ML19261D826
| ML19261D826 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 06/18/1979 |
| From: | Goodwin C PORTLAND GENERAL ELECTRIC CO. |
| To: | Schwencer A Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 7906260466 | |
| Download: ML19261D826 (48) | |
Text
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June 18, 1979 Trojan Nuclear Plant Docket 50-344 License hPF-1 Director of Nuclear Reactor Regulation ATTN:
Mr. A. Schwencer, Chief Operating Reactors Branch #1 Division of Operating Reactors U.S. Nuclear Regulatory Commission
'n'a s hing ton, D. C. 20555
Dear Sir:
Attached (Attachment 1) are our responses to your Requests for Additional Inforcation, dated February 14, 1979, relating to the installation of isolation switches at local control stations for safe shutdown equipment at the Trojan Nuclear Plant. To supplement this inf or=ation two Of f-Normal Instructions (ONI-17 Control Room Inaccessability and ON1-1 Reactor Trip) are also enclosed.
Also attached (Attachment 2) are our responses to your Requests for Addi-tional Information, dated April 18, 1979, concerning additional design details on the March 9, 1978 Safety Evaluation Report incomplete items.
As of this date, the status on the 31 equipment modification work items is as follows:
installation complete - 13, design complete / installation proceeding - 9, design not yet complete - 9.
This information will be included in the next revision of the Trojan Nuclear Plant Fire liazard Analysis, PGE-1012.
If you have any questions concerning these responses, please contact me.
Sincerely,
/
C. Goodwin, Jr.
Assistant Vice President Thermal Plant Operation and Maintenance CG/SML/4sb3A2 Attachments M
c:
Mr. Lynn Frank, Director 2312 160 is%1 State of Oregon
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Department of Energy T906260 ygg g
a ATTACHMENT 1 ENCLOSURE 1 STATEMENT OF STAFF POSITIONS PORTLAND GENERAL ELECTRIC COMPA'iY TROJAN NUCLEAR PLANT DOCKET NO. 50-344 FEBRUARY 14, 1979 1.
Staff Position Modifications to engineered safety features systems should not degrade these systems. That is, the modification should be designed to meet the same design criteria and standards of the system prior to modification.
PCE Response The decouple switch modifications will be designed to meet the design criteria and standards that are applicable for the engineered safety-feature system in which they are employed, as listed in the Trojan FSAR.
2.
Staff Position Switches to transfer control from the control room to the control station outside the control room should be keylock with keys under supervisory control, or should have other means to limit access.
PGE Response All decouple switches which transfer control f rom the con-trol room to the various Plant locations outside the control room are located in vital Plant areas. Access to these b1 1-1
vital Plant areas is limited in accordance with the vital area access control measures of the Trojan Security Plaa.
We feel that these ceasures provide an equivalent level of supervisory control for the decouple switches as that which would be provided by key-operated decouple switches.
3.
Staff Position About 90 days prior to the completion of all modifications, you will be required to submit appropriate Technic 1 Specifications governing added equipment.
In this regard, Technical Specifications should be proposed to periodically verify capability to transfer control and operate equipment locally. The procedure should also test the " decouple" ala rms.
PCE Response PCE will submit the appropriate Technical Specifications governing the added fire protection equipment at least 90 days prior to completion of all modifications.
Basically, the proposed Technical Specifications will require PCE to verify the capability to transfer control from the contro'.
room to the local panel or switchgear cubicle once per refueling outage and to simulate local operability in the "decoupled" mode as follows:
a.
On 4.16 KV switchgear and 480-V load centers, the breakers will be racked to their test position which allows the control circuitry to be tested without energizing the loads.
b.
On 480-V motor control centers, the control circuitry will be tested without energizing the loads by either lifting the circuit power leads in the breaker or removing the circuit overload elements.
2312 162 1-2
c.
On the auxiliary feedwater pumps, the Auxiliary Feedwater System valves will be aligned to the recirculation mode and the pumps will be manually started in the decoupled mode. The valves will be returned to their normal position.
Receipt of a main control board " decouple" annunciator alarm will also be verified once per refueling outage for each decouple switch when the above testing is being pe rf o rme d.
4.
Staff Position Spare fuses should be located in each panel or a.
cabinet containing a control circuit fuse for equipment used to perform remote shutdown; b.
The draft ONI for a fire in the cable spreading room should include instructions that if equipment fails to function from the local control point after transferring to local control, the control circuit fuse (s) should be checked.
PGE Response a.
Spare fuses will be located in a centrally located fuse supply cabinet. Operations personnel will be knowledgeable of this cabinet location and the fuses will be properly identified.
b.
The draft ONI for a fire in the cable spreading room will be modified to include instructions that if equipment fails to function from the local control point after transferring to local control, the control circuit fuse (s) will be checked. PGE operators would normally perform this fuse check 2312 163
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function on any piece of inoperable electrical equipment.
5.
Stafi Position The draft ONI (Item 2.3) states that the control room operator can verify that equipment has been decoupled from the control room by verifying that the status light has extinguished. However, the fire may also result in the status light being extinguished. Therefore, the procedure should also require the operatar to verify, via communi-cation with the operator (s) at the local panel, that control has been transferred.
PCE Response The draft ONI for a fire in the cable spreading room will be modified to require the control room operator to verify, via communication with the operator (s) at the local control panel, that equipment control has been transferred.
6.
Staff Position The draft ONI should reference use of the procedure for performing remote shutdown in carrying out those functions which must be performed locally.
PCE Response The draft ONI for a fire in the cable spreading room will be modified to reference the use of the remote shutdown procedure in carrying out those functions that must be performed locally.
2312 164 1-4
7.
The renote shutdown capability should include, indonecaent of cable spreading room and control room equipment, suffi-cient instrumentation to perform safe shutdown. As a min-imum, this should include pressurizer level and pressure and steam generator level.
Describe how this instrumenta-tion will be provided and its location.
PGE Response Remote shutdown capability will include, independent of the cable spreading room and control room, indicators for pressurizer level, pressuriser pressure, and steam genera-tor level. These indicators will be located on the Auxiliary Feedwater Control Panel (Panel C-160) located at Elevation 45 ft in the Turbine Building.
Signals to these indicators will be taken directly from the pressurizer and steam generator transmitters.
The associated instrument loop power supplies will be independent of the cable spreading room and control room.
2312 1o5 1-5
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_ATTACRMENT 1 ENCLOSURE 2 REOCEST FOR ADDITIONAL INFORMATION
_ PORTLAND GENERAL ELECTRIC COMPANY TROJAN NtiCLEAR PLANT DOCKET No. 50-344 FEBRUARY 14, 1979 1.
