ML032450420
| ML032450420 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 05/08/2003 |
| From: | NRC/RGN-II |
| To: | |
| References | |
| 50-424/03-301, 50-425/03-301 | |
| Download: ML032450420 (21) | |
See also: IR 05000424/2003301
Text
Draft Submittal
In._,_ n __^_,
VOGTLE OP RETAKE EXAM
50-424 & 50-42512003-301
MAY 8,2003
1. Operating Test Simulator Scenarios
Appendix D Scenario Outline Form ES-D-1
Facility: Voatle Electric Generatina Plant Scenario No.: Op-Test No.: 301-200:
Examiners: Operators:
Initial Conditions:
Rx Power loo%, EOL, Rod Operability Testing in progress with CB C and D left to do
Turnover:
1A MDAFW out of service
Event I Malf. I Event I Event
No. No. Type* Description
(RO,
dr N
(RO) Complete Rod Operability Test
Small Break LOCA
(N)ormal, (R)eactivity, (I)nstrument, (C)omponent, (M)ajor
WINDOW E03
ORIGIN SETPOINT
LTDN HX OUT
1-PT-0131 425 psig HI PRESS
1.0 PROBABLE CAUSE
1. 1-PV-0131 malfunction.
2. All three Letdown Orifice Isolation Valves open.
2.0 AUTOMATIC ACTIONS
NONE
3.0 INITIAL OPERATOR ACTIONS
1. CHECK letdown pressure and flow using 1-PI-0131A and
1-FI-0132 on the QMCB.
2. GO to 18007-C, "Chemical And Volume Control System
Malfunction" if letdown is lost.
4.0 SUBSEQUENT OPERATOR ACTIONS
NONE
5.0 COMPENSATORY OPERATOR ACTIONS
NONE
END OF SUB-PROCEDURE
REFERENCES: 1X4DB115, PLS
rinted February 21, 2003 a t 1 0 : 1 2
INSTRUCTOR STATION NO: RD09
DESCRIPTION: Control Rod Urgent Failure
CAUSE: Bank D, Group 2 power cabinet multiplexing
thyristor failure
SOFTWARE NAME ( 8 ) : Logicals Severitys
YP:XMFTB ( 8 4 )
PLANT STATUS: 100% power
EFFECTS :
The control rod urgent failure inhibits automatic control rod
motion.
Control banks A , B & C can be positioned in manual individual
control. CNTL BK D GP 2 D motion is blocked in manual and auto
due to the failure in bank D.
Malfunction removal will restore the control rod system to
normal.
12
INSTRUCTOR STATION NO: G E 0 5
DESCRIPTION: Abnormal Generator H, Pressure
Variable: 100% severity equals a leakrate that
will result in a pressure reduction of
approximately 10 psig/minute at a
generator hydrogen pressure of 75 psig.
SOFTWARE NAME (s) : Logicals Severitys
YP:XMFTB(378) YPXSVRTY(98)
CAUSE : Hydrogen leakage through a faulty relief valve
PLANT STATUS: 100%
EFFECTS :
The hydrogen pressure will decrease at a rate designated by
the malfunction severity. The rate of change of pressure will
decrease as the hydrogen pressure decreases.
A reduction in hydrogen pressure will reduce the hydrogen
Heat transfer coefficient; this will result in an increase in the
generator field temperature. The increase in generator field
temperature will in turn increase the hydrogen outlet temperature.
This will cause TIC-7097 to open TV-7097 which will increase
turbine plant cooling water to the hydrogen coolers. As the
hydrogen pressure continues to decrease, the hydrogen will no
longer be capable of removing the Heat generated in the generator
field. If the generator load is not reduced, high generator
field. If the generator load is not reduced, high generator field
temperature will result in internal insulation breakdown. This
will be indicated on the generator core monitor. Continued
operation in this condition will result in grounding the generator
field and generator neutral ground overcurrent lockout trip.
