ML17223B383
| ML17223B383 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 12/17/1991 |
| From: | FLORIDA POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML17223B381 | List: |
| References | |
| NUDOCS 9112270254 | |
| Download: ML17223B383 (78) | |
Text
1 REACTIVITY CONTROL SYSTEMS h
MODERATOR TEHPERATURE COEFFICIENT LIMITING CONDITION FOR OPERATION 3.1.1.4 The moderator temperature coefficient (HTC) shall be:
a.
Less positive than
+5 pcm/'F at < 70%
RATED THERMAL
- POWER, b.
Less positive than +3 pcm/'F at ~ 705 RATED THERMAL
- POWER, and c.
Less negative than -
'cm/'F at RATED THERMAL POWER.
-30 APPLICABILITY:
HODES 1
and 2"0 go Oh.C8.
ACTION:
With the moderato~
temperature coefficient outside any one of the above limits, be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
SURVEILLANCF. RE UIREHENTS
- 4. l. 1.4.
1 The HTC shall be determined to be within its l.imits by confirmatory measurements.
MTC measured values shall be extrapolated and/or compensated to permit direct comparison with the above limits.
h 4.1.1.4.2 The HTC shall be determined at the following frequencies and THERMAL POWER conditions during each fuel cycle:
a ~
b.
C.
Prior to initial operation above 5X of RATED THERMAL POWER, after each fuel loading.
h At any THERMAL POWER, within 7 EFPD after reaching a
RATED THERMAL POWER equilibrium boron concentration of 800 ppm.
At any THERMAL POWER, within 7 EFPD after reaching a
RATED THERMAL POWER equilibrium boron concentration of 300 ppm.
ith K ff greater than or equal to 1.0.
SSee Special Test Exceptions
- 3. 10. 2 and 3. 10. 5.
ST.
LUCIE - UNIT 2 9ii2270254 9ii2iT PDR ADOCK 05000 89 P
PDR 3/4 1"5 Amendment No. k4.
\\
lag
~.
C
~
0
~
~
~
y
~
~
k ~
I
ATTACHMENT 2 SAFETY ANALYSIS Introduction Back round This is a request to revise Section 3.1.1.4, Moderator Temperature Coefficient Limiting Condition for Operation, of the Technical Specifications for St. Lucie Unit 2.
During the recent reload cycles, the design values for the End of Cycle (EOC) Moderator Temperature Coefficient (MTC) of St. Lucie Unit 2 have been within about 2 pcm/'F of the current Technical Specification MTC limit of -27 pcm/'F.
It is expected that the design values of MTC for Cycle 7 will again be close to the Technical Specification limit at EOC.
- Further,
.comparisons of measured values from the various MTC tests to calculated values indicate that the actual EOC MTC is very close to the design values.
To avoid the possibility of having the measured MTC more negative than this Technical Specification limit, and to provide increased plant availability and improved fuel utilization, FPL authorized ABB-CE to perform the analyses necessary to justify a change in the St. Lucie Unit 2 minimum MTC Technical Specification limit from its present value of -27 pcm/'F to a value of -30 pcm/'F.
This change will increase operating margin in future cycles.
These analyses utilized the standard ABB-CE licensed safety analysis methodology.
Descri tion of Technical S ecification Chan e
The proposed license amendment will revise Technical Specification 3.1.1.4 Item c to reflect a reduction in the minimum MTC limit from the current value of -27 pcm/'F to a value of -30 pcm/'F.
Technical Discussion Impact on Final Safety Analysis Report (FSAR) Chapter 15 Accident Analysis Events A more negative Moderator Temperature Coefficient (MTC) primarily impacts the cooldown transi'ents (Increase in Heat Removal by the Secondary),
Control Element Assembly
- Drop, and Asymmetric Steam Generator events.
The Reactor Coolant System (RCS)
Depressurization event also uses the most negative MTC limit, but a
more negative MTC has negligible consequences for this event since there is virtually no core temperature reduction during this event.
For all other Design Basis Events (DBE),
a more positive MTC leads to more adverse consequences.
The Design Basis Events which assume the most negative MTC limit are discussed below.
Increase in Heat Removal b
the Secondar During the increase in heat removal (cooldown) by secondary side
- events, a reduction in core temperature with a negative MTC inserts positive reactivity and increases the core power.
The power increase results in an approach to the Departure from Nucleate Boiling Ratio (DNBR) limit and fuel centerline melt (kw/ft) limits.
A more negative MTC increases the rate of reactivity insertion during these events and causes a
more rapid approach to these limits.
The Anticipated Operational Occurrences in this category of events are the following:
1.
Decrease in Feedwater Temperature 2.
Increase in Feedwater Flow 3.
Increase in Main Steam Flow 4.
Inadvertent opening of a
Steam Generator Safety Valve or Atmospheric Dump Valve The NSSS response and the consequences of these occurrences are similar.
The Increase in Main Steam Flow event is the most limiting of the above events with respect to DNBR and Peak Linear Heat Rate (PLHR) criteria.
Inadvertent Opening of a
Steam Generator Safety Valve or Atmospheric Dump Valve event results in the greatest degradation of shutdown margin after reactor trip has occurred and the largest site boundary doses of all occurrences in this category.
The analysis of these two events will be discussed.
The Decrease in Feedwater Temperature and Increase in Feedwater Flow events will not be discussed since they are not the limiting events.
The Increase in Main Steam Flow event causes the fastest heat removal by the secondary, resulting in the most rapid power increase and closest approach to DNBR and PLHR limits.
The analysis of this event with a MTC of -30 pcm/'F is presented in Attachment 4.
The results show that DNBR and centerline melt limits are not violated with the lower MTC limit.
