ML20154H074
| ML20154H074 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 02/28/1982 |
| From: | WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP. |
| To: | |
| Shared Package | |
| ML20154H067 | List: |
| References | |
| 9464A:1, NUDOCS 8603100181 | |
| Download: ML20154H074 (38) | |
Text
.
SEAVER VALLEY DELETION OF REACTOR TRIP ON TURBINE TRIP iELOW 70 PERCENT P0'WER February, 1982 J
Westinghouse Electric Corporation Nuclear Energy Systems P. O. Box 355 Pittsburgh, Pennsylvania 152 30 8603100101 860227 PDR ADO'K 05000412' A
PDR 9464A:1
TABLE CF CONTENTS 3e :':n Title 1.0 Identification of Causes and Accident Description 2.0 Analysis of Effects and Consequences 3.0 Resul ts 4.0 Conclusion 9464A:1
LIST OF TABLES
'aS e Title 1
Initial Conditions 2
Time Sequence of Events for a Turbine Trip With Pressure Control 3
Time Sequence of Events for a Turbine Trip Without Pressure Control i
l I
1 I
-9464A:1 -.
LIST CF FIGURES I';ure Title 1
Turoine Trip with Pressure Control - Minimum Feedback -
Nuclear Power and Reactor Coolant Average Temperature 2
Turbine Trip with Pressure Control - Minimum Feedback -
Pressurizer Pressure and Water Yoltme 3
Turtine Trip with Pressure Control - Minimum Feedback - DNBR 4
Turcine Trip with Pressure Control - Maximum Feedback -
Nuclear Power and Reactor Coolart Average Temperature 5
Turbine Trip with Pressure Control - Maximum Feedback -
Pressurizer Pressurt and Water Volume 6
Turtine Trip without Pressure Control - Minimum Feedback -
Nuclear Power and Reactor Coolant Average Temperature 7
Turtine Trip without Pressure Control - Minimum Feedback -
Pressurizer Pressure and Water Volume S
Turbine Trip without Pressure Control - Minimum Feedback -
DNBR 9
Tuttine t rip without Pressure Control - Maximum Feedback -
Nuclear Powr and Reactcr Coolant Average Temperature 10 Turtine Trip without Pressure Control - Maximum Feedback Pressurizer Pressure and Water Voltme 11 Turbine Trip with Pressure Control - Minimum Feedback -
Steam Dump - Control Rod Insertion - No Loss of RCS Flow -
l Nuclear Power and Reactor Coolant Average Temperature 9464A:1
LIST CF FIGURES (Continued)
=';ure Title 12 Turcine Trip with Pressure Control - Minimum Feedback -
Steam Dump - Control Rod Insertion - No Loss of RCS Flow -
Pressurizer Pressure and ' dater Volume 13 Turbine Trip with Pressure Control - Minimum Feedback -
Steam Dump - Control Rod Insertion - No Loss of RCS Flow -
ONBR 0
l 9464A: 1
1.0 EENTIFICAT!CN OF CAUSES AND ACCICENT CESCRIPTICN
- 1aj r 'Jac 'Oss on the plant can result fr0m loss of external elec-ricai 1:ac :ue to scme electrical system ci sturcance.
Off site AC power remains avai'able to operate plant ccmponents such as the reactor coolant pumps.
Following the loss of generator load, an immediate fast closure of the turbine control valves will occur. This will cause a sudden reduction in steam flow, resulting in an increase in pressure and temperature in the steam generator shell. As a result, the heat tran-sfer rate in the steam generator is reduced, causing the reactor coolant temperature to rise, which in turn causes coolant expansion, pressurizer insurge, and RCS pressure Hse.
For a loss of external electrical load without subsequent turbine trip, no direct reactor trip signal would be generated.
The plant would be expected to tHp from the Reactor Protection System.
In the event that a safety limit is approached, protection imuld be provided by the high pressurizer pressure and overtemperature aT trips.
In the event the steam disap valves fail to open following a loss of load or turbine trip, the steam generator safety valves may lift and the reactor may be tripped by the high pressuMzer pressure signal, the high pressurizer water level signal, or the overtemperature ai signal.
The steam generator shell side pressure and reactor coolant temperatures will increase rapidly. The pressurizer safety valves and steam genera-F tor safety valves arc, however, sized to protect the Reactor Coolant j
System (RCS) and steam generator against overpressure for all load l
losses without assuming the operation of the steam disnp system, pres-l surizer spray, pressuMzer power-operated relief valves, auton:atic rod cluster control assembly control or direct reactor trip on turbine trip.
