ML13319A798
| ML13319A798 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 11/20/1987 |
| From: | Medford M Southern California Edison Co |
| To: | NRC Office of Administration & Resources Management (ARM) |
| References | |
| NUDOCS 8711230218 | |
| Download: ML13319A798 (68) | |
Text
Southern California Edison Company P. 0.
BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD, CALIFORNIA 91770 M. 0. MEDFORD TELEPHONE MANAGER OF NUCLEAR ENGINEERING NOvember 20, 1987 (818) 302-1749 AND LICENSING U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 Gentlemen:
Subject:
Docket No. 50-206 Engineered Safety Features Single Failure Analysis San Onofre Nuclear Generating Station Unit 1 By letter dated November 6, 1987, the NRC was provided with the Engineered Safety Features Single Failure Analysis Report for San Onofre Unit 1. SCE committed to provide the design descriptions for the modifications to the auxiliary feedwater system, the steam/feedwater flow mismatch trip and additional modifications to resolve the identified single failure concerns.
The purpose of this letter is to submit the above information.
Accordingly, Enclosure 1 to this letter provides design descriptions for the integration of the third auxiliary feedwater pump, the steam/feedwater flow mismatch trip, and main feedwater isolation. Additional modifications to resolve other single failure concerns are currently being evaluated. Design descriptions for the final modifications will be provided by March 31, 1988. provides the revised auxiliary feedwater system transient analysis. This analysis reflects the Cycle X auxiliary feedwater system configuration with the third automated auxiliary feedwater pump. The analysis also credits the availability of the single failure-proof steam/feedwater flow mismatch trip above 50% power (see design description). The revised analysis eliminates credit for the safety injection/high containment pressure trip for feedline breaks inside containment as discussed in SCE's July 2, 1987 submittal.
The evaluation of the radiological consequences of a feedline break outside containment is currently being reviewed. The results of this review will be provided as soon as it is completed.
If you have any questions or require additional information regarding this subject please contact me.
Very truly yours, PDR AD0CK 05000206 cc:
- 3. 0. Bradfute, NRR Project Manager, San Onofre Unit 1
- 3. B. Martin, Regional Administrator, NRC Region V F. R. Huey, NRC Senior Resident Inspector, San Onofre Units 1, 2 and 3 CYCLE X MODIFICATION DESIGN DESCRIPTIONS for AUXILIARY FEEDWATER SYSTEM UPGRADE STEAM/FEEDWATER FLOW MISMATCH TRIP MAIN FEEDWATER SYSTEM ISOLATION SAN ONOFRE UNIT 1
Cycle X Modification Design Descriptions for Auxiliary Feedwater System Upgrade Steam/Feedwater Flow Mismatch Trip Main Feedwater System Isolation San Onofre Unit 1 Introduction SCE previously committed to upgrade the auxiliary feedwater system (AFW) by automating and integrating the third AFW pump (installed to meet fire protection requirements during the Cycle IX refueling outage). Subsequently, SCE identified single failure susceptibilities of the Reactor Protection System (Steam/Feedwater Flow mismatch trip) and the Engineered Safety Features (main feedwater isolation and recirculation). Accordingly, design description for the integration of the third AFW pump, the steam/feedwater flow mismatch trip and main feedwater isolation are provided below. Modifications to correct the single failure susceptibilities of the recirculation system will be provided at a later date.
I. Auxiliary Feedwater System (AFW) Upgrades A) Add two new AFW flow control valves (FCVs) to the existing configuration so that two FCVs in parallel are provided on each AFW line. The parallel valves on each line will be on separate electrical trains. Train F FCVs will fail closed on loss of control power and the Train G FCVs will fail open on loss of control power.
B) The control system for the new FCVs will be identical to that for existing FCVs.
C) Install a venturi/orifice downstream of the AFW flow control valves in each of the three AFW lines. The venturis/orifices are to be sized so as to prevent Pump GlOS run-out and exceeding water hammer flow restrictions to depressurized steam generators. A locked closed bypass valve will be provided for each venturi/orifice.
D) A venturi/orifice is to be placed in the discharge of the GlOW pump so as to prevent exceeding the maximum flow limit to each steam generator under any sequence of events independent of the number of steam generators available. A manual locked closed bypass shall be provided for Dedicated Safe Shutdown operation of GlOW.