The analysis of Inadvertent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve event assumes continuous steam blowdown from the open secondary safety valve until 1800 seconds into the transient when operator action is credited to terminate the event.
The current analysis of this event using a
MTC of -27 pcm/'F shows a peak reactivity of -1.2% delta rho.
A MTC of -30 pcm/'F results in a peak reactivity of -0.814 delta rho and the reactor remains subcritical.
Site boundary doses for this event are not affected by a more negative MTC limit.
Therefore, the conclusions of the analysis of this event remain the same.
The postulated events in the increased heat removal category are the following steam system piping failure (steam line break) events:
l.
Inside and Outside Containment Pre-Trip Power Excursions 2.
Post Trip Power Excursion from Full Power and Zero Power The current analyses of the inside and outside containment pre-trip power excursions have been performed for a spectrum of break sizes and a range of MTC's.
These analyses shows that for the inside containment cases, the most limiting break size and MTC combination is 2.01 ft'nd -5.4 pcm/'F.
For the outside containment pre-trip steam breaks, the most limiting combination of break size and MTC is 2.27 ft'nd -10.8 pcm/'F.
In both cases a more negative MTC results in more rapid power excursions and faster action by the High Power Trip which terminates the event.
Therefore, a
more negative MTC limit does not affect the results and conclusions of the Pre-Trip Power Excursion analysis since a
MTC more negative than assumed in the current analysis of record will result in faster termination of the event and less severe consequences.
The post trip (return to power) steam line break cases are most limiting with the most negative allowed MTC.
The more negative the MTC, the greater the positive reactivity inserted in the core and the higher return to power as the RCS cools down.
The Hot Full Power (HFP) and Hot Zero Power (HZP)
Steam Line Breaks were reanalyzed for negative MTC of -30 pcm/'F and are presented in.
The results of these analyses show that the critical heat fluxes are not exceeded.
Reactivit and Power Distribution Anomalies:
CEA Dro Event A full length Control Element Assembly (CEA) Drop is defined as an inadvertent release of a CEA causing it to drop into the core.
The initial negative reactivity inserted by the dropped rod causes a
power decrease and ensuing fuel and moderator temperature reduction.
This temperature reduction, with negative fuel and moderator coefficients, inserts positive reactivity in the core, causing the core to return to its initial power with a
lower
Cr 1
moderator temperature.
The dropped CEA also redistributes the core power, causing higher radial peaks in regions away from where the dropped CEA is located.
The CEA Drop event is one of the events analyzed to determine initial margin to DNB and PLHR Specified Acceptable Fuel Design Limits (SAFDL).
The SAFDL limits must be preserved by the Limiting Conditions for Operation (LCO) limits.
For this event the concern is increased radial peaking since the core returns to power with a highly skewed power distribution.
A more negative MTC returns the core to its initial power at a higher moderator temperature.
This higher moderator temperature has no impact on approach to PLHR limit but results in a larger thermal margin (DNBR) degradation.
- Thus, the LCO limits must preserve a
greater thermal margin to prevent violation of the DNB SAFDL limit.
This event was reanalyzed to calculate the required thermal margin.
The resultant margin degradation remains less than the thermal, margin already preserved by current Technical Specification
Description of this event and the NSSS response are presented in Attachment 4.
Miscellaneous:
As metric Steam Generator Transients These events result from a load or feedwater flow change to one steam generator, causing a mismatch heat removal by the steam generators and subsequent inlet temperature asymmetry across the core.
This temperature asymmetry redistributes the power across the core, possibly causing higher radial peaks and a lower DNBR.
These events are analyzed to assure that the margin preserved by the DNBR and PLHR related Technical Specification LCO limits are sufficient so that in combination with action by the asymmetric steam generator protective trip function of the TM/LP trip, these limits are not violated.
The most limiting of Asymmetric Steam Generator transients is inadvertent closure of a single Main Steam Isolation Valve (MSIV).
A more negative MTC aggravates the power redistribution across the core, resulting in higher radial peaks and larger margin degradation during this event.
This event
- was, reanalyzed with a larger radial peak increase due to the more negative MTC.
The results show that the conservatisms in
calculation of the required margins for the current docketed analysis are sufficient to accommodate the increase in radial peaking accounting for temperature asymmetry.
Therefore, the current docketed analysis and its results are bounding for a
negative MTC of -30 pcm/'F.
Conclusions A negative MTC of -30 pcm/'F yields consequences for the Design Basis Events which are within the limits-of the acceptance criteria.
In particular, the change does not cause a violation of the appropriate fuel design
- criteria, increase previously calculated site boundary
- doses, or result in RCS pressures above the upset pressure limit.
ATTACHMENT 3 DETERMINATION OF NO SIGNIFICANT HAZARDS CONSIDERATION The standards used to arrive at a determination that a request for amendment involves no significant hazards consideration are included in the Commission s regulations 10 CFR 50.92, which states li that no significant hazards considerations are involved if the operations of the facility in accordance with the proposed amendment would not (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated or (3) involve a significant reduction in a margin of safety.
Each standard is discussed as follows:
Operation of the facility in accordance with the proposed amendment would not involve a significant increase in the probability or consequences of an accident.
previously evaluated.
The proposed change to the Technical Specification negative MTC limit is an input parameter in various transient and accident analysis.
Allowing the operating MTC to be more negative does not influence whether or not the transient is more or less likely to occur.
Safety analyses have been performed to demonstrate that any
, transients or accidents whose results would be adversely affected by a more negative MTC limit. do not have consequences that are significantly worse than previously evaluated.
