ML20041A112
| ML20041A112 | |
| Person / Time | |
|---|---|
| Site: | 05000470 |
| Issue date: | 02/12/1982 |
| From: | Scherer A ABB COMBUSTION ENGINEERING NUCLEAR FUEL (FORMERLY |
| To: | Eisenhut D Office of Nuclear Reactor Regulation |
| References | |
| LD-82-016, LD-82-16, NUDOCS 8202190112 | |
| Download: ML20041A112 (180) | |
Text
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C-E Power Systems Tel. 203/6881911 Combustion Engineenng. Inc. Telex 99297 1000 Prospect Hill Road Windsor Connecticut 06095
_a W/ q -
POWER H SYSTEMS { RECaWo 4 FEB13;gggw L Docket No.: STN-50-470F 'E8
- M fi f February 12, 1982 y g LD-82-016 Rt $
Mr. Darrell G. Eisenhut, Director Division of Licensing U. S. Nuclear Regulatory Commission Washington, D. C. 20555
Subject:
CESSAR SER Confirmatory Items (14), (15), (16), (17), (18), (19)
Reference:
Letter R. L. Tedesco to A. E. Scherer, dated January 15, 1982
Dear Mr. Eisenhut:
Transmitted herewith is a copy of revised CESSAR Chapter 15 analyses which will be formally incorporated into the CESSAR Final Safety Analysis Report (CESSAR-F) by an amendment submittal. The enclosure is transmitted for the Staff review of CESSAR-F.
The enclosed information is intended to complete the C-E input that the Staff needs to close out CESSAR confirmatory items 14, 15, 17, 18 and 19 iden-tified in Section 1.8 of the CESSAR Safety Evaluation Report. These items involve small steam line break analysis, feedwater line break analysis, steam line break analysis, steam generator tube rupture analysis, and fuel handling accident analysis.
The reactor coolant pump locked rotor analysis (CESSAR confirmatory item 16) is currently being redone in accordance with the request per the Reference. This analysis will be complete in March of 1982.
If I can be of any additional assistance in this matter, please contact me or l Mr. G. A. Davis of my staff at (203)688-1911, Extension 2803 1
Very truly yours, COMBUSTION ENGINEERING, INC.
l M: - r
- n. x lerer Director Nuclear Licensing l
l AES:ctk 8202190112 820212 F.00 Enc PDR ADOCK 05000470 g M}
A PDR Lec:losure C. I. Grimes a
15.1.5 STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE CONTAINMENT 15.1.5.1 Identification of Event and Causes A steam line break (SLB) is defined as a pipe break in the main steam system.
SLB cases are chosen to maximize potential for a post-trip return to power, to maximize potential for degradation in fuel cladding performance, and to maximize dose at the site Exclusion Area Boundary. . The results show that fission power levels remain sufficiently low following reactor trip to preclude degradation in ' fuel performance as a result of post-trip return to power, that degradation in fuel performance prior to trip is of sufficiently limited extent that the core will remain in place and intact with no loss of core cooling capability, and that doses are within 10CFR100 guidelines. The steam line breaks presented are:
A. Cases chosen to maximize potential for a post-trip return to power:
- 1. A large steam line break inside containment during full power operation with concurrent loss of offsite power in combination with a single failure, and a stuck CEA (SLBFPLOP).
- 2. A large steam line break inside containment during full power operation with offsite power available in combination with a single failure and a stuck CEA (SLBFP).
- 3. A large steam line break inside containment during zero power
. operation with concurrent loss of offsite power in combination with a single failure, and a stuck CEA (SLBZPLOP).
- 4. A large steam line break inside containment during zero power operation with offsite power available in combination with a single failure and a stuck CEA (SLBZP).
B. Cases chosen to maximize potential for degradation in fuel performance and dose at the site Exclusion Area Boundary:
- 5. A small steam line break outside of containment upstream of the main steam isolation valve (MSIV) during full power operation with offsite power available in combination with a single failure, technical specification steam generator tube leakage, and a stuck CEA (SSLBFP).
- 6. A large steam line break outside of containment upstream of the MSIV during zero power operation with concurrent loss of offsite pcwer in combination with a single failure, technical specification steam generator tube leakage, iodine spike, and a stuck CEA (SLBZPLOPD).
The largest possible steam line break size is the double ended rupture of a steam line upstream of the MSIV. In the System 80 design, an integral flow restrictor exists in each steam generator outlet nozzle. The largest effective steam blowdown area for each steam line, which is limited by the flow restrictor throat area, is approximately 30?> of the steam cross-section area, or 1.28 square feet.
15.1-10
Results are presented in Appendix C which demonstrate that the cases listed above bound the results obtained for a spectrum of break sizes, loss of offsite power times, and single failures.
15.1.5.2 Sequence of Events and Systems Operation Steam line breaks are characterized as cooldown events dee to the increased steam flow rate, which causes excessive energy removal from the steam generators and the reactor coolant system (RCS). This results in a decrease in -
reactor coolant. temperatures and in RCS and steam generator pressure. The cooldown cause's an increase in core reactivity due to the negative moderator and Coppler reactivity coefficients.
Detection of the cooldown is accomplished. by the pressurizer and steam generator low pressure alarms, by the high reactor power alarm and by _ the low steam generator water level alarm. Reactor trip as a consequence of a steam line break is provided by cne of several available reactor trip signals including low steam generator pressure, low RCS pressure, low steam generator water level, high reactor power, ~ low DNBR trip' initiated by the core protection calculators and, for inside containment breaks, high containment pressure. Far a SLB that occurs with a concurrent loss of offsite power, the events of' turbine stop valve closure, termination of feedwater to both steam generators and coastdown of the reactor coolant pumps are assumed to be initiated '
simultaneously. Following reac~ tor trip the most reactfve control rod is conservatively assumed to be held in the fully withdrawn position. The depressurization of the affected steam generator results in the actuation of a main steam isolation signal (MSIS). This closes the MSIVs, isolating the unaffected steam generator from blowdown and closes the main feedwater isolation valves (MFIVS), terminating main feedwater flow to' both steam generators. After the reduction of steam flow that occurs with MSIV closure,the level in the intact steam generator falls below the emergency feedwater signal (EFAS) setpoint. The resulting EFAS causes emergency feedwater (EFW) flow to be initiated to the intact steam generator.
The EFAS logic prevents feeding the affected steam generator. The pressurizer pressure decreases to the point where a safety injection act'uation signal (SIAS) is initiated. The isolation of the unaffected steam generator and subsequent emptying of the affected steam generator terminate the cooldown.
The introduction of safety injection boron upon SIAS causes core reactivity to decrease. The operator, via the appropriate emergency procedures, may or, in the event that offsite power is available, using MSIV bypass valves any time after the affected steam generater empties. The analysis presented herein conservatively assumes operator action is delayed until 30 minutes after first indication of the event. The plant is then cooled to 350 F and 400 psia at which point shutdown cooling is initiated. A parametric study of single failures (See Appendix C) that would;have an adverse impact on the SLB'has determined that the lure of one of the high pressure safety injectior ~(HPSI) 1 pumps to' start following SIAS has the most adverse effect for the full power case with concurrent loss of offsite power and all zero power cases (Cases l',
3, 4, and 6). Consequently, one HPSI pump is conservatively assumed to fail for these cases. The evaluation shcws that for the full power SLB without ioss A
_
- _ _ _ a M
gy -
^
r S" 2 of.offsits ;:ower (Case 2) the most adverse effect is caused by failure of
~
, < a MSIY en one of .the steam lines on the intact generator to close following PdIS. Consequently 1for this case steam is assumed to continue to be released from the intac't-steam generator after MSIS at a rate consistent with the
.-~ interface requi'.eaent r of a maximum of lit design steam flow rate non-isolable n steam flow. ;This;open flow 2 path is represented by an effective flow area for
' . steam blowdown. from the intact steam generator of 0.2556 square feet. For
' case 5 (SSLBFP): there is no single failure which increases the potential for
_ degradation in' fuel cladding performance or which increases the offsite dose.
The sequence o'f;, events for cases 1 through 5 above are presented in Tables 15.1.5-1 through 5, respectively. The sequence of events for Case 6 is the same as for Case 3'.
~
15.1.5.3 Anal'ysis of Effects and Consequences
'A. Mathematical Models The mathematical models and data transfer between codes, used in the SLB analysis are presented in Appendix C.
B. Input Parameters and Initial Conditions The initial conditions assumed in the analysis of the NSSS response to Cases 1
, through 5 are presented in Tables 15.1.5-6 through 10, respectively. The initial- conditions for Case 6 are the same as those for Case 3. . J usti fication 4
of the selection of initial conditions and input parameters is presented in Appendix C.
, C. Resul ts 4
Case 1: Large Steam Line Break During from Full Power Operation with Concurrent loss of Offsite Power (SLBFPLOP)
The dynamic' behavior of the salient NSSS parameters following the SLBFPLOP is .
presented in Figures 15.1.5-1.1 through 15.1.5-1.16. Table 15.1.5-1 summarizes the major events, times, and results for this transient.
~
Concurrent with the steam line break, a loss of offsite power occurs. At this
, time an actuation signal for the emergency diesel generators is initiated. Due
! to decreasing core flow following loss of power to the reactor coolant pumps, conditions ~ exist for a low DNBR trip. At 0.6 second a low DNBR trip signal . is initiated by the ' core protection calculators. At 0.75 second the reactor trip breakers open. 'After a 0.34 second coil decay delay, the' CEAs begin to drop into the core'at 1.09 seconds. At 8.0 seconds voids begin to form in the upper head of th.e, reactor vessel . At 8.3 seconds the steam generator pressure drops below the MSIS'setpoint.of 810 psia. The MSIS initiates closure of the MSIVs
[ and MFIVs. The.MFIVs and MSIVs close by 13.3 seconds. EFW is automatically initiated to the intact steam,generatofr, assuming no delay after the EFAS signal on low levet in the fatact steam. generator, at 13.3 seconds. At 120 seconds'the pressurizer empt?os. At 178 seconds the pressurizer pressure has dropped belog 1600 psia and initiates a SIAS. Within 30 seconds of SIAS the f operable HoSI pump is loaded on the diesels and reaches full speed and the HPSI val ves arm fully,open. At 237 seconds the affected steam generator empties.
l 15.1-12
_1 _ _
t ~
A i
_w r em +
At 259 seconds the maximum core reactivity (+ 0.09 % ap ) occurs. Safety injection' boron begins to reach the core at 280 seconds. As shown by Figure
- 15.1.5-1.16, the values of DNBR remain above those for which fuel damage would
~ be indicated.. At a maximum of 30 minutes the ' operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the atmospheric dump valves, assuming that offsite power has not been restored.
Shutdown cooling is initiated when the RCS reaches 3500F and 400 psia.
Case 2: Large Steam Line Break During Full Power Operation with Offsite Power Available (SLBFP)
The- dynamic behavior of the salient NSSS parameters following the SLBFP is presented in Figures 15.1.5-2.1 through 15.1.5-2.15. Table 15.1.5-2 summarizes the major events, times, and results for this transient.
_ c "At 6795 seconds after 'the initiation of the steam line break a trip signal is
' . , initiated'by the core prote'ction. calculators on a projected DN8R of 1.195. At
~
'7.1. seconds th,e reactor trip breakers open. After a 0.34 second coil decay delay, the CEAs begin,to drop into the core at 7.44 seconds. At 11.9 seconds voids begin to form in the upper head of the reactor vessel. At 13.5 seconds the steam generator pressure drops below the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and the operable
. - :MSIVs close by 18.5 seconds. EFW is automatically initiated to the intact steam 1 generator, assuming no delay, af ter the EFAS signal on low level in the intact steam generator, at 18.5 seconds. At 67 seconds the pressurizer empties. _ At 90 seconds the pressurizer pressure drops below 1600 psia and 1 ,
initia'tes a SI AS. Within 30 seconds of' SI AS the HPSI pumps reach full speed
'and t'de HPSI ' valves are fully open.' At 149 seconds the affected steam gene,rator eypries at 151 seconds the maximum core reactivity (-0.18% 40) occurs. Sarety injection boron begins to reach the core at 160 seconds. The
' values of DNBR remain above 10 during the post-trip approach-to-criticality
' portion of this transient. At a maximum of 30 minutes the operator, via the iJ '
aperopriate emergency procedure,> initiates plant cooldown by manual control of the turbine" bypass. valves. Shutdown cooling is initiated when the RCS reaches 350 F and 400 ps~ia.
~ Case 3: 'Latge] Steam Line Break Doing Zero Power Operation with Concurrent iloss of Offsite Power The ' dynamic behavior -of the salient NSSS parameters following the SLBZPLOP is presented in Tigures 15.1.5-3.1 through 15.1.5-3.15. Table 15.1.5-3 summarizes
!' the major events, times, and results for this transient.
Goncurrent with the steam line break, a loss of offsite . ve' occurs. At this time an actuation . signal for the emergency diesel gr ce vs is initiated. Due to decreasing core flow following loss of power + a e ctor coolant pumps,
~
i conditicns exist for a low DNBR trip. At 0.6 se' y . . . CNBR trip signal is
[ initiated by the core protection calculators. At 0.75 seund the reactor trip f breakers open. After a 0.34 second coil decay delay, the CEAS begin to drop into the core'at 1.09 seconds. At 5.7 seconds the steam generator pressure drops below the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs. ~ The MFIVs and MSIVs close by 10.7 seconds. EFW is
- automat.ically initiated to the intact steam generator, assuming no delay after the EFAS signal on low level in the intact steam generator, at 10.7 seconds..
15.1-13
At 45 seconds the pressurizer pressure drops below 1600 pe,ia and initiates a SIAS. Within 30 seconds of SIAS the operable HPSI pump is loaded on the diesels and reaches full speed and the HPSI valves are fully open. At 55 seconds voids begin to form in the upper head of the reactor vessel. At 59 seconds the pressurizer empties. Safety injection boron begins to reach the core'at 120 seconds. At 189 seconds the maximum core recctivity (-0.06% ao) occurs. At 1240 seconds the affected steam generator empties. The values of-DNBR remain above 10 during this transient. At a maximum of 30 minutes the operator, via the the appropriate ca.3rgency procedure, initiates plant cooldown by manual control of the atmospherr mp valves, assuming that offsite power has not been restored. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia.
Case 4: Large Steam Line Break Zero Power Operation with Offsite Power Available (SLBZP)
The dynamic behavior of the salient NSSS parameters following the SLBZP is presented in Figures 15.1.5-4.1 through 15.1.5-4.15. Table 15.1.5-4 summari:es the major events, times, and results of this transient.
At 6.24 seconds after initiation of the steam line breck, the steam generator pressure drops belcw the icw steam generator pressure trip and MSIS setpoint of 810 psia. At 6.79 seconds the reactor trip breakers open. After a 0.34 second -
coil ~ decay delay, the CEAs begin to drop into the core at 7.13 seconds. The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and MSIVs close by 11.'3 seconds. EFW is automatically initiated to the intact steam generator, assuming no delay after the EFAS signal on low level in the intact steam oenerator, at 11.3 seconds. At 41 seconds tiie pressurizer pressure drops below 1600 psia anc initiates a SIAS. Within 30 reconds of SIAS the operable HPSI' pump reaches ' 'l speed and the HPSI valves are fully open. At 48 seconds "oids begin to for 'n the upper head of the reactor vessel. At 52 secor.ds the pressurizer empHcs. Safety injection boron begins to reach the core at 110 seconds. At 31v se:onds the maximum core reactivity (-0.02% as ) occurs. At 418 seconds the affected steam generator empties. The values of DNBR remain above 10 fcr this transient. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cocidoun by mnual control of the MSIV bypass valves associated with the unaffected steam generator and turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia.
Case 5: Small Steam Line Break Outside Containment During Full Pcwer Operation with Offsite Power available (SSLBFP)
The dynamic behavior of the salient NSSS paremoters folic 1ing a typical limiting SSL3FP is presented in Figures 15.1.5-5.1 through 15.1.5-5.8. Table 15.1.5-5 summarizes the major events, times and results for this transient.
The consequences of this transient -- fraction of fuel rods predicted to experience DNB -- are the same as those for SSLBFPs for a spectrum of break sizes, due to the protective action of the core protection calcula ors (CPCs).
The break size assumed for the transient presented here was 1.0 squre feet.
Hot later than 28.4 seconds after initiation of the steam line break, a trip signal is initiated by the CPCs on a projec:2d DN3R of 1.19 . At 28.55 seconds 10.1-14 t.
the reactor trip breakers open. After a 0.34 second coil decay delay, the CEAs begins to drop into core at 28.89 seconds. At 29 seconds a minimum transient DNBR of 1.10 is calculated to occur, after which DNBR rapidly increases, as shown in Figure 15.1.5-5.9. At 60 seconds voids begin to form in the upper head of the reactor vessel . At 84 seconds the steam generator pressure drops below the MSIS setpoint of 810 psia.The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and the operableMSIVs close by 89 seconds.
Subsequently, the events of this transient follow a sequence similar to those of the SLBFP (. Case 2). Since the cooldown is less rapid, the potential for post-trip degradation in fuel cladding performance is less for this case (SSLBFP than for Case 2 (SLBFP). At a maximum of 30 minutes the operator, using the appropriate emergency procedure, initiates plant cooldown by manual control of the turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 350 and 400 psia.
At the point of the minimum transient DNBR no more than 0.4% of the fuel rods are predicted to experience DNB. However, as a bounding assumption, 0.7% of the fuel pins are assumed to fail. All of the activity in the fuel gap for fuel rods that are assumed to fail is assumed to be unifonnly mixed with the reactor coolant. The activity in the fuel clad gap is assumed to be 10% of the iodines and 10% of the noble gases accumulated in the fuel at the end of core life, assuming continuous full power operation. This results in a primary -
coolant activity of 617 Ci/gm. Assuming one gpm steam generator tube leakage, during a period of two hoursafter initiation of the SSLBFP the integral leakage from the RCS through the affected steam generator is 720 lbm, which is assumed to be released to the atmosphere with a DF of 1. This mass release results in a contribution to tha inhalation thyroid dose at the Exclusion Area Boundary (EAB) of 220 rem.
The total steam released from the affected steam generator is 210,000 lbm.
The affected steam generator will empty in two hours; therefore all the mass release from the affected steam generator to the atmosphere has a DF of 1. The calculated inhalation thyroid dose is 9.8 rem for the blowdown originating from the secondary system fluid discharge from the affected steam generator. .
Less than 89,000 lbm of steam from the unaffected steam generator will be released trough the steam line break. During the SSLBFP the MSIVs will isolate the unaffected steam generator and prevent it from emptying. Therefore, a DF of 100 is assumed in calculating iodine activity released from the unaffected steam generator. The resulting co'itribution to the inhalation thyroid dose at the EAB is less than 0.1 rem. Should condensor vacuum be lost during this transient upto an addi tional 750,000 lbm of steam from the unaffected steam generator would be released to the atmosphere through the atmospheric steam dump valves. This would result in an additional contribution to the dose of not more than 0.4 rem.
The foregoingg doses are calculated by the methods outlined in Section 15.0.4.
Table 15.1.5-11 presents the major assumptions, parameters, and radiological consequences for this transient.
In summary, the total two-hour inhalation thyroid dose at the EAB as a consequence of the SSLBFP is no more than 231 rem.
l 15.1-15
Case 6: Large Steam Line Break Outside Containment from Zero Power Operation with Loss of Offsite Power (SLBZPLOPD)
Case 6 is included in Case 3, since the break of the latter can be either inside or outside of containment. The Figures, Tables, and Discussion for Case 3 apply to Case 6.
Assuming one gpm steam generator tube leakage, during a period of two hours after initiation of the SLBZPLOPD the integral leakage from the RCS through the affected steam, generator is 720 lbm, which is assumed to be released to the atmosphere with a DF of 1. This mass release results in a contribution to the inhalation thyroid doses at the EAB of:
(a) 1.6 rem, assuming technical specification primary coolant activity; (b) 20.1 rem, assuming a pre-existing iodine spike; or (c) 41.5 rem, assuming an event-induced iodine spike.
The total steam released from the affected steam generator is 300,000 lbm, which is the total initial mass inventory. The affected steam generator will empty in two hours; therefore all the mass release from the affected steam generator to atmosphere has a DF of 1. The calculated inhalation thyroid dose is 14.0 rem for the blowdown steam originating from the initial steam ganerator mass inventory.
Less than 850,000 lbm of steam from the unaffected steam generator will be released through the atmospheric steam dump valves and through the steam line break within two hours. During the SLBZPLOPD the MSIVs will isolate the unaffected steam generator and prevent it from emptying. Therefore, a DF of 100 is assumed in calculating iodine activity released from the unaffected steam generator. The resulting contribution to the inhalation thyroid dose at the EAB is 0.4 rem.
The foregoing doses are calculated by the methods outlined in Section 15.0.4.
Table 15.1.5-11 presents the major assumptions, parameter, and radiological consequences for this transient.
In summary, the total two-hour inhalation thyroid dose at the EAB as a i consequence of the SLBZPLOPD is no more than 56 rem.
15.1.5.4 Conclusion For the large steam line break in combination with a single failure and stuck CEA, with or without a loss of offsite power, fission power remains /sufficiently low following reactor trip to preclude fuel damage as a result of post-trip return to power.
For a large steam line break during zero power operation in combination with a loss of offsite power and technical specification tube leakage the two-hour inhalation thyroid dose at the EAB is well within 10CFR100 guidelines:
(a) 16 rem, assuming technical specification primary coolant activity; (b) 35 rem, assuming a pre-existing iodine spike; or (c) 56 rem, assuming an event-induced iodine spike.