Upon malfunction removal the relief valve will re-seat
stopping the leak and hydrogen pressure reduction. The hydrogen
pressure can be returned to normal by using remote function G E 0 5
which will open the hydrogen supply isolation valve. The
pressurization rate for remote function G E 0 5 will be 0 . 1
psig/minute at 75 psig hydrogen pressure. Remote function G E 0 5
may also be used to increase the hydrogen pressure to 100 psig.
4
INSTRUCTOR STATION NO: RD09
DESCRIPTION: Control Rod Urgent Failure
CAUSE : Bank D, Group 2 power cabinet multiplexing
thyristor failure
SOFTWARE NAME ( a ) : Logicals Severitys
YP :XMFTB ( 84 )
PLANT STATUS: 100% power
EFFECTS :
The control rod urgent failure inhibits automatic control rod
motion.
Control banks A , B & C can be positioned in manual individual
control. CNTL BK D GP 2 D motion is blocked in manual and auto
due to the failure in bank D.
Malfunction removal will restore the control rod system to
normal.
12
Rod Group Alignment Limits
3.1.4
3.1 REACTIVITY CONTROL SYSTEMS
3.1.4 Rod Group Alignment Limits
LCO 3.1.4 All shutdown and control rods shall be OPERABLE, with all individual
indicated rod positions within 12 steps of their group step counter demand
position.
APPLICABILITY: MODES 1 and 2.
ACTIONS
CONDITION REQUIRED ACTION COMPLETION TIME
A. One or more rod(s) A.l.l Verify SDM is t the limit 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
untrippable. specified in the COLR.
-OR
A.1.2 Initiate boration to restore 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
SDM to within limit.
& lJ
A.2 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
B. One rod not within 8.1.1 Verify SDM is 2 the limit 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
alignment limits. specified in the COLR.
-
(continued)
Vogtle Units 1 and 2 3.1.4-1 Amendment No. 96 (Unit 1)
Amendment No. 74 (Unit 2)
Rod Group Alignment Limits
3.1.4
ACTIONS
CONDITION REQUIRED ACTION COMPLETION TIME
8. (continued) 8.1.2 Initiate boration to restore 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
SDM to within limit.
AND
8.2 Reduce THERMAL 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
POWER
to < 75% RTP.
AND
B.3 Verify SDM is t the limit Once per
specified in the COLR. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
AND
8.4 Perform SR 3.2.1.1 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
-
AND
8.5 Perform SR 3.2.2.1 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
AND
8.6 Reevaluate safety 5 days
analyses and confirm
results remain valid for
duration of operation
under these conditions
(continued)
Vogtle Units 1 and 2 3.1.4-2 Amendment No. 96 (Unit 1)
Amendment No. 74 (Unit 2)
Rod Group Alignment Limits
3.1.4
ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME
C. Required Action and c.1 Be in MODE 3 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
associated Completion
Time of Condition B not
met.
D. More than one rod not D.l.l Verify SDM is t the limit 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
within alignment limit. specified in the COLR.
-
D.1.2 Initiate boration to restore 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
required SDM to within
limit.
AND
D.2 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
SURVEILLANCE FREQUENCY
SR 3.1.4.1 Verify individual rod positions within alignment 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
limit.
AND
Once within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
and every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
thereafter when the
rod position deviation
monitor is inoperable
(continued)
Vogtle Units 1 and 2 3.1.4-3 Amendment No. 96 (Unit 1)
Amendment No. 74 (Unit 2)
Rod Group Alignment Limits
3.1.4
SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY
SR 3.1.4.2 Verify rod freedom of movement by moving each 92 days
rod not fully inserted in the core 2 10 steps in
either direction.
SR 3.1.4.3 Verify rod drop time of each rod, from the physical Prior to reactor
fully withdrawn position, is 5 2.7 seconds from the criticality after
beginning of decay of stationary gripper coil each removal of
voltage to dashpot entry, with: the reactor head
a. , ,T 2 551°F;and
b. All reactor coolant pumps operating.