In addition, the revised analyses, incorporating the proposed change in MTC limit, continue to demonstrate that all appropriate analyses criteria reported in the Reload Analysis Report are met.
In particular, the change does not cause any violations of the appropriate fuel design
- criteria, increase previously calculated site boundary
- doses, or result in RCS pressures above the upset pressure limit. Therefore, the proposed change in the Technical Specification MTC limit does not involve any increase in the probability or consequences of an accident previously evaluated.
In addition to the Accident analysis, the effect on the Boric Acid Makeup Tank boron concentration limits were evaluated.
This evaluation shows that this change will not affect the current limit.
The proposed change does not alter any equipment performance requirements, or the probability or c'onsequences of equipment malfunction.
2.
Operation of the facility in accordance with the proposed amendment would not create the possibility of a
new or different kind of accident from any accident previously evaluated.
The proposed change in the negative Technical Specification MTC limit does not constitute any change in procedures for plant operation or hardware nor does it require any change in the accident analysis methodology or the Design Basis Events analyzed.
Therefore, the proposed change will not create the possibility of a
new or different kind of accident from any accident previously evaluated.
3.
Operation of the facility in accordance with this proposed amendment would not involve a significant reduction in a
margin of safety; Safety analysis calculations show that incorporation of the more negative MTC limit yields results which are still within the existing acceptance criteria without the need to change any other Technical Specification LCO or LSSS limits.
Therefore, the operation of the facility in accordance with the proposed amendment involves no significant reduction in a margin of safety.
Based on the above Safety Evaluation, it is concluded that no significant hazard consideration is involved with the proposed change.
ATTACHMENT 4 COMBUSTION ENGINEERING ANALYSIS OF RECORD FOR PROPOSED TECHNICAL SPECIFICATION CHANGE
3.2.1.3 INCREASED MAIN STEAM OM 3.2.1.3.1 dentif catio of auses The Increased Hain Steam Flow event is analyzed to ensure that the Departure from Nucleate Boiling (ONB) and Fuel Centerline to Melt (CTM) Specified Acceptable Fuel Design Limits (SAFDLs) are not violated.
An Increased Hain Steam Flow event is defined as any rapid increase in steam generator steam flow other than a steam line rupture (discussed in Section 3.2.1.5 or an inadvertent opening of a secondary safety valve (discussed in Section 3.2.1.4).
Such rapid increases in steam flow result in a power mismatch between the core power and the steam generator load demand.
Consequently, there is a decrease in reactor coolant temperature and pressure.
In the presence of a negative moderator temperatur e coefficient of reactivity, the decr ease in reactor coolant temperature causes an increase in core power.
The High Power Level and Thermal Margin/Low Pressure (TH/LP) trips~rQvide primary protection to prevent exceeding the ONB limit during the event.
Additional protection is provided by other trip signals including Low Steam Generator Mater Level and Low Steam Generator Pressure.
The approach to the CTM limit is terminated by either the DNB related trip or the High Power level Trip.
In this analysis, credit is taken only for the action of the hT power input to the Variable High Power Level Trip in the determination of the minimum DNBR and maximum local linear heat generation rate.
Crediting only the hT power input calculates conservative results at the most negative
- MTC, and eliminates the need to determine a "cut-off" MTC.
The following increased main steam flow events have been examined:
Opening of the turbine control valves at Hot Full Power (HFP) due to controller failure.
Opening of the turbine control valves at hot standby due to controller failure.
The most rapid load increase at hot standby would occur for the case in which it is assumed that the turbine control'alves opened completely.
Opening of a single valve within either the Steam Dump and Bypass System or the Atmospheric Dump System.
3.2.1.3.2 al sis of fects and Conse uenses The opening of the turbine control valve at full power was initiated at the conditions given in Table 3.2.1.3-1.
A moderator temperature coefficient (MTC) of -3.0 x10-4 hp/'F was assumed in the analysis.
The most negative
- MTC, in conjunction with the decreasing coolant inlet temperature, enhances the rate of increase in the core heat flux at the time of trip.
A minimum fuel temperature coefficient (FTC), corresponding to the beginning of cycle with an uncertainty of 15K, was used in the analysis since this FTC results in the least amount of negative reactiity addition to mitigate the transient increase in core 'heat flux.
A,
The minimum CEA worth assumed to be available for shutdown is -5.0 Xhp.
The pressurizer pressure control system was assumed to be inoperable because this minimizes the RCS pressure during the event and therefore reduced the calculated DNBR.
All other control systems were assumed to be in the manual mode of operation and have no significant effect on the results of this event.
Based on previous analyses and the current evaluation, it is concluded that the opening of the turbine control valves at zero power and the opening of a single steam dump and bypass valve or an atmospheric dump valve are less severe than the opening of the turbine control valves at HFP.
3.2.1.3.3 geesu ts The Increased Main Steam Flow event, resulting from the opening of the turbine control valves at full power, resulted in a High Power Level Trip at 37.4 seconds.
The minimum DNBR calculated for the event initiated from the conditions specified in Table 3.2.1.3-1 was greater than the design limit of 1.28.
The maximum local linear heat generation rate was less than the design limit of 22 kw/ft.
Table 3.2.1.3-2 presents the sequence of events for the HFP Increased Main Steam Flow event.
Figures 3.2.1.3-1 through 3.2.1.3-5 show the NSSS response for power, heat flux, RCS temperature, RCS pressure and steam generator pressure during the event.
.2.1.3.2
~3 For the Increased Main Steam Flow events, the DNBR and CTM limits are not vi,alated.
In addition, the reactivity transient during the event is less limiting than the that of the In'advertent.Opening of a Secondary Safety Valve presented in Section 3.2.1.4.
