reviewing Organizations Review Part I and yote Inpact Below Response Requested By:
(lo) Fron:
Qt Prospect Licensing Engineer/Environ cntal .rogcct Leader (il) Inpact on Reviewing Organizat'on
- a. Section Page(s) (Note: Attach rarkcd up copy of all affected pages) .
- b. Othet'npact (12) Reviewers Signature Date (13) Required Concurrenccs:
- a. Approved S E Ri tterbusch 9/21/81 Originating Engineer
- b. Approved Responsible Supervisor
- c. Approved Date PLE/EPL
- d. Approved Date Pro)act Engineer
- e. Client Approval Date FPSL Letter Nunber (1/,) Disposition Not Inplenented Da't e (15) Connents:
cc: Pro)ect Engineer ORIOIMAL RETAIvrn vu oiv vvv >".
A I
I gueseSan 440.7~
era ll i i Provide the fo ow ng n formation t 'nergy o
lines related to pipe breaks or leaks 9m outside containment associated wet e, e i high or mo d e RHR system w h en n the plant is in a shutdown cooling mode:
Determine the maximum discharge rate from pipe break for the systems outside containment used to maintain core cooling-
- 2. Qetermine the time frame available for recovery based on these discharge rates and their effect on core cooling.g
- 3. Descry b e thee aalarms available to alert the operator to the event,
'? the recovery procedures to be utilized by the operator; t e Sma available f'r operator action.
A single failure criterion consistent with Standard Review Plan 3 $ .1 and Branch Technical Position APCSB 3-1 should be applied in tha evaluation of the recovery procedures utilized.
Response
R The moderate energy ana 1 ysxs was pperformed in order to determine the %aigh-within the hCCS areas in accordance with SRP 3.6. 1 aad 3.6.2. In order to maximize the flood conditions, t e ana 1 ys s tively utilized a 1 ea k ra tee of o 620 gpm and a minimum operator action nf thirty (30) minutes. The moderate energy flooding analysis verifzed e t I validity of the present design under these conditions.
H'xg an d mo d e rate piping failure outside the containment which could a ff ect the shutdown cooling system have been investigate leakage either from the shutdown cooling system or nearby hig h ener g system would be rowted to the ECCS supply room. Each sump is provided and t~ seismic category I level measurement der%.ees.
Any leakaea gee into n o these sumps should initiate a control room alarm, t are y i n formxng thee ooperator of a piping failure. The ECCS area ea is also p eo-vided with two safety related radiation monitors to measur ure an y airborne effluent to aid the operator in identxfying the leakage source. A cma-plete descrzptxon o f th es e monitors is provided in FSAR subsection 1 l. 5. 2. 2. 10.
In a dd'eton o the two aforementioned leakage detection systems, any axg-n ficant ni ut own Cooling System leakage should be detected immeed 9.at el y b y icant Shutdown
tion the Reactor Coolant System parameters dxsplayeed in the control rocna Pressurizer water 1 eve 1 xn @ca o and low pressurizer level alarms ~re provided in the Control Room by LT-lllOX and LT-lllOY. In aaddition t on <o the level instrumentation, both high pressurizer pressure range channels of 1500-2500 psia (PI1102A, B, C, D) and low pressurizer px~ssure range channels of 0-750 psia (PIC-1103,1104,3,105,1106) are provided This instrumentation xs su ffzc ine t to alert the operator of any aoxmrmal RHR .system operators.
4 I:Nsak7- p y(<</pi
Insert A flii/rl The above moderate energy line break analysis was performed to demonstrate that the resulting flooding would not ippcf eg~pnwt -.~ 4., a~A. s/a&du~..
Nonetheless, an additional analysis wa5 phrformed show that the plant operator has at least 20 minutes after the first alarm to identify and isolate the damaged train prior to any significant effect on 'core cooling. This time is available because the water in the RCS above the hot and cold leg piping acts as a reservoir which must be drained prior to any effect on shutdown cooling (SDC) system per-formance or core cooling (the SDC system takes suction from the RCS hot leg piping).
The RCS volume above the hot and cold leg piping includes the SG tubes, the SG inlet and outlet plenums, the reactor vessel upper head, the pressurizer sur~e line, and the pressurizer vessel for a total volume of approximately 4700 ft .
Taking credit for draining of only the SG active tubes and pressurizer volume required to cover the top of the heaters results in a reservoir of 2467 ft3 (18,454 gallons). Mith a 1eak rate of 620 gpm there is at least 20 minutes between the pressurizer low level alarm (heater uncovery) and uncovery of the SDC suction piping. Therefore, SDC system performance, coolant circulation through the reactor vessel, and core cooling are maintained.
SL-2 Round One uestions 440.18 Discuss the system used to provide pressurizer heater cutoff on
'15.2.2.1) low level. Is there any single failure that could result in the heaters remaining energized when they have lost submergence.
If so, discuss the consequences of this occurrence. In your .
answer, you may wish to consider the event which occurred at the Spert III facility in Idaho where a pressurizer was heated to a point where it lost integrity.
~Res ense:
Florida Power and Light has committed to incorporating a redun-dant low pressurizer level cutoff signal to the pressurizer heaters. These signals will de-energize the heaters prior to to the water level dropping below their tops so that no single failure in the protection system can cause them to be energized while uncovered.
No FSAR change is required.
SL'-2 ROUND ONE UESTIONS 440. 25 Provide a detailed analysis on the consequences of a RCP shaft sei zure (15.3.3) 'vent. Justify selection of limiting single failures. The'time at temperature studies which justify your claims of peak clad temperature being limited to 1300oF are not accepted by the staff. In assessing fuel failures, any rod which experiences a DNBR of less than 1. 19 must be assumed failed. Confirm that the results of the 'analysis meet the acceptance criteria of SRP 15.3.3.(2). Provide your assump-tions on flow degradation due to the locked rotor in the faulted loop, and reference appropriate studies which verify these assumptions.
Also provide a similar analysis for the locked rotor event presented in section 15.3.4. 1, and show that acceptable consequences result.
Re e The most sev single failure in conjunction with the RCP shaft seizure eve I the loss of offs ower on turbine trip, as discussed in the response "
.9.
Results show a mini NBR of 0.36 at 3.6 seconds, resulting in he fuel rods experiencing DNB he response to 440. 11). The 2-ho ~ oid dose assuming 13K failed fuel s oximately g rems. Pe S pressure is less than or equal to 2694 psi e the res'ponse to 4 5'b ~c. (~<~~
The flow coastdowns which were used i e anal of the one pump resistance to forced flow are presented in Figures and 440.25-2. The seized shaft is assumed to instantaneously -sto 0.0 with the seized rotor acting only as a'esistance to flow is coas was generated using the COAST code as documented in CENP (see Reference
~'
Reference:
ption", April 2, 1
- 1. "Coast Code D CENPD-98, 1973.
A cha to the FSAR,
\
m~~~ie.~ +;S M
~+;,l K, l. ' 4 W. (~c.e s<-=~+
5 it a.u.<<
T4.g v-~C~ ~4 +lou~
A. ML' a C: ccrc c:c. ~~M+Z l C S(~+(oV fK. <. <(
~ SL2- FSAR uestion No.
440. 67 In light of recent operating experiences (the St. Lucie Unit 1 natural circulation cooldown event of June ll, 1980, and re-analyses of SAR Chapter 15 design bases events by St. Lucie in February 1981) a potential deficiency has been identified with the CESEC computer program and NSSS model. As the pressurizer cools down and the system pressure decreases, steam can form in the reactor vessel upper head due to flashing of the hot coolant in this stagnant region. The steam bubble in the reactor vessel upper head displaces coolant from the reactor vessel into the pressurizer and the steam in the vessel head will determine the system pressure. The CESEC model used for the steam generator tube rupture event does not account for this occurrence. Further, CESEC analyses which predict that the pressurizer will empty, or that the reactor coolant system saturates, do not appear to correctly calculate the system thermal hydraulic response and are not justified for use. These events are to be re-analyzed with a suitable model or additional justification is to be provided for the CESEC analyses to demonstrate that the computer program conservatively accounts for the formation of steam in the reactor coolant system.
~Res ouse The Chapter 15 events performed with CESEC do not explictly include analyses of natural circulation cooldowns. However, a comparison has been made between CESEC and data from the St. Lucie 1 natural circulation cooldown event. This information will be provided in a document describing the CESEC-III computer code (see response to Question 440.80(k) ). Additionally, comparative analyses will be performed between CESEC-II and CESEC-III. CESEC analyses have indicated that for the steam generator tube rupture, the letdown line break, and the steam line break events, the pressurizer empties and/or the reactor coolant system (RCS) saturates. Since the steam line break event was analyzed using CESEC-III, no comparative analysis will be performed for this event. The steam generator tube rupture and letdown line break events belong to the decrease in RCS inventory event category.
The most limiting event in this category with respect to void formation, the steam generator tube rupture event, will most significantly emphasize differences between CESEC-II and CESEC-III in the calculational results. Conclusions from this analysis will bound those which would have been ascertained from a comparative analysis for the letdown break event.
m generator tube rup re C
ent will pr de the necessary justi 'tion for the us of SEC-II t analyze the letdown e jus li reak event in add'on to ication for the use o he code to predict stem espo e for the steam gener or tube rupture event Submittal f aris ep em Additional information on CESEC-III, will be prepared by 9/30/81.
440.67-1 Amendment No. 6, (9/81)
I Therefore, qualification of CESEC-II against CESEC-III for the steam generator tube rupture event will provide the necessary justification for the acceotability of Chapter I5 analyses conclusions for depressurization events.
For all Chapter 15 events for which the pressurizer fluid is calculated to drain into the hot leg, or the system pressure drops below the saturation pressure of the hottest fluid in the system, the hottest fluid will be located in the relatively stagnant upper head region of the reactor vessel.
The CESEC-II code, used in the FSAR Chapter 15 analyses did not explicitly model the steam formation in the reactor vessel upper head (except for steam line break analyses which usedCESEC III) region. The latest version of CESEC, namely CESEC-III, appropriately models steam formation and collapse in the upper head region of the reactor vessel. Heat transfer from metal structures to the reactor coolant system (RCS) fluid is modeled in addition to flashing of the reactor coolant into steam during depressurization of the RCS. Following the reactor coolant pump (RCP) coastdown due to loss of offsite power or manual shutoff following SIAS, thermal-hydraulic decoupling of the upper head region is characteri'zed in CESEC-III by progressively decreasing flow to the upper head from the transients upper plenum region. Table 440 67->summarizes the significant differences between the two CESEC code versions which impact depressurization . (Note that the 3-0 feedback impacts only the steam line break analyses).
The steam generator tube rupture event presented in the FSAR was reanalyzed, using the CESEC code version known as CESEC III. The re-analysis of the SGTR event without loss of offsite power ind":cated the following:
The modeling of the stagnant upper head region with metal structure heat transfer results in the formation of voids in this region. The void volume in the upper head region peaks at about 209 cu. ft. during the transient and gradually decreases under the combined action of the HPSI flow and the cooldown at the steam generators. The duration of the voids is a strong function of the rate of cooldown of the primary side and the HPSI flow rate.
Figure 440.67-1 provides a comparison of pressurizer pressures predicted by the CESEC I'I and CESEC III codes. The effect of upper head voids on primary system pressure is illustrated in this figure. It shows similar trends for the RCS pressures during the transient. However, subsequent to reactor trip, the pressure predicted by the CESEC III code decreases at a lower rate than that predicted by the CESEC II code. This is due to the formation of voids in the upper head region, which controls the system pressure decay after the emptying of the pressurizer subsequent to reactor trip. The voids in this region are calculated to collapse at about 1700 seconds under the combined effect of charging flow, safety injection flow, reduced primary-to-secondary leak, <<nd cooldown at the steam generators . The CESEC III code predicts refilling of the pressurizer and repressuri zation of the RCS as a result of the net mass influx into the RCS, subsequent to collapse of the upper head voids.
The CESEC II code predicts refilling of the pressurizer and RCS re-pressurization much earlier than CESEC III, since it does not explicitly account for upper head void formation and collapse.
Figure 440.67-2 shows the behavior of the liquid volume in the reactor vessel above the top of the hot legs for the CESEC III analysis. The amount of voids predicted is not large enough to expand the steam bubb'e beyond the upper head region and to the elevation of the hot legs.
0 rr) gg
/g 7
Additionally, the prediction of the upper head bubble does not alter the conclusions of the previous CESEC II analyses. That is, for the SGTR event the major concern is with radiological releases to the environment.
A breach of the primary system boundary provides a pathway for radioactive primary coolant release into the secondary side and subsequently into the atmosphere. The offsite accident dose for a SGTR event is dependent on the integrated primary to secondary leak as well as the total main steam safety valve (HSSV) steam releases. As seen from Table 440.67-2, both CESEC II and CESEC III codes predict comparable values for these parameters, The'inimum'ONER'for both analyses remains above 1.19 for the duration of the event. Thus, from the results of this comparison, it. can be concluded that the impact on the offsite doses is insignificant. Additiona'ily, the comparison demonstrated that the plant is maintained in a stable con-dition by the collapse of the upper head voids due to automatic actions.
Subsequent to operator action, the operator can bring the plant to the shutdown cooling entry conditions, by cooling down the RCS at a prescribed cooldown rate using the intact steam generator, the condenser,and the feedwater system and by following specific plant procedures.
For the steam generator tube rupture with loss of offsite power event {see response to question 440.69) similar conclusions as'or the SGTR event without loss of offsite power can be made, For this case, the operator will not have the condenser available for cooldown, and wobl d use the atmospheric dump valves. Additionally, the RCS will be in a natural circulation cooldown mode as a result of the coastdown of all RCS pumps following loss of offsite power. The analysis demonstrated that natural circulation cooldown of the RCS is not impaired as the amount of voids predicted is not large enough to expand the steam bubble beyond the upper head region and to the elevation of the'ot legs.
The conclusions from the comparative analyses for the SGTR event bound the other depressurization events in Chapter 15.6 for which void formation is less limiting and/or non-existent. This is due to slower cooldnwn rates and higher minimum RCS pressures for these depressurization events. Thus, the qualification of CESEC II against CESEC III for the SGTR event provides the necessary justification for the acceptability of the Chapter 15 analyses conclusion for depressurization events.'
TABLE 440.67-1
SUMMARY
OF SIGNIFICANT DIFFERENCES BETWEEN CESEC-II AND CESEC-III I
MODEL CESEC- III CESEC-II THERMAL HYDRAULIC 26 NODES, UPPER HEAD EXPLICITLY 16 NODES MODELED RCS FLOW EXPLICITLY MODELED INPUT TABLE RCP's FOUR, EXPLICITLY MODELED TWO HALL HEAT EXPLICITLY MODELED HONE SGTR OPTION CRITICAL FLOW CHECK DARCY EQUATION MIXING IH RY ASYMMETRIC RESPONSE EXPLICITLY ASYMMETRIC RESPONSE MODELED INCLUDED IN REACTI'/ITY CALCULATION FOR SLB 3-0 FEEDBACK YES HO
TABLE 440.67-2 COMPARISON OF RESULTS FOR THE STEAM GENERATOR TUBE RUPTURE llITHOUT LOSS OF OFFSITE POWER CESEC- II CESEC- III PRIMARY-SECONDARY 61,480 61,010 INTEGRATED LEAK (LBM)
AT 1800 SECONDS INTEGRATED MSSV STEAM 76,370 69,470 RELEASE (LBM) AT 1800 SECONDS MINIMUM DHBR >1.19 >1.19
2509 2200 1900 CESEC III CESEC II 1600 I
1300 I I
LLI 1000 700 0 300 600 900 1200 1800 r
T I YiEg SECONDS FIGURE 040,67-1 STEAM RENERATOR TUBE RUI'TUBE FOR STI LUCIE 2 WITHOUT LOSS OF OFFSITE POWER REACTOR COOLANT SYSTEM PRESSURE VSi TIME
~TOP OF REACTOR VESSEL I
-'250 1000 NAXIf'1Uf1 VOLUf'1E GF VOIDS +
CO Er 289 CUBIC LLI 750 500 250 TOP OF HOT LEbS 0
0 500 600 900 1200 1590 TIf"Er SECONDS F I suPE tl00,67-2 STEAf'1 GENERATOR TUBE RUPTURE FOR ST LUCIE 2 WIT()OUT Loss OI..
OFFS I TE PO'AER VOID FORhATI ON IN TOP OF REACTOP, VESSEL
SL-2 Round One uestions 440.69 SRP 15.6.3 acceptance criteria requires that this event be analyzed (15.6.2) with a concurrent loss of offsite power. Provide an analysis for the limiting case which includes a concurrent loss of offsite power.
~Res onse:
An analysis of the steam generator tube rupture (SGTR) event with concurrent loss of offsite power was performed. The results of this analysis show that the offsite doses are less than for the inadvertent opening of a letdown relief valve e'vent presented in Section 15.6.3.1. A discussion of this event is presented in Appendix 15 C-5.
A chenge to the PSA11, Appendix 15 C/eccosnpentes this response,
SL2- FSAR (d) There are no single failures identified in Table 15.0-6 which can adversely impact the consequences (i.e.,
pressurization) associated with the feedwater line break (FWIB) event addressed in Subsection 15.2.5.2. As a result of evaluation method applied to the FWLB analysis, the only mechanisms for mitigation of the reactor coolant system (RCS ) pressurization are the pressurizer safety valves, the reactor coolant flow and main steam safety valves. The last two influence the RCS-to-steam generator heat transfer rate-p/5$ ~ g+There are no credible failures which can degrade pressurizer safety valve or main steam safety valve capacity. A decrease in RCS to steam generator heat transfer ue to reactor coolant flow coastdown can only be caused by a failure to fast transfer to offsite power or a loss of offsite power following turbine trip (i.e., two or four pump coastdown, respectively). The FWLB analysis of Subsection 15.2.5.2 considers the worst of the two, the loss of offsite power.
X'nlSG R 7 93 gThis evaluation of single failure impacts is consistent with FWLB analyses performed for other Combustion Engineering plants. No credible single failures can aggravate the RCS pressurization associated with the FWLB (e)
~ combined with a loss of of fsite power following turbine trip ~
z>si;ay- c ~
Automatic auxiliary feedwater actuation will provide flow within two minutes of reactor trip; thereby, terminating the pressurizer level increase and any potential for filling the pressurizer.
Additional information on CESEC-III will be prepared by September 30, 1981.
440.81>>3 Amendment No. 6, (9/81)
+h5W< W 'p58g.
gag~ Qqy g(
g+XEgT .D l Nor are there any credible failures which can reduce team flow to the affected steam generator. (1)
(1) It should be noted the coincident occurrences (failures) considered
~ ~
in Chapter 15 do not include spurious independent failures, only conse-
~ ~
quential failures and pre-existing failures. Accordingly, spurious
~
~
closure of a main steam isolation valve is not considered credible during
~ ~
the FMLB event.
The assumed time for NSIV closure is consistent. with the timing of a MSIS generated by low steam generator pressure. As shown in Table 15.2.5.2-1 of the FSAR the NSIS on this parameter is not expected to occur until 163 secorlds, 137 seconds after reactor trip. For the FSAR analysis, no credit was taken for either a reactor trip or MSIS being generated on high containment pres-sure. Analysis of the Fl!LB has shown that the occurrence of this reactor trip and MSIS earlier than the presently assumed trip would reduce the-.peak RCS pressure due to the earlier reduction of core power. MSIS occurring at or after the present reactor trip at 26 seconds will have ao effect on .
peak RCS pressure because complete closure of the HSIVs occurs essentia'l1y at the same tir0e a0 the peak RCS pressure. Although the MSIYs are designed to .close within six seconds, five seconds was used for this analysis. The termi-nation of heat removal from the unaffected steam generator is not rapid enough to produce an increase in the RCS pressure for this analysis.
