ML20041D799
| ML20041D799 | |
| Person / Time | |
|---|---|
| Site: | McGuire  |
| Issue date: | 03/02/1982 |
| From: | Parker W DUKE POWER CO. |
| To: | Adensam E, Harold Denton Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20041D800 | List: |
| References | |
| TAC-48049, NUDOCS 8203090227 | |
| Download: ML20041D799 (28) | |
Text
_ _ _ _ _ _ _ _ _ _ - - - _ _ _ _
Duxs POWEIf COMPANY PowEn Dtintonwo 422 SocTu Cut:ncu STDEET, CHANI.OTTE, N. C. 28242 wiwam o. ,4a n ca, sa. March 2, 1982
/.cr petsietw, Trite eowt:Anta7C4 5'ta= Paoosct'om 3'3-4083 lf *%
Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation O U. S. Nuclear Regulatory Commission s RI- $O T-Washington, D. C. 20555 pcj?,P' h3 I Attention: Ms. E. G. Adensam, Chief surJBM,ggen Licensing Branch No. 4 9 18f- 1 Re: McGuire Nuclear Station Y , @
Docket No. 50-369 Proposed Amendment to License NPF-9
Dear Mr. Denton:
Attached are proposed changes to the McGuire Nucicar Station, Unit 1, Technical Specifications. These changes include the following items:
- 1. Reduction in boron concentration in the boron injection tank from a nominal 20,000 ppm to 2000 ppm.
- 2. Deletion of the Technical Specification on heat tracing for the boron injection tank.
- 3. Revised minimum limit for primary containment upper compartment average air temperature.
Each of these items has been reviewed and it has been determined that there are no adverse safety or environmental impacts associated with the proposed changes.
The boron injection tank changes are considered to be a Class III amendment pursuant to 10 CFR 170.22, and the containment average air temperature change is considered to be a Class II amendment pursuant to 10 CFR 170.22. Therefore, a check in the amount of $5,200 is enclosed.
V ry truly yours, l
i
. M hb
- William O. Parker, Jr.
PBN/jfw Attachments cc: Mr. P. R. Bemis Mr. James P. O'Reilly, Regional Administrator Senior Resident Inspector U. S. Nuclear Regulatory Commission McGuire Nuclear Station Region II 101 Marietta Street, Suite 3100 Atlanta, Georgia 30303 D
8203090227 820302
/ J\ G
\\
( '
Mr. Harold R. Denton, Director March 2, 1982 Page 2 WILLIAM 0. PARKER, JR., being duly sworn, states that he is Vice President of Duke Power Company; that he is authorized on the part of said Company to sign and file with the Nuclear Regulatory Commission this' revision to the McGuire Nuclear Station Technical Specifications, Appendix A to License No. NPF-9; and that all statements and matters set forth therein are true an correct to the best of his knowledge.
Mw' _ 48 . \
William O. Parker, Jr., President Subscribed and sworn to before me this 2nd day of March, 1982.
u ~ hreamAh Notary Public My Commission Expires:
September 20, 1984
r Attachment 1A McGuire Nuclear Station Technical Specification 3/4.5.4-Boron Injection System Proposed Change:
Change 3.5.4.1 to read:
The boron injection tank shall be operable with:
^
a) A minimum contained borated water volume of 900 gallons, and b) Between 2,000 and 4,000 ppm of boron.
Change 4.5.4.1 as follows:
Delete surveillance requirement 4.5.4.lc on verifying water temperature.
Justification and Safety Analysis The design function of the Boron Injection Tank (BIT) is to provide concencrated boric acid to the reactor coolant in order to minimize the impact of the reactivity addition resulting from a steam line break accident and the existence of a negative moderator coefficient of reactivity. The current requirement for a high boron concentration in the BIT tank was a result of conservatism in the safety analysis.
Due to difficulties in maintaining this high concentration a reanalysis was per-formed which shows that the analyJis is acceptable if concentration is reduced to 2,000 ppm. This analysis was performed by Westinghouse.
Analyses for the reduction in boron concentration in the Boron Injection Tank from a nominal 20,000 ppm to 2000 ppm were performed for: 1) a hypothetical major rupture of a main steam line (FSAR section 15.4.2), 2) for an accidental depressurization of the main steam system (FSAR section 15.2.13), 3) inadvertant operation of the ECCS during power (FSAR section 15.2.14), and 4) containment temperature and pressure analysis for a spectrum of break sizes in the steam line. Results of these analyses show that this reduced concentration does not result in any core damage and that releases during the steam line break accidents remain within 10 CFR 20 limits, and that the containment pressure and temperature now in FSAR section 6.2.1 are bounding.
FSAR changes to the above sections (see attachment IB) provide the results of the analyses (performed by Westinghouse) and justify the reduction in the BIT boron concentration. The range of 2,000 to 4,000 was chosen to allow sufficient operating margin. Additionally, this range does not require any special equipment or require-ment for elevated solution temperatures.
The associated Technical Specifications for heat tracing requirements needed with the higher (20,000 ppm boro::) concentration can be deleted (see attachment 2A). Although technical specifications would still be required for BIT boric acid concentration (see attachment IC), the lower concentration facilitates maintenance of the technical specification limit within the surveillance periods. The lower boric acid concentra-tion will alleviate potential degradation due to stress corrosion, reduces or eliminates
e Attachment 1A (cont) boron plateout and line plugging concerns, and improves the reliability of components associated with recirculating boric acid between the BIT isolation valves. Furthermore, recovery time both for the RCS (dilution) and the BIT (reconstitution) following an inadvertant actuation of the Safety Injection System will be significantly reduced, resulting in improved overall plant availability. The reduced concentration eliminates the need for a minimum solution temperature of 1450F to prevent crystalization, making the only minimum temperature concern 320F (freezing). However, since the BIT is located inside the auxiliary building, ambient temperatures should never reach this limit.
Attachment 1B contains marked up FSAR pages which show the effect of reduced boron concentration in the BIT on the various accident analyses. These changes to the FSAR will be included in a future revision of the FSAR after the proposed change to the Technical Specification is approved by the NRC Staff.