Inadvertent opening of a single steam dump and bypass valve of atmospheric dump valve, or the opening of the turbine control valve at Hot Zero Power result in less severe results than the 'opening of the turbine control valve at
'Hot Full Power.
The radiological consquenses are bounded by those presented in Section 3.2.1.4 (Inadvertent Opening of a Steam Generator Safety Valve or Atmospheric Dump Valve).
i C
arameter TNLE 3.2.1.3-1 P
RAM RS SSUMED 0
E N
AS D
N S AM ON EVEN
~Ut s Va1ue Initial Core Power Level (Including 2X uncertainty and pump heat)
Initial Core Coolant'nlet Temperature Initial Reactor Coolant System Pressure Initial Reactor Coolant System Flow Rate Moderator Temperature Coefficient Doppler Coefficient Multiplier CEA Scram North
~ F psia gpm 10 hp/
F 2774 552 2180 363,000
-3.0 0.85
-5.0
~
~
TABLE 3.2.1-3-2 Time seconds SE UENCE OF ENTS FOR THE.INCREASED HAIN STEAN FLOW EVENT Event Set oint or Value 0.0 24.6 37.4 37.9
- 38. 1
- 38. 1
- 38.5 38.5
- 38. 65 Turbine control valves open to maximum, flow capacity High Power Trip Signal generated by by ex-core inp'ut (trip over-riden)
High Power Trip Signal generated by hT power input 4-Reactor Trip Breakers opened Haximum Core Power reached Haximum Linear Heat Generation Rate Haximum Heat Flux Hinimum DNBR CEA's Begin to Drop 112.74K af 2700 MMt 118.Fl'f 2700 HMt
< 22 kw/ft 118.7X of. 2700 HMt
> 1.28
+ Note
- Only hT power calculators are credited to bound the cases with less negative HTCs; for which the rate of power increase is slower. For less negative HTCs the dT power calculator becomes more effective while the excore detectors become less accurate due to the temperature shadowing.
120 l00 80 60 C) 40 20 10 20 30 40 T I l1E, SE CONOS 50 60 FLORIDA ONER 4 LIGHT CO.
St.
Lucke Pl ant Un)t 2 INCREASED HA?X STUN FLOQ EVENT CORE POVER VS TINE FIGURE 3.2.1.3-l
r
120 100 0
80 CD 40 20 10 20 30 4'0 TINE.
SECONOS 50 60 FLORIDA PStER L LIGHT CO.
St.
Lucite Plant Unit 2 INCREASED HAIN STEN FLOM EVENT CORE HEAT FLUX VS TINE FIGURE 3-2.1.3-2
Y
620 600 Tan o
580 560 540 TaVC T?N 520 500 10 20 30 40 TINE.
SECONDS 50 60 FLORIDA POMER 5 LIGHT CO.
St. Lucre Plant Un1t 2 INCREASED HAIN STEAN FLOM EVENT REACTOR COOLANT SYSTEH TEHPERATVRES VS TINE FIGURE 3.2.1.3-3
2400 2300 2200 2100 2000 1900 1800 10 20 30 40 TINE.
SECONDS SO 60 FLORIOA RNER 4 LIGHT CO.
St. Lucre Plant, Unit 2 INCREASEO MAIN STEAN FLN EVENT REACTOR COOLANT SYSTBI PRESSURE VS TINE FIGURE 3.2.1.3-4
1100 1050 1000 950 C3 900 850 800 10 20 30 40
'INE.
SECONOS 50 60 FLORIQA PmtER 4 LIGNT CO.'t.
Lucio Plant On)t 2 IHCREASEO tOIH STEN FLOM EVENT STEAN GENERATOR PRESSURE VS TINE FIGURE 3.2.1.3-S
3.2.1.5c S
EAM SYS EM NG AILURE OS-NA YSIS 3.2. 1.5c. 1 Ide tif cat o
of auses The Hot Full Power (HFP) and Hot Zero Power (HZP) Steam Line Break (SLB)
Events were analyzed to show that the the critical heat fluxes are not exceeded during these events.
A break in the main steam system piping increases the rate of heat extraction by the steam generators and causes a cooldown of the Reactor Coolant S~tem (RCS).
In presence of a negative moderator temperature coefficient of reactivity, this cooldown produces a positive reactivity addition.
For breaks located between the steam generators and the main steam isolation valve, the blowdown of the affected steam generator continues even after main steam isolation.
Steam flow from the intact steam generator is terminated with the closure of both isolation valves, either one of which is capable of terminating flow.
3.2.1.5c.2 nal sis o
ects a
d Conse ue ces The HFP SLB was initiated from the conditions listed in Table 3.2.1.5c-l.
The following considerations were also included (applicable to both the HFP and HZP cases):
a)
The largest possible steam line break size (6.358 ft ) is assumed, as it results in the maximum post-trip return-to-power (R-T-P) and thus, the minimum post-trip DNBR.
This occurs because the largest break size causes the greatest temperature reduction and therefore, inserts the greatest magnitude of positive reactivity due to moderator and fuel reactivity feedback.
b)
The cooldown following a steam line break results in contraction of the reactor coolant.
For this analysis, if the pressurizer
- empties, the reactor coolant pressure is set equal to the saturation pressure corresponding to the highest temperature in the RCS.
c) d)
A Safety Injection Actuation Signal (SIAS) is actuated when the pressurizer, pressure drops below the SIAS setpoint.
Haximum time delays associated with the safety injection pump acceleration, valve opening and flushing of the unborated safety injection lines are accounted for.
The cooldown of the RCS is terminated after the affected steam generator blows dry.
As the coolant temperatures begin increasing, positive reactivity insertion from moderator reactivity feedback decreases.