Vogtle Units 1 and 2 3.1.4-4 Amendment No. 96 (Unit 1)
Amendment No. 74 (Unit 2)
Appendix D Scenario Outline Form ES-13-1
Event Malf. Event Event
No. No. Type* Description
1 R Ramp up unit by approximately 5% per procedure
(RO,
BOP)
VCT LT 185 Fails Hi
Loss of cooling to the Letdown Hx, requiring manual control
5 MT I Feed break inside containment
Post
I Automatic Feedwater isolation fails, HV 88016 thermals out when being closed,
I B M D A W fails to auto start
-tt
Scenario ends when primary and secondary plant are stable.
- (N)ormal, (R)eactivity, (I)nstrument, (C)omponent, (Wajor
INSTRUCTOR STATION NO: FW06
DESCRIPTION: Feedwater Line Rupture Inside Containment
Variable: 100% = 9,460,OO lbm/hr (25,000 gpm)
FWO6a - FWLl FWO6C - FWL3
FWO6c - FWL2 FW06d - FWL4
SOFTWARE NAME (SI : Logicals Severitys
FWL 1: JMLCFWl (I)SMLCFWl(1)
FWL 2: JMLCFWl(2) SMLCFWl(2 )
FWL 3: JMLCFWl(3) SMLCFWl(3)
FWL 4: JMLCFWl(4) SMLCFWl(4)
CAUSE: Pipe break between S/G and temp element TE-15205
PLANT STATUS: 100% power
EFFECTS :
Use the following chart to insert the malfunction:
FLOW TO CTMT FLOW TO CTMT FEED FLOW TO
SEVERITY FROM SG FROM FEED LINE AFFECTED SG
100% 5.7636 lbm/hr all FW 0 lbm/hr
80% 4.5E6 all FW 0
60% 3.436 2.336 lbm/hr 1.6E6
50% 2.8E6 1.9E6 1.9E6
40% 0 1.5E6 2.3E6
20% 0 7.6E5 3E6
10% 0 3.8E5 3.4436
0% 0 0 all FW
..............................................................
At 100% power, the malfunction can be inserted at 21%
severity and still maintain the plant on line. This is with the
FRV 100% open, three condensate pumps, and the SGFPT's in manual
at maximum speed.
Indicated feed flow to the steam generator increases. A
feedwater line rupture causes a reduction in feed flow to the
8
affected steam generator. This reduced feed flow causes the
affected steam generator level to decrease. The steam generator
level control system responds to maintain level. With maximum
severity inserted, the affected steam generator blowsdown rapidly
and causes a reactor trip/turbine trip.
The reduced feedwater flow causes a decrease in subcooling of
the affected steam generator. This causes an increase in Tavg.
Pressurizer level and pressure correspondingly increase. The
pressurizer pressure and level control systems respond to this
Once a reactor trip occurs, the affected steam generator and
the other steam generators continue to blowdown through the
rupture. This leads to a low steamline pressure condition and
initiates safety injection steamline and feedwater isolation.
When the SLI & FWI isolations occur, blowdown of the
unaffected steam generators stops. The affected loop boils dry
due to the location of the rupture. Auxiliary feedwater restores
level in the unaffected loops.
Containment pressure and humidity ncrease dependent on break
size. The sump levels increase, initiating sump pump starts.
Malfunction removal will stop the leak
9
INSTRUCTOR STATION NO: CV04
DESCRIPTION: Loss of Cooling to Letdown Heat Exchanger
SOFTWARE NAME (s): Logicals Severitys
YP:XMFTB ( 2 9 9 )
CAUSE : Temperature Element TE 130 Fails Low Causing Temp
Control Valve TV-130 to Fully Close
PLANT STATUS: 100% power
EFFECTS :
V-130 going closed will cause ACCW flow to the letdown Heat
exchanger to go to minimum. This will cause an increase in
letdown temperature downstream of the letdown Heat exchanger to
approximately that at the outlet of the regenerative heat
exchanger.