Based on the Westinghouse analysis, reduction of the boron injection tank's boron concentration does not have any adverse effect on safety of plant operation or the health and safety of the public. Furthermore, re-analysis of the steam line break accident for end-of-life conditions without considering the functioning of the BIT showed that the accident is safety mitigated. However, other plant con-siderations led to a decision to reduce boron concentration rather than eliminate the BIT completely.
l .
s '. -
ATTMwENT IB w n:t n cssu Crnrow e
- 3. A high (absolute value) Doppler coefficient of reactivity such that '
the resultant amount of positive reactivity is conservatively large.
It should also be noted that in the analysis power peaking ractors are 7 kept constant at the design values while, in fact, the core feedback effects would result in considerable flattening of the power distribution. s This would significantly increase the calculated DNBR; however, no credit is taken for this effect.
Results Reactor trip on overtemperature AT occurs as shown in Figure 15.2.12-1.
The pressure decay transient following the accident is given in Figure 15.2.12-2. The resulting DNBR never goes below 1.30 as shown in Figure 15.2.12-3 15.2.12.3 Conclusions The pressurizer low pressure and the overtemperature AT Reactor Protection System signals provide adequate protection against this accident, and the minimum DNBR remains in excess of 1.30.
15.2.13 ACCIDENTAL ~DEPRESSlJRIZATl0N OF THE MAIN STEAM SYSTEM 15.2.13.1 Identification of Causes and Accident Description The most severe core condicions resulting from an accidental depressuri-zation of the Main Steam System are associated with an inadvertent opening of a single steam dump, relief or safety valve. The analyses performed assuming a rupture of a main steam line are give, in Section 15.4.
7 The steam release as a consequence of this accident results in an initial increasa in steam flow which decreases during the accident as the steam pressure falls. The energy removal from the Reactor Coolant System causes a reduction of coolant temperature and pressure. In the presence of a negative moderator temperature coefficient, the cooldown results in a reduction of core shutdown margin.
The analysis I$ performed to demonstrate that the following criterion is satisfied: Assuming a stuck RCCA, with or without offsite power, and assuming a single. failura in the Engineered Safety Features, there will be no r _ - _ - _ _ - '- ; af ter reactor trip for a steam releaso equivalent to the rious opening, with failure to close, of the largest of any sin steam dump, relief or safety valve.
e following systems provide the necessary protection against an accidental depressurization of the Main Steam System.
- 1. Safety injection System actuation from any of the following: %
)
comegumi nal damagn. Ao N. #
Cart. eva r%ec.hr coole.%k SysM i t. 2-4 Revision dr
N. 7l a. Two-out-of-four low pressurizer pressure signals. l
- b. Two out of three low steam line pressure signal in any steam line.
36
- d. Two out-of-three high Containment pressure.
- 2. The overpower reactor trips (neu'cron flux and AT) and the reactor trip occurring in conjunction with receipt of the Safety injection Signal.
7 3 Redundant isolation of the main feedwater lines: Sustained high feed-water flow would cause additional cooldown. Therefore, in addition to the normal control action which would close the main feedwater valves following reactor trip, a Safety injection Signal would rapidly close all feedwater control valves, trip the main feedwater pumps, and close the feedwater pump discharge valves.
- 4. Trip of the fast-acting steam line stop valves (designed to close in less than 5 seconds) on:
36 a. High steam line pressure rate of change signal (2 of 3) in any j loop or low steam line pressure signal (2 of 3) In any loop.
- b. High-high Containment pressure.
15.2.13 1 Analysis of Effects and Consequences .
Method of Analysis The following analyses of a secondary system steam release are performed for this section.
- l. A full plant digital computer simulation to determine Reactor Coolant 7 System temperature and pressure during cooldown, and the effect of safety injection (Reference 7).
1 Analyses to determiner that the reactor does not return to criticality.
The following conditions, are assumed to exist at the time of a secondary steam systent release.
- 1. End of' ilfe shutdown margin at no load, equilibrium xenon conditions, and with the most reactive RCCA stuck in Its ful1y withdrawn position.
Operation of RCCA banks during core burnup is restricted in such a way that addition of positive reactivity in a secondary system steam release accident will not lead to a more adverse condition than the case analyzed.
15.2-35 Revision 36
- 2. A negative moderator coefficient corresponding to the end of life rodded core with the most reactive rod cluster control assembly in the fully withdrawn position. The variation of the coefficient with tempera- ]s ture and pressure is included. The keff versus temperature at 1000 psi corresponding to the negative moderator temperature coefficient used is shown in Figure 15.2.13-1.
- 3. Minioum capability for injection of 'Y :: : ----"^- boric acid solu-tion corresponding to the most restrictive single failure in the Safety injection System. This corresponds to the flow delivered by one char wakv c- ging pump delivering its full contents to the cold leg header. 4,ew Unbeb,
- r:: S L.*: ::!d must be swept from the safety injection lines downstream of the boron injection tank isolation valves prior to the delivery of boric acid (2^,000 ppm) to the reactor coolant loops. Thiseffecthasbeenallowed[forintheanalysis.
2000 4 The case studied is a steam flow of 248 lbs/second at 1100 psia from one steam generator with offsite power available. This is the maximum capacity of any single steam dump, relief or safety valve. Initial hot shutdown conditions at time zero are assumed since this represents the most conservative initial condition.
.Should the reactor be just critical or operating at power at the time of a steam release, the reactor would be tripped by the normal overpower protection when power level reaches a trip point. Following a trip at power the Reactor Coolant System contains more stored energy than at no load, the average coolant temperature is higher than at no load and there is appreciable energy stored in the fuel.