15.1-16
The maximum potential for radiological releases due to fuel failure occurs for small steam line breaks outside containment in combination with a stuck CEA.
For these cases the maximum potential .for degradation in . fuel cladding performance occurs prior to and during reactor trip. The fraction of fuel predicted to experience DNB for these events is no more than 0.4%. With the assumption of one gallon per minute steam generator tube leakage and a bounding assumption of 0.7% fuel failure the two-hour inhalation thyroid dose at the EAB is calculated to be.no more than 231 rem, which is within the 10 CFR100 guidelines.
Potential fuel failure is sufficiently limited to ensure that the core will remain in place and intact with no loss of core cooling capabilities.
15.1 TABLE 15.1.5-1 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH CONDURRENT LOSS OF 0FFSITE POWER (SLBFPLOP)
Time-(Sec) Event Setpoint or Value 0.0 Steam Line Break and Loss of --
Offsite Power Occur 0.6 -
Low DNBR Trip Condition Occurs, 1.19 Projected DNBR 0.75 Trip Breakers Open --
1.09 CEAs Begin to Drop --
8.0 Voids Begin to Form in RV Upper --
Head 8.3 Main Steam Isolation Signal, psia 810 13.3 MFIVs Close Completely --
13.3 MSIVs close completely --
13.3 EFW Initiated to Intact Steam --
Generator 120 Pressurizer Empties --
178 Safety Injection Actuation Signal, psia 1600 208 Safety Injection Flow Begins --
237 Affected Steam Generator Empties --
259 Maxjmum Transient Reactivity, +0.09 10- op 277 Minimum Post-Trip DNBR 2.7 280 Safety Injection Boron Begins to --
Reach Reactor Core 1800 Operator Initiates Cooldown --
TABLE 15.1.5-2 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFP)
Time (Sec) Event Setpoint or Value 0.0 Steam Line Break Occurs --
6.95 . Low DNBR Trip Condition Occurs, 1.19 Projected DNBR 7.10 Trip ~ Breakers Open --
7.44 CEAs Begin to. Drop --
11.9 Yoids Begin to Form in RV Upper _ --
Head 13.5 Main Steam Isolation Signal, psia 810 18.5 MFIVs Close Completely --. _
18.5 MSIVs Close Completely --
18.5 EFW Initiated to intact Steam --
Generator 67 Pressurizer Empties --
90 Safety Injection Actuation Signal, 1600 psia 120 Safety Injection Flow Begins --
149 Affected Steam Generator Empties --
151 Maximum Transiegt -0.18 Reactivi ty, 10- ao 151 Minimum Post-Trip DNBR 26 160 Safety Injection Boron Begins to --
Reach Reactor Core 1800 Operator Initiates Cooldown --
L
TABLE 115.1.5-3 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER OPERATION WITH LONCURRENT LOSS OF 0FFSITE POWER (SLBZPLOP AND SLBZPLOPD)
Time (Sec) Event Setpoint or Value 0.0 ' Steam Line Break and Loss of --
,. Offsite Pcwer Occur.
0.6 Low DNBR Trip Condition Occurs, 1.19 Projected DNBR 0.75 Trip Breakers Open --
1.09 CEAs Begin to Drop --
5.7 Main Steam Isolation Signal, psia 810 10.7 MFIVs Close Completely --
10.7 MSIVs Close Completety --
10.7 EFW Initiated to Intact Steam- --
Generator 45 Safety Injection Actuation Signal, 1600 psia 55 Voids Begin to Form in RV Upper Head --
59 Pressurizer Empties 75 Safety Injection Flow Begins --
120 Safety Injection Boron Begins to --
Reach Reactor core 189 Max { mum Transient Reactivi ty, -0.06 10-1240 Affected Steam Generator Empties --
1600 Operator Initiates Cooldown --
TABLE-15.1.5-4 SEQUENCE OF EVENTS FOR A LAREGE STEAM LINE BREAK ZERO POWER WITH-OPERATION WITH OFFSITE POWER AVAILABLE (SLBZP)
Time (Sec) Event. Setpoint or Value 0.0 Steam Line Break Occurs. --
6.24 '
Low Steam Generator Pressure 810 Trip and Main Steam Isolation-Signal, psia 6.79 Trip Breakers Open --
7.13 CEAs Begin to Drop --
11.3 MFIVs'Close Completely --
11.3 MSIVs Close Completely --
11.3 EFW Initiated to Intact Steam- --
Generator -
41 Safety injection Actuation Signal, 1600 psia 48 Voids Begin to Form in RV Upper Head --
52 Pressurizer Empties --
l 71 Safety Injection Flow Begins 110 Safety Injection Boron Begins to- --
Reach Reactor Core 310 Max { mum Transient Reactivity, -0.02 10- ap 418 Affected Steam Generator Empties --
1800 Operator Initiates Cooldown --
l i
e vr- .,,,i,% gw ii -- -.-p-mye- eqy-- -.' ----- +,--y----. +
TABLE 15.1.5-5 SEQUENCE OF EVENTS FOR A SMALL STEAM LINE BREAK OUTSIDE CONTAINMENT DURING FULL POWER OPERATION WITH OFFSITE POWER, AVAILABLE (55LBFP)
Time (Sec) ___
Event Setpoint or Value 0.0 Steam Line Break Occurs --
Low DNBR Trip Condition 28.4 1.19 Occurs, Projected DNBR 28.55 Trip Breakers Open --
28.89 CEAs Begin to Drop --
R29 Minimum Transient DNBR 1.10 60 Voids Begin to Form in RV --
Upper Head 84 Main Steam Isolation Signal, 810 psia 89 MFIVs Close Completely --
89 MSIVs Close Completely --
-1800 Operator Initiates Cooldown --
TABLEl5.1.5-6 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH CONCURRENT LOSS OF 0FFSITE POWER (SLBFPLOP)
Parameter Assumed Value Initial Core Power Level, MWt 3876
~'
Initial Core Inlet Coolant Temperature, F - 570 Initial Core Mass Flow Rate,106 lbm/hr 148.8 Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft 3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 ao -8.8 Initial Steam G,enerator Inventory, lbm, affected 182000 intact 148000 One High Pressure Safety Injection Pump Inoperative Core Burnup End of Cycle Bl owdc.<n Fluid Saturated Steam Blowdown Area for Each Steam Line, f t2 1.283
TABLE 15.1.5-7 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DUURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFP)
Parameter Assumed Value Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 Initial Core Mass Flow Rate,106 lbm/hr 148.8 Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, f t 3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 At -8.8 Initial Steam Generator Inventory, lbm, affected 182000 intact 148000 One Main Steam Isolation Valve on Intact Steam Inoperative Generator Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown Area for. Each Steam Line, f t 2 1.283 4
4 f
~
TABLE 15.1.5-8 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING ZERO F0WER OPERATION WITH CONCURRENT LOSS OF 0FFSITE POWER (SLBZPLOP AND SLBZPLOPD)
Parameters. Assumed Value
. Initial Core Power Level, MWt 10 Initial Core Inlet Coolant' Temperature, F 575 Initial Core Mass Flow Rate,10 6lbm/hr 147.6 Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft 3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier- 1.10 -
Axial Shape Index +.3 CEA Worth for Trip,10-2 ap -6.0 Initial Steam Generator Inventory, lbm, affected 279000 intact 143000 One High Pressure Safety Injection Pump Inopera ti ve Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown Area for Each Steam Line, f t 2 1.283
i TABLE 15.1.5-9 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER OPERATION WITH OFFSITE POWER AVAILABLE.(SLBZP).
Parameter Assumed Value Initial Core Power Level, MWt 10 Initial Core Inlet Coolant Temperature, F .575 J
Initial Core Mass Flow Rate,106 lbm/hr 147.6 Initial Pressurizer Pressure, psia 2400-
[ Initial' Pressurizer Water Volume, f t 3 1100
- Doppler Coef ficient Multiplier 1.15
' Moderator Coefficient Multiplier 1.10 i Axial Shape Index +.3 CEA Worth for Trip,10-2ap -6.C-Initial Steam Generator Inventory,1bm affected 279000 intact 163000 One High Pressure Safety injection Pump Inoperative Core Burnup End of Cycle
- Blowdown Fluid . Saturated Steam i
Blowdown Area for Each Steam Line, f t 2 1.283 i
(
i i
,, 7._, y- .
- - , . - , . .,-.,_-...,.c. . . _ , . - - . . _, ._-r-., .- __.. _,.
. TABLE 15.1.5-10'
< ASSUMPTIONS FOR A SMI.LL- LINE' BREAK OUTSIDE CONTAINMENT DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILTBLE-(SSLBFP)
Parameter Assumptions Initial Core Power Level,- MWt
- - 3876 Initial Core Inlet Coolant Temperature, F 570 I 6 Initial Core Mass Flow Rate,10 -1bm/hr 148.4 Initial Pressurizer Pressure, psia 22FC Initial Pressurizer Water Volume, ft 3 f f og Doppler Coefficient Multiplier 1.15 l
Moderate Coefficient Multiplier 1.10 Axial Shape Index -0.359 ..
Radial Peaking Factor, Fg 1.4 CEA Worth for Trip,10-2 ao -8.8 Initial Steam Generator Inventory, lbm, affected 182000 intact 148000 Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowde.vn area for each steam line, ft2 1
TABLE 15.1.5-11 (Sheet 1 of 3)
PARAMETERS USED IN EVALUATING:THE RADIOLOGICAL CONSEQUENCES OF STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM 0F MSIV Value Parameter SSLBFP (Case 5) SLBZPLOPD (Case 6)
~
-A. Data and Assumptions Used to Evaluate the Radioactive Source Term
- a. Power Level, Mwt 3876 10
- b. Burnup, years 2 2
- c. ' Percent of Fuel Assumed to Experience DNB,.* 0.7 0
- d. Reactor Coolant 4.6 4.6*
Activity Before Event Table 11.1.1-2 _ Table 11.1.1-2 (based or 3876 MWt),
p/Ci/gm.
- e. Secondary System Section 15.0.4 Section :15.0.4 -
. Activity Before Event
- f. Primary System Liquid 525,600 525,600 Inventory, ibm
- g. Steam Generator Inventory, lbm ~
- Affected Steam 182,000 300,000 Generator
--Intact Steam 148,000 143,000 Generator B. Data and Assumptions Used to Estimate- Activity Released from the Secondary System
- a. Primary to Secondary 1.0 ( total) 1.0 ( total ) ~
Leak Rate, gpm
- b. Total Mass Release from 210,000 300,000 the Affected Steam Generator
- Except for case assumitg pre-existing iodine spike (see footnote on next page).
. TABLE 15;1.5-11 (Cont'd.)-(Sheet 2 of~3)
PARAMETERS'USED IN EVALUATING.THE-RADIOLOGICAL CONSEQUENCES OF A-STEN 4 LINE BREAXS OUTSIDE CONTAlhMENT
. UPSTRER4 0F MSiv -
Value -
Parameters- SSLBAP (Case-5) SLBZPLOP0 (Case 6) c .~. T'otal Mass Release from 840,000 850,000 the Intact Steam '
Generator-
- d. Reactor Coclant System-Activity After Event, Ci Isotope 1-131 8.568(+4)*
I-132 1.217(+5)
I-133 1.605(+5)-
I-134- 1.680(+5) '
- -135 1.469(+5)
Kr-85M 1.421(+4) **
Kr-85 3.903(+2)
Kr-87 2.400(+4)' ,
Kr-00 3.475(+4)
Xe-131M 6.018(+2)
Xe-133 1.618(+5)
Xe-135- 9.724(+4)
Xe-138- 2.557(+4)
- o. Percent of Core Fission /C.:9 **
Products ' Assumed Release to Reactor Coolant
- f. Iodine Decontamination 1.0 1.0 Factor in 'the Affected Steam Generator
- g. Iodine Decontamination 100 100 Factor in the Intact 4 Steam Generator i h. Credit for Radioactive No No Decay in Transit to Dose
- - Point
- i. Loss of Offsite Power No yes
'* Number in parenthesis refer to the power of ten; e.g. 8.558(+4)=S.56SxlC
'**Three sub-cases are presented sub-case RCS activity after event, 2Ci/c
- a) technical specification _ activity- 4.6 b) pre-existing iodine spike 60 c). event-induced iodine spiPe- 124
TABLE 15.1.5-11 (Cont'd.) (SheetL3 of 3)
PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES-0F A STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM OF MSIV Val u e~ .
Parameter SSLBFP (Case 5). SLBZPLOPD (Case 6)
C. Dispersion Data
- 1. Distance to Exclusion 500 500 Area Boundary, m
- 2. Distance to Low 3000 3000 Population Zone Outer.
Boundary, m
- 3. AtmosphericDjspersion Factor, sec/m 2.00'x 10-3 2.00 x 10-3 D. Dose Data -
- 1. Method of Dose Section 15.0.4 Section 15.0.4-Calculation
-2. Dose Conversion Section 15.0.4- Section 15.0.4 Assumptions
r t
a 150 i i i I 125 - -
5 o.
_j 100 - -
2 8
U 75 5
a.
c2 50 - -
- a. -
U 8
25 -- -
I ' i 0
0 100 200 300 400 500 TIME, SECONDS c-E f FULL POWER lARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSITE POWER 15 1 5-88257f8f / / CORE POWER vs TIME i,i
150 i i i 1 2
s .
2 d
g 125 - -
h x
W g 100
-a u_
g 75 -- -
U 5
a.
s' 50 -- -
d e
W W 25 -. -
8
' I
~ I '
0 0 100 200 300 400 500 TIME, SECONDS
.C - E FULL POWER LARGE SEAM LINE BREAK WITH Figure
-CONCURRENT LOSS OF 0FFSIE POWER 15,1,5-SE--- m / CORE HEAT FLUX vs TIME 1.2
4 l l l l
\'
2000 w
' - 1500 - -
ur g -
!2 w
E l@0 -
E 2
500 - -
I ' I I O
0 100 200 300 400 500 TIME, SECONDS i
C-E f FULL POWER LARGE STEAM LINE BREAK WITH Figur e CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-SFE8v/ / RCS PRESSURE vs TIME 1,3
l 50000 , , , ,
40000 - -
S ha
- E
$ 30000 -- -
H!
3 -
b20000_. CORE _
" 10000 -
Ro d5 0 #
-10000 I i i I O 100 200 300 400 500 TIME, SECONDS C-E FULL POWER lARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSIE POWER 15.1.5-
.S E REACTOR COOLANT FLOW RATE vs TIME 1.4
d
~
700' , , i i
' ' ~
o CORE OUTLET
,600 -
0 x
R CORE AVERAGE si
& 500 - -
- s - -
[ -
2 /
g 400 CORE INLET o
E3
@300 I I I I 200 0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE. BREAK WITH Figure CONCURRENT LOSS OF OFFSITE POWER 15.1.5 -
S - REACTOR COOLANT TEMPERATURES (A) vs TIME 1.5 A
1 700 i i i l-INTACT SG HOT LEG o' 600 -
d w
INTACT SG COLD LEGS g500- N -
h "
~
p AFFECTED SG HOT LEG -
k400 -
8 8
AFFECTED SG COLD LEGS m 300 cc 200 0 100 200 300 400 500 TIME, SECONDS l
C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSITE POWER 15.1.5-S REACTOR COOLANT TEMPERATURES (8) vs TIME 1.50 t
10 i i i I
, MODERATOR 6 - N_
DOPPLER (2
z r
~
5 C
g -2 -- -
C S TOTAL SAFETY u INJECTION
-6 -
CEA i i i 1
-10 0 100 200 300 400 500 TIME, SECONDS 1
C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSITE POWER 15.1.5-
-S REACTIVITY CHANGES vs TIME 1.6
r 1200 i i i 1-1000 -- -
1 g' 800 --
5 s
e 3:
e 1
W E
5 400 -
m U
o_
i 200 - -
I I '
0 0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER [ARGE STEAM LINE BREAK WITH pigure CONCURRENT LOSS OF OFFSITE POWER 15 1 5-SE PRESSURIZER WATER VOLUME vs TIME i, f
.w 1200 , , , ,
1000 5 ~
INTACT SEAM GENERATOR
~
E G
u -
600 -
2 5
z E 400 - -
W AFFECTED STEAM GENERATOR f .
200 -
N I I I 0
0 100 200 3C0 400 500 L
TIME, SECONDS l
4 C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSITE POWER 15.1.5-S .
STEAM GENERATOR PRESSURES vs TIME 1. 8
+ 3 .
~ 7000 ^ i , , ,
N 6000 - -
8' m
5 a -
g- 5000 -
5-h4000.-- m - _
a E 3000 - -
- r g R
W -
W 2000 -
! INTACT STEAM GENERATOR -
Ww 1000 -
. AFFECTED STEAM GENERATOR l
1 I I '
0
- O 100 200 300 400 500 TIME, SECONDS
~
c-E FULL POWER LARGE STEAM LINE BREAK WITH Figure
/ CONCURRENT LOSS OF OFFSITE POWER 15.1.5-S STEAM GENERATOR BLOWDOWN RATES vs TIME 1.9
~
m.
s
=,
2500 , , , i g2 r -
_ e ,
i a
N1500 3
5-3:
S 1000 -- -
I e
w 500 -.
. INTACT STEAM GENERATOR -
- AFFECTED STEAM GENERATOR 0
0 100 200 300 400 500 TIME, SECONDS A
C-E FULL POWER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-AfE /- FEEDWATER FLOW RATES vs TIME 1.10.
500 , , , ,
400 - -
m g' 300 - -
EE 5
g 200 - -
a 5
100 - -
INTACT AND AFFECTED SEAM GENERATORS 0
0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH rigor.
CONCURRENT LOSS OF OFFSITE BREAK 15.1.5-SSE FEEDWAER ENTHALPY vs TIME 1,11
300000 i i i i 325bb00 --
x 5
a k200000
=
E W '
U 150000 E INTACT STEAM GENERATOR e 100000 e
M g AFFECTED SEAM GENERATOR W. 5TW v,
I I I I O
0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure
/77 CONCURRENT LOSS OF OFFSITE POWER 15.1.5-g EEpg/g;1/
-- L_ STEAM GENERATOPs MA SS INVENTORIES vs TIME 1.12
350000 ,. , , ,
300000 - -
250000 - -
a B:
S 200000 - -
lE
<r W
m y150000 - -
I e
W z
~ 100000 -,
[
50000 -- -
0 1 1 I i 0 100 200 300 400 500 TIME, SECONDS C-E. FULL POWER LARGE STEAM LINE BREAK WITH rigure
,/ CONCURRENT LOSS'0F OFFSITE POWER 15,1,5-Sff578,dpl INTEGRATED STM MASS RELEASE THRU BREAKvsTIMg 1,13 _
200 , , , ,
a 160 - -
bi 5
y120 - -
g . -
5 A
N 80 - -
5 M
w fi 40 _ _
0 O 100 200 300 400 500 TIME, SECONDS
-c - E #
FULL POWER [ARGE STEAM LINE BREAK WITH sicure CONCURRENT LOSS OF OFFSITE POWER 15~.1. 5 -
AE'F8hl/ / SAFETY INJECTION FLOW vs TIME 1, 14
2500 i i i i
/ TOP 0F REACTOR VESSEL 2000 - -
1 LIQUID VOLUME N1500 - -
$5 z .
8 g 1000 3
s
~
500 TOP OF HOT LEG 0
O 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSIE POWER 15.1.5-SfE - REACTOR VESSEL LIQUID VOLUME vs TIME- 1.15
10 , , , ,
8 - -
E E
E6 - -
E .
A o_
g4 - -
s E
E i g - -
- I ' ' ' I 0
O 100 200 300 400 500 TIME, SECONDS C-E #
FULL POWER LARGE STEAM LINE BREAK WITH 7; ur, CONCURRENT LOSS OF 0FFSITE POWER 5-R&3FJ.v / / MINIMUM P0ST-TRIP DNBR vs TIME 15'.1[6 l
150 , , , ,
125 - - -
a:
e '
_. 100 -
u.
8 E -
g 75 -- -
5 a.
of km 50 - -
E 8 .
50 - -
0 ' ' -' '
0 100 200 300 400 500 TIME, SECONDS C-E. FULL POWER LARGE STEAM LINE BREAK WITH Figure EfE._ / OFFSITE POWER AVAllABLE CORE POWER vs TIME 15.1.5-2.1
150 i i i I d 125 - -
s b
e h100 n.
d
? -
85 - -
,_. 75 5
W s'
50 d
a w -
g 25 - -
8 C '
0 O 100 200 300 400 500 TIME, SECONDS C - E- FULL POWER LARGE STEAM LINE BREAK WITH - scure
/
- OFFSITE POWER AVAILABLE S .-..u_ CORE HEAT FLUX vs TIME l 5-15ll1
2500 , i i i 2000 --
<c j1500 - - -
u' a
w W IMO - -
c-O ce 500 - - -
o 0 I 'I I '
i 0 100 200 300 400 500 TIME, SECONDS l.
C-E FULL POWER LARGE STEAM LINE BREAK WITH n aure
,/ OFFSITE POWER AVAILABLE 15.1.5-
[ SEEESEll RCS PRESSURE vs TIME 2.3
5%@ i _
i i i CORE 40000 - ~
iis
$ 30000 - -
$20000 -
z b
O 10000 - ~
s u
5 0
-10000 0 100 200 300 4@ 500 TIME, SECONDS C-E ymgogy F i PONA i 15-REACTOR COOLANT FLOW RATE vs TIME g,g
700 i i i- t
. CORE OUTLET m 600. y CORE AVERAGE m
i2 CORE INLET
- s 500 W
M 5
0 0 400 -
E L3 6
" 300 - -
I I I '
200 O 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH rigure OFFSITE POWER AVAILABLE 15-f3LS._.. REACTOR COOLANT TEMPERATURES (A) vs TIME 1551 2
700 , i i i
& 600 - -
m
.AFFECTED SG HOT LEG n
5 AFFECTED SG COLD LEG E 500 - -
h INTACT SG HOT LEG -
m s /
8 4W o ~
h o
INTACT SG COLD LEG h 3% - -
I I i I 200 0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH pigure OFFSITE POWER AVAILABLE 3 REACTOR COOLANT TEMPERATURES (B) vs TIME 15.1.5-2.53
10 , i i i 6.