E) Realign G10 to the same electrical train as G1OS (i.e., Train F).
F) Add GlOW to other electrical train (i.e., Train G).
-2 G) Revise the existing control room panel to include the same controls, indication and alarms for GlOW as exist for the other motor driven AFW pump. The control room panel will be revised in accordance with human factors guidelines as established by the Control Room Design Review. This will include:
- 1. Suction and discharge pressure indication and low suction pressure alarm.
- 2. Control switches and position indication of GlOW discharge valve, FV-3110. When AFWS is in auto mode, FV-3110 shall open on a Train G AFWS auto initiation signal.
- 3. Pump manual Start/Stop switches with running lights and ammeter.
H) Remove the GlOS low suction/discharge pressure trips, but retain the indication and alarm functions of the instrumentation. Pump runout protection will be provided by the venturis/orifices in each of the three AFW discharge lines and verified by pump testing.
I) Provide a manual transfer switch for selecting Dedicated Safe Shutdown (DSD) or normal Safety Related power for GlOW locally.
This switch will provide isolation of the normal and DSD power supplies.
- 3) Modify the auto-mode control circuit of each pump and respective discharge valve to operate as follows upon receipt of the steam generator low level signal (AFWS auto initiation).
- 1. Lead Train G Pump (GlOW) immediately provides flow and tubing drive Train F pump (GlO) placed in "warm-up mode."
- 2. Lag Train F pumps (GlOS and GlO) start upon a no flow signal from the GlOW pump discharge manifold and then the Train F pump discharge valves open.
- 3. Train F pumps (GlOS and G10) will stop and discharge valves close when there is a flow signal from the GlOW discharge manifold.
- 4. Separate Train F flow switches will be provided on the GlOW discharge manifold for control of the Train F pumps and control of the Train F pump discharge valves to prevent postulated single failures from causing inadvertent operation of both trains.
K) All work will be classified as Safety-Related, Seismic Category A.
(See Figure 1.)
-3 II. Steam/Feedwater Flow Mismatch Reactor Trip A) The current mismatch trip logic will be revised to provide a trip signal to the reactor trip circuit, two out of three reactor trip logic, for a high steam/feedwater flow mismatch as well as the original low flow mismatch. The setpoint for the high mismatch will be defined as part of final design.
B) The high pressurizer level trip will be retained at the 50% setpoint.
C) A P-8 permissive will be added to the revised steam/feedwater flow mismatch trip. This permissive will arm the trip at or above 50%
power. This feature is to improve plant availability by reducing the probability of unnecessary plant trips during reduced power operation and startup.
D) A minimum floor value will be provided for the main steam header pressure signal in each of the channelized steam flow calculator modules to prevent loss or spurious initiation of the steam/feedwater flow mismatch trip due to a downscale failure of PT-459.
E) The power supplies and signal paths for each steam/feedwater flow mismatch instrument loop will be channelized. Channelization of the power supplies and signal paths will prevent loss of more than one steam/feedwater flow mismatch channel due to a postulated single failure.
F) Isolation will be provided between the PT-459 instrument loop and each steam/feedwater flow mismatch channel and its associated feedwater control loop to prevent loss of the steam/feedwater flow mismatch channels due to postulated single failures of the PT-459 loop or the non-qualified control loops.
G) All work will be classified as Safety-Related, Seismic Category A.
(See Figure 2.)
III. Main Feedwater System A) Replace the solenoid valves on the main feedwater control valves (FCV-456, -457 and -458) and their bypass valves (CV-141, -142 and -143) with replacements environmentally qualified (EQ) to 10 CFR 50.49 requirements.
B) Replace the actuators on MOVs 20, 21 and 22 with replacements environmentally qualified (EQ) to 10 CFR 50.49 requirements.
C) Change the power source on the solenoid valve circuits for feedwater valves FCV-457 and FCV-458 and respective bypass valves CV-144 and CV-143 to Train 2.
-4 D) Provide N2 backup to the main feedwater control valves.
E) Modify or replace the actuators for the main feedwater FCVs, MOVs and bypass CVs to ensure valve closing time is sufficient to meet transient analysis requirements.