The decrease in moderator reactivity combined with the negative reactivity inserted via boron injection causes the total reactivity to become negative.
The delivery of auxiliary feedwater flow to the Unaffected steam generator is assumed to occur immediately after an Auxiliary Feedwater Actuation Signal (AFAS) is generated.
The signal is assumed to occur at the time that the Hain Steam Isolation Valve is completely closed.
No auxiliary feedwater enters the affected steam generator, since an Auxiliary Feedwater Isolation Signal to this steam generator is generated prior to the AFAS.
The effective Hoderator Temperature Coefficient (HTC) of reactivity assumed in the analysis is -3.0x10 Mp/'F. This negative HTC results in the greatest positive reactivity Insertion during the RCS cooldown caused by the steam line break.
Since the reactivity change associated with moderator feedback varies significantly over the moderator density covered in the analysis, a curve of reactivity insertion versus density rather than a single value of NTC is assumed in the analysis.
The moderator cooldown curve used in the analysis was conservatively calculated assuming that on reactor trip, the highest worth control element assembly is stuck in the fully withdrawn position.
The reactivity defect associated with the fuel temperature decrease is also based on a most negative Fuel Temperature Coefficient (FTC).
This FTC in conjunction with the decreasing fuel temperatures causes the greatest positive reactivity insertion during the steam line break event.
The uncertainty on the FTC assumed in the analysis is given in, Table 3.2.1.5c-l.
The p fraction assumed is the maximum absolute value including uncertainties for end-of-life conditions.
This is also conservative since it maximizes subcritical multiplication and thus, enhances the potential for R-T-P.
The minimum CEA worth assumed to be available for shutdown at the time,'of reactor trip at the maximum allowed power level is -7.8 Mp.
The analysis assumed that on a SIAS, one High Pressure Safety Injection (HPSI) pump fails to start.
A maximum HFP inverse boron worth of 110 ppm/Mp was conservatively assumed for safety injection.
For the HFP case, a'ow Steam Generator Pressure (LSGP) trip setpoint of 540 psia was assumed for a reactor trip.
The time of loss of offsite power was assumed
.to be simultaneous with the time that the Hain Steam Isolation Signal (HSIS) setpoint is reached at 460 psia.
These assumptions result in the coastdown of the main feedwater pumps concurrent with the main feedwater isolation valve closure.
The combination of trip time and delayed feedwater isolation results in the maximum cooldown of the RCS.
The HZP case was initiated at the conditions given in Table 3.2. 1.5c-l.
The cooldown curve corresponds to a core which yields an effective HTC of
-3.0xl0 Mp/'F at Hot Full Power All Rods Out condition.
The most negative FTC was also used for reasons previously discussed for HFP.
The minimum CEA shutdown worth available is conservatively assumed to be the minimum required Technical Specification limit of -5.0 Mp.
The analysis also assumed that, on SIAS, one HPSI pump fails to start.
A maximum HZP inverse boron worth of 102 ppm/Mp was assumed for the safety injection during the 7
HZP case.
For the HZP case, a Low Steam Generator Pressure (LSGP) trip setpoint of 540 psia was assumed.
Loss of offsite power was assumed to occur simultaneously with the steam line break.
These assumptions lead to the lowest core flow at the time of R-T-P and results in a lower calculated DNBR.
3.2. 1.5c.3
~esu ts
~Case Table 3.2.1.5c-2 presents the sequence of events for the HFP case initiated from the conditions given in Table 3.2.1.5c-l.
The response of the NSSS for power, heat flux, RCS temperatures,'CS
- pressure, steam generator pressure and reactivity are given in Figures 3.2.1.5c-l through 3.2.1.5c-6.
The results of the transient show that a reactor low steam generator pressure trip setpoint is reached at 3.1 seconds and trip breakers open at 4.3 seconds.
'ow st'earn generator pressure of 460 psia at 4.6 seconds will result in generation of MSIS.
Main steam isolation and main feedwater isolation valves begin to close as a result of MSIS signal and are completely closed following the maximum allowed Technical Specification delay times.
Occurrance of loss of offsite power at the time of MSIS leads to coastdown of the reactor coolant, pumps.
The results of the analysis show that SIAS is actuated at 22.0 seconds.
The affected steam generator blows dry at 88.2 seconds and terminates the.
cooldown of the RCS.
The peak reactivity attained is -.083 Mp at 115.7 seconds.
The peak post trip power of 9.6 X is produced at 116.1 seconds.
The continued fission power and corresponing heat from the fuel after termination of blowdown causes the reactor coolant temperatures to increase.
This in turn reduces the magnitude of the positive moderator reactivity inserted and thus the total reactivity becomes more negative.
The minimum DNBR during the transient does not violate the MacBeth 1.3 limit.
ZP Case Table 3.2.1.5c-3 presents the sequence of events for the HZP case initiated from the conditions given in Table 3.2.1.5c-l.
The response of the NSSS for power, heat flux, RCS temperatures, RCS pressure, steam generator pressure and reactivity are given in Figures 3.2.1.5c-7 through 3.2.1.5c-12.
The analysis assumed the loss of offsite power at the beginning of the event since this assumption leads to the lowest core flow at the time of return to power and results in -a lower calculated ONBR.
Low steam generator pressure trip setpoints is reached at 2.6 seconds and trip breakers open at 3.8 seconds.
HSIS follows after the affected steam generator pressure goes below 460 psia at 3.5 seconds.
The closure of the main steam isolation valves is completed following the maximum allowed Technical Specification delay time.
The results of the analysis show that SIAS is actuated at 28.9 seconds.