Thus, the addi tional stored. ener'gy is removed via the cooldown caused by the steam release before the no load conditions of Reactor Coolant System temperature and shutdown margin assumed in the analyses are reached. After the additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis which assumes no load condition at time zero. However, since
, the initial steam generator water Inventory is greatest at no load, the magnitude and duration of the Reactor Coolant System cooldown are less for steam line release occurring at power.
l S. In computing the steam flow the Moody Curve for fl/D = 0 is used.
l 6. Perfect:. moisture separation in the steam generator is assumed.
l Results The results presented are a conservative indication of the events which would occur assuming a secondary system steam release since it is postulated that all of the conditions described above occur simultaneously.
l Figure 15.2.13-2 shows the transients arising as the result of a steam flow of 248 lbs/second at 1100 psia with steam release from one steam generator.
i The assumed steam release is typical of the capacity of any single steam J
15.2-36 Revision (
.y r-o g
4 2 coo dump reIIef or safety valve. In this case safety inj ction is initiated automatically by low pressurizer pressure. Operatio of one centrifugal charging pump is considered. Boron solution at Mrdet ppm enters the v- h !
Reactor coolant System providing sufficient negative reactivity to.ma.i.er.as pes.vsM car e. "
- - -.. .__ 7:7 The cooldown for the case shown in l w=SS Figure 15.2.13-2 is more rapid than the case of steam release from all ,
steam generators through one steam dump, relief, or safety valve. The l transient is quita conservative with respect to cooldown, since no credit !
Is taken for the energy stored in the system metal other than that of the fuel elements or the energy stored in the other steam generators. Since the transient occurs over a period of about five minutes, the neglected stored energy is likely to have a significant effect in slowing the cooldown.
15.2.13 3 conclusions ,
The analysis shows that the criteria stated earlier in this section is satisfied.
N..__ e: -- n _-..m . m .. .. .. .
.,,..,.m., .___
c --
r r. he en aceshht depc,.ssurmbw JA em siemm sys4 m , A DN S datgw hmik s m J wmM,
%s casa. Sa less hmi4m3 4*w h s h W,.wp4ues c ,4 d*weib.4 w 5=.=Jesow 15.4. 2 .
e 15.1-37 Revision 7
% a:;-
15.2.14 'lNADVERTENT OPERATION OF ECCS DURING POWER OPERATION 15.2.14.1 Identification of Causes and Accident Description Spurious ECCS operation at power could be caused by operator error or a false electrical actuating signal. Spurious actuation may be assumed to be -
caused by any of the following:
- 1. High Containment pressure
- 2. Low pressurizer pressure
- 3. High steam line differential pressure 4
High steam line flow with either low average coolant temperature or low steam line pressure.
Following the actuation signal, the suction of the coolant charging pumps is diverted from the volume control tank to the refueling water storage tank. The valves isolating the baron injection tank (BIT) from the charging pumps and the valves isolating the BIT from the injection header then auto-matically open. The charging pumps then force-tehrh4y concentrated (M,000 2xc ppm) boric acid solution from the BIT, through the header and injection line and into the cold legs of each loop. The safety injection pumps also start automatically but provide no flow when the RCS is at normal pressure. The passive injection system and the low head system also provide no flow at normal RCS pressure.
An SIS signal normally results in a reactor trip followed by a turbine trip. However, it cannot be assumed that any single fault that actuates the SIS will also produce a reactor trip. Therefore, two different courses of events are considered.
Case A - Trip occurs at the same time spurious injection starts.
Case B - The Reactor Protection System produces a trip later in the transient.
Case A For case A the operator should determine if the spurious signal was transient or steady state in nature. The operator must also determine if the Safety injection Signal should be blocked. For a spurious occurrence, the operator would stop the safety injection and maintain the unit in the hot shutdown condition. if the ECCS actuation instrumentation must be repaired, future unit operation would be in accordance with the Technical Specifications.
Case B The Reactor Protection System does not produce an immediate trip, and the reactor experiences a negative reactivity excursion due to the injected 15.2-38 Revision d#
boron causing a decrease in reactor power. The power mismatch causes a drop in Tavg and coolant shrinkage. Pressurizer pressure and level drop, Load decreases due to the effect of reduced steam pressure on Ioad when che turbine throttle valve is fully open. If automatic rod control is used these effects are lessened until the rods have moved out of the core. -
The transient is eventually terminated by the Reactor Protection System low pressure trip or by manual trip.
The time to trip is affected by initial operating conditions including core burnup history which affects initial baron concentration, rate of change of boron concentration, Doppler and moderator coefficients.
Recovery from this incident for case B is made in the same manner described for case A. The only difference is the lower Tavg and pressure associated with the power mismatch during the transient. The time at which reactor trip occurs is of no concern for this occurrence. At lower loads coolant contraction is slower resulting in a longer time to trip.
15.2.14.2 , Analysis of Effects of Consequences Method of Analysis The spurious operation of the SIS system l{49nalyzed by employing the detailed digital computer program LOFTRAN. The code simulates the neutron kinetics, Reactor Coolant System, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, steam generator safety valves, and the effect of the safety injection system. The program computes pertinent plant variables including temperatures, pressures, and power level.
Because of the power and temperature reduction during the transient, operating conditions do not approach the core limits. Analysis of several cases shows the re=ults are relatively independent of time to trip.
i A typical transient is presented representing conditions at beginning of core life. Results at end of life are similar except that moderator feedback effects result in a slower transient.
The assumptions are:
i l 1. Initial Operating Conditions - the initial i'acs3r power and Reactor Coolant System temperatures are assumet a ;ct! Taximum values con-sistent with the steady state full powse ,pe, .. va including allowances for calibration and instrument errors.
- 2. Moderator and Doopler Coefficients of Reactivity - A low beginning of l i fe moder ator temperature coef fi cient was used. A low aosolute value Doppler power coefficient was assumed.
15.2-39 Revision 7
'foi., D c.
- 3. Reactor Control - The reactor was assumed to be in manual control.
4 Pressurizer Heaters - Pressurizer heaters were assumed to be inoperaole in oraer to increase the rate of pressure drop.
2000
- 5. Boron injection - At time zero two charging pumps inject ^,;;; ppm ~
borated water into the cold legs of each loop.