F) Provide a new solenoid valve (redundant) to each of the bypass CVs, powered and sequenced from the opposite train. This will provide redundant actuation for each bypass CV.
G) Change motive and control power for MOV-22 from MCC-3 to MCC-1, 1A or 1B (which are outside harsh areas during main steam line breaks).
H) All work will be classified as Safety-Related, Seismic Category A.
9096F
Figure 1 AUXILIARY FEEDWATER SYSTEM UPGRADE cowrAINMENr FtMo AFW hw cow arw Cn k
L.
u n k Is t
4ZOO VLY Met
~
~
~
~
A Ha OR
-*11.N6t
Figure 2 STEAM/FEEDWATER FLOW MISMATCH TRIP LOOP-6 NFST-A LOOP-A RACK-10 STAMFLE XISTING 10-50 ma RACKn(>..
YE; STEAM FLWAC (FT' EXISTING LOOP-C ESw 0-10 L 0-lO1 STEAM FLOE..
Us0 TO EXISTING ALAM P-STEAM SIGNAL SPS m-200 MICFL HICRO F-200
- -------------- CONTACT FW FL FW SIGNAL FLOW OUTPUT TO 2/3 TRIP MATRIX FT EXISTING
)v 0lSw 1-50m ST U-O P20------
S(
/P-8 PERMISSI VE llH -tY STH FLOE 1-9VIW.
F-F 0-IOV RO --
S-FC Isoaln AC FW-ggi
-ii -----
TifW 1
-f STEAM FLW GFROM P-459 LOOP-A NEST-B LOOP-B RACK-IO MAY BE DELETED DURING FINAL DESIGN 0-STEM L A ---- -----------------------
111.0-46 1-50mA 0-t0OW __
0-1OW STEAM..
moTO EXISTING ALARM g
-200 STEAM SIGL SP-200 msSP-200
-I/
CONTACT FW FLOE LMj FW SIGNAL FLOE 0-0VFIF IC OUTPUT TO 2/3 TRIP MATRIX EXISTING 0
Al
--- i-- --
10-5MA SIT V
0l
' STM FLOE 1-9V W 8 P I
VE
.-0-10-SP-200 -----------------------------------------
I y ISOLATIO FIF INTEGRATOR 1-9W FUF19 INPUT FROM PT-459. LOOP-A STEAM FLOWNTSTIN NEST-C LOOP-C RACK-11
(
0-50A
_-lo_
e-OY STEAM TO EXISTING ALARM P -200 STEAM SIGNAL SP-200 Sme20 MICRO MICRO P -
FW FLOE I/V i FW SIGNAL FLOW 0-IOV FIF -Ma OUTPUT TO 2/3 TRIP MATRIX (TEXISTING 0
WA0V 4
1-50mA STN 0-10Y STN FLOE 1-9V
[Y--4120AC FFF I-9V STN 1-9V YE-458 FF 0----0V-ISOLATI
-IEGATO-F EXISTING NEW EXISTING
0I ENCLOSURE 2 Cycle X Auxiliary Feedwater System Transient Analysis San Onofre Unit 1
.g Auxiliary Feedwater System Transient Analysis for Cycle X San Onofre Unit 1 BACKGROUND During the Cycle X refueling outage, SCE committed to automating and integrating the third AFW pump (installed to meet fire protection requirements during the Cycle IX refueling outage) into the AFW system. The AFW system must be capable of meeting minimum flow requirements established by analysis of Loss of Normal Feedwater (LONF) and Feedline Break (FLB) events, and of not exceeding maximum flow limits set by water hammer. LONF and FLB analysis was necessary to supplement the previous analysis and AFW design alternatives along with Reactor Protection System alternatives for these events.
ANALYSIS The LOFTRAN code was used to simulate the transients. The assumptions applicable to all cases are presented below. The assumptions specific to each of the five cases are presented separately. All assumptions, including initial conditions, were selected so to maximize the consequences of the applicable transient.
General Assumptions
- 1. The initial pressurizer pressure is 30 psi above its nominal value of 2100 psia.
- 2. Initial steam generator water level is at the nominal value.
- 3. A High Pressurizer Water Level reactor trip setpoint of 50% narrow range span (NRS) plus 4% NRS for uncertainties is assumed with a delay time of 2 seconds.