SL2- FSAR Additionally, the high primary system pressures reported in Subsection 15.2.5.2 are due to the conservatively assumed coincident occurrence of a loss of normal ac power. WASH 1400 estimates the conditional probability of this at 1 x 10 (Ref. Appendix III, Section 6.3). From this we can easily conclude that the joint recurrence frequency for the initiating event with a concurent loss of ac power is less than 10 per plant year. Therefore, the event analyzed in Subsection 15.2.5.2 is indeed sufficiently low to satisfy the Level C Service categorization, as defined in Section 3 of the ASME Pressure Vessel Code.
An addirional conservatism oE the SSAR analysis> that should be pointed out, is that no credit is taken for PORV operation which would tend to minimize the peak primary system pressure.
nclu i)
LL) g:
mode 'f e water line breaks prediction o will be provided by September, steam generator h uid co transfer, 1981, tions at the break location, iii) correlation for ed'on of break discharge'ate, iv) treatment s team genera to M w wa ter 1 eve 1 trip, v) sel ion of plant initial condition and vi) selection of the "wors t" break size.
The methodology utilized for analyzing.feedwater line break (FMLB) for St.
Lucie 2(SL.2) is that documented in Appendix 15B of CESSAR FSAR The major evaluation areas unique to FRLB which SL-2 metholology addresses include the selection/treatment of:
- a. Affected steam generator heat transfer.
- b. Fluid conditions at the break.
- c. Affected steam generator low level trip.
- d. Break discharge.
- e. Plant initial conditions.
- f. Break size.
The methodology utilized simplified models rather than justifying detailed best estimate models to determine an upper limit for the reactor coolant system (RCS) pressurization transient. The following description will show that the SL-2 method is valid and conservative.
Affected Steam Generator Heat Transfer RCS pressurization is largely a function of the rate which the affected steam generator heat transfer decreases as its inventory is depleted. The overall heat transfer coefficient will decrease as the steam generator tubes are exposed to increasing void fractions which force the tubes from the normal nucleate boiling heat transfer regime into transition boiling and eventually into liquid deficient heat transfer. Transition boiling is anticipated when the local void fraction exceeds 0.9. A gradual heat transfer reduction is expected, starting when the affected generator liquid inventory decreases to approximately 70,000 ibm forcing portions of the tubes into transition boiling, and continuing as transition boiling and then liquid deficient heat transfer propagate throughout the tubes. Figure 440.81.f-l shows the expected behavior of the overall heat transfer coefficient, along with the behavior assumed for SL-2 evaluations.
e
~so, el (q)
./c e- the sensitivity of RCS pressurization Appendix 15B of CESSAR FSAR documents that RCS to steam generator heat transfer behavior. The study verifiedsteam generator pressurization is maximized by under-estimating the affected liquid mass corresponding to the initiation of heat transfer degradation (i.e., over-estimating the rate oftransfer heat transfer decrease). Therefore, SL-2 conservatively assumed heat characteristics which were biased was initiated.
to under-estimate the liquid inventory at which degradation The SL-2 model simply assumed heat transfer decreases instantaneously upon steam generator dryout.
Fluid Conditions at the Break.
The enthalpy of the fluid discharged from the feedline break partially determines the heat removal capability of the affected steam generator.
Minimizing the discharge enthalpy reduces the heat removal and,thereby maximizes the RCS pressurization. The model for SL-2 was biased to con-servatively under -estimate the discharge enthalpy. Figure 440.8l.f-.2 shows the behavior of the discharge enthalpy during steam generator dry-out predicted by the SL-2 method, along with the expected behavior.
The expected enthalpy response for SL-2 can be understood by considering relatively high location of the feedwater nozzle and distribution ring on the steam generator. Fluid discharge from a feedline break is drawn from the downcomer section through the feedwater distribution ring. Saturated liquid in the downcomer normally covers the feedwater ring. Ouring FWLB the 'downcomen 'liquid will be depleted lowering the water level and uncovering the ring. A two phase fluid (high enthalpy) will de discharged thereafter.
Feedwater ring uncovery and the associated high enthalpy will occur before the steam generator liquid inventory de.reased below 100,000 ibm.
For SL-2 FWLB evaluation a simplistic model was used. The model assumes that saturated liquid is discharged from the break unitl no liquid remains in the steam generator.
Affected Steam Generator Low Level Tri Reactor trip on a steam generator low water level can mitigate the RCS heatup and- pressurization during FllLB. The SL-2 method for calculating affected steam generator low level trip was biased to conservatively delay the trip.
Steam generator level is inferred from the measured elevation head asso-ciated with the downcomer fluid between two instrument tap locations. When the measured head decreases below a pre-determined setpoint a steam generator low level trip signal is generated. As the downcomer level decreases during FWLB low level trip is expected to occur with greater than 70,000 ibm of liquid in the affected steam generator.
The SL-2 method simply and conservatively assumed affected steam generator low water level does not occur until all liquid is depleted.
Br eak Dischar e Rate Maximizing the break discharge rate, when combined with underpredicting the discharge flu id enthalpy, reduces the heat removal capability of the affected steam generator and thereby aggravates RCS heatup and pressur-ization. The SL-' evaluation conservatively estimated the flow rate assuming instantaneous establishment of frictionless critical flow through the break as predicted by the Henry/Fauske correlation.;
Plant Initial Conditions Initial conditions (e.g., RCS pressure, steam generator, liquid inventory and core burnup) can be selected to maximize the RCS heatup and pressuri-zation. The SL-2 FWLB evaluation selected the most adVerse set of initial conditions within the allowable plant operating space, based on engineering judgemerit supported by sensitivity studies like those documented in Appendix 15B of CESSAR FSAR.
cribedd.Size Break The most adverse break size (.25 ft ) was identified for SL-2 based on sen-sitivity studies consistent with the modeling assumptions previously des-In summary; the FWLB evaluation method for SL-2 utilized simplifying assump-tion which incorporated many conservative biases with respect to the pre-diction of maximum RCS pressure (e.g., treatment of the affected steam gen-erator heat transfer, fluid conditions at the break, and affected steam generator low level trip). The maximum RCS pressure predicted for limiting break size by the evaluation model is a conservative estimate which will not be exceeded by any feedwater line break event.
As documented above and in Appendix 15B of CESSAR FSAR, the SL-2 evaluation method for FWLB is valid and conservatives rd-8 s~e L-/~~ ~4 e l The allowable pressure limits for feedwater line break events have been agreed upon as 1105 of design pressure for the feedwater line break event by i,tself, and 120K of design pressure for the feedwater line break plus a coincident occurrence (eg.; the loss of offsite power). The worst feedwater line break event without a coincident occurs='nce produces a peak RCS pressure which is less than llOX of design pressure (2750 psia), see Sec ti on 15.2.3.2. 1.
A change to the FSAR Section 15.2.3.2. 1 accompanies this response.
- R. E. Henry, H. Y. Fauske, "The Two Phase Critical Flow of One-Component Mixtures in Nozzles, Orfices, and Short Tubes," Journal of Heat Transfer, Transections of the ASME, May, 1971.
SO DRYOUT
.~ 100 C7 EXPECTED 50 SL2 20 40 60 80 100 120 STEAM GENERATOR LIQUID, IO"0 LBM I
STEAM GENERATOR Figur~
FPaL HFAT TRANSFER CHA RACTERI STIC S 440.81(
, 1200 f
1100 I
I l
EXPECTED I
I l
900 l
I SL2 t
I I
I 700 l
t FV! RING t
,UNCOVERY 600 I l
500 20 40 60 80 120 STEAM GENERATOR LIQUID, 1000 LBM Figur'e FPaL DISCHARGE ENTHALPY vs STEAM GENERATOR LIQUID INVENTORY 440.81(
C-E Power Systems Tel. 203/688-1911 Combustion Engineering, Inc.
~ Telex: 99297 1000 Prospect Hill Road Windsor, Connecticut 06095
~
SYSTEMS St. Lucie Plant Unit No. 2 - 1978-890 MW Extension Mr.* K. N. Chow Ebasco Services, Inc.
2 World Trade Center 80th Floor New York, NY 10048
Subject:
FSAR Chapter 15 Revisions
Dear Mr. Chow:
The revisions listed below are attached.
~ ~
~ These
~
revisions resulted from NRC review of Chapter 15.
~
of Failure Criterion
~
Section 1.9.8:
~ ~ ~
~ Documentation Fuel Rod (NRC/RSB guestion 440.11).
Section 15.1.5: Steam Line Break Analysis (NRC/AEB)
Section 15.2.5: Feedwater Line Break Analysis'Revision (NRC/ASB)
Section 15.3.3: Seized Pump Shaft Analysis (NRC/RSB guestion 440.25)
Section 15.4.2: Part-Length Subgroup Drop Revision {NRC/CPB)
Appendix 15C.3: CEA Ejection With Loss of Offsite Power Analysis (NRC/AEB)
Appendix 15C,4: Total Loss of AC Power (Station Blackout)
Appendix 15C.5: Steam Generator Tube Rupture With Loss of Offsite If you have any questions on these revisions, please call S. E. Ritterbusch.
Very truly yours, Power'CM/SER/cw J. C. Moulton Project Manager cc: D. J. Chin K. N. Harris J. E. Sheetz B. J. Escue E. Z. Zuchman G. E. Crowell L. Tsakiris R. E. Havner L. V. Pelosi E. R. Bottrill E. W. Dotson M. Floyd
~
W. B. Derrickson C. E. Waddell W. H. Rogers, Jr. G. Boissy C. M. Wethy
EL2/R907 1/SO "SAR/ER CHPMNCE REOUEST" Change Number ll~yPLE "PL
+o (1) To: Ebasco l C-E (2) From M (g) pro)cot; Stp LUC le 2 Safety Analysis gx" CP (5) Change Affects:
{6) The Affected A'reas is: Sections(s) l5 . X Page(s)
(7) Recort ended change and reason('s) for requesting hange: (lace: Attach marked up copy of all affected oages).
Revisions and additions resulting from NRC review/
(8) Change will impact thc following: ie. Specs, Dwgs, Other Disciplines/Organizations None (9) To:
Reviewing Organizations Review Part I and Note Impact Below Response Requested By:
(10) From Pro)ect Lic.nsing Engineer/Envtronmencal Project Leader
?~
(11) Impact on Reviewing Organization L
- a. Section Page {s) (Note: Attach marked up copy of all affected pages).
b, Other Impact (12) Reviewers S'gnaturc Date (13) Required Concurrences:
- a. Approved S ~ E. Ri tterbusch PPLP 9/21/81 Originating Fnginecr
- b. Approved Dace Responsible Supervisor .
- c. Approved Date PLE/EPL W
- d. Approved Date prefect Engineer OC
'C 04
- e. Client Approval Date FP&L Lctrcr Number (1/P) Disposition Date (15) Comments:
cc: Pro)cct Engineer P
ORIGINAL RETAINED IN PLE OR EPL FILES
~
SL2" FSAR Per a memorandum and order issued on May 23, 1980 (11) the NRC has ordered ap~kj~ants for operation licenses to meet the requirements of
=
HUREG-0588 . to satisfy the aspects of 10CFR50 Appendix A, General Design Criterion 4 which relates to environmental qualification of safety-related equipment. FP&L has initiated a program to review safety related electrical equipment qualifications in light of NUR G-0588 requirements.
An amendment is anticipated to be available by January 1982.
1.9.8 DOCUMENTATION OF FUEL ROD FAILURE one pump resistance he fuel rod failure criteria used in the analysis of the to forced flow (locked rotor, Section 15.3) event ~
is consistent ~vith that Used for other Chapter 15 analyses. See Section 15.0.4.4.3(b) for a description of the fuel rod failure criterion
- l. 9-3 Amendment ho. 3, {6/Sl)
SL2- FSAR 15.1 INCREASED flEAT REMOVAL BY THE SECONDARY SYSTEM 15olol MODERATE FREQUENCY EVENTS There is no event group in Table 15.0-2 which results in an increase in heat removal by the secondary system and has an estimated frequency of oc-currence which would classify it as a Moderate Frequency event.
15.1.2 INFREQUENT EVENTS 15.1.2.1 Limiting Offsite Dose Event-Increased Feedwater Flow wxt a Fax ure to Achxeve a Fast Transter o a .xc kV Bus 15.1.2.1.1 Identification of Event and Causes All Infrequent event groups from the Increased Heat Removal by the Secondary System event type and the Infrequent event group'combination's shown in Table 15.1.2-1 were compared to find the event resulting in the maximu xte i r dose~ Increased feedwater flow with a failure to achxeve a fast transfer of a 4.16 kV bus was identified as the limiting Infrequent event.
vent roups and event group combinations evaluated and the signif-cance of the x. e o r dose~~ for each are irdicated in Table 15.1.2-1.
All events indicated as insignificant (I) would produce of fsite doses well within the acceptance guideline in Table 15.0"4. All events indicated as significant (S) produce offsite doses within the acceptance gu'deline.
No combinations o. event grouos and other fa'lures, other than tnose shown in Table 15.1.2-1 falI in the Infrequent category.
An increased feedwater flow may occur due to opening of one or anre of the main feedwater control vajves in excess of feedwater requirements, increase of steam di iven auxiliary reedwater pumps speed, or misoperatior. of the feedwater neater drain system. (See Table 15.0-1 for a list. of inxtiating events in each event group.)
Opening of all main feedwater control valves, which rcsul'n the largest increase in feedwater flow, was used to simulate this event. 1n this analysis, a failure to achieve a fast transfer of a 4.16 kV bus occurs immediately after turbine trip, assumed to result in the lo"s of condenser vacuum.
Of the two event groups, increased feedwater flow and increased main steam flow through the turbine, considered in the Infrequcn" frequency category, increased main steam flow through turbine ..i il nc" cause a reactor tri p, and thereforeg wl 1 not result in stean rele s..>> to the a"mospnerc. Increased feedwater flow with failure to achieve a "" transfer to a startup trans-former is the limiting combination, since failure rn achiev= s fast transfer of a 4.16 kV bus is assu..ed to result in loss cf ccndenser availability causirg stcam releases to occur either through h:.. main steam safety v ives (MSSVs) or through the atmospheric dump valves (A"'/s) thus maximizing the o ffsite dose"..
SL2- FSAR 15>>l>>5 LIMITING FAULT 3 EVENTS 1 5.1 Limitin Offsite Dose Event None of the Limits lt-3 event groups and event combinations
'al by th resulting in an increased hea Table 15>>1>>5-1 release a significant mosphere>> The additional fa results incrementally s and events co adverse than the increased fee
'd ondary system shown in f radioactivity to the at-here produce r flow with a failure chieve a fast transfer of a 4>>16 kV bus descr in Subsectio >>1 2 1 The offsite doses Mich would occur during the t adve e of these event groups and event group combinations are. well withe the 'ied 'n Tab 15>>1>>5>>2 Limitin Reactor Coolant S stem Pressure Event
'nAllanLimiting Fault-3 increased heat event groups and event group combinations resulting removal by the secondary system shown in Table 15>>1>>5-1 are characterized by decreasing Reactor Coolant System (RCS) pressure The peak RCS pressure which would occur during the most adverse of these events does not approach the acceptance guideline specified in Table 15 '-4 15 1>>5>>3 Limitin Fuel Performance Event - Loss of Main Steam Hith Loss of Offsite Power as a Result of Turbine Tri 15 l>>5 3 1 Identification of Event and Causes All Limiting Fault-3 (LF-3) event groups from the Increased Heat Removal by the Secondary'System event type and the LF-3 event group combinations shown in Table 15 1 5-1 were canpared to find the limiting fuel performance event The loss of main steam-large, inside containment with loss of offsite power as a result of turbine trip was identified as the limiting LF-3 event, The event groups and event group combinations evaluated and the sig-niff.cance of the approach to the fuel performance acceptance guidelines are indicated 'in Table 15>>1>>5-1>> All event groups or event group combina-tions indicated as insignificant (I) produce fuel performance we11 within the acceptance guideline in Table 15 '-4>> All events indicated as signifi" cant (S) produce 'a fuel performance within the acceptance guideline The loss of main steam"large, inside containment may occur due to a break in the 34/36 inch main steam line>>
Breaks ranging from 0>>056 ft ~ area up to the double-ended rupture of the 34/36 inch main steam line are included in this event group, Events with break areas less than 0.056 ft are classified in the small loss of main steam event group. The potential for degradatiop in fuel performance was maximized by an intermediate size break (2 27 ft ) (see Subsection 15 ~ 1 ~ 5>>3 3 for details) The loss of offsite"'power as a result of turbine trip causes the coastdown of all reactor coolant pumps Of all the event groups and event group combinations considered in the LF-3 category, loss of main steam events caused by large steam line breaks, both
- 15. 1-78 Amendment No. 2, (5/81)
0 ~
I ~ SL2-FSAR 15.1.5 LINITIHG FAULT 3 EVENTS 15.1.5.1 Limitin Offsite Dose Event - Loss of Main Steam Outside Con-tainment U stream of MSIV With Loss of Offsite Power as a Result
~fT i Ti 15.1.5.1.1 Identi fication of Event and Causes All Limiting Fault-3 event groups and event group combinations resulting in an increased heat removal by the secondary system shown in Table 15.1.5-1 were compared to find the event resulting in the maximum offsite doses. The loss of main steam-large, outside containment, upstream of MSIV with loss of off-site power as a result of 'turbine trip and with technical specification primary to secondary leakage through the steam generator tubes was identified as the limiting LF-3 event.
The event groups and event group combinations evaluated and the signifi-cance of the offsite doses for each are indicated in Table 15.1.5-1. All events indicated as insiginficant (I) would produce offsite,doses well
'within the acceptance guideline in Table 15.0-4. All events indicated as significant (S) produce offsite doses within the acceptance guideline.
The loss of main steam-large, outside containment may occur due to a.break in the. 34 inch main steam line.
Breaks ranging from 0.056 ft area up to the double-ended rupture of the 34 inch main steam line break are included in this event group. Events with break areas less than 0.056 ft2 are classified in the small loss of main steam event group. The offsite doses were maximized by assuming an interme-diate break (1.8 ft2) which results in a minimum DHBR below 1.19. Technical specification tube leakage also increased the offsite doses. The loss -of offsite power as a result of turbine trip causes the coastdown of all reactor coolant pumps.
Of the two event groups, loss of main steam-large inside containment and loss of main steam-large outside containment, in the LF-3 category, loss of main steam-large, inside containment will not cause a significant amount of steam release to the atmosphere and ther efore will not result in significant off-site doses. Loss of main steam-large, outside containment with a loss of offsite power and a technical specification tube leakage is the limiting event combination, since the decreased RCS flow due to the loss of power results in degradation of fuel performance, and the technical specification tube leakage maximizes the release of activity to the atmosphere.
J 0
Table 15.1.5.1-1 presents a chronological list and timing .of system actions which occur following the large loss of main steam event outside containment with a loss of offsite power as a result of turbine trip.
The sequence of events and systems operation are fdentical to those pre-sented in 15.1.5.3.2. and Figure 15. 1.5.3-1 with the exception of the reactor trip set points and the response of systems acutated by the occurrence of high containment pressure. High containment pressure is not present in this event.
Table 15.1.5.1-2 contains a matrix which describes the extent to which nor-mally operating plant systems are assumed to function during the transient.
The operation of these systems is consiste'nt with the guidelines of Subsec-tion 15.0.2.3.
lable 15.1.5.1-3 contains a matrix whwch describes the extent to which safety systems are assumed to function during the transient.