Request Identify the number of operators required to perform shutdown under the most severe situation (i.e., all operations performed locally).
PCE Response The draf t ONI for a fire in the cable spreading room (the mos t severe fire location) states that an auxiliary operator will be dispatched from the control room to perform the local decouple operation on equipment that becomes inoperable from the control board.
Because of redundant cable-tray separation, minimal combustible material and the suppression system available within the cable spreading room, a fire in any area of the cable spreading room will not engulf a large number of diverse /
redundant safety-related cable. Thus, a single operator will be able to perform all the needed decouple / local control operation functions.
The existing ON1-17 " Control Room Inaccessibility" states that the minimum number of operators required to perform a hot plant shutdown from outside the control room without of fsite power (most conservative) is five.
2312. i66 1-6
PORTLAND GENhRAL ELECTRIC CCMPN4Y TROJAN NUCLEAR PLMiT v' [ a J
February 4, 1976 Revision 1
/ / bkbEjY-SEbA
- t' Up4[) Ch 0FF-NORMAL INSTRUCTION ONI-17 j/
CONTROL ROOM INACCESSIBILITY M
DATE Z /6 APPROVED BY o o.-e PURPOSE This instruction describes the steps for bringing the reactor to and main-taining the reactor at a hot shutdown condition, with or without offsite power available, from outside the main Control Room if for any reason the main Control Room becomes uninhabitable.
This instruction is divided into the following sections:
I 0FFSITE PC?lER AVAILABLE II WITliolIP CFFSITE POWER AVAILABLE I.
OFFSITE POWER AVAILABLE A.
SYMPTOMS 1.
The symptoms can be any conditien that renders the Control Room uninhabitable. This procedure was written assuming the following:
a.
The control board is completely operabic following a main Control Room evacuation; i.e.,
no failures have occurred to the main control board that create an accident or p re-clude safe operation of equipment from outside the Control Room and all necessary automatic features are operational.
b.
Inaccessibility to the Control Room does not occur simultane-ously to or subsequent to an accident condition.
c.
Personnel in the adjacent office and working areas previously have evacuated the area.
2312 167 ONI-17 Page 1 of 10 Revision 1 f M
B.
PROBABl.E CAUSES 1.
Contamination.
2.
High airborne activity.
3.
Smoke.
4.
Chlorine gas.
C.
AtHO"ATIC ACTIONS i.
None.
D.
IK!EDIATE OPEPA"0R ACTIONS 1.
TRIP the reactor.
2.
The Control Operator shall proceed to the auxiliary feedwater control panel (C-160) and inform all shift personnel of the following, via the communications system:
a.
The Control Room has been evacuated and the reactor has been tripped; proceed to your designated area and take the necessary action.
(1)
Designated areas and required actions.
(a)
Shift Supervisor - Proceed to panel C-160 and evaluate present plant conditions.
(b)
Assistant Control Operator - Proceed to the control building electrical auxiliary room and wait for direction.
(c)
"A" Auxiliary Operator - Proceed to the recipro-cating charging pump room area and wait fc r direction.
(d)
"B" Auxiliary Operator - Proceed to the turbine building switchr, car room and wait for direction.
(c)
Additional personnel in the controlled access area - Proceed to the controlled access exit and stand by to give further assistance as required.
(f)
Other onsite personnel - Stay cicar of the affected areas and stand by to give assistance.
2312 168 ONI-17 Page 2 of 10 Revision 1
3.
If there is a reactor coolant system dilution operation in progress, the Control Operator shall direct stopping the running primary makeup water (I"Bi) pump.
liest P5ni pump "A" at motor control center (MCC) B25, Breaker Number 52-2555 East Phr.1 pump "B" at motor control center (MCC) B26, Breaker Number 52-2648 E.
SUBSEQUENT OPEPATOR ACTION 1.
At auxiliary feedwater control panel C-160, the Control Oper-ator shall take the following actions:
a.
Verify that the condenser steam dumps are controlling main steam line pressure at essentially no load pressure (1092 psig) on instruments PI514B, PI524B, PI534B, and PI5443.
(1)
If the condenser steam dumps are not controlling steam pressure, adjust the setpoints on the atmos-pheric steam relief valve hand indicating controllers at C-160 in order to maintain steam line pressures at 1092 psig, b.
Verify pcoper steam gener ttor levels un the steam generator wide-range-level instrut ants.
NOTE:
ine aa percent narrow-range Icyc1 is equivalent to 65 percent on the wide-range meters.
l (1)
If the turbine-driven main feedwater pumps and the feedwater regulating valves are not properly con-trolling 1cvel:
(a)
STAk' ne of the auxiliary feedwater pumps and mai. min steam generator levels between 65% and 6;t.
(b)
TRIP the turoines on the main feedwater pumps.
c.
Verify proper pressuri:er icvel.
(1)
If necessary, take LOCA! control of the following components and adjust as required to control pres-surizer Icec1 at 24 percent:
Ia)
Reciprocating charging pump local pneubatic speed control SifC-459.
(b)
Centrifugal charging pumps flow control valves FCV-121 local pneumatic controller EllC 1.210.
ONI-17 Page 3 of 10 Revision 1 2312 169
(c)
Letdown orifice isolation valves at C-160.
NOTE:
Do not let pressuri:cr Icyc1 decrease to 17 percent as the letdown line isola-tion valves will close and cannot be reopened.
d.
Verify proper pressuri:er pressure.
(1)
If necessary, take LOCAL control of the pressuri:cr backup heater breakers, and OPEN and CLOSE them as required to maintain pressuri:cr pressure at 2255 psig.
2.
OPEN the breakers en MCC B47 for the following equipment in order to isolate the Control Room.
a.
Control Room outside air supply fan 52-4708.
b.
Control Room west supply fan A 52-4710.
c.
Control Room east supply fan B 52-4711.
d.
Control Room cooling unit booster pump 52-4782, c.
Control Room recirculation fan 52-4714 3.
Verify that all turbine control and stop valves are closed locally at the turbine.
4.
Verify that the turbine lubricating oil pump 3 are started as the turbine is coasting down.
5.
If not already running, START one of the auxiliary feedwater pumps and control steam generator level between 65' and 67%
on the wide range indication.
6.
Sample the reactor coolant system for boron, and borate by the followi'ng method to a hot shutdown concentration:
START the boric acid transfer pump that is lined up to a.
the reactor makeup system at the appropriate location.