The steam generator safety valve capacity is sized to remove the steam flow at the Engineered Safety Features Rating (105 percent of steam flow at rated power) from the steam generator without exceeding 110 percent of the steam system design pressure.
The pressurizer safety valve capacity is sized based on a complete loss of heat sink with the plant 1
9464A:1
initially coerating at the maximum calculated turoine load along witn Oceration of the steam generator safety valves.
The pressuri:er saf ety ea' <es are then able to e;ieve sufficient steam to maintain the RCS acessure within 110 percent of the RCS design acessure.
The primary-side transient is caused by a decrease in heat transfer capability from primary to secondary due to a rapid termination of steam flow to the turbine, accompanied by an automatic reduction of feedwater flow.
Should feed flow not be reduced, a larger heat sink would be available and the transient would be less severe. Termination of steam flow to the turbine following a loss of external load occurs due to automatic fast closure of the turbine control valves in approximately
.25 seconds.
Following a turoine trip event, te rmination.o f s tern flow occurs via turbine stop valve closure, which occurs in approximately.25 seconds.
Therefore, the transient in primary pressure, temperature, and water volume will not be dependent on the mode of steam flow tennina-tion; therefore, a detailed transient analysis is only presented for the turbine trip event.
For a turbine trip event, the reactor would be tripped directly (unless below approximately 70 percent power) fran a signal derived fran the turtine auto stop emergency trip fluid pressure and turbine stop valves. The turbine stop valves close rapidly on loss of trip-fluid pressure actuated by one of a number of possible turbine trip signals.
Turbine-trip initiation signals include:
1.
Generator trip 2.
Low Condenser Vacuum 3.
Loss of Lubricating Oil 4
Turbine Thrust Bearing Failure 5.
Turtine Overspeed 6.
Manual Trip 9464A:1
Upon initiation of stoo valve closure, steam ficw to the turbine stops ae ruo tly.
Sensors on the stop valves detect the turoine trio and ini-titte stea1 tume and, if acove 70 sercent power, a reacto r trio.
The ioss of steam C0w results in in almost immediate ri se in secondary system temperature and pressure wi:n a resultant primary system transient.
The automatic steam dump system would nonnally acconunodate the excess steam generation.
Reactor coolant temperatures and pressum do not signficantly increase if the steam dump system and pressurizer pressure control systen are functioning properly (i.e. the better estimate case).
If the turbine condenser was not available, the excess steam generation would be dumped to the atmosphere and main feedwater flow would be lost. For this situation feedwater flow would be maintained by the Auxiliary Feedwater Systen to insure adequate residual and decay heat removal capability.
Should the steam dump system fail to operate, the stean generator safety valves may lift to provide pressure control, as discussed previously.
Nonnal power for the reactor coolant pumps is supplied through busses fran a transfonner connected to the generator.
When a generator trip occurs, the busses are automatically transferred to a transfonner sup-plied from external powr lines, and the punps will continue to supply coolant flow to the core. Following any turbine trip where there are no electrical faults which require-tripping the generator from the network, the generator remains connected to the network for approximately 30 seconds.
The reactor coolant pumps remain connected to the generator, thus ensuring flow for 30 seconds before any transfer is made.
Should the netwrk bus transfer f ail at or before 30 seconds, a complete loss of forced reactor coolant flow would result.
The immediate effect of loss of coolant flow is a rapid increase in the coolant temperature in addition to the increased coolant temperature as a msult of the tu rbi ne trip. This increase could result in DiB with subsequent fuel damage if the reactor were not tripped promptly.
i I
9464A: 1
The 'ol'cwing signals provide the necessary protection against a
- mciste loss of flew accicent:
Reactor :colant :umo acwer supply undervoltage.
2.
L:w reactor coolant loop flow.
The reactor trip on reactor coolant pump undervoltage is provided to protect against conditions which can cause a loss of voltage to all reactor coolant pumps, i.e., station blackout.
This function is blocked below approximately 10 percent power (Permissive 7).
The reactor trip on low primary coolant loop flow is provided to protect against loss of flow conditions which affect only one reactor coolant loop.
This function is generated by two out of three low flow signals per reactor coolant loop.