The affected steam generator blows dry at 134.8 seconds.
The peak reactivity attained is +.318.&p at 178.2 seconds and leads to a maximum return to power of 4.4
% at 194.4 seconds.
Turnaround of core temperatures following the affected steam generator's dryout mitigates the reactivity transient.
The miniqum ONBR during the transient does not violate the 1.3 limit.
3.2. 1.5c-4 Conclusion The Steam Line Rupture Event, analysis from HFP and HZP conditions with loss of offsite power shows that the minimum ONBR does not violate the 1.3 limit.
TABLE 3.2.1.5c-l RAME S
SSU 0
H st AK a ameter Units F
Va ue P Va ue Total RCS Power, MWt (Core Thermal Power
+ Pump Heat) 2774 Initial Core Coolant Inlet Temperature,
'F 552 540 Initial RCS Vessel Flow Rate,
~ gpm 363,000 363,000 Initial Reactor Coolant System
- Pressure, psia 2405 2405 Doppler Coefficient Uncertainty, Percent 15 15 Effective Moderator Temperature Coefficient, 10 hp/'F
-3.0
-3.0 CEA Worth at Trip, Sap 7.8 5.0 Inverse Boron Worth, pptq/Xdp 110 102
TABLE 3.2.1.5c-2 Sequence of Events for the Steam Line Break Event at Hot Full Power, Inside Containment with a oss of Offsite Power and HPSI Pum Failure Time sec Event Set oint or Value 0.0 Largest Steam Line Break Occurs 6.358 ft 3.1 Low Steam Generator Pressure Trip Signal Setpoint is Reached 540 psia 3.5 Steam Generator Differential Pressure Analysis Setpoint Reached; Auxiliary Feedwater Isolation Signal to Affected Steam Generator is Actuated 281 psid 4.3 CEA Trip Breakers Open 4.6 Main Steam Isolation Signal Setpoint is Reached; Loss of Offsite Power Occurs 460 psia 5.1 CEAs Drop into. the Core 5.7 Hain Steam Isolation Valves and Hain Feedwater Isolation Valves Begin to Close 9.7 Hain Feedwater Valve is Closed
TABLE 3.2.1.5c-2 (continued)
~ime eec
/ver
.Set oi t or Value 11.3 Hain Steam Isolation Valve is Closed; Auxiliary Feedwater Actuation Signal Generated on Intact Steam Generator Auxiliary Feedwater Oelivery to Intact Steam Generator is Initiated 178 ibm/sec 21.6 Pressurizer Empties 22.0 Safety Injection Actuation Signal Generated on Low Pressurizer Pressure 1578 psia 02.0 High Pressure Safety Injection Pump Reaches Full Speed 88.2 Affected Steam Generator Empties
< 2500 ibm 115.7 Haximum Post-Tr ip Reactivity
-0.083 Qp 116.1 Haximum Return-to-Power 9.6X of 2700 MWt 123.0 Hinimum DNBR Using HacBeth Correlation
> 1.3 237.0 Boron Enters the Core
TABLE 3.2.1.5c-3 Sequence of Events for the Steam Line Break Event at Hot Zero Power, Inside Conta'nment with a oss of Offsite Power and HPSI Pum Failure Time sec Event Set oint or Value 0.0 Largest Steam Line Break Occurs Loss of Offsite Power Occurs 6.358 ft 2.6 Low Steam Generator Pressure Trip Signal Setpoint is Reached 540 psia 3.5 Hain Steam Isolation Signal Setpoint is Reached 460 psia 3.8 CEA Trip Breakers Open 4.4 Steam Generator Differential Pressure Analysis Setpoint Reached; Auxiliary Feedwater Isolation Signal to Affected Steam Generator is Actuated 281 psid 4.6 CEAs Drop into the Core 4.7 Hain Steam Isolation Valves and Hain Feedwater Isolation Valves Begin to Close 8.7 Hain Feedwater Valve is Closed;
TABLE 3.2.1.5c-3 (continued)
Time sec
~vent
.Set oint or Value 10.3 Hain Steam Isolation Valve is Closed Auxiliary,Feedwater Actuation Signal Generated on Intact Steam Generator Auxiliary Feedwater Ent'ers the Intact Steam Generator 178 ibm/sec 28.7 Pressurizer Empties 28.9 58.9 Safety Injection Actuation Signal Generated on Low Pressurizer Pressure Higg Pressure Safety Injection Pump Reaches Full Speed 1578 psia 87.4 Boron Enters the Core 134.8 Affected Steam Generator Empties
( 2500 ibm 178.2 Haximum Post-Trip Reactivity'0.318 Mp 194.4 Haximum Return-to-Power 4.4X of 2700 HWt 194e6 Hinimum DNBR Using HacBeth Correlation
> 1.3
1SO 12S 100 CV ED 7S l
SO SO 100 1SO TIME, SECONDS 200 2SO 300 FLOR IDA P
h LIGHT CO>>
St. Luc)c Huc1 ear Pomr Plant
'KN U'E BfBg 96tt POS1-RIP Pmm PEm, RJLL PIER SnH Lm ~ AC OK POLER VS TPE FIRRE Z,2,1.5C-l
1SO 12S
~ 100 CV ED
~\\
7S LU SO 100 1SO TIME, SECONDS 200 2SO 300 FLOR IDA P
< LIGHT Can SAN U% BFM BENT se- <c<e 2 Pgg "mIP PG~ FEA5 Rll. PSER WITH LDSS (F AC SK HE'AT FLN VS TIP
700 o
600
= SOO
~ 400
~ 300 OUT 200 50 100 lSO
- TINE, SECONDS 200 250 300 FLOR ADA
& LIGHT Caw St.