(1)
South boric acid transfer pump "A" - MCC B25, breaker number 52-2516.
(2) North boric acid transfer pump "B" - MCC B26, breaker number 52-2616.
ONI-17 Page 4 of 10 Revision 1 e
2312 170 O
Y
b.
OPEN the emergency boratior, valve MO-8104 locally on bCC B22, breaker number 52-2204 c.
Visually check the flow rate indicated locally on FI-1S33, and determine the run time required to add the required amount of boric acid, d.
CLOSE MO-8104 and STOP the boric acid transfer pump when sufficient boric acid has been added.
7.
Call in a computer programmer to monitor any unavailabic plant parameters (for example: volume control tank level). This must be done by addressing the computer from the programmer's console in the computer room.
8.
Verify that the turbine goes on turning gear at zero speed.
9.
When the Control Room is again accessible, preceed with COI-4, PLANT SlitTfDOWN FROM Il0T STAND 3Y TO COLD SHtJTDOWN, or the applicable portions of GOI-1, PLANT STARTUP FROM COLD CC::D1 TION TO HOT STANDBY and COI-2, PLANT STARTUP FROM HOT STAND 3Y TO POWER OPERATION.
II.
WITH0lJr 0FFSITE POWER AVAILABLE A.
SYhTTOMS 1.
The symptoms can be any condition that renders the Control Ream uninhab itab le.
This procedure was written assuming the fo'lu:.ing:
a.
The control board is completely operabic fcilowing a main Control Room evacuation; i.e., no failures have occurred to the main control board which create an accident or preclude safe operation of equipment from outside the Control Room, and all necessary automatic features are operational.
b.
Inaccessibility to the Control Room does not occur simultane-ously with or subsequent to an accident condition.
c.
Personnel in the adjacent office and working areas have previously evacuated the area.
B.
PROBA!'LE.'AUSES 1.
Contamination.j] j7j 2. liigh airborne activity. 3. S mok e. 4. Chlorine gas. ONI-17 Page 5 of 10 Revision 1 N
C. AUTOMATIC ACTIO.1S 1. None. D. I!NEDIATE OPERATOR ACTIONS 1. TRIP the reacto'r. 2. The Control Operator shall proceed to the auxiliary feedwater control panel (C-160) and inform all shift personnel of the following, via the communications system: a. The Control Room has been evacuated, the reactor has been tripped, and offsite power is not availabic; proceed to your designated area and take the necessary action. (1) Designated areas and required actions. (a) Shift Supervisor - Proceed to panel C-160 and evaluate present plant conditions. (b) Assistant Control Operator - Proceed to control building electrical auxiliary room and wait for direction. (c) "A" Auxiliary Operator - Froceed to the recipro-cating charging pump room area and wait for direction. (d) "B" Auxiliary Operator - Proceed to the diesel rooms and ensure that the diesels are operating properly. (c) Additional personnel in the controlled access area - Proceed to the controlled access exit and stand by to give further assistance as required. (f) Other Onsite personnel - Stay clear of the affected areas and stand by to give assistance. 3. If there is a reactor coolant system dilution operation in progress, the Control Operator shall direct stopping of the running primary makeup water (P5M) pump. West PSM pump "A" at motor control center (MCC) B25, Breaker Number 52-2555 East PMW pump "B" at motor control center (MCC) B26, Breaker Ntmiber 52-2648 ONI-17 Page 6 of 10 Revision 1 2312 172
E. SUBSI:QtlENT OPl!RATOR ACTION 1. If the reciprocating charging pump was controlling pressuri:cr level in autonatic prior to the evacuation, accomplish the following: Take LOCAL control and START the reciprocating charging a. pump by closing breaker number 152-212 at 4160-V bus A-2. b. STOP both centrifugal charging pumps by the following: (1) At 4160-V bus A-1, take LOCAL control and OPEN breaker number 152-109 for south charging pump "A". (2) At 4160-V bus A-2, take LCCAL control and OPEN breaker number 152-209 for north charging pump B. 2. If a centrifugal charging pump was controlling pressuri er level in automatic prior to the evacuation, verify that the centrifugal charging pumps are started by the normal shutdown sequencer. a. STOP one of the centrifugal charging pumps. 3. Line up the alternate water supply to the center air compressor "B" as follows: a. Close bearing cooling water supply valve BC036. b. Close bearing cooling water return valve BC045. c. Install the temporaty hoses for the alternate water supply and discharge paths, d. Open air compressor "B" alternate cooling water discharge valve at PP3885B. Open air compressor "B" alternate cooling water supply c. valve BC042. f. Slowly open the alternate cooling water supply valve. 4. At auxiliary feedwater control panel C-160, the Control Operator shall take the following actions: a. Verify that the atmospheric steam relief valves are con-trolling main steam line pressure at their setpoint (1125 psig) as indicated on the following instruments - PI514B, PI524B, PI534B, and PI544B. b. Verify that both auxiliary feedwater pumps have started, and adjust their respective auxiliary feedwater control valves as necessary to control steam generator Icycis between 650 and 67S. 2312 173 ONI-17 Page 7 of 10
- Revision 1
c. Verify proper pressuri:cr level. 1. If necessary, take the LOCAL control of the following components and adjust as required to control pres-surizer Icyc1 at 24 percent. (a) Reciprocating charging pump local pneumatic speed control S!!C-459. (b) Centrifugal charging pumps flow control valve FCV-121 local pneumatic controller FilC-121B. (c) Letdcwn orifice isolation valves at C-160. NOTE: Do not let pressuri:er level decrease to 17 percent as the letdown line isola-tion valves will close and cannot be reopened. d. Verify proper pressuri:cr pressure. 5. Reset the 86 lockout relay on load center B02, and verify that center air compressor "B" starts. 6. Energize 4160-V bus A-5 from 4160-V bus A-1 by the following: a. Verify that 12,500-V bus H-1 breaker 252-103 is open. b. CLOSE breaker number 152-101 at 4160-V bus A-1. c. Verify that 4160-V bus A-5 breaker 152-301 is closed. 7. CLOSE breaker 152-504 at 4160-V bus A-5 in order to energi:e pressuri:cr heater load center B09. 8. Take LOCAL control, and CLOSE pressurizer heater group "C" supply breaker number 52-0912 at load center B09. 9. If the backup heaters were in automatic prior to the evacua-tion, verify that group "A" breaker 52-0922 goes closed if pressuri:er pressure is below the setpoint. 10. If the backup heaters were not in automatic, take local control of group "A" breaker 52-0922 and close it as necessary to maintain pressuri:cr pressure at 2235 psig (as indicated on panel C-160). 11. Start the six containment air coolers that were previously running by actuating the pushbutton at their respective load center. 2312 174 ONI-17 Page 8 of 10 Revision 1 e 1 W