When the letdown temperature exceeds the setpoint for the
high temperature exceeds the setpoint for the high temperature
diversion valve, it will shift letdown directly to the volume
control tank and bypass the demineralizers. Volume control tank
temperature will increase and annunciate a high temperature alarm
when its setpoint is exceeded.
The operator can take manual control of TV-130 and control
letdown temperature.
Malfunction removal will return the failed temperature
element to normal.
4
INSTRUCTOR STATION NO: FW02
DESCRIPTION: Feed Flow Transmitter Fails (Cont)
Variable: 0-100% of Scale
FW02a - FT 510 FW02c - FT 530
FW02b - FT 520 FW02d - FT 540
SOFTWARE NAME ( 6 ) : Logicals Severitys
510 :YP:XMFTB (443) YPXSVRTY (106)
520 :YP:XMFTB(444) YPXSVRTY (107)
530 :YP:XMFTB(445) YPXSVRTY(108)
540 :YP:XMFTB(446) YPXSVRTY(109)
CAUSE : Transmitter failure
PLANT STATUS: 100% power (assume failed channel selected for
control)
EFFECTS :
This feed flow transmitter failing high or low will generate
a steam flow-feed flow mismatch condition and alarm.
As transmitter output goes high, the associated feedwater
control valve will modulate closed to bring steam and feed flows
together. the reduced feedwater flow will cause actual steam
generator level to decrease. This level decrease will continue
until it either offsets the feed flow error or until a steam
generator low low level generates a reactor trip and auxiliary
feedwater pumps start. The time required for this to occur will
depend on the severity selected.
If this transmitter fails low, just the opposite of the above
stated reactions will occur, except that the turbine trip/reactor
trip and feedwater isolation will occur if the hi-hi steam
generator level is reached.
The operator can take manual feedwater control to stabilize
steam generator level at program level or select the other channel
for control.
Malfunction removal will cause transmitter output to return
to normal.
4
INSTRUCTOR STATION NO: GE09
DESCRIPTION: Load Rejection
Variable: Percent Entered will Equal Percent
Decrease in Load Set Setpoint
SOFTWARE NAME ( 8 ) : Logicals Severitys
YP:XMFTB(382) YPXSVRTY(102)
CAUSE : Electrical failure in EHC system
PLANT STATUS: 100% power, control rods in auto
EFFECTS :
This malfunction will decrease the load set setpoint at 133%
per minute until the percent decrease is equal to the malfunction
severity. The control valves will close at the maximum rate
allowed by the EHC hydraulic system.
The decrease in turbine impulse pressure causes control rods
to insert and will arm the steam dumps. The steam dumps will
modulate open or if the Tavg-Tref error is large enough they will
quick open. The system accepts a load reduction of 50% without
opening the atmospheric relief valve or a reactor trip. Larger
load reduction may result in a reactor trip, dependent upon the
pressurizer pressure and level control system response.
Malfunction removal will stop the decrease in the load set
setpoint.
8
pprovr I Procedure No.
Vogue Electric Generating Plant 18012-C
J . T. Gasser NUCLEAR OPERATIONS k r i 11 on NO.
ate 11
Page IO.
Unit CCmoN 1 of 5
12/6/99
Abnormal Operating Procedures
TURBINE RUNBACK
PURPOSE PRB REVIEW REOUIRED
This procedure provides instructions for validating a turbine
runback, stabilizing plant conditions following a runback and
terminating an invalid runback.
SYMPTOMS
OVERTEMP DELTA-T ROD STOP TURBINE RUNBACK C3 ON BPLB.
OVERPWR DELTA-T ROD STOP TURBINE RUNBACK C4 ON BPLB.
OVERPOWER AT ROD BLOCK AND RUNBACK ALERT Annunciator
OVERTEMP AT ROD BLOCK AND RUNBACK ALERT Annunciator
OVERTEMP DELTA-T ALERT Annunciator.
OVERPOWER DELTA-T ALERT Annunciator.
0 Unexplained loss of generator MW.
Unexplained insertion of control rods while in auto.