4 Analysis of Effects and Consequences
~
,15.1.5.1.3
~ ~ ~ ~
a) Mathematical Model s The HSSS response to a loss of'ain steam with loss of offsite power as a result of turbine trip was simulated using the CESEC computer program described in Subsection 15.0-4. The transient minimum DNBR values were calculated using the TORC code which used the CE-1 CHF .
correlation described in .Subsection 15.0-4.
b) Input Parameters and Initial Conditions From the range of values for each of'the principal process variables given in Subsection 15.0-3, a set of initial conditions contained in Table 15.1.5.1-4 was chosen that produces the lowest minimum DNBR.
Additional clat'ification of the assumptions and parameters listed in Table 15.1.5.1-4 follows.
. Maximum mimimum initial initial core power, maximum initial core inlet temperature, core mass flowrate and initial RCS pressure are chosen to minimize the DNBR, and maximize offsite doses.
The moderator temperature coefficient and break size were varied to delay the occurrence of reactor trip either on low steam generator pressure or high core power level, thus maximizing the core heat flux.
An intermediate break size corresponding to 1.8 ft~ effective steam flow.
area per steam generator with a moderator coefficient of -1.6 x 10 -4 hp/F results in the lowest value of minimum DNBR and maximum degradation of fuel performance.
In order to further maximize the degradation in fuel performance and,
'hus, to maximize offsite doses, the time of turbine trip and the loss of offsite power, which caused four reactor coolant pumps to coastdown, is chosen so that the low reactor coolant flow trip condition occurs coincident with the low steam generator pressure reactor trip.
.In this event, the turbine is assumed to tr ip prior to reactor trip due to depressurization of, Main Steam System. The reactor trip on low hdyraulic oil pressure is expected to occur during this event. In this analysis it is conservatively assumed that this trip does not occur prior to reactor trip on low reactor coolant flow or low steam generator pressure..
The Pressurizer Pressure Control System and the Pressurizer Level Con-trol System are assumed to be in the manual mode of operation and, therefore, do not function to mitigate depressurization of the Reactor Coolant System (RCS). This results in low RCS pressure which mimimizes the DNBR.
The highest one pin radial peak with the most top peaked axial power shape is chosen to minimize the DNBR during the transient.
e., Results The dynamic behavior of important NSSS parameters following this event are presented on Figures 15.1.5.l-l to 1'j. Table 15.1.5.1-1 summarizes some of the important results of this event and the times at which minimum and maximum parameter values discussed below occur.
A break in the main steam line outside containment causes an increase in steam flow, resulting in depressurization of the steam generators as shown on Figure 15.1.5.1-'9 . The pressure decrease initiates a low steam generator pressure trip and, subsequently, generates a maiin steam isolation signal (HSIS). HSIS closes the main steam isolation valves and main feedwater isolation valves isolating the intact steam generator while the steam generator connected to the ruptured line continues to blow down through the break.
The decreasing secondary pressure and temperature leads to an increase in primary to secondary heat transfer rate which causes the primary coolant (core average) temperature to. decrease. Prior to reactor trip due to a negative moderator temperature coefficient, the decreasing core average temperature causes moderator reactivity to increase, re-sulting in an increase of core power. After reactor trip, the core power further decreases to decay power level as shown on Figure 15.1.5.l-l.
The increasing core heat flux and the decreasing reactor coolant flow rate result in a decreasing minimum DNBR as shown on Figure 15.1.5.1-8.
The reactor trip causes the core heat flux to decrease resulting in a subsequent increase in minimum DNBR. The minimum DNBR experienced during a loss of main steam with a .loss of offsite power as a result of turbine trip is 0.88 resulting in 3.1 percent of the fuel pins in DNB.
During this event, two sources of radioactivity contribute to the off-site dose, the initial activity in the steam generator inventory, which is assumed to be O.l pCi/cc dose equivalent I-131, and the activity which is added to the steam generator during the transient due to assumed Technical specification. primary to secondary leakage through the steam generator tubes of 1 gallon/minute:.
During the cooldown, steam releases from the intact steam generator via the t<SSYs and ADYs contribute to the offsite dose.
The offs'ite dose due to the loss of main steam-large, outside con-tainment with loss of offsite power and with technical specification primary to secondary leakage through the steam generator tubes results in no more than a 64 rem two hour inhalation thyroid dose at the ex-clusion area boundary. The .total offsite doses during this event are shown in Table 15.1.5.1-5.
~
15.1.5.1.4
~ Conclusions This evaluation shows that the plant response to the loss of main steam-large,
~
outside containment with loss of offsite power as a result of turbine trip and with technical specification primary to secondary leakage through the steam generator tubes results in maximum offsite doses which are within the acceptance guideline in Table 15.0-4.
TABLE 15. 1. 5 . 1-1 SL2-FSAR SEQUENCE OF EVENTS, CORRESPONDING TIMES AND SUMHARY OF RESULTS FOR A LARGE LOSS OF MAIN STEAM EVENT, OUTSIDE CONTAINMENT UPSTREAM OF MSIV WITH A LOSS OF OFF-SITE POWER AFTER TURBINE TRIP Success Paths 8 IV 8 V
0 V VV 0 0 C
C$ Q Cl V cIII V co cIII ~ H V V OI C III 0 C
'0 0 V 0L4 V 0 W s O IO p C Ca V 0 VV 0 Analysis 0 V U 0 0. V III C III a Q III g V CQ c $4 C V C M Time Set Point 0 III C c a O 0 C ~
or'alue Ul F W O H ~CONJ Sec Event 0.0 1.8 ft2 break in a 34 inch main steam line 47 Turbine trip assumed
- Off-site power lose
- Diesel generator starting signal
- Four RCPs coastdown Maximum reactor power, 7.. 134
- 48. 1 Reactor trip signal generated 93 on low RCS flow, 7. of rated flow or low steam generator pressure, psia 590 50.9 Mi'nimum DNBR 0.88 66.4 MSIS generated on low SG pres- 460 sure, psia 68.0 SIAS generated on low pres>> 1578 ,X surizer pres'sure, psia X'9 Pressurizer empties 130 HPSI flow begins 311 Affected steam generator empties 650 Operator actuates auxiliary feedwater to intact SG
TABLE 15 '.5.l>>l (Cont'd) SL2-FSAR SEQUENCE OF EVENTS, CORRESPONDING TIMES AND
SUMMARY
OF RESULTS FOR A LARGE LOSS OF HAIN STEAM EVENTJ OUTSIDE CONTAINMENT UPSTREAM OF MSIV, WITH A LOSS OF OFF-SITE -POWER AFTER TURBINE TRIP Success Paths o
6 W 0 4J C
4J ts 4J 4J Q. 0 o 0
~A C7 4J CO 4J Cl H 4J 4J C Q o c o 4Jo cf W CP '44 cj o 44 c 00 4J O Cl 4J 4J 0 Analysis O o 0 0 g e O cl 4J g & 4J CO O
g 4J gM ew Time Set Point aJ cl c $4 g 0 c Sec Event or Value CC C4 lA M $ 4 Q H g4 ~ 4 CQ 1800 1. Operator actuates atmos-pheric dump valves to commence cooldown of RCS
- 2. Operator loads the following on safety buses charging pumps pressurizer heaters
- 3. Operator borates to cold shutdown concentration
- 4. Operator clears SIAS and reestablishes letdown 7200 Of f.-site Power restored 2, 24(H Shutdown cooling initiated, 350/275 F/psia
TABI.E 15. 1. 5.1 -2 SL2-FSAR DISPOSITION OF NOR'.L"'.ILY OP RATING SYSTE.1S FOR THE LOSS OF 51AIN STEAH-LARGE OUTSIDE CONTAIh~ilENT UPSTRF. OF MSIV WITH THE LOSS OF OFFSITE POWER AF TURBINR XP 8
o~ ~ <~
o co~ "
P'YSTEM
- 1. Main Feedwater System
- 2. Turbine-G nerator Control S stem
- 3. Steam Bypass Control S stem
- 4. Pr essuri zer Pressure Control Sys tern X
- 5. Pressurizer Level Control System
- 6. Control Element Drive Mechanism Control System X
- 7. Reactor Peg '.ating System
- 8. Reactor Coolant Pumps
- 9. Chemical and Volume Control S stem
- 10. Condenser Evacuation Sys tem
- 11. Tur bine Gl and Seal ing Svs tern
- 12. Component Cooling Water System
- 13. Turbine Cooling Water System
- 14. Intake Cooling Water S stem X
- 15. Condensate Transfer Sys .em X
- 16. Circulating Hater System
- 17. Spent Fuel Pool Cooling System
- 18. AC Power (Non-Safety)
- 19. AC Power (Safety)
- 20. D. C. Power
- 21. Power Operated Relief Valves
- 22. Instrument Air S stem
- 23. Waste Manaoement-Liauid NOTES l. System has no automatic mode.
2~ Lose power on loss of offsite power, then automatically loaded on diesel generator.
- 3. Operator must connect to safety bus for operation.
4, Only essential portions of the system are available.
TABLE 15.1.5.1-3 SL2 "FSAR UTILIZATION OF SAFETY SYS i~S LOSS OF MAIN STEAM-LARGE OUTSIDE CONTAINMENT UPSTREAM OF MSIV MITH THE LOSS OF OFF-SITE POWER AFTER TIJRRINE TRIP gK Q cn CD R VJ N R
$x Cce e3-
- 1. Reactor Protection S stem
- 2. En ineered Safe Features Actuation S stems
- 3. Diesel Generators and Sun ort S stems
- 4. Reactor Tri Switch Gear
- 5. stain Steam Safet Valves
- 6. Pressurizer Safetv Valves
- 7. ~sfain Steam Isolation Valves X
- 8. Main Feedwater Isolation Valves
- 9. Auxilia Feedwater S stem
- 10. Safet In'ection S stem ll. Shutdown Coolin S stem CCW 6 IQP
- 12. Atmos heric Dumo Valve S stem +X
- 13. Containment Isolation S stem
- 14. Containment S ra S stem
- 15. Iodine Removal S stem
- 16. Containment Combustible Gas Control S stem
- 17. Containment Coolin S stem NOTES:
- Manually actuated during normal cool down
- 1. Normally operating system (in nonsafety mode) 2, Permissive blocks of SIAS and MSIS are manually actuated to permit shutdown depressurization.
Systems not checked are not utili ed during this event.
15.1-
SL2-FSAR TABLE 15 ' 5il-4
~
ASSUMED INPUT PARAMETERS AHD INITIAL CONDITIONS FOR LOSS OF MAIH STEAM~
LARGE, OUTSIDE COHTAIHMEHT UPSTREC1 OF MSIV WITH LOSS OF OFFSITE POWER AS A RESULT OF TURBINE TRIP Parameter Assumed Value Initial Po$ er Level, HWt
$ 2621.4 Initial Core Inlet Coolant Temperature, F 551 Initial Core RCS Flow Rate, gpm 370$ 000 Initial RCS Pressure, psia 20150 Initial Pressurizer Water Volume, X Level 53 Axial Shape Index -0 3 Doppler Coefficient Multiplier Moderator Temperature Coef ficient, 10" Dp/F . -1.6 CEA Worth for. Trip, 10 5p -6.676 Break Size, ft 15.1"
C SL2<<FSAR TABLE 15.1.5.1-5 OFFSlTE DOSES Two Hour Exclusion Area Entire Event LoM Boundary Dose Population Zone Dose Thyroid 64 rem Whole Body
- 15. 1-
150 h 120 z
CO N
90 O
C 60 0V
.30 0
0 360 720 1080 TIME, SECONDS FLORIDA POWER 8 LIGHT COMPAh ST. LUCIE PLAHT UNIT 2 CORE POWER VS TIME FIGURE 15.1.5.I 2
iSO X
~ 120 LQ X>
D LU 0
K cf m X4 SO
< 0 60 O u.
O Q 30 360 ' 720 1080 1440 1800 TIME, SECONDS FLORIDA POWER 6 LIGHT COMPANY ST. LUCIE PLANT UHIT 2 CORE AYERAGE HEAT FLUX YS TIME
3000
<<DOES NOT lNCLUDE ELEVATION AND REACTOR COOLANT PUMP HEAD EFFECTS
~:2400
~ '1800 a "1200 O
600 0 . 36Q 720 1080 1440 1BCC TlME, SECONDS FLORIDA POWER L, LIGHT COMPANY ST. LUCIE PLANT UNIT 2 REACTOR COOLANT SYSTEM PRESSURE YS TIME
MODERATOR DOPPLER SAFETY lgJECTION TOTAL CEA 360 720 1080 i440 ~800 TtME, SECONDS FLORIDA POWER & LIGHT COMPAIIY ST. LuclE PLAHT UNIT 2 REACTIVITY VS TIME
700 600 BOO
'AVERAGE I
'R 400 INLET O
O r gg 300 200 0 360 - 720 1080 1440 1800 TIME, SECONDS FLORIDA POP/ER E LIGHT COMPANY
~
ST. LUCIE PLANT UNIT 2 CORE COOLAIIT TEMPS. YS. TIME VII,IIPI= 15 I-5
lCCC 800 0
400 200 0
0 360 . 720 1080 1440 1800 TIME, SECONDS FLORIDA POWER 8 LIGHT COMPAHY ST. LUCIE PLAHT UHIT 2 PRESSURIZER WATER VOLUME VS. TIME FlGURE 15,1,5,l-7
1 ~ 2 0 ~ 7 0 0
~ LL 0
0 u.
.V 0 0Z I
0 u+ OI-tu C Cg K ~ 2 0 0
~
I I 360 .720 1080 !440 'BQQ Tlh1E, SECONDS FLORIDA POWER h LIGHT COMPANY ST. LUCIE PLAHT UHIT 2 REACTOR COOLANT FLOW VS Tlh(E
0.9 0.6 0 10 20 30 " 40 sa QIME, SECONDS FLORIDA POWER 8 LIGHT COMP4NY ST. LUCIE PLIGHT UHIT 2 MIHIMUMOHBR VS TlME FlGURE 15.1.5,l-9
800 BOO INTACT LINE 400 RUPTURED LINE 200 0 360 720 1080 1440 1800
~
TIME, SECONDS FLORIDA POWER 8 LIGHT COh(PAHY ST. LUCIE PLAHT UHIT 2 STEAM GENERATOR PRESSURE VS TIME FIGURE 15.1,5. )-10
300 24Ci 180 0
' 120.
INTACT LINE 4
60 RuPTuRED LINE 0
0 720 1080 1440 1800 TlME, SECONDS FLORIDA POWER It LIGHT COMPANY ST. LUCIE PLANT UHIT 2 STEAM GENERATOR LIQUID MASS YS TIME FlGURE 1S.1.5. I-l 1
4000 3200 2400 16CO 800 RUPTURED LINE INTACT LINE 0
360 720 1080 1440 18CC TIME, SECONDS FLORIDA POWER 8 LIGHT COMPANY ST. LUCIE PLAHT UNIT 2 TOTAL STEAM FLOW YS TIME FIGURE 15.1.5.t-l2
400 gg lb
+a
~
320 p'
gg I-
,I cf
~
g Z LU 240 C9 tQ gg
~
160.'0.
0 0 360 . 720 1080 i 440 lBCC TIME, SECONDS FLORIDA POWER 8 LIGHT COMPANY ST. LUCIE PLAHT UNIT 2 INTEGRATED STEAM fLOM YS TIME FIGURE 15.1.5. I-13
200C 1600 120C m
0 8CC I-CI'00 I
0 360 - 720 1080 1440 180C TIME, SECONDS FLORIDA POWER E LIGHT COMPANY ST. LUCIE Pl AHT UHIT 2 FEEDWATER FLOlV YS TIME FIGURE 15.1.5. I-14
400 CQ 300 200 100 0
0 360-'20 1080 ,i 440 ,8m TlME, SECONDS FLORIDA POWER L LIGHT COMPANY ST. LUCIE PLAHT UHIT 2 FEEDWATER ENTHALPY YS TIME FlGURE 15.1.5. 1-15
Secti on 15. 2 Revi s i on
S1.2- FSAR ~
s 15.2.2.3 Limiting Fuel Pcrforirance Event None of thc Infrcquerrt event groups and event combinations resulting in a decreased heat removal by the secondary system shown in Table 15.2.2-1 pro-duce a significant approach to fuel performance guidelines. The degrad-ation in fuel performance which would occur during the most adverse of these event groups or event group coinbinations does not result in a DNBR less than 1.19 and therefore is within the acceptance guidelines in Table 15.0-4.
15.2.3 LIHITING FAULT-1 EVENTS 15.2.3.1 Limiting Offsite Dose Event Hone of thc LF-1 event: group and event group conibinations in resulting in a
~ decreased heat removal by the secondary system shown in Table 15.2.3-1 re-lease a significant: amount of radioactivity to the atmosphere. The site boundary do. e, vhiclr voula occur during the most adverse of these event groups or event group combinations, is well within the acceptance guideline
.specified in Table 15.0-4.
15.2.3.2 Linitint >>csctor Cools~et S "tes> Prcssure Event Loss of Condenser V icuum with Loss of Offsite Power, as a Result: of Turbine Trip
]5.2.3.2>1 Identification of Event and Causes All Limiting Fault 1 (LF-I) event: groups from the Decreased Ileat Removal by the Secondary Syst.em event type arid tlie Ll'-1 everit g>roup conbinations sliown in Table 15.2.3-1 vere conpared to find tlie event resulting in the rraximum React'or Coolant System (RCS) pressure. The loss of condenser vacuum with loss of offsite power as a result of turbine t:rip was identified as the limiting LF-1 event.
g> > s >~+
H)e event groups and event: combinat:ions evaluated and the significance of the RCS pressure increase for each are indicated in Table'5.2.3-1. AIl of the events indicated as insignifcant (I) produce a maxinium RCS pressure well within the acceptance guideline in Table I5.0-4..
A loss of condenser vacuum rray occur due to the failure of the Circulating Water Syst: em to supply cooling water, the failure of the Hain Condenser Evacuation System to reniove noncondensible gases, or t: he inleakage of an excessive aniount of air through a turbine gland. (Sce Table 15.0-1 for a list of all init:iating events in each event: group).
Hone of the irritiating events considered in the loss of condenser vacuum event group were analyzed. Instead, an event vhich bounds the potential RCS pressure increase due to the events in this event group vas analyzed .
For this bounding event it is assumed that coincident with the loss of con-of'ff-denser vacuum, the turbirte trips instantly. In .t'his analysis, loss site power as a r'esult of t:urbine trip is assumed to occur after turbine trip. ~ ~
All the event groups other tlian loss of condenser vacuum (including the
~ ~
loss of external load with an low probability independent occurrence) con-15.2-114 Amendment No. 2, (5/81)
Insert A to a e 15.2-114.
~ ~
The maximum RCS pressure for a feedwater line break without any coincident occurrences
~ ~
is 2715 psia. Analysjs has shown this maximum RCS pressure is produced by a feedwater
~ ~
~
ft
~
and is higher than the peak pressure produced by any other size
~
line break of 0.25
~
feedwater line break, large or small.