Breaker Number Load Center VC-201A 52-0113 B01 VC-201B 52-0214 B02 VC-202A 52-0122 B01 VC-202B 52-0232 B02 VC-203A 52-0323 B03 VC-203B 52-0432 B04 VC-204A 52-0313 B03 VC-204B 52-0433 B04 12. Reset the 86 lockout relay on load center B03, and start south control rod drive mechanism blower "C" by closing breaker number 52-0322 on load center B03. 13. Verify that all turbine control and stop valves are closed locally at the turbine. 14. Verify that turbine lubricating oil pumps are started as the turbine is coasting down. 15. Reset the 86 lockout relay on load center B04, and start south control rod drive mechanism blower "B" by closing breaker number 52-0322 on load center B04 16. Adjust the pressure setpoints on the atmospheric steam relief valve controllers at C-160 as necessary to control main steam line pressure at the no load value (1092 psig). 17. Sample the reactor coolant system for boron, and borate by the following method to a hot shutdown concentration: a. START the boric acid transfer pump that is lined up to the reactor makeup system at the appropriate location. (1) South boric acid transfer pump "A" - MCC B22, breaker number 52-2516. (2) North boric acid transfer pump "B" - MCC B26, breaker number 52-2616. b. OPEN the emergency boration valve M0-8104 locally on MCC B22, breaker number 52-2204. Visually check the flow rate indicated locally en FI-1S3B, c. and detennine the run time required to add the required amount of boric acid. d. CLOSE M0-8104 and STOP the boric acid tranfer pump when sufficient boric acid has been added. ONI-17 Page 9 of 10 Revision 1 2312 175
18. Call in a computer programmer to monitor any unavailable plant parameters (for exar.:pic: volume control tank level). This must be done by addressing the computer from the pro-grammer's console in the computer room. 19. Verify that the turbine goes on turning gear at zero speed. 20. If it is determined that additional buses or loads are required, monitor the emergency diesel generator loadings to prevent exceeding the generator ratings. 21. When the Control Room is again accessible and offsite power is restored, proceed with GOI-4, PLANT SHU1DCtN FRO)! HOT STANDBY TO COLD SHUTDC'AN, or the applicabic portion of GOI-1, PLANT STARTUP FROM COLD CONDITION TO !!OT STANDBY and G01-2, PLANT STARTUP FROM !!OT STANDBY TO PCNER CPERATICN. 2312 176 JDR ONI-17 Page 10 of 10 Revision 1 GP
PORTLM;D GENERAL ELECTRIC COMPNiY TROJAN NUCLEAR PL\\NT Ub.IA'b.r - Dcten.her 19, 1977 n o SAFETY-RELATED ' Revision M u 0 PiY l401 UYDATED OFF-NOPJ'AL INSTRUCTICN ONI-1 REACTOR TRIP / 2[/ 9!7 7 APPROVED BY , a 3/1 L / DATE / / PURPOSE This instruction describes the automatic and operator action required after a reactor trip. A. SYMPTCMS The following indicate that a reactor trip has taken place: 1. Actuation of one of the reactor first out annunciators. 2. One or both reactor trip breakers open. B. PROBABLE CAUSES 1. Exceeding any of the following parameters will cause a reactor trip: 5 1.1 One out of two source range flux high > 10 cps. 1.2 One cut of two internediate range flux high current equivalent to 25 percent of full power (interlocked by F-10). 1.3 Two out of four pcuer range high flux low setpoint of 25 percent full power (interlocked by P-10). 1.4 Two out of four power range high flux high setpoint of 108 percent full power. 1.5 Two out of four overteeperature AT greater than setroint. 1.6 Two out of four overpower AT greater than setpoint. 1.7 Two out of three low coolant flow per loop (interlocked with P-8). ONI-1 Page 1 of 6 Revision 4 2312 177 e
1.8 Two out of three low coolant flows on two loops (interlocked with P-7). 1.9 One out of t<o undervoltage on both H1 and H212-kV buses of <63 percent voltage (interlocked with P-7). 1.10 One out of two underfrequency on both H1 and H2 12-kV buses of <57.5 H: (interlocked with P-7). 1.11 Two out of four high pressurizer pressure > 2385 psig. 1.12 Two cut of four low pressuri:cr pressure < 1865 psig (interlocked with P-7). 1.13 Two out of three high pressuri:er level > 92 percent of span. 1.14 One cut of two low feeduater flow with 1/2 steam generator low level. 1.15 Two out of three low-low stean generator water level (5 percent of span). 1.16 Safety injection. 1.17 Turbine trip (intericek with P-7). 1.18 Two cut of four pouer
- range positive flux rate (+5 percent /
2 sec.). 1.19 Two out of four power range negative flux rate (-5 per. cent / 2 sec.). 1.20 Two protection trains in test. C. AIROMATIC AC IONS 1. Reactor trip: 1.1 The reactor trip breakers open and all full-length rods are dropped. 2. Turbine trip: 2.1 The stop, control, intercept, and reheat stop valves close. 2.2 The extraction bleeder trip valves close and extracticn drain valves cpen. 3. Generator trip: 3.1 The 230-kV generator brechers open. 3.2 The generator exciter field breaker opens. ONI-1 Page 2 of 6 Revision 4 2312 178 r-
3.3 The 12-kV buses H1 and !!2 supply transfers to the startup transformers. D. I?ffEDIATE OPERATOR ACTIONS 1. Verify the following automatic actions as follows: 1.1 Check that all control reds are fully inserted. If any rod is not fully inserted, e=crgency borate by 150 ppm for each rod not fully inserted. 1.2 , Check that turbine step, control, intercept, extraction and reheat stop valves are closed. 1.3 Check that 230-kV generator break'ers and field breakers have opened. E. SUBSC0f?ENT OPERATOR ACTION 1. Check that the main feedwater control valves closed when Tavg reaches
- 564cp, 2.