t uc4e 2
'ucl ear Paver Plant STEN UNE BIGS 8/BiT POST-TMP FQM FBI', FULL PSER%% t&% fF i'ACTOR KXNTSYSTEM IB'PERAl1JKS VS TItE
2500
~ 2000
~ lSOO 1000 CD
~
~
CD CY CDl CD GOO SO 100 150 TIME, SECONDS 200 250 300 FLOR IDA LIGHT Coo St. lucre 2 Huclear Power plant SKO LINE BKC BENT POST-TRIP PatKR P9lG, RILLPS'I'IH Lm (F K nCroR mOUINT Smm mSSuX VS TIra FIQJK 3,2,1.5C4
1200 1000
~ 800 W ~
g 600 l
~ 400 UNAFFECTEO 200 AFFECTED 50 100 150 TIME, SECONDS 200 250 300 FLOR IDA LIGHT COe St. Lucfez Huc1eac Power PI ant SAW UrK BRE4Ji BEG POSt-TMP P58< PEAG, FULL PNER O'tH l%S OF AC WPl (GENT)R PRESSURE VS TI%
10 MODERATOR DOPPLER TOTAL SCRAM 10 SQ 100 150 ZOO TINE, SECONDS:-
250 3QO FLOR IDA t [GHT COe St. Lucre >
Nuclear Power Plant SIFN LIt'KBf8K BENT RST-.'mIP f6ER PNG, RJLL RKR HI'IH UBS (F AC KACTV/ITIES YS TI%
FIGJPE
$,2,j..5C
4g 25 20 (D
C) c4 15 tD 10
~
~
60 120 180 TIME, SECONDS 240 300 FLOR IDA R
5 LIGHT CO e St.
Lucite >
Nucleay Power Plant SEN U<K BKC BENT POST-TMP PIER PEAG, ZE6 POER HUH UXS rF AC CORE
'IRJRE Z,2,1.5C-7
20 60 120
.180 TIME, SECONDS 240 300 LORIOA 4 LIGHT COe St. Lucre >
vcl ear Po~e Plant SIEN UfE BREN< BENT POST-TRIP KM3PNS, 2ERl POND HI'IH NiS CF K NK fFAT RN VS TIK FIRER
'5,2,1.5C<
600 SSO SOO 450 CD CD 400 CX CD I
- 350 300 FLOR EDA ER
~ t.EGHT CO<
St. Lucre >
'uclear Po~er Plant OUT TAYG IN
.60 120 180 TIME, SECONDS 240 STBn UttE mK EM%
POST-TRIP PSlER PS',
ZHU PGHER WITH Lm > <
~CRR KOREAN'YSTPl 787'ERAIUKS % TO'K 300 FIHJK g.2,1.5C-9
2500
~ 2000 Ol 1500
~ 1000 500 60 120 TIl'1E, SECONDS 180 240 300 FLORIQA LIGHT CO<
- t. Luc)e 2
'@clear pokey plant QBf'1 LINE BfEAKEYE PQST-'tRIP P0%R PFA5, ZERO PSER Mt'Bt UKS (F AG
'FACll3R (90U5T!)YYWPPES%8E VS TI%
F<8K 3,2,>,SC-
1000 800 600 400 200 AFFECTED UNAFFECTED
.,60 120 180 TIME, SECONDS 240 LOR IDA 4 LIGH7 CO>>
St. Lucre 2
hcleae Power Plant STFN LDE BREN( BENT POST-'tPJP PQM PCS, ZERO PIER ÃBl LOSS (F AC
'UPER
%HEMMER PfERkK VS TlK
MODERATOR 2
DOPPLER TOTAL BORON
'-4 SCRAM 60 120 i80 TINE, SECONDS 240 300 FLOR [DA R 4 LIGHT CO St. Lucre 2
Nucl eai Pomr Plant sr'NE 8 vK Bett mr-mr zm mes, ram p0%R MrrH tnt'F Ac FIQNE 5.2.1.K-
j
~
3.2.4.3.1 dent ficat'on of Causes The full length CEA Drop Event is reanalyzed to determine the initial thermal margins that must be maintained by the Limiting Conditions for Operation (LCOs) such that the DNBR and fuel centerline melt design limits will not be exceeded.
The CEA Drop Event is defined as the inadvertent release of CEA causing it to drop into the core.
The occurrence of an electrical or mechanical failure in a CEA drive mechanism would result in a CEA drop.
In the event of a full length CEA Drop, a decrease in reactor power would follow, accompanied by a decrease in the average reactor coolant temperature.
- Moreover, the power distribution would be distorted as a result of the presence of the CEA.
If the Reactor Regulating System is in the automatic mode and if no protective features are provided in the control element drive system to terminate CEA movement, the reactor regulating system would restore power to match the turbine load demand that existed prior to the CEA drop by withdrawing CEAs.
Prior to establishing a
match between the core power and the turbine
- load, the CEA withdrawal would result in an overshoot of the core power beyond the initial value.
The overshoot would be caused by the initial drop in the average core coolant and fuel temperatures and the fact that the controller responds to deviations from a programmed T,
versus turbine load relationship.
The LCOs are designed to maintain a
DNB ratio sufficiently above the limit to rideout a full length CEA drop without violating the DNB SAFDL and without the necessity for a reactor'trip.
The CEA drop detection systems are designed to sense a dropped CEA and to reduce turbine load to a preset value by reducing the load reference setting and reducing the setting of the turbine load limitdevice.
The protection system further prohibits the CEDH control system from automatically withdrawing CEAs.
An orderly retrieval of the dropped CEA can then be accomplished at the new steady state condition.