Between approximately 10 percent power
~
(Permissive 7) and the power level corresponding to Permissive 8, low flow in any two loops will actuate a reactor trip.
I 9464A:1
2.0 ANALYSIS OF EFFECTS AND CONSEOUENCES "e: rec :f Analysis
- n :ni s anal / sis, the tenavi:r :f the unit is evaluated for a ::colete less of steam load from 72 percent of full power wi tnout direct mactor tri p.
This shows the adequacy of the pressure relieving devices and also demonstrates the core pmtection margins; that is, the turbine is assumed to trip without actuating all the sensors for reactor trip until conditions in the RCS result in a trip due to other signals.
Thus, the analysis assumed a worst transient.
In addition, no credit is taken for steam dump. Main feedwater flow is tenninated at the time of turbine trip, with no credit taken for auxiliary feedwater to mitigate the con-sequences of the transient.
Following the loss of steam load but before a reactor trip, a f ast bus transfer is attempted. The transfer to an external power source is assumed to fail at the time producing the most limiting DN8 resulting in a complete loss of flow transient initfated from the ' loss of load condi-tions.
The loss of ficw transient coincident with turbine trip transients are analyzed by employing the detailed digital computer code LOFTRANIII.
The LOFTRAN Code calculates the loop and core flows following the ini-tial loss of load. The LOFTRAN Code simulates the neutron kinetics, RCS, pmssurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The program ccmputes pertinent plant variables including temperatures, pmssums, power level, and DNB margin.
Major assumptions are summarized below:
1.
Initial ~ 0oerating Conditions - the initial reactor power and RCS temperatures are asstmed at their maximum values consistent with the steady state 72 percent power operation including allowances for calibration and instrument errors.
(1)
Burnett, T. W. T., et al., "LOFTRAN Code Description", WCAP-7907, June, 1972.
l The initial RCS pressure is assumed at a minimum value consistent witn the steacy state 72 percent pcwer operation incluaing allow-ances f:r calibraticn and instrument errors. The initial RCS ficw i 5 assLeec 0 :e consisten for :nree loop Oceraticn.
~hi s resul ts in :ne maximum power difference for the load loss and the minimum margin to core protection limits at the intiation of the accident.
Table 1 summarizes the initial conditions assumed.
2.
Moderator and Doopler coefficients of Reactivity - the turoine trip i
is analyzed with both a least negative moderator temperature coef-ficient and a large negative moderator tenperature coefficient.
Doopler power coefficients are adjusted to provide consistent minimum and maximum reactivity feedback cases.
3.
Reactor control - from the standpoint of the maximum pressures attained, it is conservative to assume that the reactor is in manual control.
If the reactor were in automatic control, the control rod banks would insert prior to trip and reduce the severity of the transient.
4 Steam Release - no credit is taken for the operation of the steam dump system or steam generator power-operated relief valves.
The i
steam generator pressure rises to the safety valve setpoint where steam release through safety valves limits secondary steam pressure at the setpoint value.
l S.
Pressurizer Spray and Power-Operated Relief Valves - two cases for both the minimum and maximum reactivity feedback cases are analyzed:
1 a.
Full credit is taken for the effect of pressurizer spray and I
power-operated relief valves in reducing or limiting the coolant pressure.
Safety valves are also available.
b.
No credit is taken for the effect of pressurizer spray and power-operated relief valves in reducing or limiting the coolant p res sure. Safety valves are operable.
9464A: 1
,-.____.y y,_
,,-,.,__,-----,-______s--
G.
FQQcwater Flow - main feedwater flow to the steam generaters i s assumed to te lost at the time of turoine trip.
No credit is taken 7:r auxiliary feedwater fi:w since a stacili:ec :11nt c nciti:n.v111
- e es:nec cefore auxiiiary feecwater ini,i a:f on is normalij issumec
- :c:gr; newever, the auxiliary feedwater ;umas woule :e ex:ec:ac
- 0 start on a trip of the main feedwater pumps.
The auxiliary feedwater flow would remove core decay heat following plant stacilization.
7.
Reactor trip is actuated by the first Reactor Protection System trip setpoint reached with no credit taken for the direct reactor trip on the turbine trip.
Trip signals are expected due to high pressurizer pressure, overtemperature aT, high pressurizer water level, low reactor coolant loop flow, and reactor coolant puma power supply undervol tage.