Verify Tave is % 557, shift Stn Dump Control to " Pressure Mode". l!ain-tain S/G pressure 0 1092. 3. Select one source range and one internediate range channel on NR-4S, and monitor for a -50 second period. 4 If the auxiliary feedwater pumps started fren steam generator low-lou icycl, perform the ic11owing steps: 4.1 Throttle the auxiliary feedwater regulators on the auxillary feedwater pu=p that is to remain in service. 4.2 CLOSE the auxiliary feedwater regulators en the second auxiliary feedwater pump. 4.3 Slowly increase the stean generator level to normal and nain-tain normal water level with the auxiliary feedwater regulators. 4.4 STOP the second auxiliary feedwater pump. NOTE: If both rain feed turbines have tripped, the auxiliary feed pump auto start block switch cust be placed in the BLOCK position. 4.5 Shift chemical inj ection to the auxiliary feedwater pumps. 4.6 Run both main feed turbine speed and governor controllers to minimum, and trip ene turbine. OSI-1 Page 3 of 6 Revision 4 2312 179 %1
- 4.7 If boch nain feedpu=ps have already tripped, run both feedpunp l
speed and governor controllers to mininun and reset one turbine. NOTE: Once a feedpump turbine is reset, the aux, feedpump auto start block switch nay be returned to nornal. 4.3 Restore stean generator blowdown and sampling. 5. If low-low stcan generator level did not occur, and the auiliary feedpuaps did not start, perform the following steps: 5.1 CLOSE auxiliary feedwater regulators C'/-3004A1, CV-3004A2, CV-3004B1, CV-300432, CV-3004C1, CV-3004C2, CV-30C4DI, and CV-3004D2. 5.2 START the desired auxiliary feedwater pump, and nanually control stean generator levels with the auxiliary feedwater flow control valves. 5.3 Run the nain feed turbine speed and governor controllers to nininun. 5.4 TRIP one main fecdwater pump. 5.5 Restore Stean Generator Bicudown and Sampling. 5.6 Shift chenical injection to the Auxiliary Feedicater Systen. 6. If the turbine was supplying its own stean seal at the time of the trip, j reestablish stcan seal pressure by throttling open !!O-3537, stean seal supply, or MO-3536, stean seal bypass valve. 7. CLOSE nain turbine reheating steam supply valves MO-3590A, !!0-3590B, ID-3672A, and MO-36723. 8. OPFM the following turbine drain valves: 8.1 Control valve before seat drains "0-3620. 8.2 Stcan lead drains !D-3507, MO-3513, and l'0-3519. S.3 Crossaround pipe drains "C-3617A and 3, MO-361SA and 3, and MO-3619A and B. S..t l'oisture separator reheater pccket drains M0-2547A and 3, and VC-2543A and 3. S.5 Second stage reheating steam supply drains MO-3594A and B. 9. Check open the folicuing turbine drains: 9.1 Turbine stean Icad drain valve CV-3523. ONI-l Page 4 of 6 Revision 4. 2312 180 1._-...
9.2 Turbino 10th-stage drain tank dump valves CV-2354 and CV-2452 to the condenser. 9.3 Turbine lith-stage drain tank dump valves CV-2382 and CV-2451 to the condenser. 9.4 Extraction drain valves: Nunber 7 heater CV-2408, CV-2353 Number 6 heater CV-2406, CV-2359 Muuber 5 heater CV-2403, CV-2410 Nu=ber 4 heater CV-2402, CV-2376 Number 3 heater CV-2400, CV-2375 10. OPEN the feedwater pu=p turbine drain valves as follows: 10.1 Feedpump turbine lip steam line drains CV-3127A and B. 10.2 FeeJpunp turbine IIP stop valve above seat drains MO-3142 and 10-3133. 10.3 Feedpur-turbine LP stean line drains CV-3125A and CV-31253. 10.4 Feedpump turbine 12 stop valve below seat drains MO-3141 and MO-3137. 10.S Feedpump turbine 1st-stage drains MC-3143 and MO-3140. 10.6 Feedpump turbine LP stop valve above seat drains MO-3144 and 10-3139. 11. Verify that the reactor nakeup control system is in AUTO and the pressurizer level is being controlled by the charging pumps. 12. STOP the heater drain pumps when they are no longer required to maintain level in the heater drain tanh. 13. STOP the second condensate pump if it is running. Leave one con-densate pump running to provide condensate to the exhaust hood sprays. NOTE: Leave running the condensate pump in the train in which the main feed turbine is reset. 14 STAllT the startup boiler per OI-11-3 if required. l 15. As the turbine is coasting dcun, accomplish the following: 15.1 Decrease the bearing oil tenperature to SG - 00 F before the unit goes on turning gear. 15.2 Verify that the unit goes on turning gear, and all turbine oil lift purps start. ONI-1 Page 5 of 6 Pevision 4 23;2 181
15.3 Valve the hydrogen purity analy:er for turning gear operation by opening analy:er vent valve G-27 to the atmosphere and closing analy:er return valve G-26 to the generator. 15.4 Verify that the hood sprays are operating properly.
- 16. Notify Chemical and Radiation Protection personnel to ensure an RCS sanple is taken between 2 and 6 hours after the trip (if trip was at a power Icyc1 frca > 150) and sampled for iodine per the Standard Technical Specifications.