- 4. A High Pressurizer Pressure reactor trip setpoint of 2260 psia (including uncertainties) is assumed with a delay time of 2 seconds.
- 5. A loss of reactor coolant pumps with SONGS 1 specific RCP coastdown characteristics is modeled. An operating pump heat addition to the RCS of 3 MWth/pump is assumed.
- 6. 1979 ANS 5.1 Decay Heat is modeled.
- 7. An AFW temperature of 100*F is assumed.
- 8. A feedwater system purge volume of 73 ft3/loop is assumed. This piping volume must be purged of the relatively hot main feedwater before the colder AFW enters the steam generators.
-2 CASE A:
Partial Loss of Normal Feedwater at 100% power Specific Assumptions The plant is initially operating at 103% of rated power.
Initial reactor coolant average temperature is 4*F above the nominal full-power value (575.15*F).
Initial pressurizer water level is 37.5% NRS.
Main feedwater to effected steam generator is assumed to stop at the time of the failure of the flow control valve. Main feedwater to the two unaffected steam generators continues until time of reactor trip.
Pressurizer power-operated relief valves and pressurizer sprays are available.
Auxiliary feedwater (AFW) is assumed to be manually actuated and the system manually aligned to deliver flow of 185 gpm to three steam generators 30 minutes after the initiation of the event (FW flow control valve failure).
The steam flow/feed flow mismatch reactor trip is assumed not to function since required logic (2 out of 3 loops) will not be met.
Results and Conclusions The results of the Partial LONF transient at full power are shown in Figures 1 through 9. The time sequence of events is presented in Table 1. The results show that reactor trip occurs on high pressurizer water level and that the high pressurizer water level setpoint (50% NRS) prevents the pressurizer from filling. Thus, the acceptance criterion for a LONF event is met.
-3 CASE B:
Complete Loss of Normal Feedwater at 100% Power CASE B analysis was previously submitted by letter from M. 0. Medford (SCE) to G. E. Lear (NRC) dated May 1, 1986. This analysis showed that with AFW flow of 165 gpm to 3 steam generators initiated at 30 minutes, the acceptance criterion of no pressurizer fill was achieved. Reactor trip occurs on steam flow/feedwater flow mismatch.
-4 CASE C:
Complete Loss of Normal Feedwater at 50% power.
Specific Assumptions The plant is initially operating at 53% of rated power.
Initial reactor coolant average temperature is 4F above the nominal value (551.5 0F) corresponding to 50% power level on the nominal average temperature program (575.15 0 F at full power).
Initial pressurizer water level is 30.0% NRS.
Main feedwater to all steam generators is assumed to stop at the time of the complete loss of normal feedwater.
Pressurizer power-operated relief valves and pressurizer sprays are available.
AFW is assumed to be manually actuated and the system manually aligned to deliver flow of 185 gpm to three steam generators 30 minutes after the initiation of the event (loss of normal feedwater).
The steam flow/feedwater flow mismatch reactor trip is assumed unavailable (bypassed).
Results and Conclusions The results of the complete LONF at 50% power transient are shown in Figures 10 through 18.
The time sequence of events is presented in Table 2. The results show that reactor trip occurred on high pressurizer water level and that the high pressurizer water level setpoint (50% NRS) prevents the pressurizer from filling. Thus, the acceptance criterion for a LONF event is met.
-5 CASE D:
Main Feedwater Line Break Upstream of In-Containment Check Valves at 100% Power Specific Assumptions The plant is initially operating at 103% of rated power.
Initial reactor coolant average temperature is 4*F above the nominal full-power value (575.15*F).
Initial pressurizer water level is 37.5% NRS.
Main feedwater to all steam generators is assumed to stop at the time of the feedline break.
Pressurizer power-operated relief valves are available, but no credit is taken for the pressurizer'sprays.
AFW is assumed to be manually actuated and the system manually aligned to deliver flow of 125 gpm to two intact steam generators 30 minutes after the initiation of the event (feedline break).
The steam flow/feedwater flow mismatch reactor trip is assumed to occur 10 seconds after the feedline break.
The steam generators will remain pressurized due to the in-containment check valves. This scenario initially behaves as a complete loss of normal feedwater.