'EGP 18012-C
I 11
I 2 of 5
ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
IMMEDIATE OPERATOR ACTIONS
- REQUIRED:
1. Verify that a turbine
runback is
1. Go to 8.
Any 2 out of 4 runback
bistable status lights
energized:
OT DELTA-T
OP DELTA-T
2. Ensure Rod Control System 2 . Manually insert control rods
'in AUTO and inserting rods as required.
'to 'restoreTavg/Tref.
3 . Verify that a runback has 3 . Reduce load manually by
initiated: depressing LOAD DECREASE
aushbutton UNTIL:
Turbine control valves-
SHUTTING. OT DELTA-T or OP DELTA-T
Generator load
LOWERING.
- runback bistable status
lights extinguish.
LOSS OF TURB LOAD INTLK
C7 Status Light
ENERGIZED.
-
SUBSEOUENT OPERATOR ACTIONS
4. Verifv Steam Duma Svstem
ARMED-AND R E S P O N ~ I NTO~
- 4. Verify SG ARVs are in AUTO
TAVG/TREF DEVIATION.
5. Verify PRZR Pressure Control 5. Take manual control of PRZR
System - RESTORING PRESSURE
TO 2235 PSIG.
spray and heaters to restore
pressure.
6. Verify SGWLC System
RESTORING SG LEVELS TO
- 6. Take manual Control Of FRVs
and restore level.
PROGRAMMED BAND.
OemUpE 10. w I s I o i i 10. PAGE Io.
EGP 18012-C 11 3 of 5
ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
7. IF the runback condition has 7. IF less than 50% power,
cleared, THEM trip the turbine and go
continue operation in to 18011-CJ TURBINE TRIP
accordance with 12004-C, BELOW P-9,
POWER OPERATION (MODE 1).
-0R-
Trip the reactor and go to
19000-CJ E-0 REACTOR TRIP OR
SAFETY INJECTION.
NOTE: The following steps will place the turbine 'in
Standby Mode to facilitate recovery. These steps
may be used, if necessary, to stabilize turbine
ldad, and may be used in conjunction with 12004-C,
POWER OPERATION (MODE 1).
8. Stabiliz turbine loads
using S: NDBY SIGNAL MATCH
controls:
a. Match CV SIGNAL and IV
SIGNAL using STANDBY
LOAD SET potentiometer.
b. Simultaneously depress
ON and
...... BYPASS
~~~~ ..
pushbuttons on STANDBY
SIGNAL MATCH.
9. Check that turbine load 9. E less than 50% power,
stabilizes. T m trip the turbine and go
to 18011-C, TURBINE TRIP
BELOW P-9.
-0R-
-
IF runback continues,
THEN trip the reactor and go
to
~. 19000-C.
_ . E-0
~ REACTOR
~ TDTD
~I\AL
OR SAFETY-~NJECTION.
tOCEOURE NO. REVlSlON NO. PAGE I D .
EGP 18012-C 11 4 of 5
ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
CAUTION: Turbine loading rates in Standby Mode are not
restricted by the EHC System and are totally under
control of the operator.
10, Control load using the
STANDBY LOAD SET
I
Chemistry should be notified every time reactor
power is changed by 15% or more in a one-hour period
so iodine activity can be determined per Tech Spec
11. E C-7 present,
THEN reset C-7.
12. Perform 14286, TURBINE TRIP
DEVICE OPERABILITY TEST,
Section 5.1 and 5.2.
13. Continue operation in
accordance with the UOP
currently in effect.
14. E the load reduction was
unplanned or unexplained,
THEN initiate a Condition
Report per 00150-C,
Condition reporting and
Tracking System.
15. - WHEN the cause of the
runback has been corrected,
THEN initiate 13800. TURBINE
OPERATION to restore EHC to
normal,
WCEOURI NO, REYISIMI NO. P K E IO.
JEGP 18012-C 11 5 of 5
ACTION/EXPXTED RESPONSE RESPONSE NOT OBTAINED
16. Power ascension may commence
after review of event cause
and corrective action.
END OF PROCEDURE TEXT