17. Fill out a reactor trip report form and determine if a restart should be nado per A0-3-7, 18. Follcw GOI-6, Reactivity Control After Reactor Shutdown at Pcwer. 2312 182 JJT ONI-l Page 6 of 6 Revision 4
ATTACRMENT 2 RESPONSES TO REOUEST FOR ADDITIONAL INFORMATION PORTLAND GENERAL ELECTRIC COMPANY ~ TROJAN NUCLEAR PLANT DOCKET NO. 50-344 APRIL 18, 1979 3.1.4 Sprinkler System Details provided on design density, type of system, and method of actuation is still under review. No further information is required at this time. PGE Response No response required. 3.1.7 Smoke Exhaust Fans The PCE letter of January 9, 1979 indicates that alternate means of performing smoke removal for the cable spreading room and switchgear rooms are being investigated in lieu of a fixed manually operated smoke exhaust fan. Identify when the alternate means will be selected. PGE Response A single smoke exhaust system that is ducted to all three areas (cable spreading room and both switchgear rooms) was determined to have a detrimental impact on the Control Building shear walls. The re fo re, individual smoke exhaust systems were designed. A manually operated smoke exhaust system will be provided for the switchgear room located in the Turbine Building '-l ~ 2312 183
with a capacity of approximately 7500 cfs. The controls for this system will be located outaide the main entrance doors. The smoke will be exhausted outdoors to the west side of the Turbine Building. A separate manually operated smoke exhaust system will be provided for use by either the cable spreading or the elec-trical switchgear room (not both simultaneously), both located in the Control Building with a system capacity of approximately 7500 cfm. The controls for this system will be located outside each room by the main entrance door. The smoke will be exhausted to the railroad bay area northeast of the Control Building. 3.1.12 Remote Shutdown Capability Staff requests have previously been transmitted to PGE concerning the design of this system. The following information is also required: PCE-1012, Amendment 3, Page C-20 indicated that neither the nor=al in plant communications system or the sound powered communicatienc eystan would be affected by a cable spreading room fire, and thus could be used for performing shutdown functions independent of the cable spreading room. However, this statement was deleted by Amendment 7 to PCE-1012 in December 1978. Describe the communications system to be used by operators in achieving safe shutdown independent of the cable spreading room. PC7. Response Two communication systems are available to enable the operators to achieve a safe plant shutdown independent of the cable spreading room using the decouple switches. The 2312 184
primary communication system is the in plant telephone system-The backup is a sound powered phone system. The,in plant telephone system is battery backed with its normal a-c power source located in the El. 69 f t Turbine Building switchgear room. Decouple switches are located at: (1) Panel C160, Room 89, shown in Figure 3-1, (2) Electrical switchgear room, Room 107, shown in Figure 3-2, (3) Electrical switchgear room, Room 38, shown in Figure 3-2, and (4) Pressurizer switchgear room, Room 183, shown in Figure 3-1. The in plant telephone system raceway is not shown on the plant raceway drawings. Based on a field sampling and review of other plant documents, no communication system raceways to these four decouple switch locations nor their normal a-c power source raceways were found to go through the cable spreading room. Shorting'or opening of the in-plant telephone circuits affects only phones involecd and not the in plant telephone system central equipment. The sound powered phone system also interconnects the four decouple switch locations listed above. Spare conductors, in existing in plant telephone cables were used for this system. As stated above, none of the cables utilized were routed through the cable spreading room. Thus, neither the in plant nor the sound power phones which connect these four decouple switch locations should be affected by a cable spreading room fire. 2312 185 2-3
3.2.1 Cable Penetration Fire Stops Prior to the SER PGE had committed to test two different fire stop designs. Subsequently, by letter of January 9, 1979, PGE has indicated that cable penetration seals through 3-hr fire walls will be upgraded as required to be identical to configurations that have been tested to meet the NRC criteria. Details should be provided on the configuration to be used. PGE Response Brand Industries, the original installers of cable penetra-tion seals at Trojan, has been commissioned to upgrade existing seals to be consistent with tested configurations accepted by the NRC. Details of the upgraded configura-tions will be available to PGE by July 15, 1979. Follow-ing PGE review, these details will be provided to the NRC. 3.2.2 Cable Tray Tests (Train B Switchgear Room) The PGE letter of January 9, 1979 indicates that adequate test data is available in lieu of performing additional tests to obtain information related to switchgear room fire protection. PGE-1012, Page C-50 indicates that the resulta of the rest would he used in performing an analysis to show the adequacy of the air recirculation units in the safety Train B switchgear room to remove the energy generated by a fire. Identify when the results of this analysis will be provided using the available test dara. This analysis should consider maximum temperatures that Train A ecaipment in this room can withstand without malfunction in addition to the maximum allowable cable temperature identified in PGE-1012, Pages C-49 and C-50. 2312 186 2-4
Alternatives acceptable to the staf f in lieu of performing this analysis are: (a) Provide an alternate shutdown capability indepen-dent of cabling and equipment in this room to achieve safe shutdown; (b) Provide an automatic total flooding gas suppres-sion system in this area; or (c) Install a 3-hr rated barrier to separate the Train A cabling and equipment in the room from the Train B cabling and equipment. PCE Response The results of the above-referenced loss of Train B switchgear room air recirculation unit analysis will be available and distributed to the NRC by July 15, 1979. 3.2.3 Effects on Safe Shutdown Where Redundant Cables Are In Proximity (a) Further information provided by Amendments 5, 6, and 7 to PGE-1012 in response to staff position P.F.8 (Pages C-30 through C-32s of PGE-1012) partially addresses the staff concern related to potential fire damage to redundant safe shutdown cabling that may be in proximity to each other but do not crossover. For most of the areas, adequate detail is provided describing the separation between redundant safe shutdown cabling. However, additional detail is required for certain areas as described below: 2312 187 2-5
Area: (1) Intake Structure - Service Water Pumo Area The separation of safe shutdown cables in conduit from the redundant cabling is not adequately described. Details should be provided, such as marked up drawings, chowing the routing and separation of safe shutdown cabling within the area. Area: (2) Fuel Building - Elevation 45 Ft Details, such as marked up drawfags, should be provided showing the routing and separation of the Channel A cable tray and the Channel B conduits within this area. Area: (3) Fuel / Auxiliary Building - Elevation 45 Ft and Area: (4) Fuel Building - Elevation 77 Ft The information provided is not clear as to whether any safe shutdown cabling is contained in conduit in these areas. If any safe shutdown cabling is in conduit, provide details, such as marked up drawings showing the routing and separation of safe shutdown cabling within the area. Area: (10) Turbine Building - Elevation 45 Ft Details should be provided, such as marked up drawings, showing the routing and separation of the Channel A conduits and the Channel B cable tray. (b) From the information provided in PGE-1012 (Page C-31) it is not clear as to whether the adequacy of cable separation for redundant instrumentation was analyzed in the cable study. Verify that the separation of 2312 188 2-6