6 Turbine Load - Turbine load is assumed constant until the governor drives tne throttle valve wide open. The turbine load drops as steam pressure drops.
- 7. Reactor Trio - Reactor trip is initiated by low pressure at 1800 psia.
Results The transient response
- shown in Figures 15.2.14-1 and 15.2.14-2. Neutron flux starts decreasing diately due to boron injection but steam flow does r-ot decrease until seconds into the transient when the turbine throttle valves goes wide open. The mismatch between load and nuclear power causes Tavg, pressurizer water level, and pressurizer pressure to drop. The low pressure trip setpoint isreachedat([hsecondsandrods start moving into the core at(@) seconds. WDO
- H31L After trip, pressure and temperatures slowly rise since the turbine is tripped and the reactor is producing some power due to delayed neutron )
fissions and decay heat. ./
15.2.14.3 Conclusions Results of the analysis show that spurious safety injection with or without immediate reactor trip presents no hazard to the Integrity of the Reactor Coolant System.
DNB ratio is never less than the initial value, if the reactor does not trip immediately, the low pressure reactor trip is actuated. This trips the turbine and prevents excess cooldown thereby expediting recovery from the incident.
15.2.15 REFERENCES
. a. Gangloff, W. C., An Evaluation of Anticipated Operational Transients in Westinghouse Pressurized Water Reactors, WCAP-7486, May 1971.
- 2. Fairbrother, D. B.,Hargrove, H. G., WIT-6 Reactor Transient Analysis Computer Program Description, WCAP-7980, November 1972.
- 3. Hunin, C., FACTRAN, A Fortran Code for Thermal Transients in UO 3
Fuel Rod, WCAp-7908. June 1972. '
15.2-40 Revis ion d' !
- n. e.
4 Burnett, T. W. T., McIntyre, C. J., Buker, J. C., Rose, R. P., L9FTRAN Code Description, WCAP-7907, June 1972.
5 Al tomare, S. , Barry, R. F. , The TURTLE 24.0 Di f fus ion Deplet ion Code, WCAP-7758-A, February 1975 7
- 6. Bordelon, F. M.,
Calculation of Flow Coastdown Af ter Loss of Reactor .
Coolant Pump (PHOENIX Code), WCAP-7969, September 1972.
- 7. Geets, J. M.,
MARVEL - A Digital Computer Code for Transient Analysis of a Multiloop PWR System, WCAP-7909, June 1972.
- 8. Cooper, K. , Misells, V. , and Sterek, R. M. , Overpressure Protection 10 for Westinghouse Pressurized Water Reactors, WCAP-7769, Revision 1, June, 1972.
9 Geets, J. M., Salvatori, R. , Long Term Transient Analysis Program for 7
PWR's (BLK8UT Code), WCAP-7898, June 1972.
l l
15 2-41 Revision 10 L
o Table 15.2-1 (Continued) (Page'6 of 6)
Unit 1 Unit 2 Accident Events Time (sec.)
Accidental depressuriza-tion of the Reactor Coolant System Inadvertent Opening of one RCS Safety Valve 0 0 overtemperature AT trip reached 17.2 17.2
' Rods begin to drop 19 2 19.2 Minimum Dt!BR occurs 19 2 20.0 Accidental depressuriza-tion of the Main Steam System inadvertent Opening of One main steam safety or relief valve 0 0 156 Pressurizer Empties Jd[I 133 20,000 ppm boron reaches RCS loops Wir0 168 soon ee== leen== AS gSo inadvertent Operat; ion W W' of ECCS during Power Operation Charging pump's begin injecting borated water 0 0 Low pressure trip point ggg3 reached s&T 50 5 Rods begin to drop JPI ' 52.5 RevisionJdr
,s:: ' ,. - ' , _,"u.? ed
' s -
( i l
CORE AVERAGE TEMPERATURE NUCLEAR POWER AND STEAM FLOW (OF) '
(FF.ACT10N OF NOMINAL) 8 M ? $ $
- K; P 8
'- ~-
o o o o o ,
9 co g h g ~
8 8 8 8 8 8 8 -
8 8 O . . . . .
i 8 I 0
i e
l I
50 50 p. l l
100
/
2 100 h-.-- __../
2 \ 2 m 2 m
3 150 G 150 t -
O C 200 0,'g 200 fc 8 M M 250-- 250 t -
dam >
n C-4 E o$ 5 *m5 hm
.h 2 % o 300 :
- : 300 - -
Shm m %d
.o. > moz --
L M
> 0%a zmx
~
o d
O R~
+ Z Ln g o
PO I e
. s .
)
AI
!
- i . 9 S 0gb P
(
E 2gb^ '
R U
S Sgb S "
E R
P ~Ib R
E Z
I Ib^ "
R U
S S
Ib ^
E R
P eg,. b , g ,. t o 0 0 0 0 0 0 5 0 5 0 5 0 1 1 2 2 3 i
- xm OmO t
c
- 8b
)
3 T =8b -
F
( g.8 -
E g. 8 ^
M U *8 8 -
L -
O V 3o 8 -
R E
- 8 8" -
Z I *8 8 .
R U *8 8 ;
S S
E
- ' 8 R *8 8 P . 3 1
1 3
1 0 0 0 O 0 0 0 5 0 5 0 5 0 1 I 2 2 3 e-1m GmS
$ Md N%omm Sn .
E> E m* m2" @ mg -i $= om Ro" aCd2" '
orm %m$H32 .
czl ~
OkCCmzEQE$>4gz
)
n n
. c5.
5m wk
- ~ S, n m$ 58 t 2@ Z e,- '
600 00 550.00 - ..
- 500.00 .
s"
~
/
450.00 --
<o
, y 400. 00 -- ..
8 v
350 00 -- ..