SL2- FSAR between core heat addition and steam generator heat removal prior to the CEA insertion and, hence, to maximize the peak RCS pressure. The affected steam generator is assumed to instantaneously lose all heat transfer capacity when total depletion of its liquid inventory by boil-off and discharge occurs. The break area, which resulted in the highest peak RGS pressure, was found to be 0.25 ft, ~
Using the highest initial core power maximizes the RCS heat-up which is the driving force of the pressurization. Variations of initial core inlet temperature and initial reactor coolant flow had negligible effects on the peak RCS pressure. The highest initial core inlet
~
temperature and the lowest initial reactor coolant flow were used in the analysis. The Pressurizer Pressure Control System is placed in
'he the automatic mode, such that it delays reactor trip, thus prolonging RCS heat-up and increasing RCS pressurization. Using the smallest CEA worth ana the least negative moderator temperature coefficient maximizes the heat flux overshoot after reactor trip, increasing the RCS heat-upi The highest initial pressurizer liquid volume and manual operation of Pressurizer Level Control System were used to allow the maximum in-crease of pressurizer level, maximizing the transient effect of RCS pressure increase during heat-up. However, the selection of Press-urizer Level Control System operating mode and initial pressurizer liquid volume has only a small impact on the peak RCS pressurei Auxiliary feedwater was assumed to be activated by the plant operator within five minutes of the low steam generator level trip condition to prevent the pressurizer from filling solid. The assumed flow to the intact steam generator -s 500 gpm. V'
~A 5 t'p'~ rfp, To maximize RCS pressure, the SBCS is assumed to be in the manual modei In oraer to eliminate the impact of uncertainty in the water level of the affected steam generator, reactor trip on a low water level is not assumed tn occur until dryout of the affected steam generator, It is anticipated that equipment may be actuated by high containment pressure during this event. These actions are identified in the sequence of events, but are conservatively assumed not to occur in the quantitative ana'ysis of the NSSS response to this event.
c) Results The dynamic behavior of important NSSS parameters following loss of feedwater inventory with loss of offsite power as a result of turbine trip is presented in Figures )5.2.5.2-2 to 20. Table )5.2.5.2-)
summarizes some of the important results of this event and the times at wh'ch the minimum and max'mum parameter values discussed below occur, A rupture in the main feedwater line instantaneously terminates feed-water flow to both steam generators and causes liquid flow from the 15.2-150 Amendment No.2, (5/81)
ert AW ( to page 15.2 - 150)
The peak RCS pressure occurs at 31.6 seconds. Analysis has shown that if only one motor-driven AFl< pump automatically starts delivering 320 gpm to the intact steam generator at 146 seconds, the peak pressure will be unchanged and the pressurizer will be prevented from filling solid.)
SL2- FSAR 15 ~ 3+3 LIHXTENG FAULT 1 EVENTS 15o3i3il Limitin Offsite Dose Event None of the Limiting Fault-1 (LF-1) event groups and event group combina-tions resulting in a decrease in Reactor Coolant System flow rate shown in Table 15i3.3-1 release a significant amount of radioactivity to the atmo-spherei The additional failures and events considered here produce results only incrementally more adverse than the loss of offsite power described in Subsection 15.3 '.1. The offsite doses which would occur during the most adverse of these events are well within the acceptance guideline in Table 15+0-4i 15+3+3+2 Limitin Reactor Coolant S stem Px'essure Event
~
None of the Limiting Fault-1 event groups and event group combinations re-sulting in a decrease in reactor coolant flow rate shown in Table 15.3.3-1 produce Reactor Coolant System pressures greater than that produced by the loss of offsite power event described in Subsection 15.3<2.2. Therefore, the conclusions of Subsection 15 ~ 3.2 ~ 2 also apply to this section.
15.3,3.3
~ t Fuel Limitin Performance Event None of the Limiting Fault-1 event groups and event group combinations resulting in a decrease in Reactor Coolant System flow rate shown in Table 15.3.3-1 produce a significant approach to fuel performance limits.
The limiting event combination with respect to fuel performance is a one pump resistance to forced flow (shaft seizure) with a failure to achieve a fast txansfer of a 6 .9 kV bus to a startup transformer.
i ~
This results in the loss of forced flow from two additional reactor coolant pumps. For this event, no more than 5.0 percent of the fuel pins are calculated to experience OHB.
The results of this event are within the acceptance guideline for fuel performance given in Table 15.0-4.
15.3-37 Amendment No. 2, (5/81)
SL2 FSAR SL2-FSAR 15 ~ 3'4 LIMITING FAULT-2 EVENTS 15,3,4.1 Limitin Offsite Dose Event None of the Limiting Fault-2 (LF-2) event groups and event group combina-tions resulting in a decrease in Reactor Coolant System flow rate shown in Table 15.3.4-1 release a significant amount of radioactivity to the atmo-spherei The additional failures and events considered here produce results only incrementally more adverse than the loss of offsite power described in Subsection 15.3.2il+ The offsite doses which would occur dur'ing the most adverse of these events are well within the acceptance guideline in l2 Table 15+0"4o 15 ',4 ' Limitin Reactor Coolant S stem Pressure Event None of the Limiting Fault-2 event groups and event group combinations resulting in a decrease in reactor coolant flow rate shown in Table 15,3.4-1 produce Reactor Coolant, System pressures greater than that pro-duced by the loss of offsite power event described in Subsection 15.3 '.2i Therefore, the conclusions of Subsection 15.3.2.2 also apply to this sub-section.
15,3,4.3 Limitin Fuel Performance Event of the Limiting Fault-2 event groups and event group combinations 3 None resulting in a decrease in Reactor Coolant System flow rate shown in Table 15.3.4-1 produce a significant approach to fuel performance limits.
The limiting event combination with respect to fuel performance is a one pump resistance'to forced flow (shaft seizure) with a loss of offsite power as a result of turbine trip. This results in the loss of forced flow from all reactor. coolant pumps. of 4
e The transient minimum CE-1 ONBR of 0.362 occurs at 3.6 seconds. A plot of the minimum ONBR vs. time for the first seconds of the transient is provided in Figure 15.3.4.3-1. For this" event,
~
10 ~ ~ ~
no more than 13.0 percent of the fuel pins are calculated to experience
~ ONB.~
The initia1 conditions for the most adverse case are identical to those
~ ~
listed in Table 15.3.5.1-4. The results of this event are within the
~ ~
~ ~ ~ ~
acceptance guideline for fuel performance given in Table 15.0-4.
~ ~
~
~~a
2,0 j.,6
- a
- 5 1.2
- 5 9,8 0.0 2,0 0,0 6,0 , 8,0 10,0 TIMEr SECONDS FLORIDA PONER 8 LIGHT COMPANY ST. L!i~!.": PLA."!T Ut!!T 2 HOT CHANNEL MINIMUM DNBR VS i TINE FIGURE t5,'g.'t.- l
ir S L2-FSAR'5's5 LZ>~nTNG FAVLT-3 EiENTS
~ ~
XnlSFRY P'EW 'SEc~+(g~~~~+)
ps nd event group combina-tions resulti in a decrease. in Reactor Coo t System flow rate shown Table 15,3, 1 release a significant amoun of radioactivity. to the os-pherei e additional failures and eve s considered here produ results only i rementally more adverse than e loss of offsite pow described in Subs tion 15.3.2,1. The offsite ses which would occur ring the most ad@ rse of these events are wel within the acceptanc uideline in Table 1K,O"4.
15 ~ 3 ~ 5 ~ 2 Limitin Reactor Coolant S stem Pressure Event None of the Limiting Fault-3 event groups and event group combination's re-sulting in a decrease in reactor coolant flow rate shown in Table 15 ',5-1 produce Reactor Coolant System pressures greater than that produced by the loss of offsite power event described in Subsection 15.3.2.2. Therefore, the conclusions of Subsection 15.3.2.2 also apply to this sections 15+3 '.3 Limitin Fuel Performance Event'one of the Limiting Fault-3 event groups and event group combinations xesulting in a decrease in Reactor Coolant System flow rate shown in Table 15.3.5-1 produce fuel performances worse than that produced by the one reactor coolant group resistance to forced flow with a loss of offsite power as a result of turbine trip event combination described in Subsection 15 '.4.3. The'esults of Subsection 15.3.4.3, which are within the LF-3 acceptance guideline on fuel performance, also apply to this section.
15.3"41 Amendment No. 2, (5/Sl)
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~ ~ ~ ~ ~ ~ ~ ~ ~
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~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~
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Sequence of Events and System Operation Table 15.3.5.1-1 presents a chronological list and time of system actions which occur following the shaft seizure o'f a reactor coolant pump. Loss of offsite power is assumed to occur concurrent with the generator trip at 1.0 seconds after the event initiation. Refer to Table 15.3.5.1-1 while reading this and the following section.
success paths referenced are those given on the sequence
'he of events diagram (SED), Figure 15.3.5.1-1. This figure, together with Table 15.0-6, which contains a glossary of SED symbols and acronyms, may be used to trace the actuation and interaction of the systems used to mitigate the conse-quences of this event. The timings in Table 15.3.5.1-1 may be used to determine when, after event initiation, each action occurs.
The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. If offsite power can be restored, then the operator may elect instead to stabilize the plant at a mode other than cold shutdown. All actions required to stabilize the plant and perform the required repairs are not described here.
The sequence of events and systems operations described impossible.
below represent the way in which the plant was assumed to respond to the event initiator . Many plant responses are However, certain responses are limiting with respect to the acceptance guidelines for this section. Of the. limiting responses, the most likely one to be followed was selected.
Table 15.3.5.1-2 contains a matrix which describes the extent to which normally operating plant systems 8r e assumed to function during the transient. The operation of these is consistent with the guidelines of Subsection 15.0.2.3.
'ystems Table 15.3.5.1-3 contains a matrix which describes the extent to which safety systems are assumed to function during the transient.
The success paths in the sequence of events diagram, Figure 15.3.5.1-1, are as follows:
Reactivity Control:
A reactor trip signal (RTS) is automatically generated by the Reactor Protective System on low reactor coolant flow.
The RTS opens the r eactor trip circuit breakers to deenergize the control element drive mechanism (CEDM) bus power supply interrupting power to the CEDN holding coils, allowing the control element assemblies to fall into the core.
The charging pumps are manually loaded onto the safety bus and started. The RCS boron concentration is increased to the cold shutdown level by replacing the RCS volume shrinkage with borated water. This water is supplied from the boric acid makeup tanks (8AMT) by opening the gravity feed line valves and closing the volume control tank discharge valve.
Reactor Heat Removal: \
The Reactor Coolant System provides natural circulation to remove core heat following coastdown of the undamaged reactor coolant pumps. The steam generators provide primary to secondary heat transfer.
The shutdown cooling system (SCS) is manually actuated when the RCS temperature and pr essure have been reduced to 350 F and 275 psia, respectively. The SCS provides sufficient flow to cool the RCS to cold shutdown conditions.
Secondary System Integrity; The CEDM bus undervoltage relays sensing the interruption of power on the CEDM power supply buses, generate a turbine trip signal (TTS). The TTS causes the digital electro-hydraulic control system to close the turbine stop and control valves. Upon the loss of offsite power both main feedwater pumps lose power and coast down. The steam generator pressure increases to the main steam safety valves (MSSV) setpoint, and they open to dissipate heat from the RCS. The MSSYs close when the secondary system pressure drops and will cycle open and closed throughout the transient. An auxiliary feedwater actuation signal is generated on low steam generator water level. The auxiliary feedwater flow to the steam generators;is controlled automatically by the-Auxiliary Feedwater Actuation System. The condensate storage tank is the auxiliary feedwater source. The operato~
closes the main steam isolation valves and uses the atmospheric dump valve system to dump steam to the atmosphere to cool down the RCS until shutdown cooling entry conditions are reached.
Primary System Integrity:
The pressurizer assists in the control of the RCS pressure and volume changes during the transient by compensating for the initial expansion of the RCS fluid.
As the reactor coolant system (RCS) pressure increases, one of the two Power Operated Relief valves (PORVs) opens, dis-charging steam to the quench tank, where it is condensed and contained. When the plant is at power, the other PORV is isolated (by a closed block valve) to avoid an excessive discharge of reactor coolant (see Section 5.4.13.2). As RCS pressure decreases, the PORV closes.
Following isolation of the RCP controlled bleedoff line by the loss of instrument air a relief valve lifts discharging the bleedoff flow to the quench tank. During cooldown, the operator controls the auxiliary spr ays to reduce the RCS pressure. The operator uses the char ging pumps to replace the RCS volume shrinkage.
Radioactive Effluent Control Due to the loss of instrument air to pneumatically operated valves on loss of offsite power, several lines penetrating containment will be isolated. Those lines isolated include:
RCP controlled bleedoff, various sampling lines, reactor drain tank drain line, nitrogen supply, waste gas header, containment air monitoring lines, containment sump pump discharge, and steam generator blowdown lines. These actions are automatically initiated but do not contribute toward the mitigation of the event.
Maintenance of AC Power:
A low voltage on the 4.16 kV safety buses generates an undervol tage signal which starts the diesel generators.
The non-safety buses .are automatically separated from the safety buses and all loads are shed. After each diesel generator set has attained operating voltage and frequency, its output breaker closes connecting it to its safety bus.
ESF equipment is then loaded in sequence on to this bus.
15.3.5.1.3
~ ~ ~ ~ Analysis of Effects and Consequences a) Mathematical Hodels The NSSS response to one pump resistance to forced flow (shaft seizure) with a loss of offsite power as a result of tur bine trip was simulated using the CESEC computer program described in Subsection 15.0.4. The ONBR was calculated using the TORC computer code which uses the CE-1 CHF cor-relation described in Subsection 15.0.4.
b) Input Parameters and Initial Conditions The ranges of initial conditions considered are given in Subsection 15.0.3. Table 15.3.5.1-4 gives the initial conditons used in this analysis. The rational for selecting the values of the initial conditions which have a first order effect on the analysis follows. Using the highest core power maximizes the RCS heat-up, which is the driving force of the secondary steam release. The lowest primary system pressure was assumed in conjunction with the opening of one of the two power operated relief valves in order to maximize the number of fuel pins which will experience ONB. A high core inlet temperature was chosen since it yields the earliest opening of the main steam safety
.valves. The steam generator inventory and heat transfer was modeled to maximize the radiological consequences of the event.
The lowest core flow rate is used because it results in a larger percentage of fuel pins which experience ONB. Using the most positive moderator temperature coefficient and the minimum available scram CEA worth tends to maximize the heat flux after a reactor trip occurs, increasing the RCS Assuming the operator initiates plant cooldown at 'eat-up.
30 minutes maximizes the offsite doses. Ouring this event two sources of radioactivity contribute to the offsite doses, the initial activity in the steam generator and the activiCy associated with a one gallon per minute steam generator tube leak. The initial secondary activity is assumed to be at the Technical Specification limit of 0.1 pCi/gm dose equivalent I-131. The activity assumed to be present in the reactor coolant leaking through the steam generator tubes is 0.4 pCi/gm (see Subsection 15.0.4.3.1).
c) Results The dynamic behavior of important NSSS parameters following a one pump resistance to forced flow (shaft seizure) with a loss of offsite power is presented on Figures 15.3.5.1-2 to -11.
Table 15.3.5.1-1 summarizes the significant results of the event. Refer 'to Table 15.3.5.1-1 while reading this section.
The one pump resistance to forced flow (shaft seizure) event results in a flow coastdown in the affected loop and a consequent reduction in flow through the core. The reactor is tripped on a low flow signal . The reactor trip causes a tur bine trip signal to occur. The flow in the unaffected cold legs increases until the loss of offsite power (concurrent with generator trip) occurs. At this time the flow in the unaffected cold legs begins to decrease as a result of the reactor coolant pump coastdown. The loss of offsite power also causes a loss of main feedwater and condenser inoperability. The turbine trip with the SBCS and the condenser unavailable leads to a rapid buildup in secondary system pr essure and temperature.
This increase in pressure is shown in Figure 15.3.5.1-9.
The opening ofthe MSSYs limits this pressure increase. The flow rate out the MSSVs is shown in Figure 15.3.5.1-10. The integral flow out of the MSSVs is shown in Figure 15.3.5.1-11.
The increasing temperature of the secondar y system leads to a reduction of the primary to secondary heat transfer. Concur-rently, the failed reactor coolant pump and the three reactor coolant pumps coasting down ( Figure 15.3.5.1-8) result in reduced RCS flow which further reduces the heat transfer capability of the RCS. This decrease in heat removal from the RCS leads to an increase in the core coolant temperatures as shown in Figure 15.3.5.1-5.. The core coolant temperatures peak shortly after the time of reactor trip on low RCS flow.
K The increase in RCS temperature leads to an increase in RCS pressure, as shown in Figure 15.3.5.1-4, caused by the thermal expansion of the RCS fluid (see Figure 15.3.5.1,-7).
The. RCS pressure reaches a maximum value of 2427 psia at 6.25 seconds. After this time, the RCS pressure decreases rapidly due to the declining core heat flux (see Figure 15.3.5.1-3), in combination with the opening of the MSSVs.
Opening of the MSSV limits the peak temperature and pressure of the secondary system.
During the first, few seconds of the transient, the combination of decreasing flow rate, increasing RCS temperatures, and increasing core power (see Figure 15.3.5.1-2) results in a decrease in the fuel pins'NBR. The transient minimum DNBR of 0.362 occurs at 3.6 seconds as indicated in Table 15.3.5.-1-1. Figure 15.3.4.3-1 shows the variation of the minimum ONBR with time. The negative CEA reactivity inserted after reactor trip causes a rapid power and, heat flux decrease which causes the ONBR to increase again. For this event no more than 13.0 percent of the fuel pins are calculated to experience DNB.'ll fuel pins which experience ONB are conserva-tively assumed to fail (see Section 15.3.4.3).
The offsite doses for this event result from steam released through the main steam safety valves (HSSVs) and atmsopheric dump valves (ADVs). The MSSVs are open intermittently during the first 30 minutes of the transient (see Figure 15.3.5.1-10).
At 30 minutes, the operator is assumed to use the ADVs to begin cooldown. The total amount of steam released through the h/SSYs is shown in Figure 15.3.5.1-11. Table 15.3.5.1-1 shows the integrated steam release from the t1SSVs and the ADVs.
The radiological release produced by the transient results in a 7.8 rem two hour thyroid inhalation dose at the exclusion area boundary. The two hour and entire event doses for both thyroid and whole body are shown in Table 15.3.5.1-5.
15.3.5.1.4 Conclusion The evaluation shows that the plant response to a one pump resistance to forced flow (shaft seizure) with a loss of offsite power, technical specification steam generator tube leakage, and failure to restore offsite power in two hours results in a maximum offsite doses which are within the acceptance guideline in Table 15.0-4.
TABLE 1S.3. 5.1-1 SL2-FSAR SEQUENCE OF EVENTS, CORRESPONDING TIMES AND
SUMMARY
OF
'E PUMP RESISTANCE TO FORCED FLOW RESULTS FOR (SHAFT SEIZURE) WITH A LOSS OF OFFSITE POWER AS A RESULT F GENERATOR TRXP, TECHNICAL SPECIFICATION STEAM GENERATOR TUBE LEAKAGE, AND FAXLURE TO RESTORE OFFSITE POWER Success Paths 6 W o
Cl 4J tg 0
P IJ CO C$ Cl 0 O 4 Analysis 4J Q IJ 4J v 0 m H 0 cl Q 4J g I CO JJ 0 o Time Set Point a5 0 0 Cl g 0 O C O M Sec Event or Value 0.0 Seizure of RC pump shaft
-affected pump begins coastdown 0.45 Reactor trip signal generated on 93 'X.
low RCS flow, % of rated flow Turbine trip on loss of power on CEDM power sup'ply buses.