minimum instrumentation required for safe shutdown was reviewed to assure that postulated fires would not damage redundant instrumentation where redundant cabling is in proximity to each other. PGE Response (a) 1. Attached Figure A depicts the r uting and separation of safe shutdown ca, ling within the Intake Structure area. 2. Attached Figures B and C depict the routing and separation of safe shutdown cabling within the Fuel Building, Elevation 45 ft. 3. Attached Figures B, C, and D depict the routing and separation of safe shutdown cabling within the Fuel / Auxiliary Building, Elevation 45 ft. 4. Attached Figures B, C, and E depict the routing and separation of safe shutdown cabling within the Fuel Building, Elevation 77 ft. 5. Attached Figures F and G depict the routing and separation of safe shutdown cabline within the Turbine Building, Elevation 45 ft. (b) The safe shutdown instrumentation cables were analyzed to determine whether redundant safe shutdown cables could be affected by a fire in areas where these instru-centation cables are in proximity. The instrumentation cable fire analysis employed the same criteria and assumptions as was previously used for the cable tray fire analysis (Page C-32 and C-32a). 2312 189 2-7
The safe shutdown instrumentation circuits analyzed consist of the pressurizer leve_ (3 transmitters), pressurizer pressure (4 transmit-ters), and the individual level indications of each steam generator (3 transmitters per steam generator). The areas of the plant which contain redundant safe shutdown instrumentation cables were studied in detail as dicusssed below: 1. Containment - El. 45 ft 2. Containment - El. 77 ft 3. Cable Penetration Area Outside the Containment 4 Control Building - El. 77 ft - Cable Spreading Room. The following is the analysis of the areas: 1&2. Containment Buildine - El. 45 ft and 77 ft The redundant safe shutdown instrumentation cable routings, at El. 45 ft of the Containment, are shown in detail on Figures H and I. As shown in these figures, redundant cables are routed near the perimeter of the inside wall of the containment. The shield walls and the walls surrounding each 2 actor coolant pump provide adequate protection for these cables in the event of any reactor coolant pump oil fire. In Figure H, the redundant cables are in proximity near the instrument racks JRll6 and JR24D. These instrument racks are located at El. 45 ft and separated by a distance of 4 ft. The only combustible materials located in this area are the cables in one cable tray at El. 60 ft. A fire at the cable tray or near the instrument racks would not affect redundant cabling because of the 10 ft vertical distance between the cable tray and instrument racks. 2312 190 2-8
In Figure I, the redundant instrumentation cables are shown approaching and entering the Containment electrical penetra-tion area. These rede' dant cables, as shown, are separated by a horizontal distance of 30 ft with various nonsafety-related cable trays located between these redundant cables. As previously discussed on Page C-32q, fire barriers will be added to the nonsafety-related cable trays to prevent a fire from propagating and affecting redundant safe shutdown cables. In Figure J, the redundant instrumentation cable routings are shown for F'. 77 ft in the Containment. As can be seen, these cables are routed near the perimeter of the inside wall of the Containment. The only area at El. 77 ft where the cables are in the same vicinity is outside the shield wall adjacent to the pressurizer. In this particular area, the redundant cables are routed in rigid steel conduit below the cable trays. A fire at El. 77 ft or at one of the cable trays (El. 88 ft to 86 ft) would not affect the redundant cables because of the separation distance between the subject cables, cable trays, and the floor. 3. Cable Penetration Area Outside the Containment The redundant safe shutdown instrumentation cables in this area have the same routing as the safe shutdown cables previ-ously discussed on Page C-41. These instrumentation cables come out of the Containment penetrations at El. 53-74 ft, cross over the shield wall (at El. 83 f t), and run horizontally into the Control Building at El. 73 ft and 87 ft, as shown in Figure K. The subject cables are involved in a crossover outside the shield wall as they approach the Control Building. At the crossover point, the redundant cables are separated by a vertical distance of 13 ft (free air space) as shown in Section A of Figure K. The only combustible materials in this area are the cables located in the various cable trays and the nonsafety-related load center B09/B10 at El. 45 ft. 2-9 2312 191
A fire in the nonsafety-related load center (B09/B10) would not affect any of the redundant instrumentation cables because of the 20 ft vertical distance between the load center and the lowest cable tray. A fire at any of the cable tray levels would not affect redundant instrumentation cables because of the minimum separation distance of 16 ft between the redundant cable trays (,see Figrue K9). As previously stated, an automatic deluge system and additional fire detection coverage are being added to this area to ensure the protection of safe shutdown cables. 4. Control Bujj,ine - El. 77 ft, Cable Spreading Room As shown in Figure L, the redundant safe shutdown instrumenta-tion cables are routed through the cable spreading room as they enter the control room cabinets. The Channel A cables (shown in red) and the Channel B cables (shown in green) have a minimum separation distance of 8 ft. There are various nonsafety-related cable trays within this 8 ft spearation distance which provide a combustible path between these redundant instrumentation cables. The only combustibles in the room are the numerous cables in open cable trays. A fire at the nonsafety-related cable trays located between the redundant safe shutdown instrumentation cables could affect these redundant cables. Since this instrumentation is being provided at Panel C160 (independent of the cable spreading room as discussed below) it would still be available in the event that a cable spreading room fire does affect these cables. SDS!ARY Except as noted in the above analysis, no intersection between redundant cabling of different channels exists to create a fire hazard capable of affecting redundant circuitry. This fact, in combination with the separa-2-10 2312 192
tion distances between the redundant cables and raceway, ensure the integri-ty of redundant channels to at least the cable spreading room where a combustible pathway has been shown to exist. In addition to the above instrumentation cables, another group of instrumentation cables and trans-mitters which provide remote indication (at remote shutdown Panel C160) of pressurizer level and pressure, and steam generator level, will be modified to become independent of the cable spreading room and control room. This will ensure that these instrumentation parameters will be available at a remote location (C160 panel) independent of the redundant instrumentation analyzed in the subject analysis even if a cable spreading room fire affects the redundant instrumentation cables. It is thus concluded that a fire will not disable the necessary instrumentation required for safe shutdown of the plant. 3.2.4 Water Shielding PGE-1012 (Page C-54) indicates that fire suppression piping is generally not routed through safety-related areas, that a pipe routing check was performed, and that it was concluded that fire water piping could not detri-mentally impact on any safety-related equipment. For each safety-related area containing fire water piping, provide details supporting your conclusion that failures in this piping will not degrade safety-related equipment. PCE Response In evaluating the impact of water spray on safety-related equipment, a moderate-energy pipe crack was considered. The evaluation is based on the assumption that when it is shown that the impact of water spray involving a safety train or system will not propogate to its redundant counterpart, the availability of the second train is assumed without application of the single-failure criteria. Our conclusions is based on the following: 2312 193 2-11