300.00 --
250.00 1 f
2500.0 ' '
2250.0 - --
M 2000.0 -
h 1750. 0 -- --
W- 1500.0 -- --
[S 1250.0 -- --
M 1000.00 -
750.00 -- --
8 8 8 8 8 8 o
8 8
cu 8
m 8, 8 8 c w TIME (SEC)
O 2500.0 '
_ 2000 0 -
Z E 1000.00 --
!= 0.O ~
w
" -2000.0 --
-2500.0 '
8 8 8 8 8 8 o e o e o e o o S 8 8 TIME (SEC)
TRANSIENT RESPONSE FOR A STEAM LINE BREAK EQUIVALENT TO 248 LBS/SECOND AT 1100 PSIA WITH OFFSITE POWER McGUIRE NUCLEAR STATION Figure 15.2.13-2 Revision 7 New Figure
15.4.2 MAJOR SECONDARY SYSTEM PIPE RUPTURE
) 15.4.2.1 Major Rupture of a Main Steam Line l'5.4.2.1.1 Identification of Causes and Accident Description The steam release arising from a rupture of a main steam line would result in an initial increase in steam flow which decreases during the accident as the steam pressure falls. The energy removal from the Reactor Coolant System causes a reduction of coolant temperature and pressure, in the presence of a negative moderator temperature coefficient, the cooldown results in a re-duction of core shutdown margin. If the most reactive RCCA is assumed stuck in its fully withdrawn position after reactor trip, there is an increased possibility that the core would become critical and return to power. A return to power following a steam line rupture is a potential problem mainly because of the high power peaking factors which exist assuming the most 7 reactive rod cluster control assembly to be stuck in its fully withdrawn position. The core is ultimately shut down by the boric acid injection delivered by the Safety injection System.
The analysis of a main _ steam line rupture is performed to demonstrate that the following criterion is satisfied:
- 1. Assuming a stuck RCCA with or without offsite power, and assuming a single failure in the engineered safeguards, the core remains in place and intact. Radiation doses are not expected to exceed the guidelines of 10CFR100.
although DNB and possible clad perforation following a steam pipe rupture are not necessarily unacceptable, the following analysis, in fact, shows that no DNS occurs for any rupture assumin'g the most reactive assembly stuck in its fully withdrawn position.
The following functions provide the necessary protection for a steam line rupture:
- 1. Safety injection System actuation from any of the following:
- a. Two-out-of-three low steamline pressure signals in any steamline.
- b. Two-out-of-four low pressurizer pressure signals.
- c. Two-out.-of-three higit Containment pressure signals.
- 1. The overpower reactor trips (neutron flux and AT) and the reactor trip occurring in conjunction with receipt of the safety injection signal.
7 3 Redundant isolation of the main feedwater lines: Sustained high feed-water flow would cause additional cooldown. Therefore, in addition to the normal control action which closes the main feedwater valves, a
~~,
15.4-5 Revision 30
safety injection signal rapidly closes all feedwater control valves, trips the main feedwater pumps, and closes the feedwater pumo dis- 3 charge valves.
7 ,1
- 4. Trip of the fast acting steam line stop valves (designed to close in less than 5 seconds) on:
- a. Two-out-of-three low steamline pressure signals in any one loop.
30
- b. Two-out-of-three high-high containment pressure signals.
- c. Two-out-of-three high steamline pressure rate signals in any one loop (used.only during cooldown and heatup operations.
Each main steam line is provided with a fast acting isolation valve located outside the Containment immediately downstream of the steamline safety valves This is a signal actuated stop valve to prevent flow in both directions, and q would fully close within 10 seconds of a large break in the steam line. For breaks downstream of the isolation valves, closure of all valves would com-pletely terminate the blowdown. For any break in any location no more than one steam generator would blowdown even if one of the isolation valves fails to close.
mw ruw.s ws rs msWka m h sw.- gemm4. We ~1' *N
'hf S t - - -- %.,
- , a ... ... - , .._..::;-'., J,.....:; S :I '- - '- '- rtrf '- i Hwea.t of the steam generators. effective throat area of the nozzles R 1.4 sq. f t. , which is considerabl less.than the main steam pipe, and thus the nozzies aiso serve to Iimit he maximum steam fIow for a break at any location. Kg,sa how resMc.hocs vshca. b.
7 15.4.2.1.2 Analysis of Effects and Consequences Method of Analysis The analysis of the steam pipe rupture has been performed to determine:
- 1. 'The core heat flux and Reactor Coolant System temperature and pressure resulting from the cooldown following the steam line break. The M*R964- LM (Reference / code has been used.
- 1. The thermal and hydraulic behavior of the core following a steam line break. A detailed thermal and hydraulle digital-computer code, THINC, has been used to determine. If CNE occurs for the core conditions computed in (1) above The following conditions were assumed to exist at the time of a main steam {
line break accident.
- 1. End of life shutdown margin at no load, equilibrium xenon conditions, and the most reactive RCCA stuck in its fully withdrawn position: Ope ra-tion of the control rod banks during core burnup is restricted in such a way that addition of positive reactivity in a steam line break accident would not lead to a more adverse condition than the case analyzed.
D 15.4-6 Revis ion J6
- 2. The negative moderator coefficient corresponding to the end of life rodded core with the most reactive RCCA 11 the fully withdrawn position: The variation of the coefficient with temperature and pressure has been included.
'/-
The k fr versus temperature at 1000 ps! corresponding to the negative moderator temperature coefficient used is shown in Figure 15.2.13-1. The effect of power generation in the core on overall reactivity is shown in Figure 15.4.2-1.
The core properties associated with the sector nearest the affected steam generator and those associated with the remaining sector were conserva-tively combined to obtain average core properties for reactivity feedback calculations. Further, it was conservatively assumed that the core power distribution was uniform. These two conditions cause underprediction of the reactivity feedback in the high power region near the stuck rod. To verify the conservatism of this method, the reactivity as well as the power distribution was checked for the statepoints shown on Table 15.4.2-1.