Results and Conclusions The results of the feedline break at full power located upstream of inside containment check valve transient are shown in Figures 19 through 27.
The time sequence of events is presented in Table 3.
Reactor trip is provided by the steam flow/feedwater flow mismatch signal.
The results show that an AFW flow of 125 gpm initiated 30 minutes after the break is sufficient to remove core decay heat.
The reactor coolant system (RCS) remains subcooled and the pressurizer does not fill.
Thus, the core remains covered with water, and the acceptance criterion for a feedline break event is met.
-6 CASE E:
Main Feedwater Line Break Upstream of In-Containment Check Valves at 50% Power Specific Assumptions The plant is initially operating at 53% of rated power.
Initial reactor coolant average temperature is 40F above the nominal value (551.5 0F) corresponding to 50% power level on the nominal average temperature program (575.15*F at full power).
Initial pressurizer water level is 30.0% NRS.
Main feedwater to all steam generators is assumed to stop at the time of the feedline break.
Pressurizer power-operated relief valves are available, but no credit is taken for the pressurizer sprays.
AFW is assumed to be manually actuated and the system manually aligned to deliver flow of 125 gpm to two steam generators 15 minutes after the initiation of the event (feedline break).
The steam flow/feedwater flow mismatch reactor trip is assumed unavailable (by-passed).
The steam generators will remain pressurized due to the in-containment check valves. This scenario initially behaves as a complete loss of normal feedwater.
Results and Conclusions The results of the feedline break at 50% power located upstream of inside containment check valve transient are shown in Figures 28 through 36.
The time sequence of events is presented in Table 4.
Reactor trip is provided by the high pressurizer water level (50%
NRS) signal.
The results show that an AFW flow of 125 gpm initiated 15 minutes after the break is sufficient to remove core decay heat.
The reactor coolant system (RCS) remains subcooled and the pressurizer does not fill.
Thus, the core remains covered with water, and the acceptance criterion for a feedline break event is met.
-7 CASE F:
Main Feedwater Line Break Downstream of In-Containment Check Valves at 100% Power Case F analysis was previously submitted by letter from M. 0. Medford (SCE) to G. E. Lear (NRC) dated May 1, 1986. This analysis showed that with AFW flow of 250 gpm to 2 steam generators initiated at 15 minutes, the acceptance criterion of no pressurizer fill was achieved.
Reactor trip occurred on steam flow/feedwater flow mismatch.
-8 CASE G:
Main Feedwater Line Break Downstream of the In-Containment Check Valves at 50% power Specific Assumptions The plant is initially operating at 53% of rated power.
Initial reactor coolant average temperature is 4*F above the nominal value (551.5 0F) corresponding to 50% power level on the nominal average temperature program (575.15*F at full power).
Initial pressurizer water level is 30.0% narrow range span (NRS).
Main feedwater to all steam generators is assumed to stop at the time of the feedline break.
Pressurizer power-operated relief valves are available, but no credit is taken for the pressurizer sprays.
AFW is assumed to be manually actuated and the system manually aligned to deliver flow of 250 gpm to two steam generators 15 minutes after the initiation of the event (feedline break).
The steam flow/feedwater flow mismatch reactor trip is assumed unavailable (by-passed).
All three steam generators depressurize since SONGS 1 does not have main steamline isolation valves.
Results and Conclusions The results of the feedline break at 50% power located downstream of inside containment check valve transient are shown in Figures 37 through 45.
The time sequence of events is presented in Table 5.
Reactor trip is provided by the high pressurizer pressure signal.
The results show that an AFW flow of 250 gpm initiated 15 minutes after the break is sufficient to remove core decay heat.
Calculations of this case show that the core remained in a coolable geometry during this feedwater line break scenario. The detailed calculations involve showing that the mass relieved through the pressurizer PORVs (between the time of initial relief through the PORVs and the time the PORVs reseat due to the heat removal capability of the AFW exceeds the core decay heat) was not sufficient to uncover the core. As such, the acceptance criterion for a FLB event that the core remains in a coolable geometry during the transient was shown to be met.
0652P
TIM SEMMCE OF EVINTS FR CASE A PARIAL ICNF EE@
Time,.e Feedater flow cantrol valve fails -
terinnating feed
- 10.
flow to one steam generator Reactor trip an high pressurizer water level
- 96.