\-MODERATOR a
8
$2 z
[ D0PPER -
o ll D
-2 - -
\
S TOTAL SAFETY g INJECTION CEA .
~
0 100 200 3 4 500 TIME, SECONDS C-E FULL POWER LARGE SEAM LINE BREAK WITH Figure OFFSIE POWER AVAILABLE Ef85 REACTIVITY CHANGES vs TIME 15'.1' 26 5 -
1200 i i , ,
1000 - -
1 g' 800 --
5 9
x -
(600-3
~
N EE
@ 400 - -
10 E
200 - -
0 I i ' '
0 100 200 300 400 500 TIME, SECONDS i
C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure OFFSITE POWER AVAILABLE 15,1,5_
SEE _ . _ / - PRESSURIZER WATER VOLUME vs TIME 2.7
1200- , i i i 1000 h -
- s E
d 800 -
E l2 y INTACT STEAM GENERATOR -
e 600 - -
l2 W AFFECTED STEAM GENERATOR
$ 400 - -
3 Bi 200 - -
I i i i 0
0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH ricure OFFSITE POWER AVAILABLE 5-SfM STEAM GENERATOR PRESSURES vs TIME 3.5
7000 _i i i i M)00 --
e.>
bi Eco 5000 - -
W d 4000 -
8 E!3000 - -
E e
e g 2000 - -
s AFFECTED STEAM GENERATOR b
w 1000- - -
INTACT STEAM GENERATOR 0
x 1 I i
\ ' '
0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur, 0FFSITE POWER AVAILABLE FM _
STEAM GENERATOR BLOWDOWN RATES vs TIME 15j1~-
g
2500 , , , ,
1 a 2000.
Ui 3
"1 -
m' 1500 - -
W '
d 1000 - -
e
- W S
i 500 -
INTACT SEAM GENERATOR -
\ .
AFFECTED STEAM GENERATOR 7 ' 1 0 1 1 0 100 200 300 400 500 TIME, SECONDS c ~- g
'~
FULL POWER LARGE STEAM-LINE BREAK WITH rigure gg25 / OFFSIE POWER AVAILABLE FEEDWATER FLOW RATES vs TIME 5-15'.1'O 21
500 i -i i i g 400 -
")
2m
>' 300 - -
b g .-
s 5
g200 -
e 100 - -
INTACT AND AFFECTED STEAM GENERATORS .
0 0 100 200 300 400 500.
TIME, SECONDS C-E FULL POWER lARGE STEAM LINE BPsEAK WITH p
/ -OFFSITE POWER AVAILABLE If;u,,
1,5-JEEF8.v / I FEEDWATER ENTHALPY vs TIME 2 11
300000 i i i i
% 250000 - -
x 2
'S N200000
=
5 150000 -
$ INTACT STEAM GENERATOR e
h100000 r
AFFECTED STEAM GENERATOR E
50000 -
/ -
I I I i 0
0 100 200 300 400 500 TIME, SECONDS C-E- FULL POWER LARGE STEAM LINE BREAK WITH rigure OFFSITE POWER AVAILABLE 15'1 5-S STEAM GENERATOR LIQUID M^sSS vs TIME 2. 12
350000 , , i 300000 - -
250000 - -
E a
??
9 u.
200000 - -
- E -
h w
y 150000 5
o h!
z
~
100000 -
50000 -- -
' l ' '
0 0 100 200 300 400 500 TIME, SECONDS t,
C .- E FULL POWER LARGE STEAM LINE BREAK WITH ricure
,/ OFFSITE POWER AVAILABLE
~
E f E fd b / / INTEGRATED STEAM RELEASE vs TIME '15'.1 2I3 5-
200 , i i i o 160 - -
bi E
g'120 - -
d -
E y 80 - -
? r M
5 40 - -
'1 0
0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure
'/ OFFSITE POWER AVAILABLE 15,1,5-EffEF3.vf / ; SAFETY INJECTION FLOW vs TIME 2.14
P 2500 , , , ,
N 2000 -
TOP 0F REACTOR VESSEL -
LIQUID VOLUME y'1500 - -
$5 -
i x 5
8 w 1000 - -
- E -
5 S
500 TOP OF HOT LEG 0 i ' ' '
0 100 200 300 400 500 TIME, SECONDS C-E FULL POWER LARGE STEAM-LINE BREAK WIT;r p;gure 0FFSITE POWER AVAILABLE 15-Aff6 REACTOR \NSSEL LIQUID VOLUME vs TIME 15'1S 2.
150 i i i I 125 - -
e IU E
d 100 - -
2 les
& 75 - -
5 a.
I a_
50 - -
W 8
25 - -
0 0 100 2C0 300 400 500 TIME, SECONDS
'C-E ZERO POWER LARGE STEAM LINE BREAK WITH r; y,,
'/ CONCURRENT LOSS OF OFFSITE POWER 15 1 5-M3?$ff / / CORE POWER vs TIME 3,i
150 i .i i I
.M' d 1 25 - -
m 100 d
m E5 g 75 - -
a m
n_
s' 50 - -
d e -
W 25 - -
8 0^
0 100 200 300 400 500 TIME, SECONDS l
C-E ' ZERO POW 5I< LARGE STEAM LINE BREAK WITH Figure
.S _/ CONCURRENT LOSS OF OFFSITE POWER CORE HEAT FLUX vs TIME 15,1,5-3.2
2500 , , , i k
2000 -
<c G
o- 1500 -
g -:
5?
O -
E-1000 --
U e
SW -
0 0 100 200 300 400 500-TIME, SECONDS
-. c _ g ZERO POWER LARGE STEAM LINE BREAK WITH rigure
.S / CONCURRENT LOSS OF OFFSITE POWER RCS PRESSURE vs TIME 15.1.5-3,3 p
50000 i i i. i '
s 40000 - -
S w -
E
$ 3%@ - -
d 2li
^
8 u -
[z 20000 CORE 5
~
hx / .
0 '
/
O 100 2b 300 400 500
. TIME, SECONDS 4
/
C-E ZERO POWER LARGE SEAM LINE BREAK WITH pigure Efd / CONCURRENT LOSS OF OFFSIE POVER REACTOR COOLANT FLOW-RAE vs TIME 15.1.5-3.4
.s 700 , , , ,
W, d 6W - -
u E CORE OUTLET 5
w 500 -
CORE AVERAGE ;
E 5
8 o
400 - -
x
, 9 o
6@
x3 -
CORE INLET -
3 200
,- .i 0 100 200 300 400 500 i
s
~ '
w ;
.\
d_e ZERO POWER LARGE STEAM LINE BREAK WITH p;
_ _ O' / . CONCURRENT LOSS OF OFFSITE POWER 15'u,,15-
! jf2$[M9f7// I, REACTOR C00!".NT TEMPERATURES IA) vs TIME iQ
- ~
700 , , .i i I%+,'
s 600 -
INTACT SG HOT LEG g
5 \
u
$ 500 INTACT SG COLD LEGS
- s -
b!
!E
. h400 o
1 -
AFF CTED SG
% HOT LEG g.
$300
~
.4
- a::.
/ ,
AFFECTED SG COLD LEGS l
t 1 I i '
g .
200
~~
!- 0 100 200- 300 400 500
) - TIME, SECONDS
,A&
C-E ZERO POWER lARGE STEAM LINE BREAK WITH Figure L , CONCURRENT LOSS OF OFFSITE POVER 15.1.5-S{@ REACTOR COOLANT TEMPERATURES (B) vs TIME 3.5B
10 , i i i MODERATOR 6 - -
c.
<3 g D0PPLER g2 -
5 x
~
C '~ / ~
$~ TOTAL g
$3 SAFE INJECTION '
Q
-6 CEA I I I I
-10 0 100 200 300 400 500 TIME, SECONDS
'C~E ZERO POWER LARGE STEAM LINE BREAK WITH p; u,,
CONCURRENT LOSS OF OFFSITE POWER ff25 -- -
REACTIVITY CHANGES vs TIME 15'.1 e 3o 5-
1200 i i i i
1000 - -
1 y 800 . -
5 S ~
x W
g 600 --
85 N
5 400 - -
G E
O 200 -
0 0 100 200 300 400 500-TIME, SECONDS C-E- rp L
ZERO POWER LARGE SEAM LINE BREAK WITH Figure CONCURRENT LOSS 0F OFFSIE POWER 15.1.5-SSL.576G/,f/
_ PRESSURIZER-WAER VOLUME vs TIME 3.7
1200 -
i i i i 1000 - -
1 G
o_
$ 800 - - -
s
!2 INTACT STEAM GENERATOR I600 _ _
e W
5 400 - -
3 m
W 200 -
AFFECTED STEAM GENERATOR _
I I I i 0
, 0 100 200 300 400 500 TIME, SECONDS C-E ZERO POWER LARGE STEAM LINE BREAK WITH ricure
~
CONCURRENT LOSS OF OFFSITE POWER
-S STEAM GENERATOR PRESSURES vs TIME 15 3g',1. 5 -
7000 i i i I 6000 -
8 m
- E
$ 5000 -- -
W' a
@ 4000 -
i a
3 9
ca 3000 -- -
O .
g AFFECTED STEAM GENERATOR M 2000 -- -
u -
3 W
~' ~
INTACT STEAM GENERATOR
/
1 1 ' '
0 0 100 200 300 400 500 TIME, SECONDS ZERO POWER LARGE STEAM LINE BREAK WITH p
C-E "
/ CONCURRENT LOSS OF OFFSITE POWER If"1 5-SEM- STEAM GENERATOR BLOWDOWN RATES vs TIME j,6
2500 , , ,
a 2000 - -
bi E
y'1500 - -
E S
$ 1000 - -
e i 500 - INTACT STEAM GENERATOR ._
j AFFECTED STEAM GENERATOR-0 100 200 300 400 500 TIME, SECONDS C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF OFFSIE POWER gDWATER FLOW RAES vs IIME 1[Ig5-
450 , , , ,
a.
360 -- -
5 5
?B p 270 -- -
g -
1 5 ,
e 180 -- -
16!
N a
90 INTACT AND AFFECTED STEAM GENERATORS 0' ' ' '
0 100 200 300 400 500 TIME, SECONDS C-E ZERO POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF OFFSIE POWER 15*1 5-Ffd?df_ / FEEDWAER ENTHALPY vs TIME- 3, g
300000 i , , ,
3 250000 -
3 vi idi g 200000 -
z Z '
$ 150000 - -
g a.
m -INTACT STEAM GENERATOR R
g 100000 U '
3 -
$ 50000 -
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15.6.3 STEAM GENERATOR TUBE RUPTURE 15.6.3.1 Steam Generator Tube Rupture Without a Current Loss of Offsite Power 15.6.3.1.1 Identification of Event and Causes The steam generator tube rupture (SGTR) accident is a penetration of the barrier between the reactor coolant system (RCS) and the main steam system and results frbm the failure of a steam generator U-tube. Integrity of the barrier between the RCS and main steam system is significant from a radiological release standpoint. The radioactivity from the leaking steam generator tube mixes with the shell-side water in the affected steam generator.
Prior to turbine trip, the radioactivity is transported through the turbine to the condenser where the noncondensible radioactive materials would be released via the condenser air ejectors. Following reactor trip and turbine trip, with the steam bypass system in its manual mode, th'e steam generator safety valves open to control the main steam system pressure. The operator can isolate the damaged steam generator any time after reactor trip occurs.
The cooldown of the NSSS can then be performed by manual operation of the emergency feedwater and the steam bypass control system (SBCS), and using the unaffected steam generator. The analysis presented herein conservatively -
assumes that operator action is delayed until 30 minutes after initiation of the event.
Diagnosis of the SGTR accident is facilitated by radiation monitors which initiate alarms and inform the operator of abnormal activity levels and that corrective operator action is required. These radiation monitors are located in the air ejector exhaust, steam generator blowdown lines, and turbine and auxiliary building ventilation ducts and stack. Additional diagnostic information is provided by RCS pressure and pressurizer level response indicating a leak and by level response in the affected steam generator.
Experience with nuclear steam generators indicates that the probability of complete severance of the Inconel vertical U-tubes is remote. No such double-ended rupture has ever occurred in a steam generator of this design.
The more probable modes of failure result in considerably smaller penetrations of the pressure barrier. They involve the formation of etch pits or small cracks in the U-tubes or cracks in the welds joining the tubes to the tube sheet.
The most limiting steam generator tube rupture event is for a leak flow equivalent to a double-ended rupture of a U-tube at full power conditions.
15.6.3.1.2 Sequence of Events and Systems Operation Table 15.6.3-1 presents a chronological list of events which occur during the steam generator tube rupture transient, from the time of the double-ended rupture of a steam generator U-tube to the attainment of cold shutdown conditions. The corresponding success paths are given in the Sequence of Events Diagram (SED), Figure 15.6.3-1. The Sequence of Events Diagram may be used together with Figure 15.0-1 (containing a glossary of SED symbols and acronyms) to trace the actuation and interaction of the systems used to mitigate the consequences of this event.
15.6-7
l l
The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. All actions required to stabilize the plant and perform the required repairs are not described here.
The sequence of events and systems operations described below represents the way in which the plant was assumed to respond to the event initiator.
Many plant responses are possible. 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 15.6.3-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the course of the event.
Table 15.6.3-3 contains a matrix that summarizes the utilization of safety systems as they appear in the transient analyses.
The success paths in the Sequence of Events Dagram (Figure 15.6.3-1) are as follows:
Reactivity Control:
The pressurizer pressure decrease results in the generation of a CPC low pressure boundary trip and the CEAs drop into the core. Subsequently, the RCS pressure decreases more rapidly and a Safety Injection Actuation Signal (SIAS) is generated on low pressurizer pressure. As a result, additional negative reactivity is added to the system, in the form of borated water from the refueling water tank. Once the plant parameters have been stabilized, the operator adjusts the boron concentration to insure that a proper negative reactivity shutdown margin is achieved prior to cooldown. The boron concentra-tion is adjusted by manially throttling the HPSI discharge valves to replace RCS volume shrinkage.
Reactor Heat Removal:
During the initial part of the transient, reactor heat removal is accomplished in the normal manner. Additional cooling capability is available through the injection of relatively low enthalpy RWT water, on the generation of the SIAS. On the initiation of the cooldown phase, the operator secures the Reactor Coolant Pumps (RCPs) in the loop associated with the affected steam generator to minimize heat transfer to the generator. Following the cooldown phase, the Shutdown Cooling System (SCS) is manually actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia, respectively. This system provides sufficient cooling flow to cool the RCS to cold shutdown.
Primary System Integrity:
Prior to initiating cooldown procedures, the operator must reestablish the pressurizer water level. During the cooldown phase, the HPSI pump discharge valves are throttled to control RCS pressure.
When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the SITS to reduce their pressure and will then isolate them.
15.6-8
Secondary System Integrity:
Following the generation of a turbine trip on reactor. trip, the Main Feedwater Control System (F U ) enters the Reactor Trip'0verride (RTO) mode and reduces main feedwater. flow to 5% of nominal full power flow. Since the
~
Steam Bypass Control System (SBCS) is assumed to be in manual mode with cll bypass valves closed, the Main Steam Safety Valves (MSSVs) open to limit secondary system pressure there by removing the heat generated and/or stored in the core and the RCS. Following closure of the MSSVs, the FWCS is prevented f' rom over-feeding the steam generators by the High Level Override (HLO) which terminates feedwater flow until the steam generator level decreases to its nominal value. Due to the primary-to-secondary flow, the main feedwater flow to the affected steam generator is terminated before that of-the unaffected steam generator. This time difference may be used by the operator to identify the affected steam generator. Once this has been accompF shed, the operator will manually isolate the damaged steam generator and will initiate cooldown using main feedwater, the SBCS, and the unaffected steam generator. .
When steam pressure decreases to a point where the main feedwater pump can no longer be used, the operator secures the main pumps. Cooldown is continued by utilizing one feedwater pump designated as " auxiliary" and intended for -
normal startup and shutdown of the plant in conjunction with the SBCS. The
-operator may let the ESFAS regulate the feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions.
See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Systems.
Radioactive Effluent Control:
A Containment Isolation Actuation Signal (CIAS) is generated subsequent to the SIAS. CIAS isolates various systems to reduce or terminate radioactive releases. CIAS actuates primary and containment isolation equipment.
Other actions may be initiated by B0P systems. See Applicant's FSAR for details.
Upon identificatio~n of the affected steam generator, the operator isolates the steam generator and shuts off the reactor coolant pumps in that loop to minimize release from the affected generator.
15.6.3.1.3 Analysis of Effects and Consequences 15.6.3.1.3.1 Core and System Performance A. Mathematical Model The thermalhydraulic response of the Nuclear Steam Supply System (NSSS) to the steam generator tube rupture without a concurrent loss of offsite power was simulated using the CESEC III computer program described in Reference 27. The thermal margin on DNBR in the reactor core was determined using the TORC computer program described in Section 15.0.3 (Reference 18) with the CE-1 critical heat flux correlation described in CENPD-162 (Reference 19).
r 15 5-9 -
B. Input Parameters and Initial Conditions The initial conditions and parameters assumed in.the analyses of the system response.to a steam generator tube rupture without a concurrent loss of offsite power are listed in Table 15.6.3-4. Additional discussion on the input parameters and the initial conditions are provided in Section 15.0. Conditions were chosen to maximize the primary to secondary mass releases during the SGTR transient. This, in turn, leads to the most conservative predictions of radiological releases.
The initial reactor operating conditions were varied over the operating space given in Table 15.0-5 to determine the set of conditions which would produce the most adverse consequences following a steam generator tube rupture without a concurrent loss of normal ac power. Various ccmbinations of initial operating conditions were considered. These included, initial core inlet temperature, initial power level', initial RCS pressure, initial core coolant flow rate, initial pressurizer liquid level, initial steam generator liquid level, and fuel rod gap thermal conductivity. A scram reactivity consistent with the axial power distribution was employed in the parametric studies. Decreasing the initial core inlet temperature increases the primary to secondary leak rate and integrated leak, but reduces the releases via the main _.
steam safety valves. Since the steam generator pressure and temperature would be initialized at lower values compatible with the lower core inlet temperature, the steam generator pressore may not increase enough to challenge the main steam safety valves. Decreasing the RCS pressure hastens the low pressurizer pressure reactor trip and results in lower releases due to a lower leak rate. Increasing the core inlet flowrate results in a lower enthalpy for the fluid entering the steam generator, resultant increased leak rate, and higher releases from the main steam safety valves. Thus, the parametric studies indicated that the maximum total-mass release is obtained when the transient is initiated with the maximum allowed RCS pressure, maximum initial pressurizer liquid volume, maximum initial steam generator liquid volume, maximum core power, maximum core coolant flow, nominal core coolant inlet temperature, and a low fuel rod gap thermal conductivity.
The radiological consequences for the SGTR transient is also dependent on the break size. For break sizes resulting in a reactor trip during the first 30 minutes of the accident, the initial leak rate decreases from that value equivalent to a double-ended rupture, and the offsite dose also decreases due to the drop in the integrated leak. The decrease in break size also delays the time of reactor trip. As the break size is decreased further, the integral leak is reduced for the 30-minute operator action interval and the radiological consequences will be less~ severe. Therefore the most adverse break size is the largest assumed break of a full double ended rupture of a steam generator tube.
C. Results The dynamic behavior of important NS$$ parameters following a steam
, generator tube rupture is presented in Figures 15.6.3-2 to 15.6.3-17.
15.6-10
For a double-ended rupture, the primary to secondary leak rate exceeds the capacity of the charging pumps. As a result, the pressurizer pressure gradually decreases from an initial value of 2400 psia. The primary to secondary leak rate and drop in pressurizer water level causes the third CVCS charging pump to turn on. Even with all three CVCS charging pumps on line the pressurizer pressure and level continue to drop. This results in the pressurizer heaters being de-energized at 560 seconds. At 1148 seconds a reactor trip signal is generated due to exceeding the CPC low pressure boundary of 1785 psia. The pressuri2er empties at approximately 1151 seconds. At 1181 seconds a safety injection actuation signal is generated, and by 1231 seconds the safety injection flow is initiated. After the pressurizer empties, the reactor vessel upper head begins to behave like a pressurizer, and controls the reactor coolant system pressure until the pressurizer begins to refill at approximately 1447 seconds. Due to flashing caused by the depressurization, and the boiloff due to metal structure to coolant heat transfer, small amounts of voids form in the reactor vessel upper head at about 1151 seconds. Consequently, the RCS pressure begins to decay at a lower rate at this time. However, under the combined action of safety injection and charging flows, and reduced primary to secondary leakage, the upper head voids completely collapse at about 1447 seconds. Prior to this time, the RCS pressure begins to slowly increase helping to collapse the reactor vessel upper head voids. The pressurizer water level is reestablished at about the same time due to the net mass influx which increase the RCS inventory.
Following reactor trip and with turbine bypass assumed to be unavailable (i.e., in the manual mode), the main steam system pressure increases until the main steam safety valves open at 1209 seconds to control the
-main steam system pressure. A maximum main steam system pressure of 1283 psia occurs at 0.1 seconds after the M55Vs open. Subsequent to this peak in the pressure, the main steam system pressure decreases, resulting in the closure of the main steam safety valves at 1316 seconds.