These core analyses considered the Doppler reactivity from the high fuel temperature near the stuck RCCA, moderator feedback from the high water enthalpy near the stuck RCCA, power redistribution and non-uniform core Inlet temperature effects. For cases in which steam generation occurs. In the high flux regions of the core, the effect of void fnrmation was also included. It was determined that the reactivity employed in the kinetics analysis was always larger than the reactivity calculated including the above local effects. for all statepoints in Table 15.4.2-1. This result verified conservatism; i.e., underprediction of negative reactivity feed-back from power generation. .
3 Minimum capability for injection of ':s -.. ... ..mm boric acid (^^,see 2oche ppm) solution corresponding to- the most restrictive single failure in the safety injectico system. The Emergency Core Cooling System consists of three systemsr I)' the passive accumulators, 2) the Residual Heat Removal Systems, and 3) the Safety injection System. Only the Safety injection System is modeled for.the steam line break accident analysis.
The actual mode L.DFTRAN ling&of the Safety injection System inde 6 E is described in Reference
! wateraresho/. wnThe calculated on Figures transient 15.4.2-2 delivery times and 15.4.2-3 for the borated The injection curve used is shown in Figure 15.4.2-3 This corresponds to the flow delivered by one charging pump delivering its full flow to the cold leg header. No credit has been takerr for the low concentration borated water, which must be swept from the. lines downstream of the boron injection tank isolation valves prior to the delivery of h * ? n.... _.: . borated. water to the reactor coolant loops For the cases where offsite power is assumed, the sequence of events in the Safety injection System is the following. After the generation of the safety injection signal (appropriate delays for instrumentation, logic, and. signal transport included), the appropriate valves begin to operate and the high head safety injection pump starts. in 12 seconds, the valves are assumed to be in their final position and the pump is assumed to be at full speed. The volume containing the low concentration borated
^CO ppm borated
^
i waterissweptfromthelines,ofcourse,beforetheM,hinherently water reaches the core. This delay, described above, is l
Included in the modeling.
15.4-7 Revision (
dos;849e
In cases where offsite power is not available, an additional 10 second delay is assumed to start the diesels and to load the necessary safety ,%
injection equipment onto them.
- 4. Design value of the steam generator heat transfer coefficient including allowance for fouling factor is used in the analysis.
5 Since the steam generators are provided with integral flow restrictors with a 1.4 sq. ft. throat area, any rupture with break area greater than 1.4 sq. f t. , regardless of location would have the same effect on the NSSS as the 1.4 ft2 break. The following cases have been considered in determining the core power and Reactor Coolant System transients:
- a. Complete severance of a pipe, with the unit initially at no load conditions, full reactor coolant flow with offsite power available.
- b. Case (a) above with loss of offsite power simultaneous with the steam line break and initiation of the safety injection signal.
Loss of offsite power results in coolant pump coastdown.
- 6. Power peaking factors corresponding ta one stuck RCCA and non-uniform core inlet coolant temperatures are determined at end of core life. The coldest core inlet temperaturer are assumed to occur in the sector with the stuck rod. The power peaking factors account for the effect of the local void in the region of the stuck control assembly during the return to power phase following the steam Ilne break. This void in conjunction' the large negative moderator coefficient partially offsets the .
effect'of che s stuck assembly. The power peaking factors depend upon the core power,. temperature,. pressure, and flow, and, thus, are different for each case studied.
The core parameters used for each of the two cases correspond to values determined from the respective transient analysis. Five time points i used for each case are presented in Table 15.4.2-1.
Both the cases above assume initial hot shutdown conditions at time zero since this represents the most pressimistic initial condition. Should the reactor be just critical or operating at power at the time of a l
steam line break, the reactor would be tripped by the normal overpower protection system when power level reaches a trip point. Following a trip at power the Peactor Coolant Syster contains more stored energy than at ne load, the average coolant temperature is higher than at no I load and there is appreciable energy stored in the fuel. Thus, the l additional stored energy is removed via the cooldown caused by the steam 1 Tne break before the no Toad: conditions of Reactor Coolant System tempera- '
ture and shutdown margin assumed in the analyses are reached. After the ~
additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis which assumes no load condition at time zero.
( However, sir.ce the initial steam generator water inventory is greatest at no load, the magnitude and duration of the Reactor Coolant System cooldown are less than steam line breaks occurring at power. , 'h, a
15.4-8 Revision 7 '
New Page
- 7. In computing the steam flow during a steam line break, the Moody curve 3 (Reference 6) for f1/D = 0 is used.
- 8. The Upper Head injection (UHl) is simulated. The actuation pressure for the UHI is near the saturation pressure for the inactive coolant in the upper head. The insurge of cold UHI water keeps this inactive coolant from flashing and thus retarding pressure decrease. The effect of UHI Is a faster pressure decrease which in turn permits more safety injection flow into the core. These effects are very small and results are not significantly affected.
7 Results The results presented are a conservative indication of the events which would occur assuming a steam line rupture since it is postulated that all of the conditions described above occur simultaneously.
Core Power a:M Reactor Coolant System Transient Figure 15.4.2-2 shows the Reactor Coolant System transient and core heat flux following a main steam line rupture (complete severance of a pipe) at initial no load condition (Case a). Offsite power is assumed available so that full reactor coolant flow exists. The transient shown assumes uncontrolled steam release f rom only one steam generator. Should the core be critical at near zero power when the rupture occurs, the initiation of safety injection by 30 low steam line pressure, will trip-the reactor. Steam release from more than one steam generator would be prevented by automatic trip of the fast acting stop valves in the steam lines by the low steam line pressure signal. Even with the failure of one valve,. release is limited to no more than 10 seconds for the other steam generators while the one generato'r blows down. The steam 1Ine stop valves are designed to be fully closed in less than 5 seconds from receipt of a closure signal.
The steam flow on Figures 15.4.2-2 and 15.4.2-3 represents steam flow from the faulted steam generator only. In addition, all steam generators were assumed to discharge through the break for the first 10 seconds.