Except as discussed above, nonnal reactor control systems and Engineered "
Safety Systems are not required to function. The Reactor Protection System may be required to function following a turbine trip.
Pressur-izer safety valves and/or steam generator safety valves may be required to open to maintain system pressures below allowable limits. No single active failure will prevent operation of any system required to function.
Recently the NRC has expressed concerns regarding the potential increase in probability of a stuck-open pressurizer PORY following the implemen-tation of the WRAP item " Deletion of Reactor Trip on Turbine Trip below 70 percent power." The NRC current position is addressed in NUREG-0660, Vol.1, Requirement 10, Table C-3 and NUREG-0611, Paragraph 3.2.4.6:
the anticipatory reactor trip function should not be deleted "until it has been shown on a plant-by-plant bases that the small break LOCA probability resulting from a stuck-open PORY is little affected by the modi fication" The Westinghouse design criterion is that load rejections up to 100 pert:ent should not require a reactor trip if all other functions operate properly.
The power mismatch is taken up by the 85 percent steam dump and automatic rod insertion (10 percent).
The PORV's are provided to 9464A: 1
reduce the likelihood of tripping the -eactor on the high pressuri:er
- ressure signal and coening the pressuri:er safety valves, wnich cannot
- e 'sciatac.
So in addition to the Ifmiting transients described above, a better estimate transient was simulated assuming operation of the control sys-tems that nomally wuld be available.
This is done in order to simu-late a better estimate of the transient that would normally occur following a loss of Ioad without subsequent reactor trip to show that the pressuri:er PORY's would nomally not open.
Using the same initial operating conditions, the better estimate case assumed correct operation of the network buss transfer, steam dump, feedwater control system, and pressurizer pressure control system. Also for the better estimate case, automatic rod control and beginning of life reactivity feedback condi-tions wre assumed. The same protection systems wre available but not used for the better estimate transient.
]
9464A:1
3.0 RESULTS be - ans'ent -e:0nses f:r i turoire trip from 72 pement of full power
- erni:n are snown for five cases:
two cases for minimum reactivity feedback, tw cases for maximum reactivity, feedback and one better esti-mate case (Figures 1 through 13).
The calculated sequence of events for the transients is show in Tables 2 and :3.
Figures 1 through 3 show the transient responses for the total loss of steam load with a least negative moderator temperature coefficient assuming full credit for the pressurizer spray and pressurizer power-operated relief valves. No credit is taken for steam dump.
The buss transfer failure at 30 seconds results in an undervoltage trip of the reactor and the initiation of the loss of flow transient. The minimum DNBR remains well above the 1.3 limit. The pressurizer safety valves are actuated and maintain primary system pressure below 110 pement of the design value. The steam generatcr safety valves limit the secondary steam conditions to saturation at the safety valve setpoint.
Figures 4 and 5 show the responses for the total loss of steam load with a large negative moderator temperature coefficient. All other plant parameters are the same as above. The buss transfer failure at 30 sec-onds results in an undervoltage trip of the reactor and the initiation of the loss of flow transient. The minimum DNBR remains well above the 1.3 limit throughout the transient. Pressurizar reifef valves and steam generator safety valves prevent overpressurization in primary and secon-I dary systems, respectively.
A plot of DiBR versus time is only given for the beginning of, life cases since all other cases are significantly less limiting.
The turtine trip accident was also studied assuming the plant to be initially operating at 72 pert:ent of full power with no credit taken for the pressurizer spray, pressurizer power-operated relief valves, or j
steam dump. The reactor is tripped on high pressurizer pressure sig-nal. The fast bus transfer for this case is assumed to fail L.2 seconds before rod drop time to produce the transient most limiting with respect i
9464A;1
l to Of;S anc :: assume the roc droo time from the hign pressuri:er pros-sure si;na ' i s c: incident.vi:n :ne time from tne undervol tage si gnal.
ri;;res 5 :n-Ougn 3 snew :ne transients witn a leas: nega:ive moders::r c ef ficient. The neutron flux remains essentially constant at 72 per-cent of full cower until the reactor is tripped. The DNBR remains acove 1.3 tnrcugneu t the transient.
In tiis case the pressurizer safety valves are actuated and maintain system pressure below 110 percent of the design value.
Figures 9 and 10 are the transients with maximum reactivity feedback with the other assumptions being the sane as in the preceeding case.