0.98 Auxiliary feedwater actuation 25.5 signal generated on low SG water level, ft above tubesheet 1.0 Generator Trip/Loss of Offsite Power
-Diesel generator starting signal
-Unaffected reactor coolant pumps and MFW'umps. lose power and coastdown 2.1 Maximum Reactor Power, 105.6 3.6 Minimum Transient DNBR 0.362 3.7 Main Steam Safety Valves* open, 1010 unaffected loop 4.4 Main Steam Safety Valves* open, 1010 affected loop, psia PORV 2370 opens, psia 6.3 Maximum RCS pressure, psia 2427
'.0 Maximum SG pressure unaffected 1040 loop, psia Maximum SG pressure affected loop, 1028 psia 10.4 RV o
- MSSVs cycle during first 400 seconds
0 TABLE 15.3 5 l-l SL2-FSAR SEQUENCE OF EVENTS, CORRESPONDING TZKS AND SENARY OF RESULTS FOR Pl&P RESISTANCE TO FORC6 FLOW (SHAFT SEIZURE) WITH A LOSS OFOFFSITE POWER AS A RESULT F GENERATOR TRIP, TECHNICAL SPECIFICATION STEAM GENERATOR TUBE LEAKAGE, AND FAILURE TO RESTORE OEFSITE POWER IN TWO HOURS Success Paths 6 44 0
Q 4J 0
4J Cll C5 4l 0 4J0 c 4l 0 0 Analysis 0 4J 0 0 0 C C a CO Q g CQ C4 Time Set Point 0 CJ CO
~J 0 Cl cJ C C 0 O Sec Event or Value 0 C4 CJ CO W j4 M GC 121 Auxilairy Feedwater begins to 66.7 enter SGs, ibm/sec (per SG) 1800 Operator opens ADV to initiate plant cooldown Operator loads the following'n safety bus:
-instrument air compressor X X
-charging pumps X X
-pressurizer heater X
-.clos'es MSIVs 0
14,544 Operator aligns SCS, F psia 350/2 75 Total steam release to atmosphere, 1,065,000 ibm MSSV cyc e until operator actuates ADVs at 1800 seconds.
15.3
I TABLE 15.3.5:1-2 DXSPOSTTION OF NORMALLY OPERATING SYSXmS Fvz ONE PtiM'ESISTS ~CE TO FORCED PLOP (SHAFT SEIZURE) WXTH A LOSS OF OFFSXTE POWER AS A RESULT OF GENERATOR TRXP, TECHNXCAL SPECXFICATXON STEAM GENERATOR TUBE LEAKAGE, AND FAILURE TO RESTORE OFFSXTE POWER IN TWO HOURS o~~ P~
o p o~
o+go@ r<<~rg ~~
8, p e -p of~
- 4. ~ 4r o c ~y ecr o
r o ~ o "( o$ ~oti oo <~< o g ooo o~<< r~ o sJ o
~O N +(h SYSTEH
- 1. t tain Feedwater System
- 2. Turbine-lieneratol Control S stem
- 3. Steam Sypass Control S stem
- 4. Pressurizer Pressure Control System
- 5. Pressurizer Level Control System X
- 6. Control Element Drive Mechanism Control System
- 7. Reactor Regulating System 8, Reactor Coolant Pumos 4 5l
- 9. Chemical and Volume Control S stem
- 10. Condenser Evacuation System
.12. Component Cooling Mater System
- 13. Turbine Cooling Water System
- 14. Intake Cooling Mater S stem
- 15. Condensate Transfer System
- 16. Circulating Mater System
- 17. Spent Fuel Pool Cooling System 18.'C Power (Non-Safety)
- 19. AC'ower (Safety) 2 3
- 20. 0. G. Power 4
- 21. Power Operated Relief Valves I 22.. Instrument Air S stem
- 23. Waste- t1ana ement-Li oui d Operator must connect the safety bus for operation.
tOTES; 2. Only essential porr1ons otthe sy'stem are available
- 3. Lose power on lass of odfstte power, than antomarically loaded on diesel generator.
- 4. System has no automatic mode.
- 5. A locked rotor on one RCP is the initiating event.
15.3-
TABLE 15.3.5.1-3 UTXLXZATION OF SAFETY SYSTEMS FOR ONE PUMP RESXSTANCE TO FORCED FLOW
{SHAFT SEIZIJRE) WITH A LOSS OF OFFSITE POWER AS A RESULT OF GENERATOR TRIP, TECHNICAL SPECIFICATION STEAM GENERATOR..TUBE LEAKAGE, A1%) FAXLURE TO RESTORE OFFSXTE POWER XN TWO HOURS O
I
- 1. Reactor Protection S stem En ineered Safet Features Actuation S stems
- 3. Diesel Generators and Su ort S stems
- 4. Reactor Tri Switch Gear
- 5. Main Steam Safet Valves Pressurizer Scifet. Va~ve
- 7. Hain Steam Isolation Valves
- 8. Main Feedwater Isolation Valves
- 9. Auxilia Feedwater S stem 10, Safe In ection S stem
- 11. Shutdown Coolin S stem CCW & XCW
- 12. Atmos heric Dumn Valve S stem
- 13. Containment Isolation S stem
- 14. Containment S ra S stem
- 15. Iodine Removal S stem
- 16. Containment Combustible Gas Control S stem
- 17. Containment Coolin S stem NOTES:
o Manually actuatad during carnal cool down Permissive block of SIAS and MSXS are manual'y actuated to permit shutdown depressurization.
2, Portions of this system are actuated as a result of loss of instrument aira 3, Normally operating system (in nonsafety mode)
Systems not checked are not utilized during this event.
15.3-
SL2- FSAR TABLE 15 ~ 3.5.1-4 I
SUMED INPUT PARAMETERS AND XNXTIAL CONDITIONS FOR ONE PUMP RESISTANCE TO FORCED FLOP (SHAFT SEIZURE) MITH A LOSS OF OFFSITE POWER AS A RESULT OF GENERATOR TRIP, TECHNICAL SPECIFXCATION STEAM GENERATOR TUBE LEAKAGE, AND FAILURE TO RESTORE OFFSXTE POWER XN TWO HOURS Assumed Value parameter 2630 Initial Core Power Level, Mwt Core Inlet Coolant Temperature, F 551 Core Flow Rate, gpm 370,000 RCS Pressure, psia 2150 Initial Pressurzier Volume, X level 40 of narrow range tap 35 St'earn Generator Ma t err Level X span Multiplier 0.85 "pppier Coe Do ffic ient Moderator Temperature Coef ficien, 10 a,
/
p//F 04"
+0.4
-2 4 5~5 CEA 0lnr th for Trip, 10 p s cified ze in Subsection 15,0.3,2.2 an d (a) This value is outside the rangee speci
~
is chosen to maximize RCS heatup.
SL2>> FSAR TABLE ) 5 e 3 i ~e 1- 5 OFFSITE DOSES Two Hour Exclusion Area Entire Event Low Boundary Dose PopulaCion Zone Dose Thyroid 7.8 rem (Later)*
Qhole Body (Later)* (Later) *
>>to be supplied by Ebasco
14" x 17" Originals of the sequence of events diagram on the following pages Figures 15.3.5.1-1a to 15.3.5.1-1h) are available for reproduction C-E, S. Ritterbusch).
INITIATIHG EYEHT LOCKED ROTOR MIIH A LOSS OF OFFSITE REACTOR COOLANT PUHP POMER AS A RLSULT Of BEARING'FAILURE TURBINE TRIP l5.3.5.1 REACTIVITY CONTROL Ittttt ~ ~ I 000000000000000000000000001 ~~~ I~ ~ ~ ~0
~ I 000 I I IIIIISII 00000000000 I Yo ~ I I 00000 I 00 ~ 00 ~ 00 ~~
I CR NS IA
~I PI L I I LOAD INSTRUHENT AIR COMPRESSOR H OH TO 480Y SAFETY BUS TO SUPPLY . i:
)/2 . AIR TO SS. CCQ AND CVCS VALVES.:j.::
A 8 0',
CR 2/2 FSAR 9.3.1 F~sL RPS RTS NOTE: IF IA 15 HOT RESTORED.
BORON CONCENTRATION IH A 8 RCS HUST BE OETERHIHED ,:N,:::
BY CALCULATION.
S.pts 93K FSAR TABLE 15.0-7 2/3: FSAR 7.lo 7.2 1.1 I
~ I~ ~ ~ ~ tt ~~ ~ ~ ~ @I ~ ~ ~ ~ 000 ~~ ~ I~ ~ I~ I~ ~ ~ I~ ~ ~ ~ I~ ~ ~ ~
CR CR OPEHS REACTOR TRIP CIRCUIT HS OPEN GRAViTY'FEEDLINE VALV~ (V-2508 RTS RTSS BREAKERS TO DE-ENERGIZE CEOH CVCS OR V-2509) TO TAKE CHARGING PUHP H
2/2 BUS POMER SUPPLY INTERRUPTING Cb . Id SUCTION FROH BAHT. CLOSE VCT DIS-A 8 C D POMER TO CEDN HOLDING C01LS.
I/1 CHARGE VALVE (V-2501).
SAHPLIHG 2/4:,: 0.34 SECONDS I/2,: FSAR 9.3.4.2
'TE: THERE ARE FOUR PAIRS OF FSAR 15.D.2.2 CIRCUIT BREAKERS; TMO PAIRS,:.: ', FSAR 7.2.1.1.3 ONE IN EACH PtNER CIRCUIT, ARE REQUIRED TO INTERRUPT FOMER TO THE CENs.
BAHT BORATEO MATER SUPPLY FOR CHARGING PUHPS.
GRAVITY INSERTION OF CEAs t2.66 SECONDS FOR 90K IHSERTIOH Q. I ~ 8 FSAR 15.0.2.2 I/2:: FSAR 9.3.4.3 S.F. I FSAR 4.2.1.4 CfmL REACTIVITY INCREASE RCS BORON CONCEHTRA-CVCS CONTROL Cb IP, (CflARGING) TIOH TO COLD SNTOOMH LEVEL (TRIP) I/I I/3 H BY REPLACING RCS VOLUHE 5HRIHKAGE.
- .SAHPLIHG QR I/2 FSAR 9.3.4.2
- CALCULATIOH CVCS LOAD CHARGING PUHPS ON 480V (QlARGIHG)
SAFETY BUSES AND START.
REACTIVITY A 8 CONTROL (SHUTOONN)
I/3 8.3
'..::.:: FSAR NOTE: CHECK OG LO.SDING PRIOR TO ADDING t I ~ - I J'Y PfgCQ
REACTOR HEAT HOVAL RCS HATURAL CIRCULATION OF REACTOR P
COOLANT REHOVES HEAT FROH CORE.
I/2: FSAR 5,1 0
SG PRIHARY TO SECONOARY HEAT TRAHSFER.
I/2: : FSAR 5.1 ~ 5.4.2 REACTOR HEAT REHiOVAL CCtt ALIGN VALVES (14CV-14-3A,38)
TO SUPPLY COOLItiG ltATER TO 5OCHX.
1/2 'SAR 9 2 2 ALIGN LPSI FOR SHUTSNN COOLIHG CRLL CLOSE LPSI SUCTION TO RMT LlttES V3432,V3444)
SCS PP cj l&V<7-1514).~ OPEtt SIQTOOHN 1/4 I/4 COOLItiG SUCTION LINES (V3480, V3481,3654 FROH LOOP A, V3651,
<<275 psta V3652, V3665 FROH LOOP 8).
I/2 START LPSI PUHPS.
FSAR 5.4,1.2.6 :FSAR
, 5.4.1, 6.3.3.4 NOTE: T TO ENSURE I CHOSKH ttOTE: CS IS ttOT AVAILAGLE AFTER hl <<350 F SCS IS PLACEO IH OPERATION.
REACTOR HEAT REHOVAL StQTSN) 15.3.5.I-Ib
ll I
~ m 86N6
~
I' I
I I ~
Ã%
I I I I
T RRN%
I I' II Ia ~
I RHSl5 'T
.Qgg RON% I
]I .
,gg T
I ' I ' ~I I I I FE I
I I I~ ~ 'i I 0' i e I I ' ~
I' I ' I
CR NS t5 CES ACTUATE AIR EJECTORS TO CR cd RESTORE CONDENSER VACUA.
P dH I/I H NS CLOSE HSIVs (IQCV~-IA,IB).
I/1 2/2 FSAR 10 4.2 A 8 2/2 :. FSAR 7.3.1 1.5
'sh NS OPEN TURBINE BYPASS VALVES TO DUN P
STEAN TO CONDENSER TO COOLMMH RCS H SBCS T UNTIL SHUTDOMN COOLING EHTRY CONDI-I , TIONS ARE REACHED.
CONQENSFR AVAILABLE I/5 FSAR 7.3, 10.4.4 NTE: THERE ARE FOUR OINP VALVES (PCV-8802, 8803, 8804, 8805)
MITH 40K CAPACITY AND OHE CRL BYPASS VALVE (PCV-8801) METH SX CAPACITY.
59 P
ADVS OPEN AIQ COHTROL TO ONIP STEAN N Tcl TD ATHOSPHERE AhD COOL RCS.
CD HEAT SINK FOR SBCS.
A 8 C D 2/4: FSAR 7.4.1.4, 10.3.
I/I FSAR 10.4.1 NS NS CR PERHISStVE BLOCK OF SG PRESSURE OPEN VALVE LCV-12-5 ~ CLUIENSATE P L I/I H. ESFAS SIGNALS TO HSIS TD PERNIT SHUT- L cd H I/I PNPS TRAHSFER MATER FPAN CD TO OOMN OEPRESSURIZATION OF SECONR. CST.
I/O DARY SYSTEH.
A 8 C 0 FSAR 10.4.1 S.P.: 585 pslg 3/4:: FSAR 7.3.1.1.5 NOTEs IF SYSTEH PRESSURE RISES ABOVE BLOCK SETPOINT THE BLOCK IS AUTOHATICALLYRIHOVED.
HOH-FETY POME s9 ESTORED Pp REOPEN AHD CONTROL TO OUHP STEAR YES ADVS TO ATRISPHERE AHD COOL RCS.
cj A 8 C D OPEN HSBYs (I-HYM-IA, HSIS 18) THEN OPEN HSIVs Psg BELOM 400 psla FSAR 7.4.1.4 ~ 10.3.
2/2 ( I-HCV-OB-IA,18) . RECLOSE MSBVs.
2/2 FSAR 10.3 CR P
NS CLOSE HSIVs (I~M-IA,IB)
CR IH PREPARATION TO BREAK VAQIN.
1/4 NS NS START PUHPS TO PROVIDE COOL TdH H ING MATER TO THE CONDENSER.
I/2 )IELI( i)00 psI4 ~ ~ ~ ~~~~
2(2 FSAR 10 3 ~ 10 4 7 A 8 C D 2/4 FSAR 10.4.5 SEC. SYS.
P,"5!'L/HS 15.3.5.1-1d
Y SYSTEH
. NTEgRITY 0 PER ASSISTS III CONTROL OF RCS PRESSURK AND VOLUME CINNGESo FSAR 5.4.10 o
<< t ~ ~ ~ ~ 'tVtVt~ 0 ~ oVtVtVoVtV'VVo tVo 1'tVeVtVtVoVOVtVeVtVOVt'eVo 't'VOVoVoVV 'oV "Vt Vo'Vt"VVtVrtVtVt ' 'Vt O' "
V ' """ 't PSV OPEN TO LIMIT RCS PPH OI'EN TO LIHIT RCS PRESSURE INCREASE.
PORV PH A B C PRESSURE INCREASE S.P.: 2510 ps1g S.P.: 2370 psIa 0/2 FSAR 5.4.13 ~ VooVoVeVOVooV ~~~~o~~~~
'S RECEIVE AND CONDENSE ALTERNATE RECEPTACLE FOR ALTEIUIATE RECEPTACLE FOR CB MASS AND ENERGY RELEASE STEAH FROM PSVs.
RECEIVE AND CB MASS AND BIERGY RELEASE FROM PSV DISCHARGE.
CONDBISE STEAH FROM PORV DISCNARGE FROH PORV.
FSAR 5.4.11 '-:.. FSAR 6.2.1 FSAR 5.4. 11 FSAR 6.2.1 PSV CLOSE AS PRESSURE OKCREASES.
A B C S.P.: 2409 pslg 3/3:.: FSAR 5.4.13 BLOCK CLOSE TO PORV CLOSE AS P H PRESSURE DECREASE P L VALVE ISOLATE PORV res I/4 A 8 A B 2/2 FSAR 5.4.13 2/2 FSAR 5.4.c3
~
S.P.: 2346 psIa
~
PRIMARY SYSTEH PRESS/LEVE CONTROL I5.3.5.1-1e
It
~ ~ ~ ~~ ~~ ~~~ ~ tI ~ ~~0 ~ ~~ t~ ~0~ ~ ~ ~~~~~~ ~~~~~~~~
4 0
ybY0Yl~ 0 oY1YSY oYo + 0 ~ I~ t 't 4voYo I 0 ts tvo 0YovtYt ~
~
CRAL OPEN AND CLOSE AUXILIARY Pp SPRAY CONTROL VALVES TO REGUlATE P (I-SE-02-03,04).
I/O P I/3 FSAR 9.3.4
~ ~ hOTE: USE OF AUXILIARY SPPAY ALSO AFFECTS RCS IttVENTORY CONTROL.
COL HS CVCS DIVERT FLOQ TO AUXILIARY SPRAY Lp Pp (CtlARG ING) BY CLOSIHG CHARGlttG COHTROL VALVES (I-SW)2-01,02).
I/3 A B C 2/2 : 'SAR 9.3.4 OPEN VALVES I-V@7-1609 (LOCAL)
CVCS AND V2504 FROH RMT TO CHARGIHG Cb PUHPS. CLOSE BAHT DISCHARGE I/I VALVES (V2508 AHD V2509).
I S.P.: COLD SHUTDOttH BORON COHCEHTRATION FSAR 6.2 CR bblat YATER SUPPLY FOR CHARGIHG PINPS.
FSAR 6.3.2.2.4 B
CR PERHISSIVE BLOCK OF PRESSURILER 1/1 ESFAS PRESSURE INPUT TO SIAS TO PERHIT P L SRlTOOMH DEPRESSURILATIOH OF I/4 REACTOR COOlANT SYSTEH.
A 8 C D COL S.P.: 1650 pska 3/4 ', : FSAR 7.3.1.1.1 CVCS START AND STOP CINRGIHG PNPS L H(CHARG IHG)
TO HAKEUP RCS VOLUHE SHRI)tKAGE.
I/3 ~t ttOTE: IF THE SYSTEH PRESSURE RISKS A 8 C ABOVE B!.OCK SETPDINT THE BLOCK I 5 AUTOIOTICALLY REHOVEO.
CCCO COL SIT DEPRESSURILE SITS BY DPAItlIHG P OR VENTING AND ISOLATE THEH.
I/4 COL A B C D LOAD HEATERS OH SAFETY BUS..USE P H PPCS (PH)
HEATERS TO ADJUST RATE OF DECREASE 4/4: '- FSAR 6.3.2.2.1 OF PLR PRESSURE. 'EITHER PROPOR-I/O TIOttAL OR BACKUP HEATERS HAY BE
.':::;. OEPRESSVRIZIHG - P <25 pslg PROP BACKUP USED).
- ,:'..". ISOIATION - P ~278 psja I/2 FSAR 7.7.1.1.2 PRlt<. SYS.
PRESS/LEVEL 15.3.5 I-IF COttTROL t~~
RADIOACTIVE I ~ \ ~ ~ IVIIV ~ IVI'I IV~ ~ ~ ~ ~~~ I ~~~ I~ I V V ~ IVI~ ~ \ ~
EFFLUEH$ QNTROL CLOSE VALVES I-HCV-14<<1.2.6,7,8A,SS.
CVCS CLOSE LETODHN ISOLATION VALVES
'laL CCtt 9,10 TO ISOIATE HOH-ESSEtiTIAL CCtt TO (Y-2515'-2516, V-2522).
AND FROH CONTAlt8ENT SUILDIHG IHCLUD- PI L IHG RCPs.
A 8 C
- FSAS 9.2.2
- ,FSAR 7.3, 9.3.4 CLOSE VALVES IHCLUDIHG TIQSE IH RCP Cl CONTROLLED Bl.EEMFF LINE. VARIOUS SAHPLE LlllES, lolSTRUHEtlT AIR SUPPLY
/ pR IPARY Ia P
8 LINE; RDT DRAINLltlE. PRIHARY NKEUP kATER, CONTAltlHEHT PURGE. tllTROGEN
( SYSTEN I SOlAT I UN
)
SUPPI.Y, MASTE GAS HEADER, COttTAltNENT I/2: AIR HONITORING LltlE, START SIGNAL SENT TO SSYS FANS AHD OPEH SIGNAL SENT TO SBYS VALVES.