7 As shown in Figure 15.4.2-2 the core attains criticality with the RCCA insert-ed (with the design shutdown assum!ng one stuck RCCA) before boron solution at 26,400* ppm enters the Reactor Coolant System from the ECCS, A peak heat fludiess. tharr the nominal full power value is attained.
l "ZOCO '
The calculatiorr assumes the boric. acid is mixed with, and diluted by the water flowing irr the Reactor Coolant System prior to entering the reactor core. The concentration after mixing depends uport the relative flow rates in the Reactor Coolant system and.In the ECCS. The variation of mass flow rate in the Reactor Coolant System due to water density changes is included in the calculation as is the variation of flow rate in the ECCS due to changes in the Reactor Coolant System pressure. The ECCS flow calculation includes the line losses in the system as well as the pump head curve.
m 15.4-9 Revision JT
l
- l No credit has been taken for the low concentration boron which enters the Reactor Coolant System prior to the 497996 ppm boric acid. "')
1aea j Figure 15.4.2-3 shows the responses of the salient parameters for Case b which corresponds to the case discussed above-with additional loss of offsite power at the time the safety injection signal is generated. The ECCS delay time includes 10 seconds to start the diesel and 12 seconds to start the safety injection pump. In this case criticality is achieved later and the core power increase is slower than in the similar casa with offsite power available. The ability of the emptying steam generator to extract heat from the Reactor Cool-ant System is reduced by the decreased flow in the Reactor Coolant System. For this case the peak power remains less than the nominal full power value. The time sequence of event l's shown in Table 15.4-1.
It should be noted that following a steam line break only one steam generator blows down completely. Thus, the remaining steam generators are still availa-ble for dissipation of decay heat af ter the initial transient is over. In the case of loss of offsite power this heat is removed to the atmosphere via the atmospheric dump valves which have been sized to cover this condition.
Margin to Critical Heat Flux A DNB analysis was performed for both cases. Five points for each case were examined. It was found that all cases had a minimum DNBR greater than 1.30.
15.4.2.1.3 Conclusions -
The analysis has shown that the criteria stated earlier in this section are satisfied. .,
(h Although DNE and possible clad perforation following a steam pipe rupture are not necessarily unacceptable and not precluded in the criterion, the above analysis, in fact, shows that no DNB occurs for any rupture assuming the most reactive assembly stuck in its fully withdrawn position.
15.4.2.2 Major Rupture of a Main Feedwater Line 15.4.2.1.1 Identification of Causes and Accident Description A major feedwater- IIna ruptura is defined as a- break in a feedwater line large enougtr to prevent the addition of sufficient feedwater to the steam l generators to maintain shell-side fluid inventory in the steam generators.
If the break. l~s. postulated irr a feedline between the check valve and the steam generator,. fluid. frarr the steasr generator may also be discharged througtr the brealc . Furs.r, a break. in- this locatforr could preclude the subsequent addition of auxiliary feedwater to the affected steam generator.
(A break upstream of the feedline check valve would affect the NSSS only as a loss of feedwater - See Subsection 15.2.8).
Depending upon the size of the break and the unit operating conditions at the time of the break, the break could cause either a Reactor Coolant System cooldown (by excessive energy discharge through the break), or a Reactor ~
Coolant System heatup. Potential Reactor Coolant System cooldown resulting 'T
-J 15.4-10 Revision MP
";_ a:;r
Table 15.4-1 (Page 1 of .4) w' Time Secuence of Event's of Condition IV Events Accident Event Time (sec.)
Major Secondary System Pipe Rupture 7
- 1. Case a Steam line ruptures 0 g (withM offsite Pressurizer empty & b power available) Criticality attained + 13 38 se ppm boron N ;ees reaches core M lI
- 2. Case b Steam Line ruptures 0 withe.k .W d Criticality atrained -W" W E 7
gu,. veMk) Pressurizer empty 20,0^t ppm baron X $ 16 l reaches core y $ 30 l Feedwater System Pipe Break
- 1. With Offsite Po p r ' Main feedline rupture 10 Available i occurs 30 Low-low steam generator 30 level reactor trip set-point reached in ruptured steam generator 38 I Rods begin to drop 32 I Auxillary feedwater is 91 delivered to intact steam 30 generators .
Low steamline pressure 246 setpoint reached in ruptured steam generator 38 AlI main steamlIne o253 Isolation valves close Steam generator safety 467 valve setpoint reached in intact steam generators N
)
s Revision M
l Taole !5 k.2-1 (Page 1 of 2) l .
Core Parameters (Used in) Steam Break DNB Analysis 30 l l
Time Point With Offsite Power l l
1 2 3 4 5 Reactor Vessel Inlet Temperature to Sector Containins Affected Steam Generator W4 4Mr-8 W glo .4 ler7.6 W. S l
$4 t2. .% 4 Lt.2 403.% 409.~2.
Reactor Vessel inlet Temperature 38 to Remaining Sector f@6" 1 4p 1 u g D .I.
Wu9%.4 4pff'8 u97.4 W
%%. 4 SQL.o 100 100 100 100 100 l 30 l!!CSFlow (%)
Heat Flux (% of 3L25MW) El M M M M i 19 ."1 19.% 19.9 19 S 19 S l 38 Time (seconds) 2&fC .WTC Mago Krf0 W '
t40 14, o 2.0 0 %"3 b RCS Pressure Psia) W lasWf'"4 IM M .Ji@4 ggg2;c no93.4 11 9 "1.3 17057 1201 0 Revisiong
Table 15.4.2-1 (Page 2 of 2)
Core Parameters Used in. Steam Break DNB Analysis Time Point WIthout Offsite Power 1 2 3 4 5 Reactor Vessel inlet Temperature to Sector Containing Affected %l.%
Steam Generator 4Mr:1 #4' 4W5 4 E--6 42 M 392.9 W 576. t %23 354.~4 Reactor Vessel Inlet Temperature M)
CIS.
W 4W3 4M.b @ .2 5 g2."1 to Remaining Sector 522 922.b 522 RCS Flow (%) 31WT M W! 2R5 2f"D .
- 15. 13 12. ns . to.