The rcactor is tripped on the high pressurizer pressure signal and the fast buss transfer to of fsite power is assumed to fail 1.2 seconds before rod crop. Again, the minimum ONBR remains above 1.3 throughout the transient and the pressurizer safety valves are actuated to limit primary pressure.
A better estimate turbine trip accident was also simulated assuming the plant to be initially operating at 70, percent of full power with credit taken for pressurizer spray, steam dump, successful buss transfer, feed-water control system operational, automatic rod control, and beginning of life reactivity feedback conditions in mitigating the transient.
The control rods are inserted and the steam dump quickly actuated following the turbine trip event; primary side pressure increases very little, there is no reactor trip and the plant is smoothly and quickly brougnt to hot shutdown condition. DNDR remains well above 1.3 limit.
Following the turbine trip the' maximum primary pressure is 2208 psia, and the steam pressure peaks at 914 psia. Neither the primary or secondary side pressure reaches the point where the pressure PORV's or i
the steam generator safety valves are actuated.
Ca6aA 1
l 4.0.CCNCLUSICNS Resuits af One analyses snew that the plant design is such that a turoine trip without a cirect or immediate reactor trip presents no hazard to the integrity of the RCS or the main steam system.
Pressure relieving devices incorporated in the two systems are adequate to limit the maximisa pressures to within the design limits.
The analysis also demonstrates that for a complete loss of forced reactor coolant flow initiated from the most adverse preconditions of a turbine + trip, the DNBR does not decrease below 1.30 at any time during the transient.
Thus, no fuel or clad damage is predicted, and all applicable acceptance
{
criteria are met.
For nonnal plant operation with all nonnal control systems assumed operational, pressurizer pressure does not reach the point of pressur-izer PORY activation. Therefore the Deletion of reactor trip on turbine trip below 70 pen:ent powr is not expected to significantly increase the probability of a small break LOCA due to a stuck-open PORY.
9464A:1
TABLE 1 NIT:AL CC?lDITICilS I
1 No. of Active Loops 3
)
Core Power, MWt 1915 Thermal Design Flow (TOTAL) GPM 26'5500 Reactor Coolant Average Temperature, W 572.2 Reactor Coolant System Pressure, psia 2220 9464A:1
TABLE 2 7:.ME 3ECUENCE CF EVENTS FOR A TURSINE TRIP WITH PRESSURIZER PRESSURE CCNTROL Event Time ( sec.)
1.
Minimum Feedback (BOL)
Peak pressurizer pressure occurs 12 Initiation of steam release from steam generator safety valves 12.5 Fast bus transfer f ailure, flow coastdown begins, and undervoltage trip occurs 30 Rods begin to f all 31.2 Minimum ONBR occurs,.
33 2.
Maximum Feedback (EOL)
Minimum DNBR occurs O
Peak pressuri:er pressure occurs 11 Initiation of steam release from steam geneator safety valves 13 Fast bus transfer f ailure, flow coastdown begins, and undervoltage trip occurs 30 Rods begin to fall 31.2 9464A:1 j
l TABLE 3 TIME SECUENCE OF I'/ENTS FOR A TUR3:NE TRIP WITHOUT 3RE55URIZER PRESSURE CCNTRCL Event Time (sec.)
1.
Minimum Feedback (BOL)
Fast bus transfer f ailure, flow coastdown begins, and undervoltage trip occurs 8.8 Rods begin to f all, high pressur-izer pressure trip occurs 10 Minimum DNBR occurs 11.5 Peak pressurizer pressure occurs (2542 psia) 12 Initiation of steam release from steam generator safety valves 12.5 2.
Maximum Feedback (EOL)
Minimum DN8R occurs 0
Fast bus transfer f ailure, flow coastdown begins and undervoltage i
trip occurs 8.9 Rods begin to f all and high pres-surizer pressure trip occurs 10.1 I
Peak pressurizer pressure occurs (2528 psia) 11.5 Initiation of steam release from steam generator safety valves 12.5 9464A:1
- .3
=
5 2.5 Dli i
f v
r
'T 0.1
$c z.c E2 2
0,2 - -
5 t.
0 0
20 40 60 80 100 Time (sec) i 610 600 g
.~
590
?
580 t
I 57 5 0
2d 40 60 80 100 Time (sec)
Figure 1 Turbine Trip with Pressure Control - Minimum Feedback -
Nuclear Power and Reactor Coolant Average Temperature
2500 5
2200 3
y
'T V,
\\
2200
[
s (O
i 5,
u t
2000 c
+
1800 100 0
20 40 60 80 Time (sec)
H 3
1200 1100 i
f.!