Prior to reactor trip, the feedwater control system is assumed to be in the automatic mode and supplies feedwater to the steam generators such that steam generator water levels are maintained. Following reactor trip, the feedwater flow decreases to approximately 5% of the full power flow rate. Since the steam flow out of the steam generators is less than this feedwater flow, the liquid inventory in the steam generators gradually increases. At 1690 seconds a HLO mode terminates feedwater flow to the damaged steam generator. At 1778 seconds a HLO mode terminates feedwater flow to the intact steam generator.
After 1800 seconds, the operator identifies and isolate the affected steam generator by closing the main steam isolation valves and by securing the reactor coolant pumps in the affected loop. The operator then initiates an orderly cooldown via the steam bypass system and the condenser, and with manually-controlled feedwater flow to the unaffected steam generator. After the pressure and temperature of the reactor coolant are reduced to 400 psia and 350 F respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator.
.15.6-11 - -
The maximum RCS and secondary pressures do not exceed 110% of design pressure following a steani generator tube rupture event without concurrent loss of offsite power, thus, assuring the integrity of the RCS and main steam system. The minimum DNBR of 1.22 indicates no violation of the fuel thermal limits (see Figure 15.6.3-17 ).
Figure 15.6.3-12 gives the main steam safety valve integrated flow versus time for the steam generator tube rupture event without concurrent loss of effsite power. At 1800 second' when operator action is assumed, no more than 6617 lbm of steam from the damaged steam generator and 6609 lbm from the intact steam generator are discharged via the main steam safety valves. Also, during the same time period, approximately 75,275 lbm of primary system fluid is leaked to the damaged steam generator. Subsequently, the operator begins a plant cooldown at the technical specification cooldown rate (100 F/hr) using the intact steam generator, the steam bypass system, the feedwater system, and the condenser. For the first twg hours following the initiation of the event, a total of 6.516 x 10 lbm (5.58 x 10 lbm) through the turbine and 936,000 lbm through the bypass system) of steam flows to the condenser from the steam generator. For the two to eight hour cooldown period, an additional 907,000 lbm of steam is discharged through the bypass system.
15.6.3.1.3.2 Radiological Consequences A. Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture without a coincident loss of offsite power assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power. Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of low pressurizer pressure at approxi-mately 1148 seconds after the event initiation. The reactor trip -
automatically trips the turbine.
, Subsequent to reactor trip the steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator, i.e., the steam generator which experiences tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. At this time, the affected steam generator is effectively isolated and, thereafter, no steam or activity is assumed to be released from the affected steam generator. After 1800 seconds the operator initiates a plant cooldown at the technical specification cooldown rate (100 F/hr) using the unaffected steam generator, steam bypass system, feedwater system, and the condenser.
The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary system activity as well as primary system activity leaked from the tube break. The inventory of iodine and noble gas fission product activity 15.6-12 __
---M available for release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core, and the mass of steam discharged to the environment. Conserva-tive assumptions are made for all these parameters.
1 B. Assumptions and Conditions
-The following assumptions and parameters are employed to determine the activity-releases and offsite doses for a steam generator tube rupture (SGTR).
- 1. Accident doses are calculated for two different assumptions: (a) assumes a generated iodine spike (GIS) coincident with the initia-tion of the event and (b) assumes a pre-accident iodine spike (PIS).
- 2. Technical specification limits are employed in the dose 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 accider.t, the affected-steam generator 4
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-accident 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 steam 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.
- 9. 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 1 (Maximum fraction 2 5%).
- 10. A partition coefficient of 100 is assumed between the steam generator water and steam phases.
- 11. The total amount of primary-to-secondary leakage through the rupture is 75,275 lbm. -
- 12. -The two hour steam flow to the condenser is 6.516 x 106 lbm, and an additional.907,000 lbm of steam flows to the condenser during the two to eight hour time period.
15.6-13 L
- 13. Theatmgspherigdispersionfactorsemployedintheanalysesage:
2 x lg sec/m for the exclusion area boundary and 1.5 x 10 sec/m for the low population zone.
C. Mathematical Model The mathematical model employed to analyze the activity released during the course of the transient is described in Section 15.0.4.
D. Results -
The two-hour exclusion area boundary (EAB) inhalation doses and the eight-hour low population zone (LPZ) boundary inhalation doses for both the generated iodine spike (GIS) and the pre-existing iodine spike (PIS) are presented in Table 15.6.3-5. The calculated EAB and LPZ doses are well within the acceptance criteria.
15.6.3.1.4 Conclusions The radiological releases calculated for the SGTR event without a concurrent loss of offsite power are well within the 10CFR100 guidelines. The RCS and secondary system pressures are well below 110% of the design pressure limits, thus, assuring the integrity of these systems. Additionally, no violation of the fuel thermal limits occurs, since the minimum DNR remains above the 1.19 value throughout the duration of the event.
The plant is maintained in a stable condition due to automatic actions, and after thirty minutes, the operator employs the plant emergency procedure for the steam generator tube rupture event to cool down the plant to shutdown cooling entry conditions.
15.6-14
15.6.3.2 Steam Genera'.or Tube Rupture With a Concurrent loss of Offsite Pow q 15.6.3.2.1 Identification of Event and Causes The significance of.a steam generator tube rupture accident is described in Section 15.6.3.1.1. 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 ex'perience a loss of load, normal feedwater flow, forced reactor coolant flow, condenser vacuum,~and steam generator blowdown system.
The loss of offsite power subsequent to the time of reactor trip and turbine /
generator trip is assumed in the analysis, since it produces the most adverse effect on the radiological releases. The plant is operating at full power for a period of approximately 20 minutes before the consequences of the primary-to-secondary leak cause the reactor trip. Thus, during this time period the radioactivity concentration in the steam generator increases before the main steam safety valves open, releasing radioactive materials to the atmosphere.
15.6.3.2.2- Sequence of Events and Systems Operation Table 15.6.3-6 presents a chronological list of events which occur during the steam generator tube rupture event with a loss of offsite power, from the time of double-ended rupture of a steam generator U-tube to the attainment of cold shutdown conditions. The corresponding success paths are given in the sequence of events diagram (SED), Figure 15.6.3-18. The SED may be used together with Figure 15.0-1 (containing a glossary of SED symbols and acronyms) to trace the actuation and interaction of the systems used to mitigate the consequences of this event. Additionally, Table 15.6.3-7 contains a matrix which describes the extent to which normally operating plant systems are assumed to functi;n during the course of the event. The utilization of safety systems as they appear in the transient analysis is summarized by the matrix contained in Table 15.6.3-8.
Prior to reactor trip, the systems and reactor operation are identical to that described in Section 15.6.3.1.2. As a result of the reactor trip, the turbine / generator trips within one second after the CPC low pressure boundary reactor trip signal. Subsequently, offsite power is assumed to be lost due to grid instability. A 3 second delay between the time of turbine trip and the time of loss of offsite power is conservatively assumed in the analysis, based on the discussion that follows.
The loss of a power generating unit causes frequency deviations in the electical power grid which normally operates at 60 Hz. Under certain conditions the resulting grid instability will cause loss of offsite power to that unit. The degree of instability is characterized by the rate of grid frequency degradation which is dependent on the magnitude of the load mismatch and the physical parameters of the grid. The physical response of the grid is dependent on the available spinning reserve and the stiffness of-the grid, i.e., the ability to damp out frequency oscillations through load damping. Load shedding is also utilized to restore the balance between load and power generation and to return-the grid frequency to 60 Hz. When the corrective action is not sufficient to avert frequency decradation, loss'of off-site power to the plant can occur as a result of 15.6-15
that plant. tripping off line. Most plants are automatically disconnected from the grid between 56-58 Hz, to prevent underfrequency damaga to the plant components. For System 80_ plants, a frequency of 57.6 Hz is taken as the setpoint at which a loss of offsite power occurs.
In order to determine the conservative lower bound for the time delay between turbine trip and loss of offsite power, the grid system for the Florida Penninsula was employed. This grid can tie into only the Georgia and Alabama grid systems, which can make up only 400 MWe through the trans-mission lines to Florida. Therefore, the Florida grid becomes an " electrical island" for a generation deficiency caused by the loss of a 1300 MWe unit.
On the curves of grid frequency response for this grid system, the effects of a generation deficiency caused by the tripping of a System 80 plant was superimposed. Based on this evaluation, a 3.1 seconds time lag between turbine trip and loss of offsite power was calculated. This time delay is a conservative lower bound since the evaluation assumed:
(1) No credit for spinning reserve and load she'dding, (2) The Florida grid " island" conditions (no support from neighboring grid sytems),
(3) Loss of a System 80 plant as a 10% generation loss which is a much higher percentage than the actual loss (less than 3.5%), and (4) Loss of offsite power at 57.6 Hertz for all System 80 plants.
Subsequent to reactor trip, stored and fission product decay energy must be dissipated by the reactor coolant and main steam systems. In the absence of forced reactor coolant flow, convective heat transfer into and out of the reactor core is supported by natural circulation reactor coolant flow.
Initia .f, the residual water inventory in the steam generators is used and the resultant steam is released to atmosphere via the main steam safety valves. With the availability of standby power, emergency feedwater is ,
automatically initiated on a low steam generator water level signal. The operator can determine which steam generator has the tube rupture based on information from the radiation monitors 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 emergency feedwater system and the atmospheric steam dump valves of the unaffected steam generator any time after reactor trip occurs. The analysis presented herein conservatively assumes operator action is delayed until 30 minutes after first indication of the event.
The primary source of the emergency feedwater is the condensate storage tank. The capacity of the storage tank is 300.000 gallons which is sufficient feedwater to maintain the plant at hot standby for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The condensate storage tank is provided with an atmospheric vent to maintain atmospheric pressure inside the tank 4 The maximum condensate radioactivity concentration is 0.1 pCi/lbm (2.2 x 10 pCi/gm) dose equivalent I-131.
15.6-16 L
15.6.3.2.3- ' Analysis of Effects and Consequences 15.6.3.2.3.1 Core and System Performance
-A. Mathematical Model The mathematical used for evaluation of core and system performance is
-identical to that described in Section 15.6.3.1.3.1.
B. Input Par'ameters and Initial Conditions-The input parameters and initial conditions used for the evaluation of core and_ systems performance are similar to those described in Section 15.6.3.1.3 and are given in Table 15.6.3-9. Both the initial core mass flow rates and the one pin radial peaking factor were chosen to:
(1) maximizu the primary-to-secondary integrated leak, and the steam releases through the main steam safety valves, and (2) at the same time, obtain a simultaneous reactor trip on a low DNBR (=1.19) as well as a low pressurizer pressure. Consequently, a slightly lower core mass flow rate (104% instead of 116%) as well as a slightly lower radial. peaking factor (1.53 instead of 1.55) were employed in the analysis. -
C. Results The dynamic behavior of important NSSS parameters following a steam generator tube rupture with a loss of normal ac power are presented in Figures 15.6.3-19 through 15.6.3-34.
Prior to reactor trip, the dynamic behavior of the NSSS following a steam generator tube rupture with a loss of offsite power is similar to-that following a steam generator tube rupture without a loss of offsite power which is described in Section 15.6.3.1.3. At about 1187 seconds after the initiation of the tube rupture the CPC low pressure ,
boundary of 1785 psia is reached, resulting in a reactor trip signal.
Subsequent to the reactor trip, the RCS pressure begi.es to decrease rapidly, and the pressurizer empties at about 1201 seconds due to the continued primary-to-secondary leak. After the pressurizer empties, the reactor vessel upper head begins to behave like a pressurizer and controls the RCS pressure response. Due to the loss of offsite power, the reactor coolant pumps begin to coast down reducing the gore coolant flow rate, and the mass flow into the upper head region. This region becomes thermalhydraulically decoupled from the rest of the RCS, an due to flashing caused by the depressurization and boiloff from the metal structure to coolant heat transfer, voids form in this region at about 1196 seconds. The void formation is enhanced by the decoupling effect, since the RCS pressure reduction due to primary system cooling is felt in this region, while the RCS temperature reduct'on is not.
The significant. impact of voids in the upper head region is a slower RCS pressure decay resulting in the generation of the safety injection actuation signal ($1AS) at 1613 seconds. The High Pressure Safety Injection (HPSI) pumps begin delivery of Jafety injection fluid to the 15.6 RCS in about 50 seconds after the SIAS, and as a result, the upper head voids begin to collapse at about 1677 seconds.
Following turbine trip and loss of offsite power, the main steam system pressure increases until the main steam safety valves open at about 1197 seconds to control the main steam system pressure. A-maximum main steam system pressure of 1310 psia occurs at about'1205 seconds. Subsequent to this peak in pressure, the main steam system pressure decreases resulting in the closure of the safety valves at 1721 seconds.
Prior 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 1713 seconds. Subsequently, at about 1758 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 pressure and temperature are reduced to 400 psia and 350 F, respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator.
The reduction in the RCS pressure due to the loss of primary coolant through the ruptured steam generator tube results in a reduction in the thermal margin to DNB (see Figure 15.6.3-34). The transient minimum DNBR of 1.19 occurs at the time of reactor trip. The DNBR shows an increasing trend after reactor trip due to the rapidly decreasing heat flux. The RCPs do not begin their normal coastdown until after -
the loss of offsite power three seconds after turbine trip. However, there is a slight decrease in the core flow during the three seconds immediately after turbine trip and prior to the-loss of offsite power due to decreasing pump speed caused by frequency degradation (approxi-mately 1 Hertz /second) of the electrical grid. .The resultant calculation demonstrates that no violation of the fuel thermal limits occurs, since the minimum DNBR stays above the value of 1.19 throughout the transient.
The maximum RCS and secondary pressures do not exceed 110% of design pressure 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.
Figure 15.5.3-29 gives the main steam safety valve integrated flow rates versus time for the steam generator tube rupture event with a loss of offsite power. At 1800 seconds, when operator action is assumed, no more than 54,936 lbm of steam from the damaged steam generator and 54,730. Ibm from the intact steam generator are discharged 15.6-18
via the main steam safety valves. Also, during the same time period approximately 80,500 lbm of primary system mass is leaked to the damaged steam generator. Subsequently, the operator begins a plant cooldown at the technical specification cooldown rate (100 F/hr) using the intact steam generator, the atmospheric dump valves,and emergency feedwater system. Forthefirsgtwohoursfollowingtheinitiationof the event, a total of 5.76 x 10 lbms of steam flow to the condenser through the turbine (up to the time of loss of offsite power), and about 843,300 lbms of steam are released to the environment through the atmospheric dump valves. gorthetwotoeighthourcooldown period an additional 1.81 x 10 lbms of steam are released via the atomspheric dump valves.
15.6.3.2.3.2 Radiological Consequences A. Physical Model .
The evaluation of the radiological consequences of a postulated steam generator tube rupture assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power and a loss of offsite power three seconds after turbine trip. Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of low pressurizer pressure at approximately 1187 seconds after the event initiation.
The reactor trip automaticaly trips the turbine.
The steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator, i.e., tne steam generator which experiences tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. At this time, the affected steam generator is effectively isolated, and thereafter, no steam or activity is assumed to be released from the affected steam generator. After 1800 seconds, the operator initiates a plant cooldown at the technical specification cooldown rate (100 F/hr) using the unaffected steam generator, atmospheric dump valves, and the emergency feedwater system.
The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary activity as well as primary system activity leaked from the tube break. The inventory of iodine and noble gas fission product activity available for release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core, and the mass of steam discharged to the erivironment. Conservative assumptions are made for all these parameters.
B. Assumptions and Conditions The assumptions and parameters employed for the evaluation of radiological releases are identical to those described in Section 15.6.3.1.3.2 with the following exceptions and/or additions.
15.6-19 l
4
- 1. For steam release through the atmospheric dump valves, a decontamin-ation. factor (DF) of 1 is assumed.
- 2. The total amount of primary-to-secondary leakage through the rupture is 80,500 lbm.
- 3. The steam flow through the condenser is 5.76 x 106 lbms. The halfhourtotwohoursteamflowthroughtheatmgsphericdump l valves is 843,300 lbms. An additional 1.81 x'10 lbms of steam are discharged to the environment through the atmospheric dump valves during the two to eight hour time period.
C. Mathematical Model The mathematical model employed in the evaluation of the radiological consequences during the course of the transient is described in Section 15.0.4.
D. Results i The two-hour exclusion area boundary (EAB)-and the eight-hour low population zone (LPZ) boundary inhalation doses for both the event -
-generated iodine spike (GIS) and the pre existing iodine spike (PIS) are presented in Table 15.6.3-10. The calculated EAB and LPZ doses are well within the acceptance criteria.
15.6.3.2.6 Conclusions The radiological releases calculated for the SGTR event with a loss of offsite power are well within the 10CFR100 guidelines. The RCS and secondary system pressures are well below the 110% of the design pressure limits, thus, assuring the integrity of these systems. Additionally, no violation of the fuel thermal limits occurs, since the minimum DNBR remains above the 1.19 value throughout the duration of the event.- ,
Voids form in the reactor vessel upper head region during the transient, due to the thermal hydraulic decoupling of this region from the rest of the RCS. The upper head region liquid level remains well above the top of the hot' leg throughout the transient. Therefore, natural circulation cooldown is not impaired during the transient. -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 cool down the plant to shutdown cooling entry conditions.
i i
- j. 15.6-20
TABLE 15.6.3-1 (Sheet 1 of 2)
SEQUENCE OF-EVENTS FOR THE-STEAM GENERATOR TUBE RUPTURE Time Setpoint Success (Sec)-- Event. or Value Path-0.0 Tube Rupture Occurs --
30.0 Third CharCi ng Pump Started, feet -0.75 Primary below program level System Integrity 30.0 Letdown Control Valve Throttled ' 0.75 Primary-Back to Minimum Flow, feet below System program level 53.8 Backup Heaters Energized, psia 2360 Primary System -
Integrity 560.0 Pressurizer Heaters De energized 400 due to Low3 Pressurizer Liquid Volume, ft 1148 CPC Low Pressure Boundary Trip 1785 Reactivity.
Signal, psia ' Control Feedwater Flow Starts Ramp Down to 5% of Initial Full power Flow CEAs Begin to Drop Reactivity
~
1149 --
~
Turbine Trip: Stop Valves Start --
Control to Close~ --
Secondary System Integrity 1151 Pressurizer Empties -- --
1152 Turbine Stop Valves Closed --
Secondary System Integrity 1181 Safety injection Actuation Signal, 1578 Reactivity psia Control and Reactor Heat Removal 1181- Letdown Isolation Valves Closed on --
Primary SIAS System Integrity
TABLE 15.6.3-1 (Cont'd.) (Sheet 2 of 2)
SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE l
( Time Setpoint Success I (Sec) Event or Value Path 1209 Main Steam Safety Valves Open, psia 1282 Secondary System Integrity 1210 Maximum Steam Generator Pressure, 1283 psia 1231 Safety Injection Flow Intiated --
1316 Main Steam Safety Valves Close, psia 1218 Secondary System Integrity 1447 Pressurizer begins to refill --
1690 HLO Mode Terminates Feedwater Flow 80 Secondary to Damaged Steam Generator, % wide System range Integrity 1778 HLO Mode Terminates Feedwater Flow 80 Secondary to Intact Steam Generator, % wide System range Integrity 1800 Operator Isolates the Damaged Steam --
Reactor Heat Generator and Initiates Plant Cooldown Removal at 100 F/hr for the 1.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> time period 28,800 Shutdown Cooling Entry Condition 400/350 Reactor Heat are Assumed to be reached RCS Removal '
Pressure, psia /RCS Temperature, F
___ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - - - - - - - - _ - - - - - - - - - - - _ - _ - -]
j TABLE 15.6.3-2.(Sheet 1 of 2) 1
- DISPOSITICri 0F f;0R ALLY ODEPATI;;G SYSTEMS FOR -
THE STEAM GENEPATOR TUBE RUPTURE 6o g,k
- G% G
's 'e Ys n 4 / '
1 Yr Y' $ ~^ Y
\'b'c-v s
67 6 c a/
6 .n .
'eg \
(95(f ~,Af o(f>
Q tdQ'0g$5 0 0, by 9
SYSTEM \c $j \y\' *e 1
c e
d
.e 1
- 1. Main Feedwater Centrol System /
l
- 2. Main Feedwater Pump Turbine Control System * / j
- 3. Turbine-Generator Control System- /
l I
- 4. Steam Bypass Control System / I 3
Fressurizer Pressure Control System (e
S.
- 6. Pressurizer Level Control System
/
/
- 7. Control Element Drive Mecnanism Control System /
- 8. Reactor Regulating System /
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
Chemical and Volume Centrol System / i 11.
l
- 12. Secondary Chemistry Control System * / 1
- 13. Condenser Evacuation System * /
- 14. Turbine Giand Sealing System * /
t
- 15. Nuclear Cooling Water System.* / !
- 16. Turbine Cocling Water System- / !
1
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * /
- 19. Circulating '.-later System * / f
- 20. Spent Fuel Fool Coolir.g ar.d Clean-Up System * / !
i
- 21. !!cn-Class 1E (!;cn-ESF) A.C. Pcwer* / ,
22.
hl
- Balance-of-Plant Systems - ->
I 't.