Rods begin to drp
- 98.
Main feedwater flow is terminated for remaining
- 98.
two steam generators Pressurizer ICRVs open (2200 psia) 1191.
AW manually started of 185 gpa to 3 steam generators 1810.
Cold AW reaches 3 steam generators 2341.
Pressurizer PORVs close 2357.
Heat remval of AW is capable of removing core 2366.
decay heat Peak pressurizer water volume (1228 ft3) 2389.
TME SEUENCE OF EVEMS FR CSE C ILCF 50% POER Emb Time,se taPlete loss of nrmal feedwater
- 10.
Itactor trip at high pressurizer water level 136.
Rods begin to drop 138.
Pressurizer PGRVs cpen (2200 psia) 1055.
AFW anually started of 185 gpm to 3 steam generators 1810.
Pressurizer PORVs close 1871.
Peak pressurizer water volume (916 ft3) 1871.
Heat removal of AFW is capable of removing cre 1876.
decay heat Cold AFW reaches 3 steam generators 2341.
ME~ SEM)EN OF EVENTIS FR CASE D FIB FLL pI.E Fsdins Break beben the 2 MW d-mAk valves
- 10.
Reactor trip on steam flow/feed flowi mismatch
- 20.
Rods begin to drcp
- 20.
Pressurizer PCVS cqen (2200 psia) 1227i AFW maWallY started of 125 gym to 2 steam geimrators 1810.
Cold AMW reahe 2 steacm generators 2341.
Pressurizer POVs close 4373.
Heat roma Of MW is capable of ru!oring~r 4550.
decy heat
g 4A TDM SEQUECE OF EVENIS FOR CASE E FIB 50% IOER EZHE Tim,se Feedline Break between the 2 MFW check valves
- 10.
Reactor trip on high pressurizer water level (50% NRS) 160.
Rods begin to dr 162.
Pressurizer ICRVs open (2200 paia) 476.
AFW manually started of 125 gpm to 2 steam generators 910.
Cold AFW reaches 2 steam generators 1437.
Pressurizer PORVs close 1460.
Heat removal of AFW is capable of removing cre 1460.
decay heat
TDIE SEUNCE OF EVENIS PR CASE G FIB 50% POWER Time, sec Feedline Break downstream of the check valves
- 10.
inside containment Pressrizer PCRVs open (2200 psia)
- 76.
Reactor trip On high presurizer prMsure
- 84.
Rods bein to droP
- 86.
AFW manually started of 250 gym to 2 steam generators 910.
Cold AW reaches 2 steam genriators 1173.
Heat removal of AFW is capable of removing cre 3177.
decay heat Pressurizer ICRVs close 1185.
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
O 0 z 1.2 0
1.8 of0
- 0.
z U.
Ioo to, 102 185 I
TIME ISECI Figure 1
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
5 1.4 1.2 o
- 6 U.
o*
cc LO*
II.
C)
~.2 g
I 102 15 I
TIME ISECI Figure 2
CASEA SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
2800.
? 2698.
2489.
2200.
5 2ase.
M tern,.
0 0
CL L1209.
880.
W 200.
0 li 102 105 184 TIME ISECI Figure 3
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
1400.
1288.
Ipoo.
C3 at age*
- 0.
Li t!
400.
2
- 00.
Lr 8
2ee.
at
- 8.
IB tog2 ig3 10 TIME ISECI Figure 4
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
w 780.
0 675.
659.
"625.
z o 680.
575.
559.
cc a525.
- 00.
,599.
4 475.
450.
10o Io, 10I5 104 TIME ISECI Figure 5
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
8 788.
8 675.
S658.
4 U) 625.
0 x 4 75.
Figure@6 02 550.
5 25.
Li
.- 500.
tla
- 0. 47S.
0 too tot1 3
TIME (SECI Figure 6
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
' 70.
t 675.
S659.
I625.
0 O.
0 x a; 680.
j575.
05
- 50.
O O -
459 18f IIt jg2 105 1
TIME ISECI Figure 7
CASE A SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
40E cn.3SE*S cn I.3K *s a
z.25C*5 U
x ISE-S 0-E I@@
jl 102 10310 TIME ISECI Figure 8
CASE A
SCE Partial LONF at Full Power AFW Flow of 185 gpm @ 30 min.