S9[
1000 --
a
%~
}l 900 NE F
c-800 4
700 0
20 40 60 80 100 Time (sec)
Figure 2 Turbine TMp with Pressure Control - Minimum Feedback -
PressuM zer Pressure and Water Volume
9.0 J
8.0 1
+
7.0 1
6.0
..iii E
5.0 - -
A 4.0
- 3. 0 2.0 0
20 40 60 80 100 Time (sec)
Figure 3 Turbine Trip with Pressure Control - Minimum Feedback -
DNBR i
0.3 C
2
- 3. 5 -
-,.3 1
i!
.. =
'E 0.4 <
E-
\\
j U.!
)
4 5%
2 0.2 5.
L l
0.0 100 0
20 40 60 80 Time (sac) 4 610 600 -
g
~
,590 -
580 L
i 570 0
20 40 60 80 100 Time (sec)
Figure 4 Turbine Trip with Pressure Control - Maximum Feedback -
Nuclear Power and Reactor Coolant Average Temperature
~
2500 2500
+
2 00 y
I t}
23C0
+
l us u=
0~
2200 Ei 0
2100 2
2000
~
4 1900 0
20 40 60 80 100 Time (sec) 1200 u
1100 3
56d 1000 2'
IIjg 20 2"
a.
800 I
700 O
20 40 60 80 100 Time (sec)
Figure 5 Turbine Trip with Pressure Control. Maximum Feedback.
Pressurizer Pressure and Water Volume i
L
3.3 3
9
- ~
=
a
_? 5 4
0.2 E=
t 5$
?
^
=v w
I 2
0.2 -
I 0.0 0
20 40 60 80 100 Time (sac) 61 0 i
f 600 L
590
~
?
580 l
570 0
20 40 60 80 100 Time (sec)
Figure 6 Turbine Trio Without Pressure Control - Minimum Feedback -
Nuclear Power and Reactor Coolant Tegerature
ISCO r 2500 v 3
2200,P u
I g 2300 h3
/
n 2200 5
5 2100 E*
2000 1900 0
20 40 60 20 100 Time (sec) 1 1200 1100 l
u 3EL 1000 I
5 !
MO as 5
800 t
./
700 40.
60 30 100 0
20 Time (sec)
Figure 7 Turbine Trip Without Pressure Control - Minimum Feedback -
Pressurizer Pressure and Water Volume
1 i
20.0 17.5 i
i 15.0 12.5 as g
10.0
- 7. 5 5.0 2.5 0 20 40 60 80 100 l
Time (sec)
)
i Figure 8 Turbine Trip Without Pressure Control - Minimum Feedback -
l DN8R 1
i a
J.3
...E. 3.5 5I
=i l
1 g = 0.4 3i M
& 0.2 -
~
Q l
0 20 (0
66 80 TOO Time (sec) 610 600 '
4 i
C.
~
590 3
580 -
570 0
20 40, 60 80 100 Time (sec) i Figure 9 Turbine Trip Without Pressure Control - Maximum Feedback -
Nuclear Power and' Reactor Coolant Average Temperature 1
i l
2500 l 7
2500f T
~
5 200C -
$E-22C0 -
2200[ll
=.2
't E.
~~
5 2100
~
w
@2 2000 <
1900 0
20 40 60 80 100 Time (sec) 4 ll i
j.
t 1200 l
1100 - -
u l
3 "-
1000 6-
%~
i b5 900 -
M 800 4
'700 ~l 0
20 40 60 80 100 i
Time (sec)
)
f I
i Figure 10 Turbine Trip Without Pressure Control - Maximum Feedback -
Pressurizer Pressure and Water Volume l
I i
l
s
\\
2
.]
3.5 5
!d 1
2.g2 0.4 e=f 35 0.3 d v.