.._.__..--___J
TABLE 15.6.3-2 (CONTIflUED) (Sheet 2of2)
DISPOSITIC:! 0F MORMALLY OPERATI.':G SYSTEMS FOR ,
THE STEAM GE!!ERATOR TU3E RUPTURE
~
\
' ~
s *%
>+, %.'Q G e
.- va 6,,
"9,$p /
~* 6,
[bY9 Y ,Ya./'
a 'O c,, 9 c,, s , , s $'s,,:.o. #'C.? % s, O?ol0'h,Cf,%o Y
'Q Oc s ,
, '%'Q % ,e
.c. ,o
- SYSTEM c
- 23. Non-Class 1E D.C. Power- /
- 24. Class 1E D.C. Power * /
NOTES: ,
- 1. Portions of this system are isolatec, either automatically (see applicant's SAR) or manually _,
by the operator once ne cetermines which steam generator contains the ruptured tube.
I l
i
'Calance-ef-Flant Systccs l ii
TABLE 15.6.3-3 i
e UTILIZATICM OF SAFETY YSTEMS
- FOR THE STEAM GENERATOR TUBE RUPTURE 0 #
?, 4,Q 'o
.- '? 9 Q ,+ '
x,o s~ se,+> g'c ?'r,
^ e,^ 0.o #+r,f, +O e
% #,0 ' ',, Q,'e s,e SYSTEM g A C, b s
- 1. Reactor Protection System / lj
- 2. DNBR/LPD Calculator L
- 3. Engineered Safety Features Actuation Systems / l
- 4. Supplementary Protection System j
- 5. Reactor Trip Switch Gear / l
- 6. Main Steam Safety Valves * /
- 7. Primary Safety Valves
- 8. Main Steam Isolation System * / 1
- 9. Emergency Feedwater System * / h'i I
- 10. Safety Injection System / r
- 11. Shutdown Cooling System /
- 12. Atmospheric Dump Valve System * /
- 13. Containment Isolation System
- i 14. Containment spray System *
- 15. Iodine Removal System
- l l
- 16. Containment combustible Gas Control System
- j
- 17. Diesel Generators and Su: port Systems'
- 18. Component (Essential) Cooling Water System * /
i
- 19. Station Service 'a'ater System * /
l NOTES: ;
- 1. The operatcr mar.ually isciates the affected i steam generator.
.l e
- Balance-of-Plant Systems - ! h
f; '
s ,
, TABLE 15.6.3 ASSUMPTIONS AND INITIAL CONDITIONS FOR THE STEAM GENERATOR TUBE RUPTURE Parameter: Assumed Value Core Power Level, MWT_ 3876 Core Inlet Coolant Temperature, F 565 Reactor Coolant System Pressure, psia 2400 Core Mass Flow Rate, 106 1mb/hr 183.1 One' Pin Integrated Radial Peaking Factor, 1.55 with Uncertainty .' '
Steam Generator Pressure, psia ' 1020 Moderator Temperature Coefficient, 10 ~4 ap/ F -3.5 Doppler Coefficient Multiplier 1.15 CEA Worth at Trip, % ap (most reactive CEA . -10.0
- ,; fully withdrawn)
I' O,,
N, A
e
n;
- s,
+ , ;di- "k .\ s:. ,': i y- ,
3 ,; .g,,.,,.
,y 4 '
Y- .,, f pb'. .. } f ,
~'
, )f ,
/
L " ;j * ';) ;
a::
- J p> =
i . TABLE.'15;6.3-5 y r q.
o\
4
", -RADIOLOGICAL CONSEQUENCES OF THE
.d STEAM GENERATOR TUBE RUPTURE 2, 7
, Lj -l ., _ ' Location .Offsite Doses, Rems
[{ GIS PIS-7 ,
.t, .; 1. > Exclusion Area Boundary
'l ' - A q 0-2 hr Thyroid 2. 0.- 2.7-jj; -
I#~
- 2. : Low Population Zone
-Outer Boundary-0-8 hr Thyroid 0.19 0.21 1-9 4
\
i k
k-e
, 1. -
J' /.%.
- w .
j h- t- ,
er 4 ,...
1 ,e r I
s , ..w J'
. a e
4
'/
l>
.e.
TABLE 15.6.3-6 (Shee+. 1 of 2)
SEQUENCE-CF EVENTS FOR A STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF 0FFSITE POWER Time Setpoint Success (Sec)
-Event or Value Path 0.0 . Tube Rupture Occurs --
30.0 Third Charging Pump-Started, -0.75 Primary System feet below program level Integrity 30.0 L'etdown Control Valve Throttled Primary System Back to Minimum Flow, feet below Integrity-program level -0.75 53.'8 Backup Heaters Energi::ed, psia 2360 Primary System Integrity -
560.0 Pressurizer Heaters De-energized 400 due to Low3 Pressurizer Liquid Volume, ft 1187 CPC Low Pressure Beundary Trip 1785 Reactivity Signal, psia Control 1188' Turbine / Generator Trip: Stop --
Secondary. System Valves Start to-Close Integrity CEAs Begin to Drop --
Reactivity Control Turbine Stop Valves' Closed
~
1191 --
Secondary System Loss of Offsite Power --
Integrity-1197 LH Main Steam Safety Valves 1282 Secondary System open, psia Integrity 1197 -RH Main Steam Safety Valves 1282 Secondary Sytem open, psia Integrity
'1200 Pressurizer Empties --
1205 Maximum Steam Generator Pressures 1310 Both Steam Generator, psia 1563 Safety Injection Actuation Signal, 1578 Reactivity Control' psia
. . - - . ~ _ - _. .. .,.
TABLE 15.6.3-6 (Sheet 2 of 2)
SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF 0FFSITE POWER Time Setpoint Success (Sec) Event or Value Path 1563 Letdown Isolation Valves Closed --
Primary System on SIAS Integrity 1613 Safety Injection Flow Initiated --
Reactivity Control Reactor Heat Removal 1714 Emergency Feedwater Actuation 19.76 Secondary System on Low Steam Generator Level Trip Integrity Signal, ft above tube sheet 1721 Main Steam Safety Values Closed, 1218 Secondary System psia Integrity 1759 Emergency Feedwater Flow Begins --
Secondary System Integrity 1800 Operator Isolates the Damaged --
Reactor Heat Steam Generator and Initiates Removal Plant Cooldown 28,800 Shutdown Cooling Entry Conditions 400/350 Reactor Heat are Assumed to be Reached RCS Removal Pressure, psia / Temperature, F u
TABLE 15.6.3-7 .(Sh:et 1 of 2)
. DISPOSITION OF NORMALLY OPERATIllG SYSTEMS FOR THE STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF 0FFSITE POWER
~
\
> #e%k:t &
%-;:.)'e, t.,
'c.h +% wc ?;
e y k;$.
- 45. '
- b $
c fg
.\ 'k,};. g)3 . 'a gjh.A.f,C.o
- g0 Q
'9
$, QYY,5 # ' %,. #^
/ p 9
SYSTEM 'gp * \" p e
4
- 1. Main Feedwater Control System <
- 2. !!ain Feedwater Pump Turbine Control Systcm* /
fli
- 3. Turbine-Generator Control System * / I!
- 4. Steam Eypass Control Syste. / I
(
- 5. Pressurizer Pressure Control System v' l t; -
- 6. Pressurizer Level Control System y j
- 7. Control Element Drive Mechanism Control System v
- 8. Reactor Regulating System /
h
- 9. Core Operating Limit Supervisory System / 1
- 10. Reactor Coolant Pumps / li
- 11. Chemical and Volume control System v [
- 12. Secondary Chemistry control System
- v 1 l
l
- 13. Condenser Evacuation System * ./ t
- J
- 15. tiuclear Coolinc Water Sys:cm* / [
- 16. Turbine Cooling Water Systcm* v' !!
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities
- v'
]
- 19. Circulating Water System * / p
- 20. Spent Fuel Fool Cooling and Clean-Up System * !
- 21. Non-Class 1E (.';cn-E3F) /..C. Pc.,er* ! h
- 22. Class lE (EST) A.C. Power *
[
.i
- i
+ Balance-of-Piant Systems - [
TABLE 15.5.3-7 (CONTIflUED)_ (Sheet 2'of 2) 9 DISPOSITIC:! 0F .'IGF?#LLY-0PE?AT!!:G SYSTEMS FOR THE STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF 0FFSITE POWER
$o .,, %
,. ?p, #, Ch? 's g %\
g y /. ,
y\
0,',# >G ' F,%9.C\ 6 ,
' 'c <\ ?p . 0, e ,. 'cc.' C-j G \ ,. c,
'g@. PG s'o %o, vg,j ._ st,es ty$;G, g wee
\'76.'C ss r u, Dky' og T p
- p o \9.\g SYSTEM c .
- 23. Ncn-Class lE D.C. Power * /
- 24. Class lE D.C. Power * /
NOTES: ,
- 1. Portions of this system are isolated, either automatically (see applic:nt's SAR) er manually by the operator ence he determines which steam generator contains the ruptured tube.
5 I
I i,l I
I
' Scia . e-of-Plant S~vstces '
l A ._
~
TABLE 15.6.3-8 UTILIZATICN OF SAFETY SYSTE.'!S
, FOR THE STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF 0FFSITE POWER
. Y b h' k s %G %h s, e% % ,Q %.
A. ,o '$o
. A b; e b[$ ke
.% % Eg., c[1.
SYSTEM Yg 9 a \
- 1. Reactor Proteccion System / !j f
- 2. DNBR/LPD Calculator i
- 3. Engineered Safety Features Actuation Systems / .
l 4. Supplementary Protectica System (
- 5. Reactor Trip Switch Gear /
l!
- 6. Main Steam Safety Valves * <
(
- 7. Primary Safety Valves lj -
l'
- 8. Main Steam Isolation System * / 1 ;[
- 9. Emergency Feedwater System * / j.E'
- 10. Safety Injection System / i:
- 11. Shutdeun Cooling System / !;
- 12. Atmospheric Cump Valve System * / /!l:
- 13. Containment Isolation System
- j:
l -14. Containment spray System
- ji
- 15. Iodine Removal System * [
l 16. Containment Ccebustible Gas Control Systcm* [
- 17. Diesel Generators and Su;;; ort Systems' ;
- 18. Ccmponent (Essential) Ccaling Water Syster* / ';
- 19. Staticn Service Water System * . / ,
i t:0TES- !.
t
- 1. The Operator ranually i5cistes the affe ted steam generator. :
1
- Calance-of-Plant Systems -
__ - = - - - - _ _ =- _ _ _ _
_-n__-=.
LTABLE 15.6.3-9 ASSUMPTIONS AND INITIAL CONDITIONS FOR THE STEAM GENERATOR TU8E RUPTURE.
WITH A LOSS OF 0FFSITE POWER Parameter -- Assumed Value Core Power Level, MWt 3876-Core Inlet Coolant Temperature,: F' 565 Reactor Coolant System Pressure, psia 2400 Core Mass Flow Rate,=106 1mb/hr 166 One Pin Integrated Radial . Peaking Factor,
~
1.53 with Uncertainty..
Steam Generator Pressure, psia 1020
- Moderator-Temperature Coefficient, 10 -4 ap/ F
-3.S Doppler Coefficient Multiplier 1.15 CEA Worth at Trip, % Ap (most reactive CEA -10.0 fully withdrawn) i
t 1
TABLE'15.6.3-10 4
-RADIOLOGICAL CONSEQUENCES OF THE- -
. STEAM GENERATOR TUBE RUPTURE WITH A LOSS 0F 0FFSITE POWER
, Locat' ion Offsite Doses, Rems
-GIS PIS
- 1. Exc.lusi' on~ Area Boundary -
. 2 hr Thyroid 16.8 21.6
- 2. Low Population Zone 8.2 2.4 Outer, Boundary 0-8 hr Thyroid -
J i
I-r i
i i
I L-
.' . - 'a ..
h 120 100 - -
M 80 - -
u 5
o_
f60 e
u o
" 40 - -
l l
l 20 - -
l l
k 0
0 300 600 900 1200 1500 1800 TIME, SECONDS l
l l
C-E f STEAM GENERATOR TUBE RUPTURE Figure WITHOUT LOSS OF 0FFSITE POWER SfEP8t // CORE POWER vs TIME 15.6.3-2 l
120 , i i i i 100 -
$2 80 m
x' -
3 u_
60 -
w u
g 40 -
20 -
I ' '
U' '
0 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE WITHOUT Figure ggg'yt //
i LOSS OF 0FFSITE POWER CORE HEAT FLUX vs TIME 15.6.3-3
2400 i i , ,
-;p.
i 2150 - -
1900 - -
U g .
5 m
1650 - -
E c.
0
- 1400 - -
1150 - -
900 i ' ' ' '
0 300 600 900 1200 1500 1800 TIME, SECONDS C-E SEAM GENERATOR TUBE RUPTURE rigure WITHOUT LOSS OF 0FFSIE POWER S RCS PRESSURE vs TIME 15.6.3-4
?# 4
"~'650 i i i _i i 63 0 -
- g. CORE OUTI.ET T d610 - -
E e
@ CORE AVERAGE) g590 5
5 8
o 570 - -
CORE INLET) 8 o
- 550 - -
530 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE Figure WITHOUT LOSS OF OFFSITE POWER E7E RCS TEMPERATURES vs TIME 15.6. 3 - 5
1200 i i i i i
.~ .
1000 -
d
-3 SM -
u 3
S -
600 6
!5 d
9s 400 -
U u
o_
- 200 -
0 I ' ' ' '
0 300 600 900 1200 1500 1800 TIME, SECONDS 4
C-E STEAM GENERATOR TUBE RUPTURE rigure WITHOUT LOSS OF OFFSITE POWER S PRESSURIZER WATER VOLUME vs TIME 15.6 . 3 - 6 i-
- _1400
_ , i i i
-i 1300 _
y 1200 -
G c.
of 5-m 1100 -
u O l
" 1000 -
900 -
800 ' I I ' '
0 300 600 900. 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE Figure WITHOUT LOSS OF 0FFSITE POWER S Es S.G. PRESSURE vs TIME 15.6 . 3 - 7
[t . 4- .
3000
' ' ' $p _
9.. 3 i 4, . .
8 m 2500 - -.
5 a
N
$ 2000 y
u w
e g
@1500 w
di c_
B S 1000 u_
E W
w .
y 500 - -
s2 0 i i i J < i 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E f STEAM GENERATOR TUBE RUPTURE Figure
' gggCgg / / e WITHOUT LOSS OF 0FFSITE POWER TOTAL STEAM FLOW vs TIME
- 15. 6.3~-
. 8
~2700 , , , , . ,
E^ INTACT SG q 2250 -
DAMAGED SG -
a 1800 - -
M 3
si 1350 - _
S u_
x i!
5 c 900 - -
!ii u_
450 - -
0 i i i i i 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E / STEAM GENERATOR TUBE RUPTURE pigure WITHOUT LOSS OF 0FFSITE POWER Sf26278' / / FEEDWATER FLOW vs TIME 15.6. 3 - 9
(
~600 < s a n ., n J' h\ -_ . .
500 - _
- E
".u
- 400 - _
B m
Y b --
I 300 - _
u.
e b'
<c
$200 - -
W u
i 100 0 3b0 6b0 900 1200 1500 1800 TIME, SECONDS l
l l
e**
c-e f STEAM GENERATOR TUBE RUPTURE pi u,,
WITHOUT LOSS OF 0FFSIE POWER 15.6,3-i I
Sff9f8t // .FEEDWAER ENTHALPY vs TIME 10:
290 , , , , ,
s .. y p.e.-.
8: '..
M.h.E D' Ndt
~ 270 E
"}
a.
~ ,'
250 -
r w
m /
< /
2 /
O /
5 230 Q
i
/ -
e /
9
< /
m DAMAGED SG /
W 210 -
/ -
u l 1 /
< /
W
^
/
/
190 -
f INTACT SG t
170 0 300 600 900 1200 1500 1800 TIME, SECONDS
- . f-ll%
c-E , STEAM GENERATOR TUBE RUPTURE Figure S f/ E P 8 // WITHOUT LOSS OF 0FFSITE POWER S.G. LIQUID MASS vs TIME 15*6'}~ .I
12000 , , i i i
[
,s. p :-
el10000 v; -
f5 o_
$ 8000 - ~
c' o
W y 6000 - _
E W
- 2'
> 4000 - -
b w
- E g 2000 w .
E
$ i i i i i 0
0 300 600 900 1200 1500 1800 TIME, SECONDS C-E / STEAM GENERATOR TUBE RUPTURE Figure WITHOUT LOSS OF OFFSITE POWER SfEP8v / / MAIN STM SAFETY VALVE INTEGRATED FLOW vs TIME 15.6. 3 -]2
.560 , i i i L ., i
- q .
- .; K '.
y 5 .' N 540 - -
s 520 -
"I a
e 500 R
5 5
m 480 - -
o e
460 - -
1 MO '
! O 300 600 900 1200 1500 1800 TIME, SECONDS i
I
.S s:... .
t C-E / STEAM GENERATOR TUBE RUPTURE Figure
/
t WITHOUT LOSS OF 0FFSITE POWER 3-EfEF8.v / - RCS INVENTORY Vs TIME 15.6 13
4 90 i i i ' '
75 -
M -
e 60 _
5
_.i K
N -
g 45 -
u b \ /
u
? 30 - -
k 15 0
0 300 600 900 1200 1500 1800 TIME, SECONDS C-E. SEAM GENERATOR TUBE RUPTURE Figure WITHOUT LOSS OF OFFSIE POWER Ef8 TUBE LEAK RAE vs TIME 15.6.3-14
?
90000 , i . . i
- eS, 75000 -
$60000 5
c' E 45000 - -
B o
16!
30000 - -
15000 - -
0 ' ' ' ' '
0 300 600 900 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE Figure WITHOUT LOSS OF 0FFSITE POWER 15.6 EE INTEGRATED LEAK FLOW vs TIME 5-
.e.- .
Tc ;i.
,; _ 2000 0.r. ,
TOP OF RV e
d .1600 - -
z a.
R 1200 - -
W 8 -
5 9-o 800 - -
5 3
9
-a tg 400 - -
cr O
~
TOP OF HOT LEG 0
0 300 600 900 1200 1500 1800 TIME, SECONDS i
c_e STEAM GENERATOR TUBE RUPTURE p;gu,,
WITHOUT LOSS OF OFFSITE POWER Sf3 15 6 -
LIQUID VOLUME A BOVE TOP OF HOT LEG vs TIME
_e 3.0 i , i i i FR = 1.55 2.5 2.0 -
E E
51.5 - -
2 5
s 1.0 - -
0.5 - -
I I i 1 1
- 0. 0 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE p' S '
WITHOUT LOSS OF OFFSITE POWER SSE MINIMUM DNBR vs TIME 15.g".3-
l 120 , , , , ,
- 7. - . . .
C 100 - ' -
g 80 - -
u f5 c.
!II 60 - -
3 -
2 u
o u 40 - -
20 - -
i i C
0 i i i 0 300 600 900 1200 1500 1800 TIME, SECONDS s
C-E , STEAM GENERATOR TUBE RUPTURE rigur, WITH LOSS OF 0FFSITE POWER 156 SfEP8E / / CORE POWER vs TIME 9
.,120 . . . . .
, :. : . C' 100 -
80
!;i:
u 5
n.
60 - -
u e 40 - -
8 20 - -
k i 0
0 300 600 900 1200 1500 1800 TIME, SECONDS C-E f STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS.0F 0FFSITE POWER E7EFJs / / CORE HEAT FLUX vs TIME 15.6 . 3-2 0
'4
. ; .. 2600 . . . .
s
, . ~ , ,
2400 ,'
i '.
\
t 2200 -
E E' ,
a 2000 - ' - -
w y ..,
- n. _
M o .
1800 -
1600 -
1400 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E #
SEAM GENERATOR TUBE RUPTURE rigure WITH LOSS OF 0FFSITE POWER 15~6'3-Sff9P85 / RCS PRESSURE vs TIME -
71 s
k 650 . - ' ' '
~
. l** 't i;.-- ,, g
.:[.-- p , #
~
- . . .630
- 0^
CORE OUTLET)
E-d 610 o:
R
/
- $ CORE AVERAGE 3 E.
- E 590-f Y '
z 5 %
o C 8 570 -
CORE INLET )
E o
o 550 i
i
' ' ' ' i SO
!. 0 300 600 900 1200 1500 1800 TIME, SECONDS
- 1-d l
n a o.=
l l
C-E /. STEAM GENERATOR TUBE RUPTURE p;gu,,
WITH LOSS OF 0FFSITE POWER SEf8t /j CORE COOLANT TEMPERATURES vs TIME 15*6h2 l .
1
)p .
b t
5 I,2 i a i i , i
^'
r., .
I d}:
1000 -
~
s u.
, ur
- E 800 - -
-3o y
d600 - - -
3:
f5 N
x 5 400 - -
a m .
a-200
[ -
0 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E / STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF 0FFSITE POVER SEf8ul / PRESSURIZER WATER VOLUME vs TIME 15*6')3-
1400
~
, , , . i j;;:,l
1300 -
1200 -
J///// A E
u' 5?1100 - -
0 E
c; -
vi 1000 - -
900 - -
800 ' ' ' ' '
0 300 600 900 1200 1500 1800 TIME, SECONDS
. =
?.: g:c,-
C-E STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF 0FFSITE POWER S STEAM GENERATOR PRESSURE vs TIME 156.3-24
3000 , i i i i 8
T 2500 - -
5, x'
R g 2000 -
W 8
2 h1500 m
5 c_
5:
@1000 2
W w
$ 500 - -
p ,,, t > c l
0 ' ' ' II - - - - - - -- - - - -
! 0 300 600 900 1200 1500 1800 TIME, SECONDS l
l l
L C-E / SW.AM GENERATOR TUBE RUPTURE Figure ggggg5 7/ WITH LOSS OF 0FFSITE POWER TOTAL STEAM FLOW PER S.G. vs TIME 15.6 25 3-
2700 , , , , ,
.r . l S 2250 -
m 5
a of j21800 -
5 u .