Heat Flux (S of 3425 Mwt) 84 . 4HS 1H-t id M 11 . 4 M . *l 16 9 1%.7 tt.$
Time (seconds) 2Eff0 3GftT M , Wet?" Jeer"tf ro go 90 too tse RCS Pressure (Psia) 10 W 6 IW 10 W 4 10 M 8 1(M&-6 12%t.0 12 % .9 129 5 nos.- ss t'b.)
Revision /
2500.0 ' '
2250.0 - --
M 2000.0 - --
S 1750.0 --
I, m --
M< 1500.0 -- --
m
% 1250.0 -- r --
M 1000.00 -- --
750 00 -- --
500.00-- - c.s ._.
2500.0 ' ' ' ' '
_ 2000.0 -- --
1
$ 1000.00 -- --
$ 0.0 '
b l l , roco.e - { -.
w
" -2000.0 -- --
-2500.0 , : : : :
7 3.5000 .
v 3.0000 - - --
@_ 2.5000 - --
2 o z E 2. 0000 - --
du 1.5000 - -
I 1.0000 - - --
w
- .50000
( --
- 0. 0 1 t
~
600.00 ' ' ' '
- a. 550.00 - --
1 W 500.00 -- --
l y"o 450.00 -- --
t t
, < a 400. 00 --
w o
w 350.00 -- --
300.00 -- -
250.00 ; f i o o o f
o f
o e
o o e o e o e o o 2 2 8 5 8 8 TIME (SEC)
TRANSIENT RESPONSE TO STEAM LINE BREAK DOWNSTREAM OF FLOW MEASURING I
N0ZZLE WITH SAFETY INJECTION AND r, 0FFSITE POWER
\
McGUlRE NUCLEAR STATION Figure 15.4.2-2 :
Revision 38
2500.0 ' ' '
2250.0 - --
- 2 2000.0 - --
m - 1750.0 -- --
M M4 1500.0 -- --
m S 1250.0 --
~~
M 1000.00 -- --
750.00 -- --
500.00 , i- ' ~
" -~
2500.0" 2000.0 -- -.
1
$ 1000.00 -- -.
$ 0. 0 N-
?.
, -soce.o -
4 w
" -2000.0 -- -.
-2500.0 1 -
A
, 3.5000 '
y 3.0000 - -
@_x 2.5000 - ,
omzo 2.0000 - --
du o 1.5000 - ,
E 1.0000 --
..I w
Di .50000 --
- 0. -
~ ~ ~
~-~~ ~'
- 0. W
- a. 550.00 -
E -.
ht 500.00 -- -.
y "* 450.00 --
5
< a. 400. 00 --
w -.
5 v
350.00 -- -.
i 300.00 -- ..
250.00 o o o e o e o o o o o o o o o e o e o d a h h h TIME (SEC) l TRANSIENT RESPONSE TO STEAM LINE I
BREAK DOWNSTREAM OF FLOW MEASURING
! N0ZZLE WITH SAFETY INJECTION WITH-OUT OFFSITE POWER
( McGUIRE NUCLEAR STATION l Figure 15.4.2-3 i
l Revision 38 l
is.4.6.1 Tr i o Ft.act ivi ty insertion ,
l The trip reactivity insertion assured is given in Table 15.4.6-1 cnd includes I the effect of one stuck RCCA. These values are rcduced by the ejected rod j 7 reactivity. The shutdown reactivity was simulated by dropping a rod of the required worth into the core. The start of rod motion occurred 0.5 seconds after the high neutron flux trip point is re' ached. This delay is assumed to consist of 0.2 seconds for the instrument channel to produce a signal, 0.15 seconds for the trip breaker to open and 0.15 seconds for the coil to release the rods. A curve of trip rod insertion versus time was used which assumed that insertion to the dashpot does not occur until 2.2 (unit 1), 3 3 (Unit 2) ,
42 seconds after the start of fall. The choice of such a conservative insertion rate means that there is over 1 second after the trip point is reached before significant shutdown reactivity is inserted into the core. This is a parti-7 cularly important conservatism for hot full power accidents.
The minimum design shutdown margin available for the units at HZP may be reached only at end of life in the equilibrium cycle. This value includes an allowance for the worst stuck rod, an adverse xenon distribution, 38 conservati.ve Doppler and moderator defects, and an allowance for calculational uncertainties. Physics calcu-lations for the units have shown that the effect of two stuck RCCA's (o,ne of which is the worst ejected rod) is to reduce the shutdown by about an .
additional 1% ak. Therefore, following a reactor trip resulting from an RCCA ejection accident, the reactor would be subcritical when the core returns to HZP.
Depressurization calculations have been performed for a typical four-loop unit assuming the maximum possible. size break (2.75 inch diameter) located in the reactor pressure vessel head. The results show a rapid pressure drop and a decrease in system water mass due to the break. The Safety injection
^# low pressurizer pressure 2 2 ' - '
System is actuated on W - ' : ---
wbm 6 one minute after the break. The RCS pressure continues to drop and reaches saturation (1100 to 1300 psi depending on the system temperature) in about two to three minutes. Due to the large thermal inertia of primary 7 and secondary system, there has been no significant decrease in the RCS temperature below no-load by this time, and.,the depressurization itself has caused an increase in shutdown margin by about 0.2% ak due to the pressure coefficient. The cooldown transient could not absorb the available shutdown margin until more than 10 minutes after the break. The addition of ' T ',
borated (^ ,^^ ppm) safety injection flow starting one minute after the break is more than sufficient to ensure that the core remains subcritical during the coldown.
2000 Cases are presented for both beginning and end of life of zero and full power.
Beginning of Cycle, Full Pcwer Control bank D was assumed to be inserted to its insertion limit. The worst 42 l ejected rod worth and hot chtnnel factor were 20% (Uni t 1), .23% (Uni t 2) AK l and 7.1 (Unit 1) , 5.9 (U- ? t 2) respectively.
15.4-29 RevisionJ4
. _ _ _ _ _ _ _ _ _ _ _