1690.
1400.
CL o 1200.
0 IB.
8608.
cm o
600.
z 400.
c 200.
- 8.
Io lt 102 105 1g4 TIME ISECI Figure 9
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
zO
.1.4 0
1.2
. 6 0
6t I
oi
- z T IME ISEIX)
Figure 10
&a
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
1.4 0
1.2 0
I,.6
.4 U)
U.
TIME ISECI Figure 11
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
S2600.
CL 40 0.
2209.
l ees.
(L 6j 1600.
Li 1200.
I TIME ISECI Figure 12
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
1 1600.
s iee.
Li
! 1400.
1200.
I 1
001112 R
0 Figure11
- o0 Iw LII Figure 13
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
~67s.
G6se.
662S.
at nW I.NW.Inen.I aIE ISC Figue 1
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
- 708.
L9 L 675.
625.
680.
5d75.
0 450.
100 I
102 gg5 104 TIME ISECI Figure 15
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
700.
~67S.
2S.
0ss w
0 0 Li Igur 16 5
0
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
.SSE-S at QD
.25E-5 IOEn
.51E*S I
- 0.
TIMEESEC Fiur 17
CASE C SCE Complete LONF at 50% Power AFW Flow of 185 gpm @ 30 min.
1600.
1400.
CL o 1200.
S
-j CL I.'
or I a z
400.
290.
Ie 101 12 15 1g TIME ISECl Figure 18
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes 0
z 06 U2 le I
102 165 184 TIME ISECl Figure 19
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes z
1.4 1.2 O
U
.8 0
I".
.2 cc
- 30.
1SO l10 192 18 104 TIME ISECI Figure 20
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes 2690.
2600.
2400.
e2 2 9.
of 2000.
ca S169.
of 1499.
U1 w 1200.
1000 1s1 192 gg5 104 TIME ISEC)
Figure 21
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes 1600.
1409.
DI 1200.
688.
0 Li CL Figure 22
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes 700.
o 675.
658.
625.
o 888.
559.
w525.
0475.
0 650.
109 Is' 102 tg5 4
TIME ISECI Figure 23
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes 700.
0675.
625.
o 680.
2 575.
? 558.
a 475.
O.
450.
0
-J 458.
I08 ig 102 105 104 TIME ISECI Figure 24
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes
- 70.
- 650.
625.
600.
E 575.
CL
? 559.
'. 525.
.- see.
p 475.
Ao.
- 0.
10O 1ot 102 105 184 TIME ISECI Figure 25
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes
.50E*S z
.45E*5
.49E*S u'.55E*5 at 2.25E*5 Z.29E*5
.1SE*5 x.19(05 U.
10~
1i1
,g2 ig5sg TIME ISECI Figure 26
CASE D SCE FLB Upstream of Check Valve Steam/Feed Mismatch Reactor Trip AFW Flow of 125 gpm @ 30 minutes 4
a 1608.
1400 o 1200.
0
-i z
- 00.
Li S2ee2.
- 0.
100 101 102 105 104 TIME ISECl Figure 27
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes z 1.4 0 z 1.2 S
o 0
2
&.6 CL o
.2
- 0.
108 1s, 102 105 1
g4 I
~I TIME ISECI Fu 2
Fiur 2
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes
.4 0
z 1.2 atj L
.6 cc
.4
~f.2*
ll 10 ti 2 gg5 184 TIME ISECI Figure 29
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes 2889.
or 100.
C 2400.
22N8.
Li 1000.
188.
I1 111.
at 1208.
Li 1200.
100
~
g 102 10 14 TIME ISEC I Figure 30
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes 9-0 8 1600.
U 1280.
0 ~..
-e see.
See.
I dU le 1i 182 105 sg4 TIME ISECI Figure 31
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes Li 675.
- 50.
.625.
0 L' 57S.
I Li I
s I
Of'SI S2S.
cL47S.
0 108 le 151 4
TIME ISECI Figure 32
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes Lj 700.
8 675.
g 650.
625.
0
- S75.
LI o S525.
5a.
cL 475.
.11 182 g5 194 TIME ISECI Figure 33
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes Ii.