31350 -
W w
5 a.
@ 900 tt' g 450 - -
tt 0
0 300 600 900 1200 1500 1800 TIME, SECONDS a,
C-E STEAM GENERATOR RJBE RUPTURE rigure SE / WIU. LOSS OF 0FFSITE POWER FEEDWATER FLOW PER S.G. vs TIME 15.6.f6-L
600 , , , ,
"l ,
500 - -
$400 - -
3 5
d -
p 300 - -
w 5
a::
ti!
g 200 - -
a 100
{
0 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF OFFSITE POWER S FEEDWATER ENTHALPY vs TIME 15.6, 3 - 2 7
1250 i i i i i g,g.; , .. l;;
- M. ~
225 - -
a vi
$ 200 -
AFFECED S.G.
E o
5 cr
'e175 -
\ -
S \
< UNAFFECED S.G. \
5 \
'5 o \
150 3 \
< \
N
" N
\
\
125 -
,\ -
N s 100 ' ' ' ' '
0 300 600 900 1200 1500 1800 TIME, SECONDS yw .. .
l q;=: .
C-E i STEAM GENERATOR TUBE RUPTURE Figure gggg' f', / WITH LOSS OF QFFSIE POWER 3.6.3-28 S.G. LIQUID MASS vs TIME
l 60000 , i i . i Q' . :-
a .
- H m 50000 f5 b o-3:
$40000 -
o W
4 g
e W - -
g 30000 W
d H
H g20000 - _
e w f 5
g10000 - _
s 2
0 i i i i ,
0 300 600 900 12M 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE 7;Su,,
WITH LOSS OF 0FFSITE POWER Sf/Tc MSSV INTEGRATED FLOW PER S.G. vs TIME 15.6. 3 - 2 9
E . . ,
560 , , , , ..,, ,
- E
$ 540 -
8 2
d g 520 - -
5 3
~ -
h500 - -
S w
!iE 5
8 480 - -
o x
f?
"c E 460 - -
440 ' ' ' ' '
0 300 600 900 1200 1500- 1800 TIME, SECONDS.
C-E STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF OFFSITE POWER S REACTOR COOLANT SYSTEM INVENTORY vs TIME 15. 6, 3 - 3 0
90 i i i ' '
75 -
S 60 - ~
y w-5 N _ -
@ 45 z
w % /
y 30 -
g 15 - -
0 0 3 6 9 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF OFFSITE POWER Ef2@ TUBE LEAK RATE vs TIME 154 3-31
~
90000 i i i i '
75000 - -
m, 60000 - -
??
9 u- .
$45000 c
it!
$30000 i5 15000 - -
t 0
l 0 300 600 900 1200 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF 0FFSITE POWER L E INTEGRATED TUBE LEAK vs TIME 15.6. 3 -3 2
[
i
, ,.4....
2000 , , , ,
TO P OF RV 1 1600 - -
e B
E x
g 1200 - -
o_
i?
W h800 a
W a
y 400 - -
a TOP OF HOT 1.EG 0 ' ' ' ' '
0 300 600 900 1200 1500 1800 TIME, SECONDS 1
C-E SEAM GENERATOR TUBE RUPTURE Figure WITH LOSS OF 0FFSIE POWER SE LIQUID VOLUME A BOVE TOP OF HOT LEGS vs TIME 15.6 3 -33 s
I 3.0 , , , , ,
FR = 1.53 2.5 - -
- 2. 0 - -
E E
51.5 - -
- E
!ii!
E 1.0 - -
0.5 - -
I I I I I O
0 300 600 900 1200- 1500 1800 TIME, SECONDS C-E STEAM GENERATOR TUBE-RUPTURE r; !
WITH LOSS OF OFFSITE POWER 15!u,,6.3-Sf8 MINIMUM DNBR vs TIME 34
15.7 RADIOACTIVE MATERIAL RELEASE FROM A SUBSYSTEM OR COMPONENT 15.7.1 Waste Gas System Failure (see Applicant's SAR) 15.7.2 Radioactive Liquid Waste System Leak or Failure (see Applicant's SAR) 15.7.3 Ra.dioactive Release Due to Liquid Containing Tank Failure (see Applicant's SAR) 15.7.4 Fuel Handling Accident 15.7.4.1 Identification of Event and Causes The only event involving C-E scope components and resulting in radioactive release from a subsystem or compcnent which was considered was the Fuel Handling Accident. The Fuel Handling Accident that is considered resulted from the dropping of a single fuel assembly during fuel handling. Interlocks and procedural and administrative controls involved in fuel handling are described in Section 9.1.4.
15.7.4.2 Sequence of Events and Systems Operation All systems required to produce the safety functions necessary to mitigate the consequences of the Fuel Handling Accident are outside the CESSAR scope.
15.7.4.3 Analysis of Effects and Consequences A. Mathematical Model If a dropped assembly were damaged to the extent that one or more fuel rods were broken, the accumulated fission gases and iodines in the fuel rod gaps would be released to the surrounding water. Release of the solid fission .
products in the fuel would be negligible because of the low fuel temperature during refueling.
The fuel assemblies are stored within the spent fuel rack at the bottom of the spent fuel pool . The top of the rack extends above the tops of the stored fuel assemblies. A dropped fuel assembly could not strike more than one fuel assembly in the storage rack. Impact could occur only between the ends of the involved fuel assemblies, the lower end fitting of the dropped fuel assembly impacting against the upper end fitting of the stored fuel assembly.
Analytical methods used to calculate the impact velocity and the resulting impact stress in the fuel rod cladding for the vertical drop are described bel ow.
The analysis of the fuel assembly vertical drop employed a summation of the forces acting on the fuel assembly in the vertical direction to determine the equation of motion of the fuel assembly. The resulting equation of motion is given below:
Fvert =M x a = FD+FB - Fw
where:
M = mass of a fuel assembly a = acceleration
.FC = drag force cf a fuel assembly [ Drag Coeff. x (velocity)2]
FB = bouyant force of a fuel assembly Fy = Weight (dry) of a fuel assembly The analysis assumed the fuel assembly drop distance was sufficient for the fuel assembly ,t,o reach its terminal velocity (acceleration equals zero in the above equation), thus making the results conservative or applicable for any drop height. For this worst case, the terminal velocity, and therefore the assumed impact velocity of the fuel assembly, is 254.4 inches /second, and the resulting stress in the fuel rod cladding is 24,000 psi.
The equation employed in calculating the above impact stress in the fuel rod clad is as follows:
OI " VI Exp where o = impact stress -
Yg = impact velocity Eg = modulus of elasticity P = mass density The yield stress of the fuel rod cladding is 49,000 psi. This is the minimum yield stress value for unirradiated Zircaloy-4 and is conservative for irradiated fuel . Thus, for the fuel assembly vertical drop, the impact stresses which result from absorbing the kinetic energy of the drop are below the yield stress of the clad and no fuel rod failures will occur.
Horizontal impact of a fuel assembly could result from a dropped fuel assembly falling in the horizontal position, or from a vertical fuel assembly rotating to the horizontal position. As in the vertical drop described above, worst case assumptions are made for the horizontal impact velocity (based on the terminal velocity) and the rotational impact velocity (based on an initial angular velocity of 5 radians /second). The worst case bundle impact results from the horizontal drop since the kinetic energy at impact is greater for the horizontal drop than for the rotational impact (3629 f t-lbs versus 2375 ft-lbs, respec ti vely) . During this horizontal drop, it is postulated that the assembly strikes a protruding structure. For this analysis, a localized loading of one grid span has been assumed.
An analysis of the fuel assembly drop has revealed that the most severe impact location is between the top two spacer grids since that impact area is within the fuel rod upper plenum region and the fuel pellets do not provide support for the cladding. To obtain an estimate of the number of fuel rods which might fail, the fuel assembly's grid span was modeled and calculations performed to relate the assembly's kinetic energy at impact to the resulting strain energy in the fuel rods and guide tubes
B. Input Parameters and Initial Conditions Input data to the analysis that described material properties and pool conditions were kept consistent with the circumstances of the event (i.e.,
irradiated fuel assembly material properties, water, and fuel rod cladding temperatures corresponding to spent fuel pool conditions). As a result of the fuel assembly drop, no more than four rows of fuel rods (60 rods) would fail due to the strain resulting from the fuel rods and guide tubes absorbing the bundle's kinetic energy at impact. Fuel rod cladding failure was assumed to occur if the maximum clad strain reached the ultimate strain of irradiated Zi rcal oy. The use of irradiated fuel rod properties for the horizontal impact is conservative' because of the greater energy absorbing capability of unirradiated Zircaloy. The earliest anticipated time at which a spent fuel assembly would be handled is 3 days after shutdown.
C. Results Assumptions and parameters used in evaluating the fuel handling accident are listed in Table 15.7. The radioactive inventory of the 60 fuel rods was obtained by multiplying the activity of the most radioactive fuel rod 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after shutdown by a factor of 60. The calculational methods and assumptions described in Regulatory Guide 1.25 apply since: (1) the values for maximum fuel rod pressurization, (2) peak linear power density for the highest power assembly discharge, (3) maximum enterline operating fuel temperature for the -
assembly in item (2) above are less than the corresponding values in Regulatory Guide 1.25.
As described in the above presentation, the failure of all 236 fuel rods in one spent fuel assembly is not credible. However, the evaluation of the failure of all fuel rods in a fuel assembly (236 fuel rods) can be performed to demonstrate consistence with the recommendations of Regulatory Guide 1.13.
This evaluation would be identical to the design basis accident with the exception that the radioactivity would be obtained by multiplying the activity of the most radioactive fuel rod 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> af ter shutdown by a factor of 236.
In addition, a radial peaking factor of 1.65 can be used in place of the realistic assumption of 1.5c. in order to demonstrate the consistency with the recommendations of Regulatory Guide 1.25.
15.7.4.4 Conclusion The exclusion area boundary dose resulting from the fuel assembly drop event will be determined by the applicant.
Table 15.7.4-1 PARAMETERS USED IN EVALUATING THE RADIOLOGICAL~
CONSEQUENCES OF A FUEL HANDLING ACCIDENT Parameter Design Basis Regulatory Guide Assumptions 1.25 Assumptions Source Data:
~
-Radial peaking factor 1.55 1.65 Burnup 3 full-power years 3 full power years at 80% plant factor at 80% plant factor Decay time, hr. 72 72 Number of failed rods 60 236 Fraction of fission product gases contained in the gap region of fuel rods, %
Kr-85 30 30 Other Noble Gases 10 10 Iodine 10 10 Activity Release Data:
Percentage of gap activity 100 100 released to pool Activity released to fuel pool, 60 rods- 236 rods Isotope I-129 2.19 x 10-3 9.95 x 10-3 1-131 1.44 x 10 4 6.55 x 10 4 Xe-131m 1.17 x 10 2 5.34 x 10 2 Xe-133 2.91 x 10 4 1.32 x 10 5 KR-85 5.67 x 102 2.58 x 10 3
9 APPENDIX 15B METHODS FOR ANALYSIS OF THE LOSS OF FEE 0 WATER INVENTORY EVENTS
)
. TABLE-0F CONTENTS CHAPTER -15 APPENDIX 15B Section Subject Page No.
~
15B.1' . INTRODUCTION 15B-1 15B.2 DISCUSSION 15B-1 15B.3- - METHOD OF ANALYSIS 15B-2 i
158.4 RESULTS 15B-7 I'
158.5 ~ CONCLUSION 1SB-9 P
W i
I e
4 i
i wy- r-w-- a , -r g~ e 9 = eg e- 3 -
--% , emy-4 -.y., -e,-, .-y-e, . r-m---, e -- , 3 -- - - - - - ,
LIST OF FIGURES CHAPTER 15 APPENDIX 15B Figure Subject 158-1 . Loss of Feedwater Inventory Maximum RC System Pressure vs Breax Area 15B-2 Loss of Feedwater Inventory Maximum RC System Pressure vs Initial RC-System Pressure 15B-3 Loss of Feedwater Inventory Maximum RC System Pressure vs Initial Core Power 15B-4 Loss of Feedwater Inventory Maximum RC System Pressure vs Initial Reactor Vessel Flow 15B-5 Loss of Feedwater Inventory Maximum RC System Pressure '
vs Initial Pressurizer Water Volume 15B-6 Loss of Feedwater Inventory Maximum RC System Pressure vs Pressurizer Safety Valves Rated Flow 15B-7 Loss of Feedwater Inventory Maximum Reactor Coolant System Pressure vs Doppler Multiplier 158-8 Loss of Feedwater Inventory Maximum Reactor Coolant System Pressure vs. Core Life L
158-9 Loss of Feedwater Inventory Maximum RC System Pressure vs Fuel Gas Gap Heat Transfer Coefficient 15B-10 Loss of Feedwater Inventory Maximum RC System Pressure vs Initial Steam Generator Inventory 15B-11 Loss of Feedwater Inventory Maximum RC System Pressure vs Feedwater Enthalpy 158-12 Loss of Feedwater Inventory Maximum RC System Pressure
- vs Initial Core Inlet Temperature 158-13 Loss of Feedwater Inventory Limiting Case Core Power vs Time 15B-14 Loss of Feedwater Inventory Limiting Case Core Average Heat Flux vs Time 158-15 Loss of Feedwater Inventory Limiting Case Reactivity vs Time ii
LISTOFFIGURES(Cont'd.)
CHAPTER 15 APPENDIX 158 Figure Subject 15B-16 '
Loss of Feedwater Inventory Limiting Case Core Average Coolant Temperature vs Time 15B-17 Loss of Feedwater Inventory Limiting Case Reactor Coolant Flows vs Time 158-18 Loss of Feedwater Inventory Limiting Case RCS and Pressurizer Pressure vs Time 15B-19 Loss of Feedwater Inventory Limiting Case RCS and Pressurizer Pressure vs Time 158-20 Loss of Feedwater Inventory Limiting Case Pressurizer Surge Line Flow vs Time .-
158-21 Loss of Feedwater Inventory Limiting Case Pressurizer Water Volume vs Time 15B-22 Loss of Feedwater Inventory Limiting Case Pressurizer Safety Valve Flow vs Time 15B-23 Loss of Feedwater Inventory Limiting Case Steam Generator Pressures vs Time 158-24 Loss of Feedwater Inventory Limiting Case Total Steam Flow vs Time l 158-25 Loss of Feedwater Inventory Limiting Case Total Steam Flow vs Time l
158-26 Loss of Feedwater Inventory Limiting Case Break Discharge Flow vs Time '
- j. 15B-27 Loss of Feedwater In"entory Limiting Case Break Discharge Enthalpy vs Time 15B-28 Loss of Feedwater Inventory Limiting Case Steam Generator i
Liquid Mass vs Time 15B-29 Loss of Feedwater Inventory Limiting Case Steam Generator Water Level vs Time 158-30 Minimum DNBR vs Time for the Loss of Feedwater Inventory l Appendix 158 l
! iii l
APPENDIX 1SB HETHODS FOR ANALYSIS OF THE LOSS OF FEEDWATER INVENTORY EVENTS 1
58.1 INTRODUCTION
This appendix describes the methods utilized in the transient analysis of Section 15 to envelope the overpressurization potential of the loss of feedwater inventory (LFI) event. The method involve simplifying, but conservative, modeling assumptions with respect to the feedwater line break mass and energy discharge rates and their affect on steam generator water level and heat transfer response. Using these assumptions sensitivity studies are performed to determine the most adverse set of initial plant operating conditions and transient parameters. The example used to demon-strate these methods corresponds to the limiting case feedwater line break defined in Reference 1 which includes consideration of the entire spectrum of break sizes and locations with the most adverse set of operating conditions, a loss of normal on-site and off-site electrical power at the most adverse time, the most adverse active single failure, and the failure of the most reactive control element assembly to insert following a reactor trip signal.
158.2 DISCUSSION Th'e LFI event is initiated by a break in the main feedwater system (MFS) -
piping. Depending on the break size and location and the response of the MFS, the effects of a break can vary from a rapid heatup to a rapid cooldown of the Nuclear Steam Supply System (NSSS). In order to discuss the possible effects breaks are categorized as small, if the associated discharge flow is within the exce'ss capacity of the MFS, and as large, otherwise. Break locations are identified with respect to the feedwater line reverse flow check valves which are located between the steam generator feedwater nozzles and the containment penetrations. Closure of these vTlves to reverse flew from the nearest steam generator maintains the integt.ty of that generator in the presence of a break upstream of the valves.
Breaks upstream of the check valves can initiate one of the following tran-sients. If the MFS is unavailable following the pipe failure, a total loss of normal feedwater flow (LOFW) results. With the MFS remaining in operation no reduction in feedwater flow occurs for small breaks, while large breaks impose either a partial LOFW or a total LOFW, if the area is sufficient to discharge the entire feedwater pump flow capacity.
In addition to the possibility of partial or total LOFW events, breaks downstream of the eneck valves have the potential to establish reverse ficw from the nearest steam generator (referred to as the " ruptured" generator) back to the break. Reverse flow occurs whenever the MFS is not o;:erating subsequent to a pipe break or when the MFS is operating but without sufficient capacity to maintain pressure at the break above the steam generator pressure.
It is only these breaks which develop reverse flow that are of interest in this analysis.
158-1
~
Depencing on the enthalpy of the reverse flow and the ruptured stea:. genera-tor's heat transfer characteristics, the reverse flow m:y induce either an RCS heatup or cooldown. However, excessive heat removal througn the break is not considered in this analysis, because the cooldown potential is less than that of the loss of main steam inventory (LMSI) events. The maximum-break size is smaller for the LFI events than for LMSI events. In addition, the LMSI breaks have a greater potential for discharging high enthalpy fluid due to the location of steam piping above feedwater piping within the steam generator. Furthermore, the LFI breaks cause an instant reduction in feedwater flow uniike LMSI breaks which results in a reduced heat removal capacity due to the lower liquid inventory. Since LFI breaks can cause a rapid depletion of ruptured steam generator liquid mass, reducing the heat transfer capability and causirig a rapid RCS heatup and pressurization, it is the heatup pot tial which is emphasized in this study. ,
A general description folicws of the LFI event assuming a break downstream of the check valves, inoperability of the HFS, and low enthalpy break discharge. The loss o' subcooled feedwater flow to both steam generators causes increasing steam generator temperatures and decreasing liquid inven-tories and water levels. The rising secondary tamperatures reduce the primary-to-seenndary heat transfer and force a heatup and pressurization of the RCS. The heatup becomes more severe as the ruptured steam generator experiences a further reduction in its heat transfer capability due to insufficient liquid inventory as the break discharge continues. This initial sequence of events culminates with a reactor trip on high pressurizer pressure, icw steam generater water level or high containment pressure.
RCS heatup can continue af ter trip due to a total loss of heat trar.sfer in the ruptured steam generator as it empties. Eventually the decreasing core power folloviing reactor trip reduces the core heat rate to the heat removal capacity of the intact steam generator.
The analysis methode. address the influence of the four major controlling parameters; discharge enthalpy and flow, low water level trip condition in the ruptured steam generator, and the heat transfer cnaracteristics of the ruptured steam generator.
15B.3 Method of Analysis Analysis of the LFI event is performed using the CESEC II computer program described in Section 15.0.3. along with several simplifying assumptions which, with resoect to RCS overpressurization, conservatively model the break discharge flow and enthalpy and the ructured steam generator water level and heat transfer. In addition, sensitivity of the RCS overpres-surization to changes in various plant initial conditions is evaluated to determine the most adverse initial conditions for the LFI event.
Blowdown of the steam generator nearest the feedwater line break is modeled assuming frictionless critical ficw as calculated by the Henry-Fauske correlation (Reference 2). Although the enthalpy of the bicwdown physically depends upon the location of the break relative to fluid concitiens within the ruptured steam generator, it is assumed that saturatec liquid is ciscnarged until no liquid' remains at which time saturated steam discharge is assumed.
155-2
With respect to RCS overpressurization these assumptions result in conserv-atively high mass flow and conservatively low energy flow frcm the steam generator to the break, thereby mir,imizing the ruptured generator heat removal capacity.
In lieu of detailed steam generator modelling to calculate the redistribution of fluid under the influence of blowdown to the break, no credit is taken for a low water level trip condition in the ruptured steam generator until the generator is emptied of liquid. This conservatively delays the time of reactor trip, prolonging the RCS heatup and overpressurization. No credit is taken for the high containment pressure trip.
In order to determine the sensitivity of the RCS overpressurization to the ruptured steam generator heat transfer characteristics without implementing a detailed steam generator model, the effective heat transfer area is assumed to decrease linearly (from the design value to zero) as the steam generator liquid mass decreases (from a selected value to zero). The mass interval over which the rampdown is assumed to occur is referred to as "d!" . Therefore, decreasing values of di imply a more rapid loss of heat transfer in the ruptured steam generator.
Sensitivity studies are used to establish the most adverse set of initial -
operating and transient parameters with respect to RCS overpressurization.
These parameters include break size, 91, initial core power, initial RCS pressure, initial reactor vessel ficw, initial pressuri:er liquid volume, pressurizer safety valve rated flow, core physics conditions, fuel gas gap heat transfer coefficient, initial core inlet temperature, initial feedwater enthalpy and initial steam generator inventory. ,
The first parametric analysis includes various combinations of break sizes and steam generator heat transfer characteristics (1M) with nominal full power beginning-of-cycle plant operating conditions assumed. At the time of turbine trip there is an assumed loss of both normal on-site and off-siteelectrica} power. The break size is varied from 0.0 to the maximum ~
area of 1.4 ft . The maximum area is restricted to the sum of the ficw distribution holes in the steam generator economizer section. The value of et is varied from 0 to 100,000 lbm to envelope all possible rates of decreasing the ruptured steam generator heat transfer. Results of this study are shown in Figure ISB-i.