3.2.4.3.2 a
sis of ects and Conse uences This event was analyzed for both single and subgroup CEA Drop.
The latter case yielded the maximum initial margin to be maintained by LCOs and is presented below.
Table 3.2.4.3-1 presents the initial conditions assumed in the analysis.
Additional conservative assumptions include:
a)
The CEA drop detection system is assumed to be inoperable.
The turbine
'oad is not reduced, but
$ s assumed to remain the same as prior to the CEA drop.
This results in a power mismatch between the primary and secondary
Credit is taken,
- however, for the fact that the automatic withdrawal of the CEAs by the CEDN control system is disabled, as discussed in the previous section.
J
'kp
b)
The most negative moderator and fuel temperature coefficients of reactivity are used because these coefficients produce the minimum RCS coolant temperature decrease upon return to 100 percent power level and thus minimize DNBR.
c)
Charging pumps and proportional heater systems are assumed to be inoperable during the transient.
This maximizes the pressure drop during the event and minimizes DNBR.
d)
All other systems are assumed to be in manual mode of operation and have no impact on this event.
The event is initiated by dropping a full length CEA subgroup over a period of 1.0 second.
The maximum increases in radial peaking factors (integrated and planar) in either rodded or unrodded planes are used in all axial regions of the core once the power returns to the initial level.
Conservative values of 19 percent are assumed for these peak increases.
The axial power shape in the hot channel is assumed to remain unchanged
- and, hence, the increase in the 3-D peak for the maximum power is directly proportional to the assumed maximum increase in radial peaking factor of 19 percent.
Since there is no trip assumed, the peaks will stabilize at these asymptotic values after a
few minutes as the secondary side continues to demand 100 percent power.
i 3.2.4.3.3 Jesuits
~
~
~
I Table 3.2.4.3-2 presents the sequence of events'or the Full Length CEA Subgroup Drop Event initiated at the conditions described in Table 3.2.4.3-1.
The event was analyzed parametric in axial shape index to determine the maximum required overpower margin needed to ensure the SAFDLs are not violated.
Figures 3.2.4.3-1 through 3.2.4.3-4 show the NSSS response fo} core
- power, core heat flux, RCS temperatures, and Figure 3.2.4.3-5 shows the minimum DNBR versus time for a
limiting CEA drop.
A minimum CE-1 DNBR of 1.28 is calculated at 300 seconds.
A maximum allowable initial linear heat generation r ate of 17.2 KW/ft could exist at HFP as an initial condition without exceeding the Acceptable Fuel Centerline Melt Limit of 22.0 KW/ft during this transient.
This amount of margin is assured by setting the linear heat rate related LCOs based on the more limiting allowable linear heat rate for LOCA (13.0 KW/ft, see Section 3.3)..
3.2.4.3.4 onc usions This event initiated from the Tech Spec LCOs will not exceed the DNBR and Centerline to Melt Design Limits.
r
TABLE 3.2.4.3-1 E
PARAMETERS ASSU EO OR HE ULL LENGTH CEA DROP VEN Palameter
~Un'ts Value.
Total RCS Power (Core Power +
Pump Heat)
Initial Core Coolant Inlet Temperature Initial Reactor Coolant System Pressure Initial RCS Vessel Flow Rate Moderator Temperature Coefficient Doppler Coefficient Multiplier MWt
'F Psia GPM xl0 Zp /'F 2720+
549'225~
377,500+
-3.0 1.15 For DNBR calculation, effects of uncertainties on these parameters were combined statistically.
TABLE 3.2.4.3-2 SE UENCE OF EVEN S FO FULL LENGTH CEA DROP-
~me sec 0.0 1.0 1.26 Event CEA Begins to Drop into Core CEA Reaches Full Inserted Position Core Power Level Reaches Minimum and Begins to Return to Power due to Reactivity Feedbacks Set oint or Value 100X Inserted 76.7% of Initial 40.0 Core Power Returns to its Maximum Value 100K of Initial 85.0 Core Inlet Temperature Reaches New Steady State Value 544.3 F
276 300 Minimum DNBR is Reached
> 1.28 Reactor Coolant System Pressure Reaches 2173.0 New Steady State Value
P
120 110 80 70 60 106 1b0 200 T'INE.
SECONDS 2S0 300 FLORIDA P
ER 8
LIGHT COe St. Lucie 2
ar Power P1ant FULL EN6% (ZA DROOP MN mRE P5JER vs TINE FIGJK g,g,l~,3-].
~ t I
0 I al
~ I II Ii
~
I I tl P ~
P
~ \\
)
~
~
~
~
i '
g f
~)I
650 625 600 out 57S LLI 550 avg "in 525 500 GO 100 150 200 TIME.
SECONOS 250 30C FLOR IDA WER h LIGHT CO e St. Lucie 2 clear Power Plant FULL LBGIH CEA DWP B/BtT KACT0R CmLNT PSTEN tH'KNTlJKS% TIE:
FIR)PE 3.2.~.5-3
2350 2300 2250 2200 2150 2100 50 l
l 100 150 T I HE.
SECONDS 250 300 FLOR IDA POWER I LIGHT COe St. Lucre 2'r Power PIant
/
~
RJLL LEH6% CEA DFf'/ENT i
8EPQOR mOLNT SYSTB'l PKSSOK VS TItK; i
FIRPE 5.2.Ll.3-4
'7 Cp
1.0 E9 1,3 1.2 1.n 0
50 35'.)
TH', SERVE 200 FLORIDA R
8 LIGHT CO<
St.
Lucie 2
ear Power Plant FULL lHKIH CE'A DIP E%N
'NIHIL(Z-1 QGR VS TIE