FSAR 6.2 4, 7.3.1.1.4, 9.4 CLOSE STEAt< uEteERATOR SLSttettt SGDS AND BLOltDO'",t SlHPLING ISOLATIOtl RELIEVES CONTROLLED BLEEDOFF FROH Ia VALYES (I-l CV-23,3,5,7,9),
CVCS I RCPs TO QT VIA V2199 UPON'LOSS OF P~H IttSTRUNEHT AIR.
2/2::.:.:F SAR 10.4.8 FSAR 9.3.4 SECOtiDAR~Y
( SYSTEH ISOLATION
)
RECEPTACLE FOR CONTROLLED BLEEDOFF FROH QT RCPs FOLLO'lIHG CONTAII1IEHT ISOIATION.
FSAR 5.4.11 COHTAIt'tENT)
( BOILDIHG ISOLATION
~~~~~~~ I ~ ~ ~ ~ I ~ I ~ ~ ~ ~ ~ ~ ~ ~ I ~ I ~ ~ ~ ~ ~ ~ ~ ~ ~ I~ ~ I ~ ~ ~ ~ ~ ~ ~ ~ ~~~~ I ~ 0 ~ I ~ I ~ I ~ ~ ~ ~ ~ I ~ ~ I~ I ~ I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I I ~
~ ~ e'Ie I'o'O'IYCCCIYO'IYIVI IYI'O'IYIYIYIVIYCIYIYIYIYIYCI'IVIVI'IYIYIVIVIYIYI'IVIVI'IYIYIYIVIY<VCIYIVIYIYIVIYIY 15.3.5.1-19
SPENT FUEL POOL RESTORATIOtt HEAT REISVAL OF AC. fNER CRSL FUEL COOLING BY HEATING BUVR SFP OF SPENT FUEL POOL RATER.
Vsaf" (4.16KV)
FSAR 9.1
- FSAR l.4, 8.3.1.1.l.f, 8.3.1.1.h OPEN VALVE (2-IV@V-14-19 UVS STARTS CR CCH OR 20) TO RESTORE COOLltG 1/1 1/I RATER TO FPHX.
sfpH FSAR 8.3.1.).if, 8.3.1.1.2.13, I/2:. FSAR 9.2.2 9.5.&
CR I
I/l~ LOAD FUEL POOL PLNP(s) sf p /2 PCPS Ott SAFETY BUS. CIRCU-LATE POOL ttATER THROUGH FSAR 9.1.3.2.1 THE FUEL POOL HEAT EX-CHANGER FOR COOLING.
I/2 FSAR 9.1.3 SAFETY BUS CIRCUIT SHED ALL LOADS.
BREAKERS SPENT FUEL POOL HEAT REHOVAL 1/I:". : FSAR 8.3.1.1.2.h SAFETY BUS CLOSE DG OUTPUT BREAKER TO CONNECT V~L , CIRCUIT DG TO 4.16KV SAFETY BUS. (10 SECONDS BREAKERS FROH START OF DG).
I/1 ':; ','FSAR 8.3.1.1.2.h LOAD REQUIRED ESF LOADS FOLLOHIHG Vsa" I.S OG..\
ISOLATIOH OF 4.16KV BUS AHD COHNEC-TIOH OF
- FSAR 8.3.1.1.1f, 8.3.1.1.2.h 18 SEC. TO LOAD ALL SAFETY I.OADS.
FSAR TABLE 8.3-2 NOTE: TttE ABOVE PATH IS TYPICAL OF THE STARTIHG AHD LOADIHG OF ONE DG.
RESTORATIOA
~ ~
HG CD C) 60 40 tD o 20 0 10 ZO 30 40 T I NE ~ 5 E CO !~) I 5 FLORIDA PO'6'FR 8a LIGHT COM ST t.U. % PL xlT Ui!I7 2 CORE POWER VS) TINE FIGURE 15,5,5,1-2
120
) GP o
. I-OX
. UJ~
. Xc( 69 W LJ UZ UJ ~ 4Q llJ ~
>0
~ Q.
QQ OU f I 0 }0 . 2O 3O 40 T I ~IF. SFCO'.~US FLORIDA PO'4'ER 8 LIGHT CQJ!PAt ST. LUG!". PL/.."iT U".!IT 2
~ @
~
CORE AYERAGE HEAT FLUX VS I TINE
2 ".GG 2160
~gg 0 1920 DOES NOT INCLUDE ELEVATION OR REACTOR COOLANT PUMP HEAD EFFECTS 1800 0 10 20 3O 40 T I llE, 5 ECON"'5 F L0 R 1 0A P 0'>' R 5 L GH T COMP A 1
1'T.
LU".'."= PL,".1T U."!1T RCS PRESSURE VS TIME FIGURE 15.3,5,1-4
OUTLET AQERQQE INLET ZO 30 40 ~C" f.
T I MF. SL'CDN" 5 FLORIDA PO'4'ER 8 LIGHT COi". A; ST. LIJ."'."- ?I./.!IT L>I!IT 2 CORE COOLANT TEHPERATURE YS I T[HE FIGURE 15 5 5 j."3
r ~ ~
0 I
~ t ~
2,0 ~ ~ ~
~ ~ ~
4 DOPPLER 0.
0'ODERATOR ~
I I
4
-2,0 0-I- ~ ~ ~
-4.0 I
O ~ TOTAL LU '-
-6,0. CEA
~ ~ ~~~
0 10 20 30 50 T I MEg S ECONDS PLQRIDA PQ'O'ER 5 LIGHT CQ< ANY ST. LU..'."= PL,'!ll L'."!IT "
I REACTIVITY VS s TIME FIGURE j.5.3,5,1-6
903.6 I~
753.0 602,4 301,2 j.50,6 0
0 10 20 30 40 T IhE . SECDt" DS
~ ~
FLORlDA POPE'ER 8 LlGHT t"O.'.lPkh" ST. l U..a". PL@?t7 UH) ( 2 PRESSURI'ZER WATER VOLUNE VS> TINE FIGURE 15,3.5.1-7
1,2
~ I
~ ~
~ ~
1,0
~ r ~ ~ ~ -~ ~
P ~ I 0,8 ~ I
~ t ~
~ P 0,6 ~
~ 'L
~
~1
~ ~ I I ~
~ ~
I
~ ' ~ '1 ~
~ ~ ~
0 20 00 60 80 100 T INES SECONDS FLORIDA PO'i" ER 8a LI GHT CG. l. AI ST. LUCI"- PLAHl UHIT 2 FRACTIONAL CORE FLOW TIr~E 'S.
FIGURE 15<5,5~3.-8
106Q UNAFFECTED LOOP 1025 AFFECTED LOOP 1
4 lg I
990 955 O~Q v4,J 885 85" I
I 0 100 200 300 4QC 5 4'0 TJ.NE. SECONDS
~%
FLORIDA PO'PER 8 LIGHT COMPAh'T.
LUG!":. 'PL/i".IT UHIT 2 STEAM GENERATOR PRESSURE.
VSi TIME FIGURE j.5. 3, 5, 1-9
BOG 750 UNAfFECTED LOOP AFFECTED LOOP C3 BGG
)rg 300 i r 0-1SG 0
0 I
200 r4QG iOG T I I'iE SECDt" DS FLORIDA POi'IER 8 LIGHT COI.'PALY ST LV-'"- PLA!Ii UNIT 2 MA EN STEAN SAFETY VALVE FLOW RATE VS TIME FICURE 15,3,5,1-10
80,000 70,000 Sb,000 I
\
~ ~
02,000 28,900 1LI,OOO 0
360 720 1080
'INEA'ECONDS FLORIDA PO"liR 8 LIGHT COMPAt'~
LU..,'.. L IT UxIIT 2 INTEGRATED. STEAM FLOW YSs TINE FIGURF 15.5 5,1-11
Section 15.4 Revisions
SL2-FSAR RCS volume shrinkage. RCS pressure is gradually reduced by the pressurizer spray valves. The operator may also actuate the pressurizer heaters during coo).down, to permit using a higher spray rate and obtain better pressure contro) and mixing of fluid in the pressurizer. During cooldown, the charging pumps initially take suction from the boric acid makeup tank BAMT until the RCS has been increased to the cola shutdown boron concentration, at. which time the charging pump suction is realigned to the refueling water tank. As the RCS pressure is reduced, the operator blocks the safety in-jection actuation signal to prevent, its inadvertent. actuation. The safety injection tanks are depressurized by draining or venting and then are iso)ated to permit. further depressurization of the RCS. After the reactor coolant pumps have been stopped, the operator uses the auxiliary spray to reduce pressurizer pressure.
Maintenance of AC Power:
Upon )oss of power to the unit. auxiliary transformers, their loads are transferred to the startup transformers by a fast-dead bus transfer.
15.4 .2.3.3 Ana).ysis of Effects and Consequences a) Mathematical Models The NSSS response t'o the PLCEh Subgroup Drop was simulated using the CESEC code described in Subsection 15.,0.4, The transient minimum DNBR values were calculated using the TORC code which uses the CE<<1 CHF corre)ation described in Subsection 15.0.4.
b). Input. Parameters and Inertia), Conditions range of initial conditions considered are given in Subsect:on 15.0.3. Table 15.4.2.3-4 gives the initial conditions used in this ana)ysis. Haximum core power, highest. core inlet coolant tempera-ture, lowest. core mass flow rate, and lowest. pressurizer pressure l~t'he are used since these values have the most adverse impact on DNBR.
The least. negative Doppler coefficient and the smallest scram CEA worth maximizes the heat f)ux increase after a reactor trip occurs, givin a )ower minimum DNBR. The moderator temperature coefficient i.s set at. t e ' 'a).ue that. is allowed by the Technica).
Specifications with part; length CEAs in the core. For this analysis, the thermal margin/low pressure and high local power density trips are assumed not to function.
Result. s The dynamic behavior of important NSSS parameters fol.lowing a part length CEA Subgroup drop is presented on Figures 15.4.2.3-2 t'o 8.
Table 15.4.2.3-1 summarizes some of the important. results of this event, and the times at. which the minimum and maximum parameter values discussed below occur.
15,4 3l Amendmend No. 4, (6/91)
SL2-FSAR TABLE 15.4.2.3&
INPUT PARAMETERS AND INITIAL CONDITIONS ASSUMED FOR PART LENGTH CEA SUBGROUP DROP ANALYSIS Parame t. er Assumed Value Power Level, 1&t 2630 Core Inlet. Coo]ant Temperat.ure, F 551 Core Flowrat.e, gpm 370,000 RCS Pressure, psia 2150 Pressurizer hat.er Volume, X level 52.7 Axial Shape Index -.30 St.earn Generat.or bat.er Leve), X of narrow range tap span 70 Doppler Coefficient. Mu]ti plier 0,85 Moderat.or Temperature Coefficient., 10 .4P/F -0.5 CEA Wort.h for Tri p, 10 4p 5~5 gor1X ~F Q,~'hw5~~ yO
( fd% z~scr //Aj~~ i<pa-p~)
15,4-37 Amendmene No. 4, (6/81)
SL2-FSAR 15e4e4.4 Limitin Loss of Shutdown Mar in Event None of the Limiting Fault-2 event groups or event group combinations re-sulting in reactivity and power distribtuion anomalies shown in Table 15e4 e4 1 result in a closer approach to loss of shutdown margin than that produced by the slow positive reactivity insertion described in Subsection 15e4.2e4. The additional plant conditions and failures considered here do not have an adverse effect on this event, with respect to time to loss of shutdown margin. Therefore, the conclusions of Subsection 15e4e244 also apply to this section.
15e4e5 LIMITIhG FAUL1 3 EVENTS 15e4 5.1 Limitin Offsite Dose Event-Control Element Assembl E'ection with a Failure to Achieve a Fast Transfer of a 4 '6 kV Bus and Hi h Steam Generator Tube Leaka e Rate
.15,4,5,1.1 Identification of Event and Causes All Limiting Fault 3 (LF-3) event groups in the Reactivity and Power Dis-tribution Anomalies event type and the LF-3 event combinations as shown in Table 15.4.5-1 were compared to find the event resulting in the maximum offsite doses, The CEA ejection with a failure to achieve fast transfer ol a 4,16 kV bus and a high steam generator tube leakage rate was
, identified as the limiting LF-3 event.
The event groups and event combinations evaluated and the significance of the approach to acceptance guideline for offsite dose are indicated in Table 1544 ' 1e The events indicated as insignificant (I) produce offsite doses well within the acceptance guideline in Table 1540-4e All events listed as significant (S) produce offsite doses within the acceptance 2
'uideline.
This event occurs due to the rupture of a CEDM nozzle or housing, subse-quent ejection of its CEA (from the core) and release of primary coolant into failure to achieve a fast transfer to a startup transformer can cause the containment' A
loss of either one 6e9 kV bus or one 4416 kV bus. The loss of the 4 '6 kV bus causes the loss of condenser vacuum while the loss of the 6.9 kV bus causesthe loss of two reactor coolant pumps and one feedwater pump.
Hithout the condenser, cooldown must be performed through the atmospheric dump valves (ADVs), hence the effect on the radiation release from the CEA ejection event is more adverse with the failure to achieve a transf r of the 4.16 kV bus.
~ SC t ~
cf jCQ.Eesfibsc4J+ lofd-'f sKi'fc f44 All: ldvents listed in labia 15.4.5-1, except. those involving a CEA ejection,
~
g ~
have an insignificant approach to the acceptance guideline for the offsite
~
g doses, Only the CEA ejection event releases primary coolant into contain-ment. The CEA ejection with a loss of offsite power as a result of turbine trip also causes a loss of conctenser vacuum as well as the loss of all four reactor coolant pumps. However, the failure to achieve a fast transfer of a 4.16 kU bus is more severe than the loss of offsite power as a result of turbine trip, since it maintains forced Reactor Coolant System (RCS) flow, 2 15.4-140 Amendment Ho. 2, (5/81)
SL2-FSAR TABLE 15.6.2.1-1 SEQUENCE OF EVENTS, CORPJ'SPOtlDING TDKS AND SUt22RY OF RESULTS FOR TtlE STEAM GENERATOR TUBE RUPTURE Success Pa ths 6 W 0
O VV O r4 M
e F 4J elf M c tJ 0 Sc Q $4 '0 0 V 4J Analysis g~
CO CO V 4J 0 Cl V g Ck 4J CJ c) Q Time Set Point ol c 4 C e O 0 C Sec Event or Valve AO lQ W l4 O W f4 ~
0.0 Tube rupture occurs 28 PPCS energizes propo nal heaters, psia 0 PLCS generates minimum letdown signal, inches below programmed le,vel
-PLCS generates maximum charging signal, inches below programmed level
-PPCS energizes 'backup heaters, psia 120 L,w pressurizer level alarm, inches below programmed level 15 800 Pressurizer heater de-energized, inches below programmed level 158 1272 Reactor tri.p signal generated on TM/LP, low pressurizer pressure floor, p ia 1875
-Maximum reactor power, % 102. 9 k
-Turbine tri'p on loss of power on CEDM power supply buses
-Fast transfer to start-up transformers 80 Hain stcam safety valves 'open"<,
psig 975 Maximum SG pressure, psia 10l6 1287 Pressuri.zcr empties
+ MSSVs cycle until operator actuates SBCS at 13'20 seconds
SL2- FSAR CHAPTER 15 TABLE OF CONTENTS (Cont'd)
Section Title 15C SUPPLEMENTARY INFORMATION 15C-i 15C .1 INADVERTENT LOADING OF A FUEL ASSEMBLY 15C-1 15C.2 ADDITIONAL INFOHl&TION FOR CEA MISOPERATION 15C 2a ANALYSES XN SUBSECTION 15.4.2.3 15D CEEEC 15D-1 15D. 1 INTRODUCTION 15D-1 15D. 2 PRIMARY COOLANT THERMAL - HYDRAULIC MODEL 15D-1 15D.3 PRESSURIZER 15D-2 15D.4 REACTOR KINETICS 15D-3 15D.5 HEAT TRANSFER WITHIN THE CORE 15D-3 15D.6 STEAM GENERATOR MODEL 15D-4 15D.7 CHARGING AND LETDOWN 15D-7 15D,8 REACTOR PROTECTIVE SYSTEM TRXPS 15D" 7 15D.9 SAFETY INJECTION SYSTEM 15D-8 15D.10 CRITICAL FLOW 15D-9 MODEL'TEAM 15D.11 LINE BREAK VERSION OF CESEC 15D-9 15D.11.1 RCS THERMAL-HYDRAULICS 15D" 9 15D.11.2 CLOSURE HEAD MODE 15D-10 15D.11.3 FLOW MODEL 15D-10 15D.11.4 PRIMARY-TO-SECONDARY HEAT TRANSFER 15D-13 15D,11.5 SAFETY INJECTION TANK 15D-14 THE 3-D REACTIVITY FEEDBACK MODEL 15D-14a 15D-15 15- iv Amendment No. 6. (9/81)
INSERT A Pa e 15-iv 15C.3 CEA EJECTION WITH LOSS OF OFFSITE POWER 15C.4 TOTAL'LOSS OF AC POWER (STATION BLACKOUT) 15C.5 STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF OFFSITE POWER AS A RESULT OF TURBINE TRIP
SL2<<FSAR 15C.2 ADDITIONAL INFORMATION FOR CEA HISOPERATION ANALYSES IN SUBSECTION 15 '-2 '
Analysis of the following three uncontrolled positive reactivity insertion events was performed:
- 1. Single part length CEA drop (SPLD)
- 2. Sequential rod withdrawal (high and low power)
- 3. Part length subgroup drop (PLSD)
The limiting fuel performance event was found to be the PLSD. The PLSD is presented in FSAR Subsection 15.4.2.3. The reasons that the other two events are less limiting are discussed below.
15C.2.1 Sin le Part Len th CEA Dro I
Significant differences exist in the method of thermal margin protection for the SPID as opposed to the PLSD. The PLSD will cause a reactor trip, whereas the SPLD wilL not. Sufficient margin exists during steady state operation
~
~
~ ~ ~
such that the SPLD will not significantly approach thermal margin limits. The Technical Specifications will stipulate the appropriate time period for operator zesponse to retrieve the rod or reduce core power to prevent a violation of the specified acceptable fuel design limit (i.e., ~ DHBR 1.19) ~
The PLSD produces more limiting fuel performance results for the following reasons:
a) Relative to the SPLD, the PLSD results in a greater hot channel 3D power distribution increase in the region where the minimum DNBR occurs.
b) The PLSD causes a greater increase in total core power due to a greater reactivity increase than the SPLD.
Tne two above effects result in the pazt length CEA subgroup drop experiencing a larger deczease in DHBR than the single part length CEA drop. Ihus:, the part length CEA drop has less adverse fuel performance than the part length CEA subgroup drop which is presented in Subsection 15.4.2.3.
15C.2.2 Se uential'Rod withdrawal (hi and low ower):
Similarly, analysis of the sequential rod withdrawal (high power and low power) shows that it is also not as limiting as the part length CEA subgroup drop. The sequential rod withdrawa.l has much less of a adial and axial power distribution distortion than a part length CEA subgroup drop. The sequential rod withdrawal actually flattens the planar radial power distzibution at the core heights in the areas where rods are being withdrawn. At other core heights, the radiaL power distribution will remain the same. At no position 15C a Amendment No. 6, (9/81)
SL2- FSAR y will the
~
planar radial power distribution become more peaked
~
~ The in the axiaL power distribution to a more top peaked shape occurs very
~
slowly due to the slow withdrawal rate, as compared to the part length CEA subgroup drop ~ The concurrent increase in core power also occurs very slowly. Thus, the degradation in DNBR margin occurs slowly. Les s thermal margin degradation occurs for a slower transient since the DNBR margin degradation between time of trip add time of minimum DNBR is less than that for a faster transient.