For each value of Mi the curve of peak RCS pressure versus break area is characteri:ad by a relatively sharp rise in pressure with increasing break area followed by a gradual decline. Pressures for break area less tnan that corresponding to the inflection point are reduced due to a reactor trip on low water level in the intact steam generator before total heat transfer is lost in the ruptured steam generator. Larger breaks trip on high pressurizer pressure or low water level in the ruptured generator.
The ' relationship between pressure and break area af ter the inflection point is due to a combination of more rapid loss of heat transfe- with increasing area, off-set by greater steam relievir.g capacity of larger breaks once the ruptured steam generator empties which is important in reducing tne CS heatup following turbine trip.
Except for the range of small breaks, larger values of M result in lower RCS pressures. The more gradual decrease in heat transfer asscciated with a larger M allows for more reactivity feedback from the moderator temperature which reduces core power prior to trip, and also allows for a greater shift of secondary heat transfer from the ruptured steam generator to the intact generator prior to trip. Both of these phenomena minimize the rate of RCS heatup and pressurization after reactor trip. However, for the range of small breaks and small M, no decrease in heat transfer occurs before trip, but as M increases, heat transfer reduction begins prior to and continues after reactor trip. -- .
2 The study shows that a break area of 0.2 ft and M equal to 0.0 is the most adverse combination. This combination is used as the base case for the rest of the sensitivity studies.
The sensitivity of peak RCS pressure to initial RCS pressure is shown in Figure 158-2. For pressures to the right of peak in the figure, reactor trip occurs on high pressurizer pressure prior to the loss of heat transfer in the ruptured steam generator. Lower initial pressures trip on low water level in the ruptured steam generator (once emptied). And as the initial pressure is lowered the RCS pressure at reactor trip decreases reducing the -
peak pressure. The concavity of the curve up to 2200 psia is due to the limiting effects of the pressurizer safety valves.
Due to the se.g.sitivity of the maxinum RCS pressure to initial RCS pressure, each of the following parametric studie:, adjusts the initial RCS pressure within its full power operating band to provide a high pressurizer p'ressure trip signal coincicent with the first reactor trip signal, if possible.
This provides an equal basis for comparison.
The sensitivity of RCS pressure to initial core power is shown in Figure 158-3. Lowering the core power reduces the RCS heatup associated with losing one steam generator heat transfer capability.
The sensitivity of RCS cverpressurization to initial reactor vessel flow is negligible as shown in Figure 15B-4.
The initial pressurizer liquid volume shows no significant influence on the maximum RCS pressurization (' Figure 15B-5). RCS pressurization prior to re-actor trip is more raplo for Targer initial liquid volumes, however, the volume does not affect the rate of RCS heatup nor the pressurizer safety valve opening ar.d associated pressure required to accommodate the volumetric insurge flow due to the heatup. In the absence of significant sensitivity, the r.Jtxiou: pressuriter liquid volume is considered the most adverse due to the increased potential for completely filling the pressurizer witn liquid during the course of the transient.
The rated flow of the four pressurizer safety valves is restricted to a minimum cf 460,000 lbm/hr/ valve to a maximum of 575,000 lbm/hr/ valve.
Figure 15B-6 shows that within this range the :aximum RCS pressure decreases only sligntly with increasing rated flow. This indicates that the maximum
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volumetric insurge to the pressurizer during tha maximum rate of RCS heatup is well within the relieving capacity of the safety valves (i.e., a valve with a lower rated flow must open oroportionately further to provide the required flow, but not beyond its limit).
A multiplier applied to the Doppler reactivity feedback has negligible impact on the peak RCS pressure (see Figure 15B-7). This result is due to compensating effects which the Doppler feedback has-en the core power transient before reactor trip relative to after trip. Increasing the feedback (multiplier) slightly reduces the core power before, but reduces the rate of core power decay after the reactor _ trip.
Figure 15B-8 sh$s the response of the maxi 5um RCS pressure to relative changes in the core life. The decrease in RCS pressure is predominately due to decreasing moderator temperature coefficient of reactivity (ncminally
-1.13 x 10' ao/F at beginning-of-cycle to -2.46 x 10-4 ao/F at end-of-cycle, assuming equilibrium xenon and a core average temperature of 594*F).
The more negative coefficient produces a greater reduction of core power prior to trip and thereby reduces the RCS heat up and pressuri:ation following reactor trip.
The fuel gas gap heat transfer coefficient affects the initial fuel tempera-turas and the associated stored energy in the fuel. In the LFI event in-creased stored energy increases the core heat flux following reactor trip and hence the RCS heatup. Therefore, as shown in Figure 15B-9, the maximum RCS pressure reaches a peak for the lowest value of fuel gas gap heat
- transfer coefficient (corresponding to cold clean fuel).
Because the core power has a significant impact on the peak RCS pressure and can be influenced by moderator reactivity feedback prior to reactor trip, sensitivity studies on parameters whicn strongly affect moderator temperature (i.e., initial core inlet temperature, initial steam generator water mass and feedwater enthalpy) use the base case modified by implementing the most positive moderator reactivity versus temperature curve (beginning-of-cycle) including uncertainties.
The sensitivity of traximum RCS pressure to initial steam generator water mass shown in Figure 15B-10 has fcur characteristic segments. For initial masses between 90,000 lbm and 115,000 lbm, a reactor trip condition is first encountered on low water level in the inta:t steam generator event with an adjustment of the initial RCS pressure to the upper limit of operation (2400 psia). Within this range a decrease in initial mass forces an earlier reactor trip and lower RCS pressure at trip. Between 115,000 lbm and 135,000 lbm the initial RCS pressure can be adjusted to provide sicultaneous reactor trip signals frcm high pressurizer pressure and icw water level in the intact steam generator and hence the plateau of maximum RCS pressure.
From 135,000 lbm to 155,000 lba reac:cr trio still occurs on hign pressurizer pressure and intact steam generator low water level, however heat transfer rampdown in the ruptured steam generator begins prior to reaching the maximum RCS pre:sure. Above 155,CC0 lbm the low water level trip conditien is due to emptying of the ruptured s eam generator. Therefore, all heat transfer is lost in the ruptured steam ge.serator prior tc reac:Or trip causing the most adverse RCS heatup initiated with the pressurizer pressure at the trip setpoint. .
153-5
~
Figure 15B-11 shows the'results of the parametric analysis on maximum RCS prcssure versus initial feedwater enthalpy. Raising the degree of feedwater subcooling increases the rate of RCS heatup once main feedwater is terminated.
The RCS pressurization is greater, therefore, for decreasing feedwater enthalpy.
The final sensitivity study on initial core inlet temperature indicates only a small dependence of peak RCS pressure on temperature. There are several off-setting influences of temperature. Lowering tN core inlet temperature increa.ses the initial moderator temperature coefficient of reactivity. It decreases the secondary side tempera'ture, thereby reducing the degree of feedwater subcooling. The corresponding decrease in the steam generator pressure reduces the break discharge flow and also prevents opening of the main steam safety valves prior to reactor trip. The result of the interaction of these changes is shown in Figure 15B-12.
The results of these sensitivity studies provide a set of initial conditions and transient parameters which establish the limiting RCS overpressurization LFI event. In summary this set includes:
2
- 1. 0.2 ft break area
- 2. Instantaneous loss of heat transfer in the ruptured steam generator (AM=0)
- 3. Initial RCS pressure which forces a high pressurizer pressure trip co-incident with the first reactor trip signal -
- 4. Nominal reactor vessel flow
- 5. Maximum initial core power
- 6. Maximum initial pressurizer liquid volume
- 7. Minimum pressurizer safety valve rated flow
- 8. Nominal Doppler reactivity feedback
- 9. Most positive moderator temperature coefficient of reactivity
- 10. Minimum fuel gas gap heat transfer coefficient
- 11. Nominal initial steam generator water mass
- 12. Minimum initial feedwater enthalpy
- 13. Maximum initial core inlet temperature 158-6
159.4 RESULTS ,
- An example li:niting analysis of the LFI transient suggested by Reference 1 was performej applying.the conservative methods with the most adverse set of initial plant conditions and transient parameters discussed above.
Table 15B-1 lists the assumptions utilized in this worst case. The sequence of events and the dynamic rasponse of the important NSSS parameters are provided in Taole 15B-2 and Figures 15B-13 through 15B-30. respectively. ,
A 0.2 ft .2 crack in'the main feedwater line is assumed to instantaneously terminate feedwater flow to both steam generators and establish critical flow (~2000 lbm/sec of saturated liquia) from the generator nearest the break. The absence of subcooled feedwater flow causes a constant heatup and pressurization of the steam generators during the first 33.8 seconds.
which reduces the primary-to-secondary heat transfer rate. Rising reactor coolant temperatures and pressure result. Due to temperature reactivity feedback during this period the core pcwer decreases slightly from 102 percent to 98 percent of design full power.
At 33.8 seconds the ruptured steam generator is assumed to instantaneously lose all heat transfer capability due to total depletion of its liquid in-vantory by boil-off and the break discharge flow. This initiates a rapid '
heatup and pressurization of the reactor coolant system and depressurization of the steam generators. Once emptied, credit is taken for a low water level trip condition in the ruptured steam generator which leads to a reactor trip signal at 34.4 seconds simultaneous with a high pressurizer pressure trip signal. The rate of reactor coolant system pressurization is further aggravated at 38 5 seconds. Closure of the turbine leaves the pipe break as the only steam relief path, thereby reducing the energy flow from the intact steam generator below that of the primary-to-secondary heat transfer rate. The resulting steam generator pressurization reduces the primary-to-secondary temperature difference. In addition, the loss of reactor coolant flow following the loss of electrical power decreases the heat transfer coefficient of the coolant in the steam generator tubes.
A significant heat transfer reduction occurs.
Compression of the pressurizer steam volume due to the high insurge flow raises the pressure to the safety valve setpoint at 34.6 seconds. Thereafter every increase in the surge flow causes a slight pressurization which opens the safety valves such that their volumetric discharge cate matches 'that of the insurge. The reactor coolant system pressure continuas to increase to a maximum of 2Sa3 psia at 35.2 seconcs. At that time the increased cressure establishes a surge line p assure gracient which provides sufficient flow to allow the reactor coolant to expand uncer the existing heatup with no further pressurization. Pressuri:er pressure and serge line flow are also at their maxir.a of 2537 psia and 2205 lbrusec, respectively.
- The rate of heatup decreases subseouer.t to core heat flux decay causi g the primary press ses tc v 0p. 3. 20.5 s a cs the '
stesy s a My M. e s open tnus stacilizing tne se:an c ry sica te.nperature anc allc ing :ne 158-7
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rising primary coolant temperature to develop greater heat trans'fer to the intact steam generator._ The intact generator is forced to a maximum of 1318 psia before the heat transfer begins to decrease. However, the core-s to-steam generator heat rate mismatch is reduced sufficiently by 45.4 seconds to allow closure of the pressurizer sa'fety valves and by 45.8 seconds the reactor coolantssystem enters a cooldown. Under the influence of steam blowdown through'the stupttred steam generator to the break, the cooldown proceeds evenJaf g ter. the> steam gene'rator safety valves close at 73.8 seconds. 0- P ,,
5; A main steam; isolation.sianal is generated at 165.6 seconds on low steam generator pressure'wpich' closes the main steam isolation valves decoupling the intact steam generator from the ruptured steam generator and the break.
The intact steam generator repressurizes, thereby reducing its heat transfer and eventually causing a primary system heatup by 300 seconds. With the main steam safety valves open by 314.2 seconds, the primary-to-secondary heat inbalance is eliminated by approximately 600 seconds. Thereafter the NSSS enters into a quasi-steady state with a very gradual cooldown and depressurization'due to decreasing core decay heat and with emergency feedwater flow'which was initiated at 89.6 seconds maintaining an adequate liquidjnventorywithintheintactsteamgeneratorforheatremoval. By .
1800 seconds the operator initiates a controlled cooldown to shutdown cooli.ng utilizin;g theatmospheric dump valves. ,
The minimum DNBR N. Time es shown on Figure 15B-30 remains above .1.19 throughout the tra'nsient.
During the first 30 minutes following the initiation of this LFI event mass releases from the system amount to 2970 lbm of steam from the pressurizer safety valves te the reactor drain tank, 79,700 lba of steam frcm the main steam safety 3va'Ives to atmosehere, and 69,200 lbm of liquid and 34,200 lba of steam from the feedwater line break to containment. Steam release to the reactor drain tank may burst the tank's rupture disc discharging its .
contents to containment.
During this event, two sources of radioactivity contribute to the site boundary dose, the initial' activity in the steam generator inventory, and the activity associated with primary to secondary leakage from the steam generator tubes which are assumed to be at the technical scecification limits of 0.1 uCi/gm and A.6 pCi/gm dose equivalent I-131 respectively. During the first two hours of this evant, the total activity from the steam generators includes 8.9 Ci frcm the affected steam generator to the containment building including 1.6 Ci associated with technical specification tube leakage (1 gpm) and 0.33 Ci total activity released from unaffected steam generator to the contairment and atmosphere. Assuming all the radioactivity is released to the atmosphere, the offsite dose due to feedwater -
line break with loss of offsite power results in no more than 9.5 rem two hour inhalation thyroid dose at exclusion area boundary.
~
1 15B.5 CONCt.USION (1)
These conservative methods, even when applied to the limiting case of Ref-erence 1, produce an NSSS transient with maximum pressures not greater than
- 2843 psia in the RCS and 1318 psia in the steam generators which is sufficiently low to ensure that the integrity of the pressure boundaries is maintained.
offsite power This evaluation shows that feedwater line break with loss The produces a radiological dose which is well within 10CFR100 guidelines.
minimum DNBR whic,h remains above 1.19 indicates that no fuel cladding failure occurs.
FOOTNOTE:
(1) It must be reiterated that the analysis methods discussed and applied above to the LFI events utilize simplifying assumptions which are clearly conservative for the entire spectrum of break sizes, are intended to identify an upper limit for the associated .RCS pressurization transient, and do not provide the expected RCS response. With respect to RCS pressurization, these methods are especially conservative for small line breaks. Basedonamogerealistic,yet _
still conservative reanalysis of the RCS response to a 0.2 ft break, the maximum RCS pressure will not exceed 2700 psia following any small feedwater line break.
The reanalysis of the 0.2 ft break was performed utilizing the same methods described in Section 158.3, except that reactor trip on low water level in the rup5; red steam generator was assumed prior to its emptying, and the ruptured The steam generator's heat transfer was assumed to decrease more gradually.
event definition was not changed (i.e., a feed line break located between the steam generator and the nearest reverse flow check valve, a loss of offsite electrical power following i.urbine trip, etc.). Frictionless critical flow of saturated liquid from the raptured generator to the break was assumed, and the most adverse set of plant initial conditions was selected based on the sensitivity studies described in Section 158.3 (e.g., the initial RCS pressure was selected to provide a reactor trip on high pressurizer pressure coincident with the low steam generator water level trip signal).
However, reactor trip on low water level in the ruptured steam generator was assumed to occur with 22,000 lbm of liquid remaining in it, rather than delaying the trip until the generator empties. Under full power loss of feedwater conditions more than 60,000 ibm of liquid are calculated to be in the steam generator with the water level at the trip setpoint. This calculation considered the impact of the break discharge on the level measurement uncer-tainty. Since the steam generator pressure response during a small feed line break is similar to the total loss of feedwater transient, and the discharge.
flow to the line break is small relative to the recirculation flow within lbn/sec, the generator (e.g. , fu discharge from a 0.2 f t{l power recirculation is app %ximately 10 los of feedwater flow calculation is considered to be applicable to the small breas analysis. However, a conservatively low value of 22,000 lbm was used.
Also, rather than instantaneously reducing heat transfer to the ruptured steam generator when it empties (i.e., AM = 0), heat transfer was more gradually reduced (AM = 22,000).~ Calculations of steam generator behavior during the total loss of feedwater ATWS (anticipated transient without scram) event , indicate that greater than 40,000 lbm of liquid remain in-each generator when heat transfer begins to degrade (i.e., a shift from the nucleate boiling to liquid deficient heat transfer regime). Again, since the break discharge flow is small relative to the recirculation flow within the steam generators, the total loss of feedwater flow ATWS calculation is considered to be applicable to the small break analysis. However, a conservatively smaller value of aM was selected. See Figure 15B-1 for the relative sensitivity of maximum RCS pressure to the value of AM.
Based on these more reglistic and still conservative assumptions the re-analysis of the 0.2 ft feedwater line break showed that the maximum RCS pressure remains below 2700 psia.
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< References for Appendix 15B
- 1. - "USNRC.Standa'rd Review Plan,-Section 15.2.8, Feedwater System Pipe Breaks Inside and Outside Containment (PWR)", NUREG-75/087, November
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24, 1975.
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.2. R.E. Henry, H.K. Fauske, "The.Two Phase Critical Flow of:One-Comconent Mixtures in Nozzles, Orifices, and Short Tubes", Journal of Heat Transfer, Transactions ~of the ASitE,tiay, 1971.
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F APPENDIX 15C ANALYSIS METHODS FOR STEAft LINE BREAKS i
l TABLE OF CONTENTS-CHAPTER 15 APPENDIX 15
'Section Subject Page No. ,
15C.1 , INTRODUCTION 15C.2 MATHEMATICAL MODELS 15C.2.1- PrimaryLand Secondary Thermohydraulic Model 15C'. 2 . 2 Nuclear Model
-15C.2.3 DNBR Evaluation Methodology 15C.3 INPUT PARAMETERS AND. INITIAL CONDITIONS 15C.3.1 General 4 -
_15C.3.2 _ Parameters and Conditions fo_r Maximizing -
' Pre-trip Degradation in Fuel Performance
^
15C.3.3 Parameters and Conditions for' Maximizing Post-trip Degradation in Fuel Performance 15C.3.3.1 Background 15C.3~.3.2 Plant Initia1 ' Conditions -
15C.3.3.3 Analysis Assumptions . ,
15C.3.3.4 Single Failures 15C.3.4 Parameters and Conditions for Maximizing Secondary System Contribution to Radiological Releases REFERENCES
P LIST OF TABLES Table. Subject
. 15C-1 Effect of Time of Reactor Coolant Pump Trip on Maximum Post-Trip Reactivity, Co e Average Power, and DNBR for Double-Ended Guillotine Main Steam Line. Breaks with a~ Stuck CEA and a Single Failure.
15C-2 Effect of Single Failure of MSIV or. One HPSI Pump on Maximum Post-Trip Reactivity Core. Average Power and DNBR for Double-Ended Guillotine Main Steam Line Break with a Stuck CEA.
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APPENDIX 15C ANALYSIS METHODS FOR LARGE STEAM LINE BREAKS 15C.1 INTRODUCTION This appendix provides a description of methods used in t.he analysis of nuclear steam supply system (NSSS) response to the steam line break (SLB) events presented in Section 15.1.5. Computer codes and supporting calculational methods used in the analysis are discussed in Section 15C.2. Analysis assumptions which were used to maximize the potential for degradation in fuel cladding performance and to maximize radiological releases are discussed in Section 15C.3.
15C.2 MATHEMATICAL MODELS
)
15C.2.1 PRIMARY AND SECONDARY SYSTEM THERMAL-HYDRAULIC MODEL The NSSS response to the steam line break was simulated using the CESEC computer program version described in Reference 4. Major model changes relative to versions of CESEC used for earlier FSAR analyses include: (1) a more detailed reactor coolant systen (RCS) thermal-hydraulic model to include -
the effect of temperature tilt in the reactor core during asymmetric transients and an explicit representation of the reactor vessel upper head region (2) a reactor coolant pump model which in combination with an RCS loop momentum model, explicitly calculates the time dependent reactor coolant mass flow rate; (3) a safety injection tank model (4) an RCS metal heat transfer model; and (5) a three-dimensional reactivity feedback model .
The explicit representation of the reactor vessel upper head region which nominally receives only about one percent of the total reactor vessel flow, produces a more accurate RCS pressure calculation for those transients which result in steam formation in the reactor vessel. In this region the RCS metal heat transfer model accounts for heat transfer between the upper head region fluid and metal (including the vessel wall and cladding, the upper guide structure and the control element assembly (CEA) guide tube shrouds).
The effect of decreasing reactor vessel downcomer fluid terroerature on ex-core neutron detector response during steam line break is expl4 itly modeled in CESEC through the use of a decalibration factor. Ex-core detector decalibration, which is caused by increased neutron attenuation, delays the occurrence of the high core power reactor trip signal during steam line breaks.
15C.2.2 NUCLEAR MODEL Core power as a function of time is calculated in CESEC using a six delayed group point kinetics model . Moderator, Doppler, boron, and scram rod reactivity contributor are explicitly modeled. The moderator and Doppler reactivity functions are based on two-dimensional PDQ-X (described in subsection 4.3.3.1.1) calculations. Moderator and Doppler reactivities are parameterized as functions of average moderator density and effective fuel temperature, respectively, for use by CESEC. Values used for scram rod worth (with one stuck CEA) as a function of scram rod insertion and for reciprocal boron worth were also calculated using PD0-X. Reactivity coefficients
corresponding to end-of-cycle operation w re used for the steam line breaks appearing in Section 15.1.5 to maximize post-trip reactivity insertion.
Calculational uncertainty in the PDQ-X calculations was accounted for through the use of conservative multipliers on the CESEC reactivity functions.