I O.2 t,
0.1 l
0.0 O
50 100 150 200 Time (sec) i 600
!so 560
.u.
w g
540
=
$20 500 0
50 100 150 200 Time (sec) i i
Ficura li Turcine Trio With Pressure Central
'iinimum. eectack -
$taam 'lumo - 0:ntrol Rod Inse" tion
,'ic '. ass of ECe
~
~
Flow
.'luclear :cwer and teact:r C:oiant aver 19e Temcerature
I N: :
L L
3 2300
=
.Ao i
.uL, bO 2200 t
zm 5
o u
l i~
2100 2000 0
30' 100 150 200 Time (:ec) i s
l 100 I
I u=
soo
-W
%w u~
3
'E $
o-I A O
=>
soo w
I 400 0
50 100 150 200 Time (sec}
I Figure 12 Turcine Tric with Pressure Centrol - Minimum ~etet:ack -
Steam Cumo - Control Rod Inser:icn - tio Lass af RC3 ficw -
PressuM:er Pressure and Water 'lolume
l 4.0 3.5 3.0 E
2.5 I
2.0 l
1.3 0
Sd 100 150 200 Time (sec)
Figure 13 Turbine Trip With Pressure Control - Minimum Feedback -
Steam Dumo - Control Rod Insertion - No Loss of RCS Flow -
CNBR 1
i f,
9 9
9 0
Se I
ATTACHMENT 2
VAXLMUM :0SE RELEASE ANALYSIS 1r tra'js's :# ;9e aors: :sse ea.e -eleases nas :er#:r ec using ice #:: wing
- as : 1ssa ::':ns :
F an; is in ranual ::n:rol race 2.
Pressuri:er pressure control (spray and PORY relief) 3.
30L conditions (minimum moderator feedback) 4 No steam dump 5.
Successful bus transfer to offsite power 6.
Feedwater control system operational 7.
No operator action for 30 minutes A considerable amount of steam may be released during this transient througn the Steam Generator Safety Valves to the environment.
This is assumed to occur for 30 minutes due to operator action delay.
However the pressurizer PORV's and SG safety valves do not lift until 12 seconds into the transient (following primary to secondary pressure and temperature increases due to turbine trip).
By 40 seconds the pressurizer PORV's and spray and SG safety valves and the plant conditions stabilize at approximately 681 power, a high DNBR, and 68.4% nominal steam flow out of the steam generator safety valves.
It is the steam flow we are concerned with.
Graphs of pertinent parameters are on the following pages.
Total flow through SG safety valves = 68.4% nominal flow
(.684)(2223.49 lbm/S)(1800 sec - 12 sec) = 3942300. lbm Since a Reactor Trip is not:obtained and the plant stabilizes at a high power level and steam flow, this case is very conservative with respect to steam release for all cases presented in the main body of this report.
Therefore this release (3942300 lbm) is conservative and may be used to verify the acceptability of all transients with respect to radiological dose releases.
The dose releases will be calculated by Stone and Webster as their part to verify the acceptability for the deletion of the reactor trip on turbine trio below 70% power for Beaver Valley Unit 2.
w%.
- 3. 5 i
j
~
t l
5 a,-
u.-
1E t
Li b e.
l
- =
0.4
-g
);
?
1
- 0. 2 -
l
~
l 0
500 1000 1500 1800 Time (sac) i 610 t
600
'I C
t l
-~
590 4 f,'
i 1
i 580 j
570 0
500 1000 1500 1800 Time (sec)
,t Figure 1 Turbine Trip With Pressure Control - Minimum Feedback -
Nuclear Power and Core Average Temperature
2600 IECC.
s IACC -
3 i ~
i 0
i tg 2200 u
?
~
u23 2200t
~w 3
2100 Uw 2000-1900 0
500 1000 1500 1800 Time (sec) 1200 1100' u3-k 1000 "
b~
- I h-9004 as 2
800.
70u-0 500 1000 1500 1800 Time (sec)
Figure 2 Turbine Trip with Pressure Control - Minimum Feedback -
Pressurizer Pressure and Water '/olume
3.3 i
N 2
=..:
53 l
i 3.3 E2 I 0.2 30 24 l
- $ 0.1 4-1 0.0 i
.02 0
500 100 1500 1800 Time (sec) i 0.5 i
3 0.4
i II 0.3 a
3*
C 5 0.2 "I
- t 2* 5. 0.1 0.0
.03 0
500 1000 1500 1800 Time (sec)
Figure 3 Turbine Trip With Pressurs Control - Minimum Feedback -
Steam Flow, l. cops 2 and 3 i
4.0 3.5 E 3.0 E
2.5 L
2.0 0
500 100 1500 1800 Time (sec)
Figure 4 Turbine Trip with Pressure Control - flinimum Feedback -
ONBR
.