Therefore, the part length CEA subgroup drop produces more adverse fuel performance results relative to both the part length CEA drop and the sequential CEA withdrawal (high power and low power). Thus, the part length CEA subgroup drop was presented as. the infrequent category limiting fuel performance event in FSAR Subsection 15.4.2.3.
15C' Amendment No. 6, (9/81)
t 15C.3 The power:
(1)
CEA following CEA Ejection with CEA ejection Loss cases of Offsite Power.
were requested to ejection with control element housing rupture be analyzed without and subsequent offsite rapid blowdown into containment.
(2) CEA ejection where=the control element housing does not rupture and the primary system leaks to the secondary system through leaks in the steam
~
generator tubes.
The analysis of a CEA ejection with a rapid blowdown into containment is pre-sented in Section 15.4.5.1. This analysis also assumed a failure of the 4.16 KV bus to fast transfer following turbine trip. The main impact of this is the assumption that the condenser is unavailable for one hour.+The analysis of a CEA ejection where the housing does not ruptur e is discussed in this section.
This case was analyzed without offsite power to determine the steam released to the atmosphere.
Figures 15 C.3-1 and 15 C.3-2 are the pressure versus time curves for primary and secondary side pressures, respectively. Table 15C.3-1 presents information associa 'adiological release calculations.
U'l ln The Shield Ventilation System (SBVS) is assumed to be actuated two minutes following the event initiation. Design basis leak rate of 0.5X by volume.
phr day is assumed to reach the shield building annulus. The SBVS passes this material through'once-through system of charcoal absorbers. These filters are assumed to remove 95Ã of the el.cmental and organic iodine, and 99Ã of the particulate iodine.
Table 15C.3-1 CEA Ejection with Loss of Offsite Power Radiological Release Information
- 1. Steam Released to Atmosphere During Cooldown (ibm) 0 - 2 hours:
MSSVs 74400 AOVs 451000 Entire Event:
MSSYs 74400 ADVs 572000
- 2. Fuel Pin Failure (/) 9.5 (See Section 15.4.5.1)
- 3. Primary Iodine Concentration 8.3 x 103 Based on 9.55 Failed Fuel (pCi/gm).
- 4. Secondary Iodine Concentration Based on Tech. Spec. Limits (pCi/gm).
- 5. Decontamination Factor for 10 Steam Generator Iodine Transport
- 6. Two Exclusion Boundary 16.7 Thyroid Dose from Secondary Releases {Rem).
2700 2400 2100 NO LEAK 1800 1500 l
1200 I WITH LEAK 900 400 800 1200 1600 2000 TIME, SECONDS FLORIDA POWER 5 LIGHT COMPANY ST. LUCI E PLANT UNIT 2 RCS. PRESSURE vs. TIME FIGURE 15C.3-1
1100 h
1000 900 800 5 700 c 600 500
<00 500 200 100 2 0 6 8 10 12 1LI 16 18 h
h TrVIE ( x 102 SEC0NDS)
FLORIDA POWER 8 LIGHT COMPANY ST. LUCIE PLAHT UNIT 2 STEAM GENERATOR PRESSURES VS. TIME FIGURE l 5C. 3-2
APPENDIX 15C-4 q/ZO/Z(
STATION BIAOKOUT ANALYSIS PjnA +p>+)PgcL The station blackout event. is outside of the design basis for St.
Lucie Unit 2. Nonetheless, an analysis was performed as requested by the NRC in response to the decision of ALAB-603. This analysis shows that St.
Lucie Unit 2 can successfully endure a complete loss of AC power for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. However, it is expected that AC power would be restored either one of'the following within 30 minutes to one hour as a result of-corrective actions:
- 1. Offsite power is restored;
- 2. One or both of the St. Lucia Unit 2 diesel generators are started.
Operator action at 30 minutes is credited to open the atmospheric dump valves resulting in the closure of the main steam safety valves, Operator control of. the- atmospheric dump valves to assure natural circulation by maintaining subcooling in the RCS occurs after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The results of this analysis have shown that:
- 1. Natural circulation and core cooling can be maintained; r
- 2. The reactor core remains in a subcxitical condition;
- 3. There is no fuel failure;
- 4. The RCS coolant pressure remains within limits; and,
- 5. The resulting radiological doses are within limits.
Therefore, this analysis shows that St. Lucie Unit 2 can successfully endure station blackout event. Florida Power and Light will implement operator training and emergency procedures to ensure that plant operators would take appropriate actions to assure maintenance of natural circulation.
15C.4 Total Loss of AC Power (Station Blackout) 15C.4.1 Identification of Event and Causes The Station Blackout event results from a loss of offsite power followed by failure of both standby diesel generators to start.
For Unit 2, this event results in a loss of all onsite AC power except that supplied by inverters from the two safeguards batteries.
This provides power to the 120 VAC (safeguards) instrument power and other required DC loads.
15C.4.2 Sequence of Events and Systems Operation
.Table 15C.4-1 shows a chronological list of the timing of systems actions from the initiation of a station blackout event to the time that offsite power is restored. (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />). A description of the sequence of events" 'is given below for each safety function:
Reactivity Control:
As a result of the loss of power to the reactor coolant pumps an automatic reactor trip signal is generated by the RPS on low reactor coolant system flow, as measure ed by steam generator delta-pressure (hP). The reactor trip signal interrupts power to the reactor trip switchgear which in turn releases the CEA's to drop into the core. The negative reactivity inserted by the CEAs is sufficient to maintainthe core suhcritical th'roughout the rest of the transient.
Reactor Heat Removal:
Following coastdown of the reactor coolant pumps, flow through the reactor is maintained by natural circulation. Heat is trans-ferred to the secondary system through the steam generators.
Primary System Integrity:
A Power Operated Relief Valve (PORV) opens to limit the RCS pres-sure increase following turbine trip. Steam released from the PORV is contained in the quench tank. Letdown is isolated by the closing of the letdown control valve on loss of offsite power.
Late in the transient, the Safety Injectdon Tanks provide borated water to the RCS increasing RCS inventory and helping to maintain subcooling in the hot leg.
Secondary System Integrity:
A turbine trip signal {TTS) is generated following the loss of offsite power and causes the tur bine stop valves to close. The Main Steam Safety Valves (MSSVs) open to limit the pressur e in-crease.
- Those safety actions necessary to maintain the plant in hot shutdown.
Auxiliary feedwater is automatically actuated on low steam gen-erator level. Flow is provided by the turbine driven pump which derives< all its control power from the station batteries. The operator opens the Atmospheric Dump Valves (ADVs) and regulates them from the control room to maintain steam generator pressure below the setpoint of the MSSVs and to: reduce the primary system temperature to maintain subcooling in the hot leg.
Restoration of AC power:
Although the analysis which follows shows acceptable results as-suming no AC power for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, in actuality AC power would be restored to the plant prior to this time (within 30 mi nutes to one hour) by either one of the, following corrective actions.
- 1) Offsite power is restored and the onsite buses are manually connected to the startup transformers. Equipment is manually loaded on these buses,,according to pl,ant emergency proces dures, or,
- 2) One (or both) Unit 2 diesel generators is started and safe-guards loads are manually sequenced onto its 4.16 KY bus.
Analysis of Effects and Consequences A. Mathematical Models The NSSS response to a Station Blackout was simulated using the CESEC-III computer program.
B. Input Parameters and Initial Conditions The initial conditions assumed for this event are contained in Table 15C.4-2.'hese conditions were chosen to provide the largest and most rapid depletion of RCS inventory and shutdown margin. The highest initial pressurizer pressure, least negative Doppler co-efficient and most positive moderator temperature transientcoefficient maximize the power and RCS pressure early in the re-sulting in inventory loss thraugh the PORV. The majorlosses and contributors to the RCS depressurization are the pressurizer heat RCS lea.kage. Maximum values of these parameters were sel.ected based on technical specifications,,plant operating data and reactor coolant'ump test results. The lowest initial pressurizer water volume minimizes the available RCS inventory. Initial core inlet temperature, core mass flow rate and pressurizer pressure have a negligible impact on the primary system depressurization. The eval-uation of shutdown margin depletion was performed using the most negative moderator temperature coefficient and the least negative CEA'orth for trip. This minimizes the shutdown margin remaining at the end of the transient.
The disposition of normally operating. systems is given on Table 15C.4-3. The utilization of safety systems is given on Table 15C.4-4.
C. Results The dynamic behavior .of impor tant NSSS parameters 'following a Station Blackout is presented in Figures 15C.4-1 to 15C.4-12. '.
Table 15C.4-1 summarizes some of the important results of this event and the times at which the minimum and maximum parameter values discussed below occur . The loss of all AC electrical power initiates, among other things, a simultaneous loss of
'eedwater, loss of load, and loss of forced reactor coolant flow. As indicated in Figure 15C.4-1, the core power increases initially cQe to positive reactivity feedback and reaches a maximum value within a few seconds. Subsequent to loss of power to the reactor coolant pumps, the primary coolant flow decreases and a low flow reactor trip occurs as indicated in Table 15C.4-1.
Reactor coolant flow vs. time is shown on Figure 15C.4-7. Sub-sequently, due to the insertion of large negative reactivity by the scram rods, the core power decreases very rapidly and approaches the decay heat value. Departure from nucleate boiling does not occur and therefore no fuel damage is predicted. Se" Figura lSL'..4-8.
During the initial few seconds prior to reactor. trip, the reduced steam generator heat rejection capability leads to a rapid in-crease in both the primary and secondary fluid temperatures. The volumetric expansion~ due to these increases in temperature'roduces sharp increases in primary and secondary pressures as well as an insurge of primary coolant into the pressurizer. The variations of the primary and secondary pressures are illustrated in Figures 15C.4- 3, and 15C.4.9. The initial rapid increases in both pres-sures, are terminated by the opening of the PORV and MSSVs. The primary relief valve closes rapidly, as the primary system pres-sure decreases below the setpoint value within a few seconds after opening of the valve. The secondary safety valves cycle open and closed until the operator opens the atmospheric dump valves.
MSSY and ADV fTow vs. time are shown on Figures 15C.4-11 and 15C.4-12, respectively.
The, steam generator liquid level decreases during the transient and reaches a minimum value after auxiliary feedwhter flow is automatically actuated using the steam-driven auxiliary feedwater pump. Steam generator level increases until normal water level is reached . The operator subsequently controls auxiliary feedwater to maintain normal level. See Figure 15C.4-6.
The RCS pressure and temperature gradually decrease at fairly constant rates in the long term as a result of pressurizer heat loss, RCS leakage,low heat transfer rates at the steam generators, and the operator manually reducing secondary side pressure. Since the RCS pressure decreases at a higher rate than the RCS temperature, the pressure approaches the saturation pressure.
Saturation occurs in the reactor vessel head. Continued primary pressure drop without a significant decrease in primary tem-peratures would result in conditions in the hot leg.
'redit is taken for operatorsaturated action to maintain at least 10'F
'subcooling in the hot leg. This is accomplished by further opening the atmospheric dump valves to reduce the secondary system pressure and temperature. The increased heat removal in the steam generators caused by the larger BT across the steam generator tubes reduces the primary system temperatures. Yoiding is restricted to the vessel head and natural circulation is not adversely impacted for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
'he Safety Injection Tanks (SITs) provide borated water to the RCS after RCS pressure is reduced below their discharge pressure. No credit is taken for the negative reactivity added as a result of this discharge.
At 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, sufficient AC power is assumed to bestored"'to '.-
pfovide power to the charging pumps and pressurizer heaters.
These will be used to pressurize the RCS and to continue hot leg subcooling.
Operability of the turbine driven auxiliary feedwater pump requires at least 50 psia secondary pressure. At 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the initi-ation of the event, the secondary pressure will be greater than 300 psia. Less than 100,000 gallons of auxiliary feedwater are used during the event. The condensate storage tank capacity is greater than 300,000 gallons.
Conclusions
.The maximum RCS pressure is 2591 psia ( including reactor coolant pump andelevation heads). This is well below 110% of design pressure.
Natural circulation is maintained for at least the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period that offsite AC power and diesel generator power are assumed unavail-able. During this time voids are restricted to the reactor vessel head and subcooling is maintained in the hot leg.
The radiological release due to a Station Blackout results in no more than a 0.4 rem 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> inhalation thyroid dose at the exclusion area boundary.
The average RCS temperature at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is above 430 F. This is above the temperature at which the shutdown margin would be depleted.
Therefore, the core remains subcritical following reactor trip for the duration of the event.
No fuel damage occurs during this event.
Table 15C.4-1 SEQUENCE OF EVENTS, CORRESPONDING TIMES AND
SUMMARY
OF RESULTS FOR THE STATION BLACKOUT EVENT Setpoint or Time Sec Event Value 0.0 Loss of all on - and off-site AC power 1.5 LoQ Primary Coolant Fl ow Reactor Tri p, 5 93 2.0 Auxil iary Fee)water Actuation Signal, Ã of Narrow Range Tap Span 2.4 Power Operated Relief Valve Opens, ps'ig 2385 2.6 Maximum. Core Power, A 104.8 5.5 r Maximum RCS pressure, psia 2541 6.0 Ma~ximum pressuri zer pressure, psia 2460 6.3 Main Steam Safety Valves Open, psig 995
'8.'5 Power Operated Relief Valve'Closes, psig 2361
- 2. Total Primary Relief Valve Release, ibm 554 1'2".2 Maximum Secondary System Pressure, psia 1038 182.,0 Auxiliary Feedmater reaches Steam Generators, gpm 500 1800;0 Operator Opens and Controls Atmospheric Dump Valves, psia 900
- 2. Main Steam Safety Valves close, psig 945
- 3. Total Main Steam Safety Valve Release, ibm 116630
Tabl e 15C.4-1 (continued)
Setpoint- or Time Sec Event Value 2258.0 Voiding Occurs in Reactor Vessel Head 8600.0 Operator Begins to Reduce Steam Generator Pressure ...
to Maintain Hot Leg Subcooling 117,85.'0 Main Steam Isolation Valves close, psig 435. 0
. 12540.0 Safety Injection Tanks actuated, psia 583. 0 14400.0 l. Operator Restores AC Power
. 2. Total Atmospheric Dump Valve Release, ibm 363300.0
TABLE 15C.4-2 P
ASSUMED INITIAL CONDITIONS FOR STATION BLACKOUT ANALYSIS PARAMETER ASSUMED VALUE Initial Core Power Level, MWt 2630 Core Inlet Coolant Temperature, 'F 551 Core Mass Flow Rate, 106 ibm/hr 133.9 Pressurizer Pressure, psia 2350 Initial Pressurizer Water Volume, X Level 40 Steam Generator Water Level, X of Narrow Range Tap Span 70 Doppler Coefficient Mul tipl ier 0.85 Moderator Temperature Coefficient, 10 4 hp/'F To determine initial power transient, 0- 10 seconds To determine degree of shutdown margin depletion 2~7 CEA Worth for Trip, 10 2 b,p 6.68 Pressurizer Heat Loss, 106 BTU/hr 0. 546 Primary Coolant Leakage, gpm: 16 Identified Leakage, gpm a) Technical Specification Steam Generator Tube Leakage b) Primary Safety Valve Leakage c) Other Identified Leakage Unidentified Leakage RCP Controlled Bleedoff RCP Seal Leakage 16
\
SL2-FSAR DISPOSITION OF NOfNALLY OPEPATING SYSTEMS v~
O~
g+g 0c% P 0<+0+0 +c+p
>o ~
P~ ~~ d~ O~
~< ~~~ o C SYSTBl .
~ ~
- 1. Hain Feedwater System X
- 2. Turbine-Generator Control S stem
- 3. Steam Sypass Control S stem
- 4. Pressurizer Pressure Control System
- 5. Pressurizer Level Control System X
- 6. Control Element Orive Mechanism Control System
- 7. Reactor Regulating System
- 8. Reactor Coolant Pumps Chemical and Volume Control S stem-Condenser Evacuation System
- 12. 'omponent Cooling Hater System
- 13. Turbine Cooling Mater System
- 14. Int'ake Cooling Mater S stem
- 15. Condensate Transfer System
- 16. Circulating Ha ter System
- 17. Spent Fuel Pool Cooling System
- 18. AC Power (Non-Safety)
- 19. AC Power (Safety)
- 20. 0. C. Power
- 21. Power Operated Relief Valves X 22.. Instrument Air S stem
- 23. Haste Hanaaement-Li uid QQTEE: l. RCP bleedoff is not isolated during this event.
- 2. Portions of these systems, powered by the saf ety bus o'n loss of AC, are not available due to the failure of both diesel generators.
- 3. Only the AC power supplied through the inverters is available.
TABLE 15C.4-4 SL2 "FSAR UTXLXZATlON OF SAFETY SYSTEMS FOR STATIOf'I BLACKOUT A
- 1. Reactor Protection S stem En ineered Safe Features Actuation S stems
- 3. Diesel Generators and Su ort S stems X 1
- 4. Reactor Trio Switch Gear
- 5. Main Steam Safe Valves
- 6. Pressurizer Safe Valves
- 7. Hain Steam Isolation Valves
- 8. Main Feedwater Esolation Valves
- 9. Auxi,lia Feedwater S stem 2,4
- 10. Safet ln'ection S stem
- 11. Shutdown Coolin S stem CCP & 1CM
- 12. Atmos heric Dum Valve S stem
- 13. Containment Isolation S stem
- 14. Containment Sora S stem
- 15. Xodine Removal S stem
- 16. Containment Combustible Gas Control S stem
- 17. Containment Coolin S stem Notes: 1. Both diesel generators fail, for this event.
- 2. Only those portions powered f'rom the safeguard batteries are available.
- 3. Safety Injection Tanks are available.
- 4. Auxiliary Feedwater is automatically actuated ~ Only the turbine driven pump is available.
- 5. ADVs can be manually operated from the control room.
- 6. Portions of this system are actuated on loss of instrument air.
Systems not checked are not utilized during this event.
120 90 CD CD I
5 60 50 2 6 8 10 12 14 Trrz, X 10> SECONDS FLORIDA PO'<ER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT $
CORE POWER VS TIME FIGURE lGC.4-1
120 OC
~~ 90 I
XW w Z
~
Ll W
I)
'I
~
LIJ CY W 60 QW W 0 CD w -50 2 4 6 8 10 12 14 TItlE, X 10~ SECONDS FLORIDA PG'i<ER 8 LIGHT CGh(PANY ST. LUCIE PLANT OHIT 2 I
CORE AVERAGE HEAT FLUX VS T'IME FIGURE i5C.4-2
2400 1800 1200 600 2 4 6 8 10 12 14 TINE, X 10~ SECONDS FLORIDA POP/ER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT 2 REACTOR COOLANT SYSTEM PRESSURE VS TIME FIGURE l GC.4-3
610 590 570 HOT 550
~ 5>O COLD 510 S 490 f70
/'g, 450 QO 6 8 10 12 10 TINE, X 10~ SECONDS FLORIDA POPOVER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT 2 CORE'COOLANT TEHPS" VS TIHE'IGURE 1GC.4-4
DOPPLER ZERO LINE CEA 8 10 12 14 TIME, X 10> SECOi'WADS FLORIDA PONER 8 LIGHT COMPANY ST. LuCIE PI ANT UNIT 2 REACTIYITIES VS. TII1E FIGURE 15C.4-o
1:20 o0 UJ CD 600 UJ I
Ct.
UJ Wl 50 CL.