Auxiliary / Fuel Buildina Elevation - 5 Ft The 3-in. fire line is 3 ft 6 in. above the doorway to the east safety injection pump room. Since the safety injection pump motors are dripproof, a fire water pipe rupture is not likely to affect pump pe rfo rmance. Considering the spatial separation, the interposing wall and the flood protection provided, the postulated water spray will not impact the west safety injection pump or its components. Also this equipment is generally not used for anything but an emergency core cooling function, not normal shutdown. MCC B-56 is approximately 40 ft from HS-34 and it will not be affected by water spray or flooding from a postulated crack. Auxiliary / Fuel Building - Elevation 25 Ft The piping to and from hose station HS-33 remains outside the safety-related equipment rooms on this elevation. Spatial separation, interposing walls, and flood protection is available to keep spray from a fire water line cract from affecting safe shutdown equipment. Auxiliary / Fuel Building - Elevation 45 Ft Hose station HS-19 is located 16 ft from service water booster pump P-148C, which is redundant to P-148A and C. Water spray from a crack in the fire line would not impact both service water booster pump trains simultaneously. This is the only safety-related equipment near fire water piping in this area. 2312 194 2-12
Auxiliary / Fuel Building - Elevations 61 Ft, 77 Ft, and 93 Ft There is no safety-related equipment used for safe Plant shutdown within the range of influence of a postulated fire water pipe rupture on these floors. Safety-related equipment, not used for Plant shutdown, that is within the range of water spray includes the post-accident hydrogen vent analyzer C-285B and the Spent Fuel Fool and Fuel Building cranes. This equipment is either provided with a redundant compo-nent (post-accident hydrogen vent analyzer C-285A) that is not affected by the water spray, or is classified as safety-related for structural integrity only (cranes). Control Building - Elevation 61 Ft The electrical equipment (safety Train B) in this area, such as switchgear, is dripproof but could be impacted by direct water spray. Since this equipment is redundant to that in the Train A switchgear room in the Turbine Building, loss of Train B switchgear would not jeopardize Plant safety, since safety Train A switchgear remains available. Control Building - Elevation 77 Ft Safety-related equipment on this elevation consists of the cable spreading room and mechanical equipment room. These areas are already protected by sprinkler systems and would not be adversely impacted by a pipe rupture. 2312 195 2-13
Control Building - Elevation 93 Ft A rupture in hose station HS-25 piping in the mezzanine area behind the control panels could impact several control room panels. A metal baffle has been instal-led as a water shield. A small portion of sprinkler system "M" piping serving the Shif t Supe rviso rs office and hallway could rupture and affect a control room panel. This piping is being disconnected. Control Building - Elevation 105 Ft Hose station HS-24 is located on the south wall, 14 ft from the electric heaters of HVAC System CB-1. The heaters are inserted in the air duct and their ter-minals are protected by a metal cover. The fan motor of System CB-1 is shielded by the elevator wall. Water spray from HS-24 will not impact safety-related System CB-1. A pipe crack in the 1-1/4 in, diameter fire line in the filter room will not impact System CB-1 because the filter train enclosures are of airtight construction. Turbine Building - Elevation 45 Ft The emergency diesel generators and auxiliary feed-water pumps are safety-related, required for safe Plant shutdown, and are provided with sprinkler systems. A fire water pipe rupture in any single area would not adversely affect Plant shutdown since these components are adequately separated from their redundant components. The remote shutdown panel (C-160) cannot be affected by a fire water pipe 2312 196 rupture. 2-14
Turbine Building - Elevation 63 Ft No fire water pipinr; exists within the Train B switchgear com at this elevation and adequate barrier separation exists between this room and the adjacent walkway area, that contains fire water piping, to guarantee equipment operability. 3.2.5 Administrative Controls No further information is required. PGE Response No response required. 3.2.6 Containment Fire Suppression (a) To preclude the potential for a large oil fire which could not be promptly suppreased as required by BTP 9.5-1 and Appendix A, one of the following should be provided at the reactor coolant pumps: 1. An automatic sprinkler system; 2. An automatic AFFF (Aqueous Film Forming Foam) system; 3. An oil collection system to collect leakage at potential leakage points and drain oil to a closed container. Potential leakage points to be protected should include: flanged connections, drain plugs, fill points, upper and lower reser-voirs. sight glasses, lift pump, and external oil cooler. 2312 197 2-15
(b) To provide the capability to suppress fires in elec-trical cable trays and residual oil at the reactor coolant pumps, manual fire hose stations should be provided inside Containment. These may be provided by hose connections to an existing water system if fire water demands will not degrade capability of this system to meet safe shutdown demands. PCE Response (a) PGE will provide an oil collection systea for the reactor coolant pumps. This system will be designed to collect all leakage from potential leakage points and drain to a closed and properly vented container. Vendor personnel have been contacted and the oil collection system design has begun. Due to vendor personnel availability, Containment access con-straints and the fabrication time required to imple-ment this design, installation of this system cannot be assured prior to startup of Cycle 4, presently scheduled for the Spring of 1981. Since this commit-ment was not required by the NRC-issued Safety Evaluation Report of March 9, 1978, and PGE has shown by analysis (Pages C-33 ' rough C-37) that a large RCP oil fire will not degrade the safe shutdown capability of the Plant, we believe this schedule is adequate to maintain sufficient safety margins. (b) PGE will provide manual hose stations inside Contain-ment which differs in design from other hose stations within the Plant. Various decontamination wash-down stations in the Containment will be used for this function. The system is expected to provide a minimum of 25 gpm of demineralized water. Appropriate 2312 198 2-16
hose lengths (1-1/2 in. diameter) of "ethylane propa-lene rubber" or other suitable material, will be provided so that an effective hose stream can be directed to any area containing combustible material within the Containment below El. 100 ft. Since combustible materials within the Containment are negligible (excepting oil within the RCPs), and portable extinguishers are adequate for possible fires within the Containment, this fire water supply is judged to be more than adequate. 3.2.7 Cable Penetration Area Fire Protection PCE-1012 (Pages B-25 and C-39) indicates that the spray system to be provided for this area will be a two-zoned system that will be actuated by redundant photoelectric detectors. Provide details on the actuation logic for this system, definition of detector zones, and identifi-cation of which trays are to be covered with 0.3 gpm/sq ft (Zone 1) and which are to be covered with 0.15 gpm/sq ft (Zone 2). PCE Response The cable penetration area is divided into two zones as shown in Figure 3-1. Zone 1 is Room 183 which has a ceiling and two open-air walls. It contains both the pressurizer heater switchgear with oil filled transformers and the containment penetration module nitrogen supply bottles. To protect against possible transformer fires, the deluge system will provide 0.30 gpm/sq ft spray. Zone 2 is Roon 358 which contains the containment electrical penetrations. This area will be provided with a deluge system capable of 0.15 gpm/sq ft spray. 2312 199 2-17
Each suppression zone has provision for manual actuation via a pull station located at Turbine Building, El. 45 ft near HS-15, shown in Figure 3-1. In addition, each sup-pression zone is automatically actuated by two cross-zoned detection circuits (A and B). Both suppression zone detector circuits operate identically as follows: Receipt of either a Detector Circuit A or Detector Circuit B alarm initiates a 2-min time delay relay. If, at the end of 2 min, both a Detector Circuit A alarm and a Detector Circuit B ala rm exist, their associated suppression zone is automati-cally actuated. This method of cross-zoning is designed to minimize false automatic zone spray actuation. 2312 200 SML/4gah66.39A2 2-18
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