The CESEC three-dimensional reactivity feedback option gives the capability of including three-tH.1cnsional reactivity feedback effects associated with core inlet plane tes. 'ure distribution, stuck CEA, and changes in core power distribution. The 3-D reactivity contribution is based on HERMITE (described in subsection :4.3.3.1.1) calculations, and is parameterized in PESEC as a function of core inlet plane temperature tilt (difference between hot and cold edge temperatures), core flow, and core fission power. This option was not used for the steam line breaks presented in Section 15.1.5.
15C.2.3 DNBR CALCULATIONS For steam line breaks initiated from full power conditions, pre-trip DNBR in the hot channel was calculated.using the TORC computer code discussed in Sebsection 15.0.3.1.6, and the CE-1 critical heat flux correlation described in CENPD-162. The initial axial core power distribution was determined by selecting the most adverse
- axial shape index ( ASI) allowed by the core operating limit supervisory system (COLSS) for steady-state conditions. The allowed axial shares for steady-state full power conditions were calculated using the 0VIX computer program, which is discussed in Subsection 4.3.3.1.1.
The initial power distribution was used from beginning of the transient until reactor trip. Average core heat flux, reactor coolant flow rate, RCS pressure, and core inlet temperature from CESEC are provided as input to TORC. The planar radial peaking factor provided as input to TORC corresponds to the most adverse
- radial peak at the ASI for which the power operating limit (POL) is not exceeded.
The determination of DNBR for post-trip steam line break conditions requires methods which differ from those described above. This is due to the fact that the verified range of the CE-1 correlation dose not cover low pressures and low flow rates. Therefore the Macbeth DNBR correlation (References 1 and 2) has been selected to represent margin to DNB during periods of return-to-power.
Macbeth correlates critical heat flux to mass flux, inlet subcooling, pressure, heated diameter, and channel length. Application of a channel heat balance allows the correlation to be converted to a " local conditions" form. Using this local conditions form of the correlation, critical heat flux as a function of height in the hot channel (which is located near the stuck CEA location) is calculated, where the effect of non-uniform axial heating is incorporated using the method applied by Lee (Reference 3).
Open core calculations indicate that local quality in the hot channel during steam line break post-trip return-to-power conditions seldom exceeds a few percent, regardless of fission power rate or core average mass flux. Thi s occurs due to the assembly cross-flow effects. The presence of low density liquid or of voids at the top of the hot channel causes post-trip power generation to occur near the bottom of the core. For return-to-power DNBR
- See Section 15C.3.2
calculations an integrated radial peaking factor of 15 and an axial peaking factor of 3 are used to bound all possible power distributions unless explicit 3-D HERMITE calculations are performed. Enthalpy as a function of height is computed by performing a closed channel heat balance. Hot channel inlet enthalpy is set equal to the average enthalpy predicted by CESEC for the fluid at the core inlet for that half of the core on the side associated with the affected steam generator. Maximum enthalpy is limited to that corresponding to 20% quality at the system pressure, to account for the cross-flow effect.
15C.3 INPUT PARAMETERS AND INITIAL CONDITIONS 15C.3.1 GENERAL The consequences of steam line breaks are evaluated with respect to criteria on:
- a. over-pressure
- b. fuel performance, and
- c. radiological releases
~
Steam line breaks are initially depressurization events. During the portion of the transient after steam generator dryout and before operator action, some repressurization can occur due to safety injection pump flow, decay heat addition, and transfer from the hotter walls and structure of the RCS.
However, the emergency feedwater system and the primary and secondary system safety valves are designed to relieve in excess of the energy available from these sources while maintaining primary and secondary pressures at, or below, design pressure. Therefore, input parameters and initial conditions were not chosen to maximize over pressure for the analyses of SLB initiated transients.
Degradation in fuel performance can occur during SLB initiated events either during the portion of the transient prior to and during reactor trip (henceforth referred to as the pre-trip portion) or during the post-trip r eturn-to-criticality, or approach-to-criticality, portion of the transient (hence-forth referred to as the post-trip portion). Input parameters and initial conditions which maximize the potential for pre-trip degradation in fuel performance are discussed in Section 15C.3.2. Input parameters and initial conditions which maximize the potential for post-trip degradation in fuel performance are discussed in Section 15C.3.3. The departure from nucleate boiling ratio (DNBR) provides a measure of fuel performance. Therefore the discussions of potential for degradation in fuel performance will be in terms of those parameters which can decrease local DNBR (i.e., degrade fuel performance) for the conditions present in a PWR during SLBs:
- a. increase in local heat flux, ,
- b. decrease in coolant flow,
- c. decrease in coolant pressure, and j' d. increase in coolant temperature.
i i
If there is a potential .for -degradation in fuel performance such that more than a very small fraction (on the order of 0.1% for System 8D) of the fuel pins in the core must be assumed .to fail, then offsite doses are sufficiently dominated by the contribution from primary system activity that assumptions which maximize the potential for degradation in' fuel performance also maximize the radiological releases. If there is not a potential for degradation in fuel performance such that more than a very small fraction of the fuel pins in the core must be assumed to fail, then offsite doses are sufficiently dominated by the contribution from secondary system activity that assumptions which affect -
the contribution of the secondary system activity to the offsite dcse must be considered. The input parameters and initial conditions which maximize the contribution of the secondary system activity to the offsite dose are discussed in Section 15C.3.4.
15C.3.2 PARAMETERS AND CONDITIONS FOR MAXIMIZING PRE-TRIP DEGRADATI.
IN FUEL PERFORMANCE Due to .the protective action of the core protection calculators (CPCs) the pre-trip minimum transient DNBR will be nearly the same for a wide spectrum of steam line break sizes, initial conditions, and analysis assumptions. The CPC low DNBR trip ensures that no more than 0.7% of the fuel pins will be calculated to exoerience DNB during any outside containment SLB. In the SLB transient presented for pre-trip degradation in fuel performance in Section 15.1.5 (Case 5), the CPC trip is taken at a time which illustrates an approach _
to this limit on fraction of fuel which will be calculated to experience ONB.
The initial conditions chosen for RCS pressure and temperature, core flow, and power are .such as (a) to make the initial state near a power operating limit for the values of ASI and . radial peaking factors used and (b) to achieue a transient minimum DNBR less than 1.195. thus requiring the proteci,ive ection of the CPCs. The value of ASI and radial peaking factor, Fo, are chosen to maximize the fraction of fuel pins calculated to experience DNB for a given transient minimum DNBR. The mcst negative ASI (-0.3) and the lowest Fg (1.4) were found to yield the largest fraction of fuel pins calculated to experience DNB for a given minimum DNBR. Assumptions concerning initial pressurizer water level and initial steam generator water level have .little or no impact on the transient DNBR.
One analysis assumption does impact the minimun transient DNBR: For cases initiated from a power operating limit and where loss of offsite power is assumed to occur concurrent with the SLB, there will be a CPC trip on pro,iected DNBR within the first 0.6 second of the initiation of the event. Thus the CPC trip occurs much earlier !n the transient for cases with concurrent loss offsite power than for cases with offsite power available. Tne loss of ficw (LOF) due to RCP coastdown causes a more rapid rate of reduction in M3R for the St B cases with concurrent loss of offsite pcwer. H0.:ever the cower operating limit is determined such that the CPC trip will prevent the transient minimum DNBR due to a (LOF frem being less than 1.19 . The only significant additional effect of the SLB, over that of the LOF, up to the timc of minicum transient DNBR will be a reduction in RCS pressure. Therefore for SL5s witn
- concurrent loss of offsite power the transient minimum CN3R will be only incrementally lower than 1.195. Analyses done to determine the transient
~
minimum-DNBR for SLEs with concurrent loss of of fsite poder hava shown th2t I
this minimum DNBP is not less tnan 1.13. Thus the minimum-DNbR of SLBs with concurrent loss of offsite power less adverse than the minimum DNBR for the SLB events with offsite power available discussed in Case 5 of Section 15.1.5.
15C.3.3 PARAMETERS AND CONDITIONS FOR MAXIMIZING POST TRIP DEGRADATION IN FUEL PERFORMANCE 15C.3.3.1 Background Degradation in fuel performance during the post-trip portion of SLB initiated transients can only cccur if there is a return-to-power (R-t-P). Therefore the primary consideration for maximizing post-trip degradation in fuel performance is to select those parameters and conditions which will maximize R-t-P. The magnitude of R-t-P is primarily determined by the value of the maximum post-trip reactivity, the timing of this reactivity, and the duration of the reactivity peak. (Other parameters which can affect the R-t-P, such as delayed neutron fraction, have a minor effect within the range of values of the parameters. These other parameters are therefore chosen to be appropriate to the core burnup which yields the maximum transient post-trip total reacti vi ty. ) The timing of the maximum post-trip reactivity has an important effect on the post-trip R-t-P: the same reactivity will produce less R-t-P later in a transient since (a) fission power will have decreased to a lower .
value prior to R-t-P, requiring more multiplication to reach a given power level, and (b) the delayed neutron background will be lower, requiring more reactivity to produce a given, positive rate of change of power. The duration of the reactivity peak is important in that this parameter determines how long the post-trip power will continue to rise (if a R-t-P occurs) before being turned around by decreasing reactivity.
For transients which result in R-t-P, degradation in post-trip fuel cladding performance (measured by the DNBR) is impacted strongly by core flow at the time of R-t-P. Core flow at the time of R-t-P is primarily a function of the analysis assumption on time of reactor coolant pump coastdown. Initial conditions and possible single failures have little or no effect on this core fl ow. For the rarge of pressure and temperature involved, the direct effect of pressure and t=aperature upon post-trip DNBR is small compared with the impact of these parameters upon fuel performance through their effect on the magnitude of the R-t-P via the reactivity feedbacks.
Initial conditions which impact the R-t-P are discussed in Section 15C.3.3.2.
The effect of analysis assumptions on the R-t-P and the core flow at time of R-t-P are presented in Section 15C.3.3.3. A discussion of the effect of possible single failures on R-t-P is presented in Section 15C.3.3.4.
15C.3.3.2 Plant Initial Conditions The impact of initial conditions on the potential for post-trip degradation in fuel performance is through their effect on. R-t-P via the magnitude, timing, and duration of tne post-trip total reactivity peak. These effects act through tr eir contributions to the moderator reactivity, the Doppler reactivity , and the safety injection boron reactivity.
The ranges of the parameters given in Table 15.0-5 (with the restriction on core inlet coolant temperature given in footnote 2 of that table) were L
considered in establishing the most adverse initial plant state for R-t-P.
(The radial peaking factors given in Table 15.0-5 are not used for post-trip analysis. See the discussion in Section 15C.2.3.) For System 80 this most adverse state has been found to be the maximum core power, most positive ASI, minimum core flowrate, maximum pressurizer water level, maximum core inlet coolant temperature, maximum reactor coolant system pressure, and maximum water.
level in the affected steam generator with the water level in the unaffected steam generator at the maximum value which can exist initially and still result in emergency feedwater actuation at the time of main steam isolation valve closure (i.e., the transient time of minimum level).
Maximizing the core power and core inlet temperature and minimizing the core flow impact the R-t-P adversely via their effect of maximizing RCS average temperature and core outlet temperature. Maximizing RCS average temperature maximizes the rate of cooldown since it maximizes steam generator pressure.
Maximizing RCS (core) average temperature also causes the cooldown to occur over a more adverse portion of the moderator reactivity function, i.e. the portion having the greatest rate of change of reactivity with temperature.
Maximizing core outlet temperature maximizes the energy stored in the water and metal of the upper head region of the reactor vessel and also maximizes the saturation pressure of the water in this region. As the RCS pressure falls below the nturation pressure of the liquid in the upper head region, the stored energy provides the energy necessary to. vaporize this liquid, resulting in a low rate of decrease of RCS pressure below the saturation pressure of the liquid in the upper head. This in turn minimizes the safety injection boron reactivity at the time of R-t-p, since the safety injection actuation signal is delayed and the safety injection pump flow is impeded by the higher transient pressures.
Use of the most positive ASI maximizes the delay in insertion of CEA reactivity following trip. This has little effect on the R-t-P. Maximizing pressurizer water level and pressure maximizes the energy stored in the pressurizer. This maximizes transient RCS pressures, delaying and impeding safety injection flow.
Maximizing steam generator water level in the affected steam generator maximizes the amount of cooldown, thus maximizing the moderator reactivity.
Maximizing the water level in the unaffected steam generator maximizes the amount of steam blowdown from that steam generator before MSIS, since a higher initial steam generator water level results in a lower rate of decrease of steam generator pressure causing a lower rate of decrease in steam blowdown flow rate. Thus increasing the initial water level in the unaffected steam generator increases the cooldown due to steam bicwdown from this steam generator, also. However, if the initial water level in the unaffected steam generator is above some minimum level, the level in this steam generator will not fall below the EFAS low level setpoint during the transient. It has been found that, for System 80, the cooldown provided by emergency feedwater is more than the additional cooldown that would result from initializing the water level at the maximum possible level in the unaffected steam generator.
Therefore cooldown by the intact steam generator is maximized by using the maximum initial water level which will result in EFAS at the time of MSIV closure (the point at which level stops decreasing).
15C.3.3.3 Analysis Assumptions The impact of analysis assumption on the potential for post-trip degradation in fuel performance is through their effect on core flow at the time of R-t-P and their effect on R-t-P via the magnitude and timing of the maximum post-trip reac tivity.
The analysis assumption which affected core flow at time of R-t-P was the time of reactor coolant pump (RCP) trip. Early RCP trip yields low flow at time of R-t-P and therefore low minimum DNBR. The time of RCP trip (initiation of four-pump coastdown) a.lso affects the magnitude of the R-t-P, primarily via the timing of the maximum post-trip total reactivity -- but also via the magnitude of this reactivity. Higher flow tends to produce a larger R-t-P. However, the magnitude of the core flow, itself, at the time of R-t-P has more effect upon the minimum DNBR than does the less direct effect via the magnitude of the R-t-P. Therefore, loss of offsite power concurrent with the steam line break yields the greatest potential for degradation in post-trip fuel performance, since the RCPs begin to coastdown at the beginning of the transient. Table 15C-1 shows, for System 80, the effect of time of RCP trip on post-reactor-trip R-t-P, maximum total reactivity, and minimum DNBR for RCP trip concurrent with the break and at time of SIAS as well as for cases with no RCP trip.
A number of analysis assumptions affect the magnitude of the R-t-P.
Conservative analysis assumptions which affect the R-t-P and which were used in the System 80 SLB analysis include:
a) The CEA of maximum-worth stuck in the fully withdrawn position after reactor trip.
b) End of equilibrium burnup cycle core conditions to yield the most negative moderator coefficient.
c) Saturated steam blowdown with no moisture carryover from the steam generators to yield the maximum energy removal .
d) A 10 percent _ increase for the slope of the moderator reactivity versus coolant temperature function to assure that the calculation of the reactivity increase due to cooldown of the moderator is conservative.
e) A 15 percent increase in the slope of the Doppler reactivity versus fuel temperature function to assure that the calculation of the reactivity increase due to cooldown of the fuel is conservative.
f) A 10 percent decrease in the slope of the boron reactivity versus boron concentration to assure that the calculation of SI reactivity is conservative.
g) The steam line breaks were initiated by a postulated double-ended rupture of one steam line upstream of the MSIV. This break location results in an initial blowdown area for each steam generator (until the MSIVs close) equivalent to two flow restrictor areas (since there are two steam lines per steam generator). As the MSIVs close, steam blowdown from the unaffected steam generator terminates and the
effective blowdown area for affected steam generator is reduced to one flow restrictor area (i.e., blowdown through the other steam line for the affected steam generator is terminated by the closed MSIVs). A smaller break delays the time of maximum post-trip reactivity and therefore decreases the magnitude of the R-t-P generated.
h) Heat transfer areas in the reactor vessel upper head region were increased by 10% to assure that the heat added by the walls and structure in this region was conservatively large, causing the
~
transient pressures to be higher and, as a result, the safety injection reactivity to be less.
- 1) Heat transfer areas in the RCS, other than those in the reactor vessel upper head region, were decreased by 10% to assure that the heat added by the walls and structure in these regions was conservatively small, causing the RCS cooldown to be increased.
j) Moderator reactivity was determined as a function of the Towest cold leg temperature to account conservatively for the effect of uneven temperature distribution on the moderator reactivity. Asymmetric heat removal causes unequal cold leg temperatures at the reactor vessel inlets for the two steam generator loops. Unequal reactor vessel '
inlet temperatures in combination with incomplete mixing of coolant in the reactor vessel downcomer and lower plenum results in a temperatur_e distribution at the core inlet plane. The effect of this temperature distribution is included by basing moderator reactivity on core cold edge moderator density.
15C.3.3.4 Single Failures Of the single failures possible for System 80 (Table 15.0-6) only the failure of one MSIV to close and failure of one HPSI pump can affect the potential for post-trip R-t-P and consequent possible degradation in fuel performance. (The failure of the most reactive CEA to insert and a loss of offsite power are assumed, additionally, f or SLB analyses). Whether the additional cooldown provided by the failure of an MSIV on the unaffected steam generator or the decreased safety injection boron reactivity resulting from the failure of a HPSI pump is more adverse for a transient depends upon a number of factors. In general the failure of a HPSI pump will be more adverse unless transient characteristics (e.g., RCS pressure, time of R-t-P) are such that little or no safety injection boron reaches the core before R-t-P, even when both HPSI pumps are assumed to be operative.
Table 15C-2 shows the maximum post-trip reactivities, core average powers, and minimum DNBRs with an assumed MSIV failure and with an assur'ed HPSI pump failure for double-ended guillotine SLBs for System 80. Cases are presented for SLBs initiated at full power and at zero power, with and without loss of offsite power. For all cases except the SLB initiated at full power with offsite power present, the HPSI failure produces the most adverse transient results.
15C.3.3 PARAMETERS AND CONDITIONS FOR MAXIMlZING SECONDARY SYSTEM CONTRIBUTION TO RADIOLOGICAL RELEASES The contribution of the secondary system to radiological releases is maximized by (a) the maximum initial steam generator inventory in the affected steam generator, (b) a loss of condenser availability, and (c) the maximum amount of post-accidient heat to be removed.
(a) Assuming that the initial steam generator water level is at the highe's't permissible operating level maxim'tes the potential for radiological release due to the discharge to atmosphere of the contents of the affected steam generator. Further, cases initiated from zero power operating conditions will have the maximum initial steam generator water inventory for a given water level.
(b) A loss of condenser availability (due to loss of offsite power, e.g.)
requires that the plant be cooled down by use of the atmospheric dump valves. This causes additional radiological releases due to the discharge to atmosphere of water from the unaffected steam generator.
(c) Maximizing the amount of post-accident heat tc be removed maximizes the amount of liquid from the unaffected steam geni.rator that must be -
vaporized and released to the atmosphere (in the absence of condenser availability of (b) above) to achieve cold shutdown. The amount of post-accident heat to be removed is maximized by assuming the maximum initial plant temperature and by assuming that the decay heat to be removed is that appropriate to full power operation, even for cases initiated at zero power: It is assumed that the event occurred at zero power, but that within the previous half hour the plant had been at equilibrium full power conditions.
9 REFERENCES
- 1. Macbeth, R. Y., "An Appraisal of Forced Convention Burn-out Data,"
Proc. Instn. Mech. Engrs, Vol .180,1Pt3c, pp 37-50,1965-66.
- 2. Macbeth, R. V., " Burn-out Analysis - Part 5: Examination of Published i World Data for Rod Bundles," A. E. E. W. . Report R358,.1964.
- 3. Lee, D'. H.,'"An Experimental -Investigation of Forced Convection Burn-out in High Pressure Water-Part IV, large Diameter Tubes at About 1600 psia," A. E. E. W. Report R479, 1966. ,
- 4. Later e
b F
TABLE 15C-1 EFFECT OF TIME OF REACTOR COOLANT PUMP TRIP ON MAXIMUM POST-TRIP REACTIVITY, CORE AVERAGE POWER, AND DNBR FOR DOUBLE-ENDED GUILLOTINE MAIN STEAM LINE BREAKS WITH A STUCK CEA AhD A SINGLE FAILURE.
Time of Post- Reactor Initial Power Level Reactor- Coolant Trip: Pump Trip FULL ZERO Maximum
- core average power 0 5.5 0.007
(% of 3800 MW) at SIAS 4.1 0.018 no trip 5.1 0.017 Maximum reactivi ty 0 +0.09 -0.64
(% ad at SIAS -0.28 -0.52 no trip -0.18 -0.19 Minimum DNBR 0 2.7 >10 at SIAS >10 >10 no trip >10 >10
- or value at time of maximum reactivity, if no return-to-power occurs.
l TABLE 15C-2 l EFFECT OF SINGLE FAILURE OF MSIV OR ONE HPSI PUMP ON MAXIMUM POST-TRIP REACTIVITY, CORE AVERAGE POWER, AND DNBR FOR DOUBLE-ENDED GUILLOTINE MAIN STEAM LINE BREAKS WITH A STUCK CEA.
INITIAL MAXIMUM POST-TRIP:
POWER OFF-SITE SINGLE LEVEL POWER FAILURE CORE AVERAGE REACTIVITY POWER
(% ) (% OF 3800 MW)
ONE HPSI PUMP +0.087 5.5 2.7 LOSS 0F MSIV -0.005 4.5 >10 FULL ONE HPSI -0.64 2.4 >10 AVAIL- PUMPS ABLE MSIV -0.18 5.1 >10 ONE HPSI -0.64 0.007 >10 LOSS PUMP OF l MSIV -1.3 0.007 >10 i ZERO l ONE HPSI -0.19 0.017 >10 AVAIL- PUMP ABLE MSIV -0.39 0.007 >10
- Maximum value or value at time of of maximum reactivity, if no return-to-power
! occurs.
I l
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