2 0 6 8 10 12 10 TINE, X 10 SECONDS FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLAHT UNIT 2 PRESSURIZER <V TER VeLuI4E VS. TIVE FIGURE 15C.4-6
1.2 CD I
5 CD I
2 4 6 3 10 12 TINE, X 10> SECONDS FLORIDA POWER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT 2 REACTOR COOLANT FLOW VS. TINE FIGURE 'ISC.4-7
320 3.00 2.80 Pg 2.60 R
Cl 2.40 R
220 2.00 xV O 1.80 x
1.60 1AO 120 0 1 2 3 4 6 6 7 8 9 10 TIME, SECONDS FLORIDA POY(ER 8 LIGHT COh(PANY ST. LUCIE PLA'IT UNIT 2 HOT CHANNEL MINIMUM DI"BR VS. TlhiE FI GURE 15C.4'-8
1200 1000 800 600 Q
'00 200 6 8 10 12 14 TINE, X 10> SECONDS FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 STEAM GENERATOR PRESSURE YS. TIME FIGURE 15C.4-9
20000
~ 160000 C/>
.120000 I
~80000
'40000 2 4 6 8 10 12 14 TIME x 10~ SECOI'LDS FLORIDA PO'h'ER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT 2 STEAM GENERATOR llATER MASS, VS. 1IM FIGURE 15C.4-10
1200
~ 900 600
~ 500 2 4 6 8 10 12 14 16 18 TINE, X 102 SECONDS FLORIDA POWER 8'LIGHT COMPANY ST. LUCIE PLANT UNIT 2 NSSV FLO'A VS. TIi~1E FIGURE 15C.4-11
90 CD I
60 CD 30 8 10 12 10 TINE, X 103 SECONDS FLORIOA POWER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT 2 ADV FLOW VS. TIME.
FIGURE l 5C.4-12
15,C, Steam Generator Tube Ru ture With a Loss of Offsite Power As A Result
~fi bi T 15,.C.6.1 Identification of Event and Causes The significance of a steam generator tube rupture accident is described in Section 15.6.2. A double-ended break of a steam generator tube rupture with a loss of offsite power as a result of turbine trip event was determined to be the most limiting case with respect to radiological releases. As a result of the loss of normal.AC power, electrical power would be unavailable for the station auxiliaries such as the reactor coolant pumps and the main feedwater pumps. Under such circumstances the plant would experience a loss of load, normal feedwater flow, forced reactor coolant flow, condenser vacuum, and ,
steam generator blowdown system. The plant is operating at full power for a period of approximately 14.3 minutes, before the consequences of the primary-to-secondary leak causes the reactor trip. Thus, during this time period, the radioactivity concentration in the steam generator is allowed to increase .,
before the main steam safety valves open, releasing radioactive materials to the atmosphere.
15.C.6.2 Sequence of Events and Systems Operation Table 15.C.6-1 presents a chronological list of events which occur during the steam generator tubr rupture event with a loss of offsite power, from the time of the full double-ended rupture of a steam generator U-tube to the attainment of cold shutdown conditions. The corresponding success paths are also pro-vided.
Prior to reactor, trfp, the systems and reactor trip operation are identical to that described in Section 15.6.2. Subsequent to reactor trip, stored and fission products decay energy must be dissipated by the reactor coolant and main steam system. In the absence of forced reactor coolant flow, convective heat transfe'n into and out of the reactor core is supported by natural cir-culation reactor coolant flow, Initially, the residual water inventory in the steam generators is used and the resultant steam is release to atmosphere via the main steam safety valves. With the availability of standby power, auxiliary feedwater is automatically initiated o'n a low steam generator water level signal. The operator can determine which steam generator has the tube rupture based on information from the radiation moritors prior to trip and the difference in the post-trip steam generator water levels. The operator can isolate the damaged steam generator and cool the NSSS using manual operation of the auxiliary feedwater system and the atmospheric dump valves of the un-
- affected steam generator any time after reactor trip occurs. The analysis presented herein conser vatively assumes operator action is delayed until 30 mi nutes after initiation of the event.
15.C.6.3 Analysis of. Effects and Consequences 15.C.6.3.1 Hathematical Model The thermalhydraulic response of the Nucl.ear Steam Supply System {NSSS) to the steam generator tube rupture with a loss of offsite power as a re'suit of turbine trip was simulated using the CESEC III computer program described in Reference 16 to Section 15.0. The thermal margin in the reactor core was determined using the, TORC computer program described in Section 15.0.4 with the CE-1 CHF correlation.
- 15. C.6.3.2' Input Parameters and Initial Conditions The input parameters and initial conditions used in the analysis are similar to those described in Section 15.6.2 and are listed in Table 15 C.6-2. In addition, the assumptions and conditions employed in the radiological release calculations are listed in Table 15.0.6-3.
Resul,ts The dynamic behavior of important NSSS parameters foliolring a steam generator tube rupture with concurrent loss of offiste power are presented in Figures 15,C.6-1 through 15 C.6-16.
Prior to reactor trip, the dynamic behavior of the NSSS following a steam qen-erator tube rupture with loss oV offsite power 'is similar to that following a steam generator tube rupture without loss of offsite power which is described in Section 15.6.2. At about 863 seconds, after the initiation of the tube rupture, the reactor trips due to reaching the TM/LP low. pressurizer pressure floor of 1875 psia. The reactor trip initiates a turbine/generator trip. The loss of offsite power is assumed to occur con-current with this" trip at about 863 seconds. Subsequent to the reactor trip, the RCS pressure begins to decrease rapidly, and the pressurizer empties at about 883 seconds due to the continued primary-to-secondary .leak. 'fter the pressurizer empties, the reactor vessel upper head begins to behave. like a .
pressurizer and controls the RCS pressure response. Oue to the loss of offsite power, the reactor coolant pumps begin to coast down reducing the core coolant flow rate, and th'e mass flow into the upper head region. This region becomes thermalhydraulically decoupled from the rest of the RCS, and due to flashing caused'by the depressurization and boiloff from the metal structure to coolant lieat transfer, voids form in this region at about 889 seconds. The void formation is enhanced by the decoupling effect, since the RCS pressure re-duction due to primary system cooling is felt in this region, while the RCS temperature reduction is not. The significant impact of Voids in the upper head region, is a slower RCS pressure decay. A safety injection actuation signal {SIAS) is generated at 888 seconds on low pressurizer pressure, .The.
High Pressure Safety Injection {HPSI) pumps begig delivery of safety injection fluid to the RCS at about 1509 seconds and as a result, the upper head voids begin to collapse at about 1717 seconds.
Fol lowing turbine trip and loss of offsite power, the main steam system pres-sur'e increases until the main steam safety valves open at about 870 seconds to control the main steam system pressure. A maximum main steam system pres-sure of 1006 psia occurs at about 875 seconds. Subsequent to this peak in .
pressure, the main steam system pressure decreases,.and the safety valves
continue to open and close to control the SG pressures. P}ior to turbine trip, the feedwater control system is in the automatic mode, and supplies feedwater to the steam generators to match the steam flow through the turbine. Following turbine trip and loss of offsite power, the feedwater flow ramps down to zero.
Consequently, .the steam generator water levels decrease due to the steam flow out through the main steam safety valves, and a low steam generator level signal is generated at about 864 seconds. Subsequently, at about 1044 seconds emergency feedwater flow is initiated, and the steam generator water levels begin to recover.
After 1800 seconds, the operator identifies and isolates the affected steam generator by closing the main steam isolation valves. The operator then initiates an orderly cooldown by means of the atmospheric dump valves and emergency feedwater flow to the unaffected steam generator . After the pres-sure and temperature are reduced to 275 psia .and 350'F, respectively, the operator activates the shutdown cooling system and isolates the 'unaffected steam generator.
The reduction in primary coolant flow rate subsequent to the loss of offsite power does not result in a reduction in thermal margin to DNB. The transient
~
minimum DNBR of 1.39 occurs immediately after the. loss of offsite power. This
~
~
results in no fuel pins experiencing DNB based on the methodology described
~
in the response to guestion 440.11.
~
~ ~
The maximum RCS and secondary pressures do not exceed ll05 of design pres-sure following a steam generator tube rupture event with a concurrent loss of offsite power, thus, assuring the integrity of the RCS and the main steam system.
At 1800 seconds, when operator action is assumed, no more than 46,420 ibm of steam from the damaged steam generator and 40,860 ibm from the intact steam
'generator are discharged via the main steam safety valves. Also, during the same time period approximately 69,0201bms of primary system <sass is leaked to the damaged steam generator. Subsequent]y, the operator begins a plant, cooldown at the technical specification cooldown rate (75 'F/hr ) using the intact steam generator, the atmospheric dump valves, and the emergency feedwater system. For the first two hours following the initiation of the event, a total of 2.74 x 106 lbms of steam flow to the condenser through the turbine (up to the time of loss of offsite power), and about 448,490 lbms of steam are released to the environment through the atmospheric dump valves.
For the two to eight hour cooldown period an adgitional 882,180 lbms of steam are released via the atmospheric dump valves.
The two hour exclusion area boundary (EAB) and the eight hour low pop-ulation zone (LPZ) boundary inhalation doses for the case of generated
- iodine spike (GIS) and the case of pre-existing iodine spike (PIS) are presented in Table 15.C.6-4. The calculated EAB and LPZ doses are well within the acceptance criteria.
15, C.6.4 Conclusions The radiological releases calculated for the steam generator tube rupture event with a loss of offsite power are well within the guidelines of
'10CFR100. The RCS and secondary system pressures are well below the 110%
of the design pres ure limits, thus, assuring the integrity of these systems.
Hone of the fuel pins experience DNB during the transient, since the minimum
Table 15.C.6-3 List of Assum tions and Conditions for Radiolo ical Release Calculations for the Steam Generator Tube Ru ture with a Loss of Offsite Power-
- 1. Accident doses are calculated for two different assumptions:
(a') assumes an event generated iodine spike (GIS) coincident with the initiation of the event and (b) assumes a pre-existing iodine spike (PIS) or fuel failure with the most reactive ., control rod fully withdrawn.
- 2. Technical specification limits are employed in the do'se calculations for the primary system (4.6 pCi/gm) and secondary system (0.1 pCi/gm) activity concentrations.
- 3. Following the accident, no additional steam and radioactivity are released to the environment when the shutdown cooling system is placed in operation.
4, Thirty minutes after the accident, the affected steam generator is isolated by the operator. No steam and fission products activities are released from the affected steam generator thereafter.
- 5. A spiking factor of 500 is employed for the event-generated iodine spiking (GIS) calculations.
- 6. For the pre"existing iodine spiking (PIS) condition, the technical specification limit (60 pCi/gm) for the primary system activity concentration is employed.
- 7. Technical specification limit (1 gpm) for the tube leakage in the
. unaffected steah generator is assumed for the duration of the transient.
- 8. Steam jet air ejector release is assumed throughout the transient with a decontamination factor (DF) of 100.
A fraction of the iodine in the primary-to-secondary leak is assumed to be immediately airborne, if a path is available, with a partition coefficient of (Maximum fraction -= 5%).
1
- 10. A partition coefficient of 100 is assumed between the steam generator water and steam phases.
The total amount of primary-to-secondary leakage through the rupture is 69,020 ibm.
- 12. For steam release through the atmospheric dump valves, a de-contamination factor (DF) of 1 is assumed.
- 13. The atmospheric dump dj'spersion factors employed in the analyses are: 1.6 x 10 4 sec/m~ for the exclusion area boundary and 6.7 x 10-5 sec/m3 for the low population zone.
- 14. The steam flow through the condenser is 2.74 x 10 lbms. The half hour to two hour steam flow through the atmospheric dump valves (ADVs) is 448.490 lbms. An additional 882.180 lbms of steam is discharged to the environment through the ADVs during the two-eight hour time period.
Tabl e 1S.C.6-4
-Radiolo ical Conse uences of a Steam Generator Tube Ru ture Event With a Loss of Offsite Power Offsite Doses, Rems Location GIS PIS
- l. Exclusion Area Boundary 0-2 hour thyroid. 0.38 0.68
- 2. Low Population Zone Outer Boundary 0-8 hour thyroid. 1.96 0.49
DNBR calculated is 1.39. Therefore, no fuel failure occurs.
Voids form in the reactor vessel upper head region during the transient due to thermalhydraulic decoupling of this region from the rest of the RCS.
However, the upper head region liquid. level remains well above the top of the hot legs throughout the transient. Therefore, natural circulation cooldown is not impaired. Furthermore, the upper head voids begin to collapse upon actuation of the safety injection flow, indicative of stable plant conditions.
After thirty minutes the operator employs the plant Emergency Procedure for the steam generator tube rupture event to cooldown the plant to shutdown cooling entry conditions.
SL2-FSAR TABLE 15. C.6-1 SEqUE tCE OF EVENTS COrZZSPOmlNG TX>ZS AND SVr.">RY OF
',RESULTS FOR THE STEAM CEHEPATOR TUBE RUPTURE t'IITH LOSS OF OFFSITE POttER AFTER TURBINE TRIP Success Paths 0
6 4J 44 Ol 0 4J Cl 0 4J CA V ~
~O
+
4J 0$ c 0 v 0 0 40 'k k CJ c> 0 Analysis 4J 4J CO CO 0 00 0 V 4J V 0 0 CN g @$ 4 4J Cl Set Point C) g e 6 V 4J 4J g 4J Time Sec Event or Value 0o C4 C4 Cfl 4 g H 0 OH tel 0.0 Tube rupture occurs
~ o PLCS generates minimum letdown signal, inches below programmed .
level
- 40. 5 -PLCS generates maximum charging signal, inches below programmed level 14 X
-56. 7 -PPCS energizes backup heaters, psia 2310 Low pressurizer level alarm, inches below programmed level 15 574 Pressurizer heatex de-energized, inches below pxogrammed level 158 X 863 Reactor trip signal generated on TM/LP, low pressurizer pxessure floor, psia 1875
-Maximum reactor power, % loz,.7
-Turbine trip on loss of power on CEDH power supply buses
-loss of offsite power.
864 ;EFAS on lo<v SG level signal,
'~bove tube sheet.
ft.:
29.8 870 Hain steam safety valves open+,
psig 975 Maximum SG pressure, psia l006 883 Pressurizer empties
+ MSSVs cycle until operator actuates s at 1800 seconds.
Table 15.C.6-2 Assum tions and Initial Conditions for the Steam Generator Tube Ru ture With a Loss of Offsite Power Parameter'alue Power, NHt 2630 Core Inlet Temperature, F 548 Core Average Flowrate, gpm 370,000 Pressurizer Water Level, 5 Level Steam Generator Pressure, psia 794 Steam Flow Rate, ibm/sec 3174 Steam Generator U-tube Break Size, in 0.336 CEA Worth for Trip, Xhp(most reactive CEA -5.5 fully withdrawn)
RCS pressure, psia 2350
II' 100 I
80 l~
BG 0 300 600 '00 '200 '00 TINE, SECONC5 P~euRE 15.C,6-1 STEAN GENERATOR TUBE RUPTURE 81TH LOSS OF QFt=StTE POl'lER CORE POldER QS TIQE
120 100 X 80 60 0 300 600 900 '200 '~00 TINE SECONDS FIGURE 15 C,6-2 STEQQ GENERATOR TUBE RUf'TURE 4'ITH L0$ $ OF OFFSITE PO'I'E'ER
. CORE HEAT FLUX JSs TIQE
1900 1600 13GG 700 0 300 600 900 200 'GG T I NF SECONDS f IGURE lS,C,6-3 STEAN GENERATOR TUBE RUPTURE WITH LOSS OF OFFSITE f'9'l~'ER REACTOR COOLANT S'(STEf') PRESSUPE yS, TII,E
620
~ 580 OUTLET i60 AVERAGE INLET
,540 0 300 600 900 200 .'. 500 T I NE, SECONt'5 FIGURE 15.C.6-0 STEAM GENERATOR TUBE RUPTURE KITH LOSS OF OFFSITE 'POWER REACTOR COOLANT SYSTEM TEMPERATURES YS< TIME
r
'DOPPLER 0
BORON Q
-2
~TOTAL CEA
-8
-10 0 300 600 900 l200 '. GGO T I HE SECONI 5 l
FICURE 15.C,6-5 STEAM GENERATOR TUBE RUPTURE WITH LOSS OF OFFSITE POWER REACTIVITIES VS> TIME
1200 1000 200 0
0 300 600 900 '.200 TINE, St"CONGS FIGURE 15,5.6-6 STEAN CENERATOR TUBE R*UPTURE I",.ITH.LOSS OF OFI=SI.TE POi'lER P/ESSURI.ZER HATER bt'OLUHE JS TIt,E
500 x 480 460 440 D
420 300 6no 900 1200 1500 1800 TIMEp SECONDS j
FIGURE 15; C e 6-7 STEAM GENERATOR TUBE RUPTURE WITH LOSS OF OFFS ITE POWER REACTOR COOLANT SYSTEM MASS VS> TIME
90GOO 75000 60000 30000 15000 0 300 60C 900 1200 '500 TINt. SECCNt"S FIGURE 15.C,6-8 STEAN GENERATOR 'I'UBE RUPTURE WITH LOSS 0~ OF. SITE PONER INTEGRATED RCS LEAKAGE TO SECONDARY SYSTEM
200 180 160 AFFECTED 2 j40
~ 120 UNAFFECTED 10 80 0 300 600 900 1200 1500 1800 TINEg SECONDS FIGURE 15.C 6-9 STEAN GENERATOR TUBE RUPTURE WI,TH LOSS OF OFFSITE POWER STEAN GENERATOR WATER MASS VSi TINE
!500 1350 1200 (i3 (Q
'05G e
900 75G 600 0 300 600 9QO '1200 1500 TINE, SECONt:5 FIGURE 15,C,6-10 STEAQ GENERATOR TUBE PUPTURE ldITH LOJS QF OFFSITE. POKIER STEAN GENERATOR PRESSURE PS $ T IQE
I 0 0 300 600 900 1200 !spp T I-NE SECONDS FIGUP.E 15 C.6-1j..
STEAN GENERATOR TUBE RUPTURE YtI TH LOSS OF OFFS I TE PONER INTEGRATED STEAN FLO'H PER STEAN GENERATOR YS, T I YE
120 100 X
80 60 I~0 Pr 20 0
0 300 600 900 1200 150Q 1800 TIMEg'ECONDS FicUP,E 15. C,6-12 STEAM GENERATOR TUBE RUPTURE 0i'1TH LOSS OF OFFS I TE POKER TOTAL MSSY STEAM RELEASE YS I TIME
1800
~ 1500
~ 1200 QA 900 6GG F) 300 0
0 300 600 900 1200 1500 T I HE SECONI 5 I INURE 15, C,6-U STEAQ GENERATOR TUBE RUPTURE WITH LOSS OF OFFSI,TE POWER FFEDWATER FLOW QS I TIP)E
500 300 200 100 0
300 son 900 1200 1500 1800 TINEA'ECONDS FICURE 15 C,6-1'TEAN GENERATOR TUBE RUPTURE WITH LOSS QI= OFFSITE POWER FEEDWATER ENTHALPY VS e TINE
1500
~TOP OF REACTOR VESSEL 1250 1000 750 500 250 0
~ TOP OF HOT LEG 0 300 600 900 1200 1500 18K TIMEp SECONDS FIGURE 15 C,6-15 STEAM GENERATOR TUBE RUPTURE WITH LOSS OF OFFS ITE POWER AFTER TURBINE TRIP LIQUID VOLUME ABOVE TOP OF HOT LEG VS. TIME
2,4 ASI = -0,2901 2,2 2,0 1,6 MINIYUH DNBR = 1.398 1.2 0 600 900 1200 1500
<. 4I T Ib)Eg S ECONDS FIGURE 15, C.6-16 STEAN GENERATO'R TUBE RUPTURE l<ITH L0$ $ OF qFFSITF POiqER MINIMUM DNBR YS. TIMf
t