659.
W 625.
o 698.
0 9
575.
-? 550.
w 525.
- a.
TIME ISEC)
Figure 34
CASE E
SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes
.45E*5
.46E*5
- mI.55t*S 3
0S
&.25E*S z.28E*5 2:.15E*5 0.18E*5
.58E*4 TIME ISECI 0I.
Figure 35
CASE E SCE FLB Upstream Check Valve at 50% Power AFW Flow of 125 gpm @ 15 minutes 1400.I
- 0.
I o
a 690.
L i a200.
10 o 19,
Ig21 5
g4 TIME ISEC)
Figure 36
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes zc 1.2 01 z1.
0 z
m.6 W
Z
- 0.
I U
2 D
10 0102 g 05 104 TIME ISECI FIGURE 37
CASE G
SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes 1i.4 1.2
- 0.
U 101 0215I c
F
.4 o
U).2 ci
-10.
2g TIME ISECI FIGURE 38
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes 2839.
2400.
2200.
S200.
18M.
1.'
1122N.
g4*
aim 41tIME ISEC FIGURE 39
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes 16M LA lI 6 I9.
o14e.
129..
CI 0
see.
Gas.
4g.
a, 1s@
Ii 102 165 IB TIME ISECI FIGURE 40
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes L 708.
L2 o 675.
650.
625.
O a 608.
-j 0
? 575.
Li 550.
4 475.
0 0
458.
II0 ig2 1g5 1g4 TIME ISECI FIGURE 41
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes Li Li 700.
LS 3 675.
659.
625.
O o600..
0
? 575.
559.
La 525.
C Li a 475.
0 0
J 450.
e 1@,
1021g4 TIME ISECI FIGURE 42
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes U
L9 Li 708.
at 8 675.
'650.
625.
c 600.
8 575.
Li of 550.
or of 0 525.
Li 500.
.475.
0 0
-' 450.
102 105 IB TIME ISECI FIGURE 43
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 gpm @ 15 minutes
.50E*5
-J.45E*5
.ASE'5
.40E*S U).55E*5 m.50E*5 0
2.25E*5 Z.20E*S Li r.ISE*S Li I.10E S
.50E*4.
100 10, 102 105 194 TIME ISECI FIGURE 44
CASE G SCE FLB DOWNSTREAM CHECK VALVE AT 50% POWER AFW Flow of 250 @ 15 minutes 1600.
1400.
1200.
z 400.
CL 800.
- 0.
L2 5
200.
L*
- 0.
100 101 102 185 10 TIME ISEC)
FIGURE 45
REGULA Y INFORMATION DISTRIBUTIO 3YSTEM (RIDS)
ACCESSION NBR:8711230218 DOC.DATE: 87/11/20 NOTARIZED: NO DOCKET #
FACIL:50-206 San Onofre Nuclear Station, Unit 1, Southern Californ 05000206 AUTH.NAME AUTHOR AFFILIATION MEDFORDM.O.
Southern California Edison Co.
RECIP.NAME RECIPIENT AFFILIATION Document Control Branch (Document Control Desk)
SUBJECT:
Forwards design descriptions for mods to auxiliary feedwater sys,steam/feedwater flow mismatch trip & main feedwater isolation & revised auxiliary feedwater transient analysis, per util 871106 commitment.
DISTRIBUTION CODE: AO1D COPIES RECEIVED:LTR ENCL SIZE: _
7 TITLE: OR Submittal: General Distribution NOTES:License Exp date in accordance with 10CFR2,2.109.
05000206 RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD5 LA 1
0 PD5 PD 5
5 BRADFUTE,J 1
1 INTERNAL: ARM/DAF/LFMB 1
0 NRR/DEST/ADS 1
1 NRR/DEST/CEB 1
I NRR/DEST/MTB 1
1 NRR/DEST/RSB 1
1 NRR/DOEA/TSB I
I NRR/PM6,qZIRB 1
1 OGC/HDS2 1
0 01 1
1 RES/DE/EIB 1
1 EXTERNAL: EG&G BRUSKES 1
1 LPDR 1
1 NRC PDR 1
1 NSIC 1
1 TOTAL NUMBER OF COPIES REGUIRED: LTTR 21 ENCL 18